UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 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 |
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| 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 |
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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 September 30, 20152016 |
|
| The Southern Company | | Par Value $5 Per Share | | 908,938,919979,999,480 |
|
| 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
September 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
September 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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| 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 |
AGL Resources | AGL Resources Inc., a Georgia corporation |
| 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, effective July 1, 2016, of Merger Sub with and into AGL Resources on the terms and subject to the conditions set forth in the Merger Agreement, with AGL Resources continuing as the surviving corporation and a wholly-owned, direct subsidiary of Southern Company with and into Southern Company Gas, with Southern Company Gas continuing as the surviving corporation |
Merger AgreementMirror CWIP | Agreement and Plan of Merger, dated as of August 23,A regulatory liability used by Mississippi Power to record customer refunds resulting from a 2015 among Southern Company, AGL Resources, and Merger SubMississippi PSC order |
DEFINITIONS
(continued)
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| |
| Term | Meaning |
| | |
Merger Sub | AMS Corp., a Georgia corporation and 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 |
| NCCR | Georgia Power's Nuclear Construction Cost Recovery |
| Nicor Gas | Northern Illinois Gas Company, a wholly-owned subsidiary of Southern Company Gas |
| NRC | U.S. Nuclear Regulatory Commission |
| OCI | Other comprehensive income |
| PATH Act | The Protecting Americans from Tax Hikes Act |
| 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'sS&P Global Ratings, Services, a division of The McGraw Hill Companies,S&P Global Inc. |
| scrubber | Flue gas desulfurization system |
| SCS | Southern Company Services, Inc. (the Southern Company system service company) |
| SEC | U.S. Securities and Exchange Commission |
| SMEPA | South Mississippi Electric Power Association |
| Southern Company | The Southern Company |
| Southern Company Gas | Southern Company Gas (formerly known as AGL Resources Inc.) and its subsidiaries |
| Southern Company Gas Capital | Southern Company Gas Capital Corporation, a wholly-owned subsidiary of Southern Company Gas |
| 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, and, as of July 1, 2016, Southern Company Gas |
| 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 |
Tranquillity | RE Tranquillity Holdings, LLC |
Tranquillity Credit Agreement | Secured Credit Agreement, dated as of July 31, 2015, by and among RE Tranquillity LLC, an indirect subsidiary of Southern Power Company, the several lenders and issuing banks party thereto, and Norddeutsche Landesbank Girozentrale, New York Branch, as Administrative Agent |
| 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 potential financing of the Merger, the expected timing of the completion of the Merger, the proposed settlement agreement between the Vogtle Owners and the Contractor, 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 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;
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current and future litigation, regulatory investigations, proceedings, or inquiries, including 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;
the ability to complete the proposed settlement among the Vogtle Owners and the Contractor, including the satisfaction of conditions to such settlement;
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 regulated rates, the strategic goals for the wholesale business, economic conditions, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, financing activities, completion dates of acquisitions and construction projects, filings with state and federal regulatory authorities, federal income tax benefits, estimated sales and purchases under power sale and purchase agreements, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
the impact of recent and future federal and state regulatory changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the utility industry, environmental laws regulating emissions, discharges, and disposal to air, water, and land, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;
current and future litigation, regulatory investigations, proceedings, or inquiries, including, without limitation, IRS and state tax audits;
the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company's subsidiaries operate;
variations in demand for electricity and natural gas, including those relating to weather, the general economy and recovery from the last recession, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;
available sources and costs of natural gas and other fuels;
limits on pipeline capacity;
effects of inflation;
the ability to control costs and avoid cost overruns during the development and construction of facilities, which include the development and construction of generating facilities with designs that have not been finalized or previously constructed, including changes in labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, sustaining nitrogen supply, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by any PSC);
the ability to construct facilities in accordance with the requirements of permits and licenses, to satisfy any environmental performance standards and the requirements of tax credits and other incentives, and to integrate facilities into the Southern Company system upon completion of construction;
investment performance of Southern Company's employee and retiree benefit plans and the Southern Company system's nuclear decommissioning trust funds;
advances in technology;
state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;
legal proceedings and regulatory approvals and actions related to Plant Vogtle Units 3 and 4, including Georgia PSC approvals and NRC actions;
actions related to cost recovery for the Kemper IGCC, including the ultimate impact of the 2015 decision of the Mississippi Supreme Court, the Mississippi PSC's AugustDecember 2015 interim rate order, and related legal or regulatory proceedings, Mississippi PSC review of the prudence of Kemper IGCC costs and approval of further permanent rate recovery plans, actions relating to proposed securitization, the ability to utilize bonus depreciation, which currently requires that assets be placed in service in 2015, satisfaction of requirements to utilize ITCs and 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 expected timing, likelihood, and benefits of completion of the Merger, including the failure to receive, on a timely basis or otherwise, the required approvals by AGL Resources' shareholders and government or regulatory agencies (including the terms of such approvals), the possibility that long-term financing for the Merger may not be put in place prior to the closing, the risk that a condition to closing of the Merger or funding of the Bridge Agreement may not be satisfied, the possibility that the anticipated benefits from the Merger cannot be fully realized or may take longer to realize than expected, the possibility that costs related to the integration of Southern Company and AGL ResourcesSouthern Company Gas will be greater than expected, the credit ratings of the combined company or its subsidiaries may be different from what the parties expect, the ability to retain and hire key personnel and maintain relationships with customers, suppliers, or other business partners, and the diversion of management time on Merger-related issues, and the impact of legislative, regulatory, and competitive changes;integration-related issues;
the ability of counterparties of Southern Company and its subsidiaries to make payments as and when due and to perform as required;
the ability to obtain new short- and long-term contracts with wholesale customers;
the direct or indirect effect on the Southern Company system's business resulting from cyber intrusion or terrorist incidents and the threat of terrorist incidents;
interest rate fluctuations and financial market conditions and the results of financing efforts;
changes in Southern Company's and any of its subsidiaries' credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;
the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on currency exchange rates, counterparty performance, and the economy in general, as well as potential impacts on the benefits of the DOE loan guarantees;
the ability of Southern Company's subsidiarieselectric utilities to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;
catastrophic events such as fires, earthquakes, explosions, floods, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;
the direct or indirect effects on the Southern Company system's business resulting from incidents affecting the U.S. electric grid, natural gas pipeline infrastructure, or operation of generating or storage resources;
the effect of accounting pronouncements issued periodically by standard-setting bodies; and
other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the registrants from time to time with the SEC.
The registrants expressly disclaim any obligation to update any forward-looking statements.
THE SOUTHERN COMPANY
AND SUBSIDIARY COMPANIES
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
| | | | For the Three Months
Ended September 30, | | For the Nine Months
Ended September 30, | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | | | | | | | | |
| Retail revenues | $ | 4,701 |
| | $ | 4,558 |
| | $ | 11,958 |
| | $ | 12,186 |
| |
| Wholesale revenues | 520 |
| | 600 |
| | 1,435 |
| | 1,719 |
| |
| Retail electric revenues | | $ | 4,808 |
| | $ | 4,701 |
| | $ | 11,932 |
| | $ | 11,958 |
|
| Wholesale electric revenues | | 613 |
| | 520 |
| | 1,455 |
| | 1,435 |
|
| Other electric revenues | 169 |
| | 169 |
| | 494 |
| | 503 |
| 181 |
| | 169 |
| | 529 |
| | 494 |
|
| Natural gas revenues | | 518 |
| | — |
| | 518 |
| | — |
|
| Other revenues | 11 |
| | 12 |
| | 34 |
| | 42 |
| 144 |
| | 11 |
| | 281 |
| | 34 |
|
| Total operating revenues | 5,401 |
| | 5,339 |
| | 13,921 |
| | 14,450 |
| 6,264 |
| | 5,401 |
| | 14,715 |
| | 13,921 |
|
| Operating Expenses: | | | | | | | | | | | | | | |
| Fuel | 1,520 |
| | 1,656 |
| | 3,932 |
| | 4,765 |
| 1,400 |
| | 1,520 |
| | 3,334 |
| | 3,932 |
|
| Purchased power | 193 |
| | 194 |
| | 507 |
| | 514 |
| 227 |
| | 193 |
| | 581 |
| | 507 |
|
| Cost of natural gas | | 133 |
| | — |
| | 133 |
| | — |
|
| Cost of other sales | | 84 |
| | — |
| | 161 |
| | — |
|
| Other operations and maintenance | 1,097 |
| | 1,021 |
| | 3,320 |
| | 3,026 |
| 1,411 |
| | 1,097 |
| | 3,616 |
| | 3,320 |
|
| Depreciation and amortization | 528 |
| | 514 |
| | 1,515 |
| | 1,515 |
| 695 |
| | 528 |
| | 1,805 |
| | 1,515 |
|
| Taxes other than income taxes | 264 |
| | 258 |
| | 761 |
| | 751 |
| 309 |
| | 264 |
| | 821 |
| | 761 |
|
| Estimated loss on Kemper IGCC | 150 |
| | 418 |
| | 182 |
| | 798 |
| 88 |
| | 150 |
| | 222 |
| | 182 |
|
| Total operating expenses | 3,752 |
| | 4,061 |
| | 10,217 |
| | 11,369 |
| 4,347 |
| | 3,752 |
| | 10,673 |
| | 10,217 |
|
| Operating Income | 1,649 |
| | 1,278 |
| | 3,704 |
| | 3,081 |
| 1,917 |
| | 1,649 |
| | 4,042 |
| | 3,704 |
|
| Other Income and (Expense): | | | | | | | | | | | | | | |
| Allowance for equity funds used during construction | 60 |
| | 63 |
| | 163 |
| | 182 |
| 52 |
| | 60 |
| | 150 |
| | 163 |
|
| Interest expense, net of amounts capitalized | (218 | ) | | (207 | ) | | (612 | ) | | (623 | ) | (374 | ) | | (218 | ) | | (913 | ) | | (612 | ) |
| Other income (expense), net | (21 | ) | | (7 | ) | | (41 | ) | | (20 | ) | 21 |
| | (21 | ) | | (38 | ) | | (41 | ) |
| Total other income and (expense) | (179 | ) | | (151 | ) | | (490 | ) | | (461 | ) | (301 | ) | | (179 | ) | | (801 | ) | | (490 | ) |
| Earnings Before Income Taxes | 1,470 |
| | 1,127 |
| | 3,214 |
| | 2,620 |
| 1,616 |
| | 1,470 |
| | 3,241 |
| | 3,214 |
|
| Income taxes | 500 |
| | 392 |
| | 1,076 |
| | 889 |
| 448 |
| | 500 |
| | 942 |
| | 1,076 |
|
| Consolidated Net Income | 970 |
| | 735 |
| | 2,138 |
| | 1,731 |
| 1,168 |
| | 970 |
| | 2,299 |
| | 2,138 |
|
| Less: | | | | | | | | |
| Dividends on Preferred and Preference Stock of Subsidiaries | 11 |
| | 17 |
| | 42 |
| | 51 |
| 11 |
| | 11 |
| | 34 |
| | 42 |
|
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries | $ | 959 |
| | $ | 718 |
| | $ | 2,096 |
| | $ | 1,680 |
| |
| Net income attributable to noncontrolling interests | | 27 |
| | — |
| | 39 |
| | — |
|
| Consolidated Net Income Attributable to Southern Company | | $ | 1,130 |
| | $ | 959 |
| | $ | 2,226 |
| | $ | 2,096 |
|
| Common Stock Data: | | | | | | | | | | | | | | |
| Earnings per share (EPS) — | | | | | | | | | | | | | | |
| Basic EPS | $ | 1.05 |
| | $ | 0.80 |
| | $ | 2.30 |
| | $ | 1.88 |
| $ | 1.17 |
| | $ | 1.05 |
| | $ | 2.37 |
| | $ | 2.30 |
|
| Diluted EPS | $ | 1.05 |
| | $ | 0.80 |
| | $ | 2.30 |
| | $ | 1.87 |
| $ | 1.16 |
| | $ | 1.05 |
| | $ | 2.36 |
| | $ | 2.30 |
|
| Average number of shares of common stock outstanding (in millions) | | | | | | | | | | | | | | |
| Basic | 910 |
| | 898 |
| | 910 |
| | 894 |
| 968 |
| | 910 |
| | 940 |
| | 910 |
|
| Diluted | 912 |
| | 902 |
| | 913 |
| | 898 |
| 975 |
| | 912 |
| | 945 |
| | 913 |
|
| Cash dividends paid per share of common stock | $ | 0.5425 |
| | $ | 0.5250 |
| | $ | 1.6100 |
| | $ | 1.5575 |
| $ | 0.5600 |
| | $ | 0.5425 |
| | $ | 1.6625 |
| | $ | 1.6100 |
|
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
| | | | For the Three Months
Ended September 30, | | For the Nine Months
Ended September 30, | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Consolidated Net Income | $ | 970 |
| | $ | 735 |
| | $ | 2,138 |
| | $ | 1,731 |
| $ | 1,168 |
| | $ | 970 |
| | $ | 2,299 |
| | $ | 2,138 |
|
| Other comprehensive income (loss): | | | | | | | | | | | | | | |
| Qualifying hedges: | | | | | | | | | | | | | | |
| Changes in fair value, net of tax of $(11), $-, $(10) and $-, respectively | (18 | ) | | — |
| | (16 | ) | | — |
| |
Reclassification adjustment for amounts included in net income,
net of tax of $1, $1, $3 and $2, respectively | 1 |
| | 1 |
| | 4 |
| | 4 |
| |
| Pension and other post retirement benefit plans: | | | | | | | | |
Reclassification adjustment for amounts included in net income,
net of tax of $1, $1, $3 and $2, respectively | 2 |
| | 1 |
| | 5 |
| | 2 |
| |
Changes in fair value, net of tax of $12, $(11), $(74), and $(10),
respectively | | 19 |
| | (18 | ) | | (118 | ) | | (16 | ) |
Reclassification adjustment for amounts included in net income,
net of tax of $2, $1, $13, and $3, respectively | | 2 |
| | 1 |
| | 20 |
| | 4 |
|
| Pension and other postretirement benefit plans: | | | | | | | | |
Reclassification adjustment for amounts included in net income,
net of tax of $1, $1, $2, and $3, respectively | | 1 |
| | 2 |
| | 3 |
| | 5 |
|
| Total other comprehensive income (loss) | (15 | ) | | 2 |
| | (7 | ) | | 6 |
| 22 |
| | (15 | ) | | (95 | ) | | (7 | ) |
| Less: | | | | | | | | |
| Dividends on preferred and preference stock of subsidiaries | (11 | ) | | (17 | ) | | (42 | ) | | (51 | ) | 11 |
| | 11 |
| | 34 |
| | 42 |
|
| Comprehensive Income | $ | 944 |
| | $ | 720 |
| | $ | 2,089 |
| | $ | 1,686 |
| |
| Comprehensive income attributable to noncontrolling interests | | 27 |
| | — |
| | 39 |
| | — |
|
Consolidated Comprehensive Income Attributable to Southern Company | | $ | 1,152 |
| | $ | 944 |
| | $ | 2,131 |
| | $ | 2,089 |
|
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
| | | | For the Nine Months
Ended September 30, | For the Nine Months Ended September 30, |
| | 2015 | | 2014 | 2016 | | 2015 |
| | (in millions) | (in millions) |
| Operating Activities: | | | | | | |
| Consolidated net income | $ | 2,138 |
| | $ | 1,731 |
| $ | 2,299 |
| | $ | 2,138 |
|
| Adjustments to reconcile consolidated net income to net cash provided from operating activities — | | | | | | |
| Depreciation and amortization, total | 1,787 |
| | 1,798 |
| 2,109 |
| | 1,787 |
|
| Deferred income taxes | 821 |
| | 330 |
| (22 | ) | | 821 |
|
| Investment tax credits | 319 |
| | (70 | ) | — |
| | 319 |
|
| Allowance for equity funds used during construction | (163 | ) | | (182 | ) | (150 | ) | | (163 | ) |
| Pension, postretirement, and other employee benefits | | (158 | ) | | 79 |
|
| Settlement of asset retirement obligations | | (117 | ) | | (20 | ) |
| Stock based compensation expense | 77 |
| | 51 |
| 87 |
| | 77 |
|
| Hedge settlements | | (236 | ) | | (4 | ) |
| Estimated loss on Kemper IGCC | 182 |
| | 798 |
| 222 |
| | 182 |
|
| Income taxes receivable, non-current | (444 | ) | | — |
| — |
| | (444 | ) |
| Other, net | 7 |
| | (116 | ) | (98 | ) | | (48 | ) |
| Changes in certain current assets and liabilities — | | | | | | |
| -Receivables | (118 | ) | | (640 | ) | (458 | ) | | (118 | ) |
| -Fossil fuel stock | 239 |
| | 522 |
| |
| -Materials and supplies | (22 | ) | | (45 | ) | |
| -Fossil fuel for generation | | 204 |
| | 239 |
|
| -Natural gas for sale | | (222 | ) | | — |
|
| -Other current assets | (18 | ) | | (29 | ) | (111 | ) | | (40 | ) |
| -Accounts payable | (266 | ) | | (92 | ) | (9 | ) | | (266 | ) |
| -Accrued taxes | 408 |
| | 403 |
| 1,062 |
| | 408 |
|
| -Accrued compensation | (129 | ) | | 96 |
| (122 | ) | | (129 | ) |
| -Mirror CWIP | 99 |
| | 112 |
| — |
| | 99 |
|
| -Other current liabilities | 171 |
| | 20 |
| (18 | ) | | 171 |
|
| Net cash provided from operating activities | 5,088 |
| | 4,687 |
| 4,262 |
| | 5,088 |
|
| Investing Activities: | | | | | | |
| Plant acquisitions | (1,128 | ) | | (218 | ) | |
| Business acquisitions, net of cash acquired | | (9,513 | ) | | (1,128 | ) |
| Property additions | (3,490 | ) | | (3,686 | ) | (5,252 | ) | | (3,490 | ) |
| Investment in restricted cash | — |
| | (11 | ) | (750 | ) | | — |
|
| Distribution of restricted cash | | 746 |
| | — |
|
| Nuclear decommissioning trust fund purchases | (1,164 | ) | | (635 | ) | (838 | ) | | (1,164 | ) |
| Nuclear decommissioning trust fund sales | 1,159 |
| | 633 |
| 832 |
| | 1,159 |
|
| Cost of removal, net of salvage | (118 | ) | | (106 | ) | (155 | ) | | (118 | ) |
| Change in construction payables, net | 20 |
| | 11 |
| (259 | ) | | 20 |
|
| Investment in unconsolidated subsidiaries | | (1,421 | ) | | — |
|
| Prepaid long-term service agreement | (166 | ) | | (145 | ) | (125 | ) | | (166 | ) |
| Other investing activities | 7 |
| | — |
| 95 |
| | 7 |
|
| Net cash used for investing activities | (4,880 | ) | | (4,157 | ) | (16,640 | ) | | (4,880 | ) |
| Financing Activities: | | | | | | |
| Increase (decrease) in notes payable, net | 662 |
| | (1,117 | ) | |
| Increase in notes payable, net | | 655 |
| | 662 |
|
| Proceeds — | | | | | | |
| Long-term debt issuances | 3,992 |
| | 2,715 |
| |
| Interest-bearing refundable deposit | — |
| | 75 |
| |
| Common stock issuances | 136 |
| | 484 |
| |
| Long-term debt | | 14,091 |
| | 3,992 |
|
| Common stock | | 3,265 |
| | 136 |
|
| Short-term borrowings | 280 |
| | — |
| — |
| | 280 |
|
| Redemptions and repurchases — | | | | | | |
| Long-term debt | (2,562 | ) | | (437 | ) | (2,405 | ) | | (2,562 | ) |
| Interest-bearing refundable deposits | (275 | ) | | — |
| — |
| | (275 | ) |
| Preferred and preference stock | (412 | ) | | — |
| — |
| | (412 | ) |
| Common stock | (115 | ) | | (5 | ) | — |
| | (115 | ) |
| Short-term borrowings | (255 | ) | | — |
| (475 | ) | | (255 | ) |
| Distributions to noncontrolling interests | | (22 | ) | | (6 | ) |
| Capital contributions from noncontrolling interests | | 367 |
| | 274 |
|
| Purchase of membership interests from noncontrolling interests | | (129 | ) | | — |
|
| Payment of common stock dividends | (1,465 | ) | | (1,391 | ) | (1,553 | ) | | (1,465 | ) |
| Payment of dividends on preferred and preference stock of subsidiaries | (48 | ) | | (51 | ) | |
| Other financing activities | 253 |
| | (48 | ) | (151 | ) | | (63 | ) |
| Net cash provided from financing activities | 191 |
| | 225 |
| 13,643 |
| | 191 |
|
| Net Change in Cash and Cash Equivalents | 399 |
| | 755 |
| 1,265 |
| | 399 |
|
| Cash and Cash Equivalents at Beginning of Period | 710 |
| | 659 |
| 1,404 |
| | 710 |
|
| Cash and Cash Equivalents at End of Period | $ | 1,109 |
| | $ | 1,414 |
| $ | 2,669 |
| | $ | 1,109 |
|
| Supplemental Cash Flow Information: | | | | | | |
| Cash paid (received) during the period for — | | | | | | |
| Interest (net of $88 and $80 capitalized for 2015 and 2014, respectively) | $ | 590 |
| | $ | 560 |
| |
| Interest (net of $94 and $88 capitalized for 2016 and 2015, respectively) | | $ | 766 |
| | $ | 590 |
|
| Income taxes, net | (13 | ) | | 263 |
| (151 | ) | | (13 | ) |
| Noncash transactions — Accrued property additions at end of period | 483 |
| | 415 |
| 578 |
| | 483 |
|
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
| | | Assets | | At September 30,
2015 | | At December 31,
2014 | | At September 30, 2016 | | At December 31, 2015 |
| | | (in millions) | | (in millions) |
| Current Assets: | | | | | | | | |
| Cash and cash equivalents | | $ | 1,109 |
| | $ | 710 |
| | $ | 2,669 |
| | $ | 1,404 |
|
| Receivables — | | | | | | | | |
| Customer accounts receivable | | 1,432 |
| | 1,090 |
| | 1,718 |
| | 1,058 |
|
| Energy marketing receivable | | | 526 |
| | — |
|
| Unbilled revenues | | 488 |
| | 432 |
| | 639 |
| | 397 |
|
| Under recovered regulatory clause revenues | | 126 |
| | 136 |
| | 54 |
| | 63 |
|
| Income taxes receivable, current | | | — |
| | 144 |
|
| Other accounts and notes receivable | | 248 |
| | 307 |
| | 317 |
| | 398 |
|
| Accumulated provision for uncollectible accounts | | (19 | ) | | (18 | ) | | (43 | ) | | (13 | ) |
| Fossil fuel stock, at average cost | | 691 |
| | 930 |
| |
| Materials and supplies, at average cost | | 1,046 |
| | 1,039 |
| |
| Materials and supplies | | | 1,268 |
| | 1,061 |
|
| Fossil fuel for generation | | | 664 |
| | 868 |
|
| Natural gas for sale | | | 627 |
| | — |
|
| Vacation pay | | 177 |
| | 177 |
| | 178 |
| | 178 |
|
| Prepaid expenses | | 248 |
| | 665 |
| | 459 |
| | 495 |
|
| Deferred income taxes, current | | 258 |
| | 506 |
| |
| Other regulatory assets, current | | 421 |
| | 346 |
| | 414 |
| | 402 |
|
| Other current assets | | 45 |
| | 50 |
| | 168 |
| | 71 |
|
| Total current assets | | 6,270 |
| | 6,370 |
| | 9,658 |
| | 6,526 |
|
| Property, Plant, and Equipment: | | | | | | | | |
| In service | | 71,929 |
| | 70,013 |
| | 94,174 |
| | 75,118 |
|
| Less accumulated depreciation | | 24,190 |
| | 24,059 |
| | 29,590 |
| | 24,253 |
|
| Plant in service, net of depreciation | | 47,739 |
| | 45,954 |
| | 64,584 |
| | 50,865 |
|
| Other utility plant, net | | 73 |
| | 211 |
| | — |
| | 233 |
|
| Nuclear fuel, at amortized cost | | 869 |
| | 911 |
| | 901 |
| | 934 |
|
| Construction work in progress | | 9,562 |
| | 7,792 |
| | 10,069 |
| | 9,082 |
|
| Total property, plant, and equipment | | 58,243 |
| | 54,868 |
| | 75,554 |
| | 61,114 |
|
| Other Property and Investments: | | | | | | | | |
| Goodwill | | | 6,223 |
| | 2 |
|
| Equity investments in unconsolidated subsidiaries | | | 1,541 |
| | 6 |
|
Other intangible assets, net of amortization of $39 and $12
at September 30, 2016 and December 31, 2015, respectively | | | 942 |
| | 317 |
|
| Nuclear decommissioning trusts, at fair value | | 1,473 |
| | 1,546 |
| | 1,616 |
| | 1,512 |
|
| Leveraged leases | | 752 |
| | 743 |
| | 769 |
| | 755 |
|
| Miscellaneous property and investments | | 489 |
| | 203 |
| | 249 |
| | 160 |
|
| Total other property and investments | | 2,714 |
| | 2,492 |
| | 11,340 |
| | 2,752 |
|
| Deferred Charges and Other Assets: | | | | | | | | |
| Deferred charges related to income taxes | | 1,553 |
| | 1,510 |
| | 1,590 |
| | 1,560 |
|
| Unamortized debt issuance expense | | 203 |
| | 202 |
| |
| Unamortized loss on reacquired debt | | 232 |
| | 243 |
| | 228 |
| | 227 |
|
| Other regulatory assets, deferred | | 4,733 |
| | 4,334 |
| | 6,446 |
| | 4,989 |
|
| Income taxes receivable, non-current | | 444 |
| | — |
| | 413 |
| | 413 |
|
| Other deferred charges and assets | | 823 |
| | 904 |
| | 1,133 |
| | 737 |
|
| Total deferred charges and other assets | | 7,988 |
| | 7,193 |
| | 9,810 |
| | 7,926 |
|
| Total Assets | | $ | 75,215 |
| | $ | 70,923 |
| | $ | 106,362 |
| | $ | 78,318 |
|
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
| | | Liabilities and Stockholders' Equity | | At September 30,
2015 | | At December 31,
2014 | | At September 30, 2016 | | At December 31, 2015 |
| | | (in millions) | | (in millions) |
| Current Liabilities: | | | | | | | | |
| Securities due within one year | | $ | 3,313 |
| | $ | 3,333 |
| | $ | 2,254 |
| | $ | 2,674 |
|
| Interest-bearing refundable deposits | | — |
| | 275 |
| |
| Notes payable | | 1,490 |
| | 803 |
| | 1,670 |
| | 1,376 |
|
| Energy marketing trade payables | | | 533 |
| | — |
|
| Accounts payable | | 1,419 |
| | 1,593 |
| | 1,732 |
| | 1,905 |
|
| Customer deposits | | 400 |
| | 390 |
| | 577 |
| | 404 |
|
| Accrued taxes — | | | | | | | | |
| Accrued income taxes | | 404 |
| | 151 |
| | 375 |
| | 19 |
|
| Other accrued taxes | | 566 |
| | 487 |
| | 641 |
| | 484 |
|
| Accrued interest | | 223 |
| | 295 |
| | 410 |
| | 249 |
|
| Accrued vacation pay | | 223 |
| | 223 |
| | 231 |
| | 228 |
|
| Accrued compensation | | 462 |
| | 576 |
| | 505 |
| | 549 |
|
| Mirror CWIP | | 369 |
| | 271 |
| |
| Asset retirement obligations, current | | | 390 |
| | 217 |
|
| Liabilities from risk management activities, net of collateral | | | 125 |
| | 156 |
|
| Other regulatory liabilities, current | | | 99 |
| | 278 |
|
| Mandatorily redeemable noncontrolling interest | | | 174 |
| | — |
|
| Other current liabilities | | 820 |
| | 570 |
| | 851 |
| | 590 |
|
| Total current liabilities | | 9,689 |
| | 8,967 |
| | 10,567 |
| | 9,129 |
|
| Long-term Debt | | 22,326 |
| | 20,841 |
| | 41,550 |
| | 24,688 |
|
| Deferred Credits and Other Liabilities: | | | | | | | | |
| Accumulated deferred income taxes | | 11,990 |
| | 11,568 |
| | 14,218 |
| | 12,322 |
|
| Deferred credits related to income taxes | | 183 |
| | 192 |
| | 204 |
| | 187 |
|
| Accumulated deferred investment tax credits | | 1,004 |
| | 1,208 |
| | 1,721 |
| | 1,219 |
|
| Employee benefit obligations | | 2,408 |
| | 2,432 |
| | 3,022 |
| | 2,582 |
|
| Asset retirement obligations | | 2,952 |
| | 2,168 |
| |
| Asset retirement obligations, deferred | | | 4,124 |
| | 3,542 |
|
| Unrecognized tax benefits | | 369 |
| | 4 |
| | 381 |
| | 370 |
|
| Accrued environmental remediation | | | 415 |
| | 42 |
|
| Other cost of removal obligations | | 1,210 |
| | 1,215 |
| | 2,771 |
| | 1,162 |
|
| Other regulatory liabilities, deferred | | 399 |
| | 398 |
| | 401 |
| | 254 |
|
| Other deferred credits and liabilities | | 603 |
| | 590 |
| | 641 |
| | 678 |
|
| Total deferred credits and other liabilities | | 21,118 |
| | 19,775 |
| | 27,898 |
| | 22,358 |
|
| Total Liabilities | | 53,133 |
| | 49,583 |
| | 80,015 |
| | 56,175 |
|
| Redeemable Preferred Stock of Subsidiaries | | 118 |
| | 375 |
| | 118 |
| | 118 |
|
| Redeemable Noncontrolling Interest | | 41 |
| | 39 |
| |
| Redeemable Noncontrolling Interests | | | 49 |
| | 43 |
|
| Stockholders' Equity: | | | | | | | | |
| Common Stockholders' Equity: | | | | | | | | |
| Common stock, par value $5 per share — | | | | | | | | |
| Authorized — 1.5 billion shares | | | | | | | | |
| Issued — September 30, 2015: 912 million shares | | | | | |
| — December 31, 2014: 909 million shares | | | | | |
| Treasury — September 30, 2015: 3.3 million shares | | | | | |
| — December 31, 2014: 0.7 million shares | | | | | |
| Issued — September 30, 2016: 981 million shares | | | | | |
| — December 31, 2015: 915 million shares | | | | | |
| Treasury — September 30, 2016: 0.8 million shares | | | | | |
| — December 31, 2015: 3.4 million shares | | | | | |
| Par value | | 4,558 |
| | 4,539 |
| | 4,900 |
| | 4,572 |
|
| Paid-in capital | | 6,150 |
| | 5,955 |
| | 9,217 |
| | 6,282 |
|
| Treasury, at cost | | (141 | ) | | (26 | ) | | (30 | ) | | (142 | ) |
| Retained earnings | | 10,233 |
| | 9,609 |
| | 10,685 |
| | 10,010 |
|
| Accumulated other comprehensive loss | | (136 | ) | | (128 | ) | | (225 | ) | | (130 | ) |
| Total Common Stockholders' Equity | | 20,664 |
| | 19,949 |
| | 24,547 |
| | 20,592 |
|
| Preferred and Preference Stock of Subsidiaries | | 609 |
| | 756 |
| | 609 |
| | 609 |
|
| Noncontrolling Interest | | 650 |
| | 221 |
| |
| Noncontrolling Interests | | | 1,024 |
| | 781 |
|
| Total Stockholders' Equity | | 21,923 |
| | 20,926 |
| | 26,180 |
| | 21,982 |
|
| Total Liabilities and Stockholders' Equity | | $ | 75,215 |
| | $ | 70,923 |
| | $ | 106,362 |
| | $ | 78,318 |
|
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRD QUARTER 20152016 vs. THIRD 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 the parent entities of Southern Power and Southern Company Gas and owns other direct and indirect subsidiaries. Discussion of the results of operations is focused on the Southern Company system's primary business of electricity sales by the traditional electric operating companies and Southern Power.Power and, following the closing of the Merger on July 1, 2016, the distribution of natural gas by Southern Company Gas, formerly known as AGL Resources Inc. The four traditional electric operating companies are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through seven natural gas distribution utilities and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. Southern Company's other business activities include providing 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.
Proposed Merger with AGL ResourcesSouthern Company Gas
On August 23, 2015,July 1, 2016, Southern Company AGL Resources, and Merger Sub entered intocompleted the Merger Agreement. Under the termsfor a total purchase price of the Merger Agreement, subject to the satisfaction or waiver (if permissible under applicable law) of specified conditions, Merger Sub will be merged withapproximately $8.0 billion and into AGL Resources. AGL Resources will survive the Merger and becomeSouthern Company Gas became a wholly-owned, direct subsidiary of Southern Company. Upon the consummation of the Merger, each share of common stock of AGL Resources issued and outstanding immediately prior
Prior to the effective timecompletion of the Merger (Effective Time), other than shares owned by AGL Resources as treasury stock, shares owned by a subsidiary of AGL Resources, and shares owned by shareholders who have properly exercised and perfected dissenters' rights, will be converted into the right to receive $66 in cash, without interest and less any applicable withholding taxes (Merger Consideration). Other equity-based securities of AGL Resources will be cancelled for cash consideration or converted into new awards from Southern Company as described in the Merger Agreement.
Southern Company intends to initially fund the cash consideration for the Merger using approximately $7.0 billion of debt and $1.0 billion of equity. Southern Company expects to issue approximately $2.0 billion of additional equity through 2019 to offset a portion of the debt issued to fund the cash consideration for the Merger. In addition, Southern Company entered into the $8.1 billion Bridge Agreement on September 30, 2015 to provide financing for the Merger in the event long-term financing is not available.
Consummation of the Merger is subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) approval of the Merger Agreement by AGL Resources' shareholders, which is scheduled for vote on November 19, 2015, (ii) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, (iii) the approval of the California Public Utilities Commission, Georgia PSC, Illinois Commerce Commission, Maryland PSC, New Jersey Board of Public Utilities, and Virginia State Corporation Commission, and other approvals required under applicable state laws, and the approval of the Federal Communications Commission (FCC) for the transfer of control over the FCC licenses of certain subsidiaries of AGL Resources and any other approval which Southern Company and AGL Resources agree are required, (iv) the absence of a judgment, order, decision, injunction, ruling, or other finding or agency requirement of a governmental entity prohibiting the consummation of the Merger, and (v) other customary closing conditions, including (a) subject to certain materiality qualifiers, the accuracy of each party's representations and warranties and (b) each party's performance in all material respects of its obligations under the Merger Agreement. Southern Company expects to complete the required state regulatory filings in the fourth quarter 2015.
Subject to certain limitations, either party may terminate the Merger Agreement if the Merger is not consummated by August 23, 2016, which date may be extended by either party to February 23, 2017 if, on August 23, 2016, all
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
conditions to closing other than those relating to (i) regulatory approvals and (ii) the absence of legal restraints preventing consummation of the Merger (to the extent relating to regulatory approvals) have been satisfied. Upon termination of the Merger Agreement under certain specified circumstances, AGL Resources will be required to pay Southern Company a termination fee of $201 million or reimburse Southern Company’s expenses up to $5 million (which reimbursement shall reduce on a dollar-for-dollar basis any termination fee subsequently payable by AGL Resources). Southern Company currently expects to complete the transaction in the second half of 2016.
Prior to the Merger, Southern Company and AGL Resources will continue to operateSouthern Company Gas operated as separate companies. Accordingly, except for specific references to the pending Merger, the descriptions of strategy and outlook and the risks and challenges Southern Company faces, and theThe discussion and analysis of results of operations and financial condition set forth herein relate solely toinclude Southern Company.Company Gas' results of operations since July 1, 2016 and financial condition as of September 30, 2016. See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information regarding the Merger.
During the three and nine months ended September 30, 2016, Southern Company recorded in its statements of income costs associated with the Merger of approximately $40.8 million and $104.1 million, respectively, of which $40.6 million and $73.5 million is included in operating expenses and $0.2 million and $30.6 million is included in other income and (expense), respectively. These costs include external transaction costs for financing, legal, and consulting services, as well as rate credits and additional compensation-related expenses.
See RISK FACTORS in Item 1A herein for additional information regarding the Merger andrelated to the various risks related thereto.to the Merger.
The ultimate outcome of these matters 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"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
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $241 | | 33.6 | | $416 | | 24.8 |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $171 | | 17.8 | | $130 | | 6.2 |
Consolidated net income attributable to Southern Company'sCompany was $1.1 billion ($1.17 per share) for the third quarter 2015 net income after dividends on preferred and preference stock of subsidiaries was2016 compared to $959 million ($1.05 per share) compared to $718 million ($0.80 per share) for the third quarter 2014.2015. The increase was primarily the result of an increase in retail electric revenues resulting from warmer weather and base rate increases, a decrease in income taxes primarily from income tax benefits at Southern Power, and lower charges related to lower pre-tax charges of $150 million ($93 million after tax) in the third quarter 2015 compared to a pre-tax charge of $418 million ($258 million after tax) in the third quarter 2014 for revisions of the estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC, and an increase in retail base rates. The increases were partially offset by increases in interest expense, depreciation and amortization, and non-fuel operations and maintenance expenses. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Southern Company's year-to-date 2015Consolidated net income after dividends on preferred and preference stock of subsidiariesattributable to Southern Company was $2.2 billion ($2.37 per share) for year-to-date 2016 compared to $2.1 billion ($2.30 per share) compared to $1.7 billion ($1.88 per share) for the corresponding period in 2014.2015. The increase was primarily the result of lower pre-tax chargesan increase in retail electric revenues resulting from base rate increases as well as the 2015 correction of $182 million ($112 million after tax) recordeda Georgia Power billing error and a decrease in 2015 income taxes primarily from income tax benefits at Southern Power, partially offset by increases in interest expense and depreciation and amortization.
Although several individual income statement line items reflect variances resulting from the Merger on July 1, 2016 and the acquisition of PowerSecure International, Inc. (PowerSecure) on May 9, 2016, consolidated net income for the third quarter and year-to-date 2016 was not significantly impacted by these transactions.
See Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information on the Merger and the acquisition of PowerSecure.
Retail Electric Revenues
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $107 | | 2.3 | | $(26) | | (0.2) |
In the third quarter 2016, retail electric revenues were $4.8 billioncompared to pre-tax charges of $798 million ($493 million after tax) recorded in$4.7 billion for the corresponding period in 2014 for revisions of estimated costs expected2015. For year-to-date 2016, retail electric revenues decreased slightly compared to be incurred on Mississippi Power's construction of the Kempercorresponding period in 2015.
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 increases were partially offset by increases in non-fuel operations and maintenance expenses.
Retail Revenues
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $143 | | 3.1 | | $(228) | | (1.9) |
In the third quarter 2015, retail revenues were $4.7 billion compared to $4.6 billion for the corresponding period in 2014. For year-to-date 2015, retail revenues were $12.0 billion compared to $12.2 billion for the corresponding period in 2014.
Details of the changes in retail electric revenues were as follows:
| | | | | Third Quarter 2015 | | Year-to-Date 2015 | Third Quarter 2016 | | Year-to-Date 2016 |
| | | (in millions) | | (% change) | | (in millions) | | (% change) | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | | $ | 4,558 |
| | | | $ | 12,186 |
| | | |
| Retail electric – prior year | | $ | 4,701 |
| | | | $ | 11,958 |
| | |
| Estimated change resulting from – | | | | | | | | | | | | | | | |
| Rates and pricing | | 130 |
| | 2.9 |
| | 237 |
| | 1.9 |
| 84 |
| | 1.8 |
| | 379 |
| | 3.2 |
|
| Sales growth | | 11 |
| | 0.2 |
| | 52 |
| | 0.4 |
| |
| Sales growth (decline) | | (18 | ) | | (0.4 | ) | | (14 | ) | | (0.1 | ) |
| Weather | | 50 |
| | 1.1 |
| | 59 |
| | 0.5 |
| 169 |
| | 3.6 |
| | 82 |
| | 0.7 |
|
| Fuel and other cost recovery | | (48 | ) | | (1.1 | ) | | (576 | ) | | (4.7 | ) | (128 | ) | | (2.7 | ) | | (473 | ) | | (4.0 | ) |
| Retail – current year | | $ | 4,701 |
| | 3.1 | % | | $ | 11,958 |
| | (1.9 | )% | |
| Retail electric – current year | | $ | 4,808 |
| | 2.3 | % | | $ | 11,932 |
| | (0.2 | )% |
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 20152016 when compared to the corresponding periods in 20142015 primarily due to increases in base tariffs at Georgia Power under the 2013 ARP and the NCCR tariff and 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,Rate CNP Compliance, all effective January 1, 2015, as well as higher contributions from variable demand-driven2016. Also contributing to the increase in rates and pricing from commercial and industrial customers. Thefor year-to-date 2015 increase2016 was partially offset by the 2015 correction of ana Georgia Power billing error affecting billings since 2013 to a small number of large commercial and industrial customers under a rate plan allowingand the implementation of rates at Mississippi Power for variable demand-driven pricing at Georgia Power. certain Kemper IGCC in-service assets, effective September 2015.
See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power,– 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 (A)(B) to the Condensed Financial Statements herein for additional information.
Revenues attributable to changes in sales increaseddecreased in the third quarter 20152016 when compared to the corresponding period in 2014. Weather-adjusted commercial2015. Industrial KWH sales increased 1.0%decreased 3.3% in the third quarter 20152016 primarily due to customer growth and increased customer usage. Weather-adjusted residential KWH sales increased 0.1% in the third quarter 2015 due to customer growth, partially offset by decreased customer usage. Industrial KWH sales decreased 0.6% in the third quarter 2015 primarily due to decreased sales in the chemicals, paper, primary metals, paper, chemicals, pipelines, and non-manufacturing sectors, partially offset by increased sales in the transportation, stone, clay, and glass lumber, and pipeline sectors. A strong dollar, low oil prices, and weak global growtheconomic conditions have constrained growth in the industrial sector. Weather-adjusted commercial KWH sales decreased 0.7% in the third quarter 2016 primarily due to decreased customer usage resulting from an increase in energy saving initiatives, partially offset by customer growth. Weather-adjusted residential KWH sales decreased 0.4% in the third quarter 2016 primarily due to decreased customer usage primarily resulting from an increase in multi-family housing and efficiency improvements in residential appliances and lighting, partially offset by customer growth.
Revenues attributable to changes in sales increaseddecreased for year-to-date 20152016 when compared to the corresponding period in 2014.2015. Industrial KWH sales decreased 2.1% for year-to-date 2016 primarily in the primary metals, chemicals, pipelines, and stone, clay, and glass sectors. A strong dollar, low oil prices, and weak global economic conditions have constrained growth in the industrial sector. Weather-adjusted commercial KWH sales increased 0.8%decreased 0.6% for year-to-date 20152016 primarily due to decreased customer growth and increasedusage resulting from an increase in energy saving initiatives, partially offset by customer usage.growth. Weather-adjusted residential KWH sales increased 0.5%0.2% for year-to-date 2015 as a result of2016 due to customer growth, partially offset by decreased customer usage. Industrial KWH sales increased 0.5% for year-to-date 2015usage primarily due to increased salesresulting from an increase in the transportation, stone, clay,multi-family housing and glass,
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
pipeline, lumber,efficiency improvements in residential appliances and petroleum sectors, partially offset by decreased sales in the primary metals, chemicals, and paper sectors.lighting.
In the first quarter 2015, Mississippi Power updated the methodology to estimate the unbilled revenue allocation among customer classes. This change did not have a significant impact on net income. The KWH sales variances discussed above reflect an adjustment to the estimated allocation of Mississippi Power's unbilled thirdfirst quarter and year-to-date 20142015 KWH sales among customer classes that is consistent with the actual allocation in 2015.2016. Without this adjustment, third quarter 2015year-to-date 2016 weather-adjusted residential sales increased 0.1%0.3%, weather-adjusted commercial sales increased 1.2%decreased 0.5%, and industrial KWH sales decreased 0.6%2.0% as compared to the corresponding period in 2014. Also, without this adjustment, year-to-date 2015 weather-adjusted residential sales increased 0.4%, weather-adjusted commercial sales increased 0.7%, and industrial KWH sales increased 0.4% as compared to the corresponding period in 2014.2015.
Fuel and other cost recovery revenues decreased $48$128 million and $576$473 million in the third 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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased powerPPA costs, and do not affect net income. The traditional electric operating companies may alsoeach have one or more regulatory mechanisms to recover other costs such as environmental and other compliance costs, storm damage, new plants, and PPAs.PPA capacity costs.
Wholesale Electric Revenues
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(80) | | (13.3) | | $(284) | | (16.5) |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $93 | | 17.9 | | $20 | | 1.4 |
Wholesale electric revenues consist of PPAs primarily with investor-owned utilities and electric cooperatives and short-term opportunity sales. Wholesale electric revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues 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 electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Solar and wind PPAs do not have a capacity charge and customers purchase the energy output of a dedicated renewable facility through an energy charge. Wholesale electric revenues at Mississippi Power include FERC-regulated municipal and rural association sales as well as market-based sales. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system's variable cost to produce the energy.
In the third quarter 2015,2016, wholesale electric revenues were $520$613 million compared to $600$520 million for the corresponding period in 20142015. This increase was primarily related to a $52$121 million decreaseincrease in energy revenues, andpartially offset by a $28 million decrease in capacity revenues. For year-to-date 2015,2016, wholesale electric revenues were $1.4$1.46 billion compared to $1.7$1.44 billion for the corresponding period in 20142015. This increase was primarily related to a $214$112 million decreaseincrease in energy revenues, andpartially offset by a $70$92 million decrease in capacity revenues. The decreasesincreases in energy revenues were primarily relateddue to lower fuel costs,an increase in short-term sales and renewable energy sales at Southern Power, partially offset by increases in energy revenues from new solar PPAs at Southern Power.lower fuel prices. The decreases in capacity revenues were 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 in December 2014 at Georgia Power, partially offset by an increase due to a new wholesale contract at Alabama Power. Additionally, the year-to-date 2016 decrease in capacity revenues was due to unit retirements at Georgia Power.
See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Gulf Power" herein for additional information regarding the expiration of long-term sales agreements at Gulf Power for Plant Scherer Unit 3, which will impact future wholesale earnings, and PPA expirationsGulf Power's request to rededicate its ownership interest in Scherer Unit 3 to the retail jurisdiction.
Other Electric Revenues
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $12 | | 7.1 | | $35 | | 7.1 |
For year-to-date 2016, other electric revenues were $529 million compared to $494 million for the corresponding period in 2015. The increase was primarily due to increases in customer temporary facilities services revenues, outdoor lighting revenues, and solar application fee revenues at SouthernGeorgia Power.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Natural Gas Revenues
Natural gas revenues represent sales from the seven natural gas distribution utilities and certain non-regulated operations of Southern Company Gas. Following the Merger, $518 million of natural gas revenues are included in the consolidated statements of income for the third quarter and year-to-date 2016.
See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
Other Revenues
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $133 | | N/M | | $247 | | N/M |
N/M - Not meaningful
In the third quarter 2016, other revenues were $144 million compared to $11 million for the corresponding period in 2015. For year-to-date 2016, other revenues were $281 million compared to $34 million for the corresponding period in 2015. These increases were primarily due to $91 million and $150 million for the third quarter and year-to-date 2016, respectively, of revenues from products and services at PowerSecure, which was acquired on May 9, 2016, and $25 million of revenues from gas marketing products and services at Southern Company Gas following the Merger. Additionally, for the third quarter and year-to-date 2016, revenues from certain non-regulated sales of products and services by the traditional electric operating companies of $17 million and $63 million, respectively, were reclassified as other revenues for consistency of presentation on a consolidated basis. In prior periods, these revenues were included in other income (expense), net.
See Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information on the Merger and the acquisition of PowerSecure.
Fuel and Purchased Power Expenses
| | | | | Third Quarter 2015
vs.
Third Quarter 2014 | | Year-to-Date 2015
vs.
Year-to-Date 2014 | Third Quarter 2016
vs.
Third 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 | | $ | (136 | ) | | (8.2) | | $ | (833 | ) | | (17.5) | $ | (120 | ) | | (7.9) | | $ | (598 | ) | | (15.2) |
| Purchased power | | (1 | ) | | (0.5) | | (7 | ) | | (1.4) | 34 |
| | 17.6 | | 74 |
| | 14.6 |
| Total fuel and purchased power expenses | | $ | (137 | ) | | $ | (840 | ) | | $ | (86 | ) | | $ | (524 | ) | |
In the third quarter 2015,2016, total fuel and purchased power expenses were $1.7$1.6 billion compared to $1.9$1.7 billion for the corresponding period in 2014.2015. The decrease was primarily the result of a $139$209 million decrease in the average cost of fuel and purchased power primarily due to lower natural gascoal prices, and a $26 million decrease in the volume of KWHs generated, partially offset by a $28$123 million increase in the volume of KWHs generated and purchased.
For year-to-date 2015,2016, total fuel and purchased power expenses were $4.4$3.9 billion compared to $5.3$4.4 billion for the corresponding period in 2014.2015. The decrease was primarily the result of a $918$573 million decrease in the average cost of fuel and purchased power primarily due to lower coal and natural gas prices, andpartially offset by a $22$49 million decreasenet increase in the volume of KWHs generated partially offset by a $100 million increase in the volume of KWHsand 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"Recovery" herein for additional information. Fuel expenses incurred under Southern Power's PPAs are generally the responsibility of the counterparties and do not significantly impact net income.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of the Southern Company system's generation and purchased power were as follows:
| | | | | Third Quarter
2015 | | Third Quarter
2014 | | Year-to-Date 2015 | | Year-to-Date 2014 | Third Quarter 2016 | | Third Quarter
2015 | | Year-to-Date 2016 | | Year-to-Date 2015 |
Total generation (billions of KWHs) | | 53 | | 54 | | 146 | | 147 | |
Total purchased power (billions of KWHs) | | 4 | | 3 | | 10 | | 9 | |
Total generation (in billions of KWHs) | | 56 | | 53 | | 145 | | 146 |
Total purchased power (in billions of KWHs) | | 5 | | 4 | | 13 | | 10 |
Sources of generation (percent) — | | |
| Coal | | 40 | | 44 | | 37 | | 45 | 38 | | 40 | | 33 | | 37 |
| Nuclear | | 15 | | 15 | | 16 | | 16 | 15 | | 15 | | 16 | | 16 |
| Gas | | 43 | | 40 | | 44 | | 36 | 44 | | 43 | | 46 | | 44 |
| Hydro | | 1 | | 1 | | 2 | | 3 | 1 | | 1 | | 3 | | 2 |
| Renewables | | 1 | | — | | 1 | | — | |
Cost of fuel, generated (cents per net KWH) — | | |
| Other Renewables | | 2 | | 1 | | 2 | | 1 |
Cost of fuel, generated (in cents per net KWH) — | | |
| Coal | | 3.86 | | 3.63 | | 3.65 | | 3.87 | 2.97 | | 3.86 | | 3.10 | | 3.65 |
| Nuclear | | 0.84 | | 0.84 | | 0.78 | | 0.87 | 0.81 | | 0.84 | | 0.82 | | 0.78 |
| Gas | | 2.71 | | 3.42 | | 2.72 | | 3.77 | 2.74 | | 2.71 | | 2.40 | | 2.72 |
Average cost of fuel, generated (cents per net KWH) | | 2.90 | | 3.13 | | 2.78 | | 3.34 | |
Average cost of purchased power (cents per net KWH)(*) | | 5.95 | | 6.77 | | 6.13 | | 7.60 | |
Average cost of fuel, generated (in cents per net KWH) | | 2.54 | | 2.90 | | 2.38 | | 2.78 |
Average cost of purchased power (in cents per net KWH)(*) | | 5.57 | | 5.95 | | 5.31 | | 6.13 |
| |
| (*) | Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider. |
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel
In the third quarter 2015,2016, fuel expense was $1.5$1.4 billion compared to $1.7$1.5 billion for the corresponding period in 2014.2015. The decrease was primarily due to a 20.8% decrease in the average cost of natural gas per KWH generated and a 9.4% decrease in the volume of KWHs generated by coal, partially offset by a 7.8% increase in the volume of KWHs generated by natural gas and a 6.3% increase in the average cost of coal per KWH generated.
For year-to-date 2015, fuel expense was $3.9 billion compared to $4.8 billion for the corresponding period in 2014. The decrease was primarily due to a 27.9% decrease in the average cost of natural gas per KWH generated, a 17.0% decrease in the volume of KWHs generated by coal, and a 5.7%23.1% decrease in the average cost of coal per KWH generated, partially offset by a 22.5%an 8.7% increase in the volume of KWHs generated by natural gas.
For year-to-date 2016, fuel expense was $3.3 billion compared to $3.9 billion for the corresponding period in 2015. The decrease was primarily due to a 15.1% decrease in the average cost of coal per KWH generated, an 11.9% decrease in the volume of KWHs generated by coal, and an 11.8% decrease in the average cost of natural gas per KWH generated, partially offset by a 6.1% increase in the volume of KWHs generated by natural gas.
Purchased PowerConstruction Program
In the third quarter 2015, purchased power expense was $193 million compared to $194 million for the corresponding period in 2014. The decrease was primarily due to a 12.1% decreaseConstruction continues on Plant Vogtle Units 3 and 4 (45.7% ownership interest by Georgia Power in the average cost per KWH purchased primarily as a result of lower natural gas prices, partially offset by an 11.3% increase in the volume of KWHs purchased.
For year-to-date 2015, purchased power expense was $507 million compared to $514 million for the corresponding period in 2014. The decrease was primarily due to a 19.3% decrease in the average cost per KWH purchased primarily as a result of lower natural gas prices, partially offset by a 15.2% increase in the volume of KWHs purchased.
Energy purchases will vary dependingtwo units, each with approximately 1,100 MWs) and Mississippi Power's 582-MW Kemper IGCC. See RESULTS OF OPERATIONS – "Estimated Loss on demand for energy within the Southern Company system's service territory, the market prices of wholesale energy as comparedKemper IGCC," FUTURE EARNINGS POTENTIAL – "Construction Program," and Note (B) to the costCondensed 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 Company system's generation, and the availability of the Southern Company system's generation.Power" herein.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $76 | | 7.4 | | $294 | | 9.7 |
In the third quarter 2015, other operations and maintenance expenses were $1.1 billion compared to $1.0 billion for the corresponding period in 2014. The increase was primarily due to a $31 million increase in employee compensation and benefits including pension costs, a $26 million increase in generation expenses primarily related to non-outage operations and maintenance, $11 million related to AGL Resources acquisition costs, and a $5 million increase in customer accounts, service, and sales costs primarily related to customer incentive and demand side management programs, partially offset by a $19 million decrease in transmission and distribution costs primarily related to overhead line maintenance and an $11 million decrease in scheduled outage and maintenance costs at generation facilities. In addition, in the third quarter 2014, Alabama Power deferred approximately $16 million of certain non-nuclear outage expenditures under an accounting order.
For year-to-date 2015, other operations and maintenance expenses were $3.3 billion compared to $3.0 billion for the corresponding period in 2014. The increase was primarily due to an $88 million increase in employee compensation and benefits including pension costs, a $69 million increase in generation expenses primarily related to non-outage operations and maintenance, a $26 million increase in customer accounts, service, and sales costs primarily related to customer incentive and demand side management programs, a $19 million increase in scheduled outage and maintenance costs at generation facilities, and $11 million related to AGL Resources acquisition costs, partially offset by a $16 million decrease in transmission and distribution costs primarily related to overhead line maintenance. In addition, in the first nine months of 2014, Alabama Power deferred approximately $57 million of certain non-nuclear outage expenditures under an accounting order.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
See Note 3Key Performance Indicators
Southern Company continues to the financial statementsfocus 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 under "Retail Regulatory Matters – Alabama Power – Non-Nuclear Outage Accounting Order" in Item 87 of the Form 10-K for additional information related to non-nuclear outage expenditures. Also see Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.10-K.
Depreciation and AmortizationRESULTS OF OPERATIONS
Net Income
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $14 | | 2.7 | | $— | | — |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $171 | | 17.8 | | $130 | | 6.2 |
InConsolidated net income attributable to Southern Company was $1.1 billion ($1.17 per share) for the third quarter 2015, depreciation and amortization was $528 million2016 compared to $514$959 million ($1.05 per share) for the corresponding period in 2014.third quarter 2015. The increase was primarily due tothe result of an increase in retail electric revenues resulting from warmer weather and base rate increases, a $27 million increase related to additional plantdecrease in serviceincome taxes primarily from income tax benefits at the traditional operating companies and Southern Power, and a $9 million increase in amortization of regulatory assets associated with the Kemper IGCC at Mississippi Power primarily as a result of interim rates that became effective with the first billing cycle in September (on August 19). These increases were partially offset by a $23 million decrease as a result of a reduction in depreciation rates at Alabama Power effective January 1, 2015.
For year-to-date 2015, depreciation and amortization was flat compared to the corresponding period in 2014
primarily due to a $74 million increaselower charges related to additional plant in service at the traditional operating companies and Southern Power and a $10 million increase in amortization of regulatory assets associated with the Kemper IGCC at Mississippi Power primarily as a result of interim rates that became effective with the first billing cycle in September (on August 19). These increases were offset by a $72 million decrease as a result of a reduction in depreciation rates at Alabama Power effective January 1, 2015 and a $15 million reduction in depreciation at Gulf Power, as approved 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 8revisions 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.
Also see Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Estimated Loss on Kemper IGCC
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(268) | | (64.1) | | $(616) | | (77.2) |
In the third quarter 2015 and 2014, estimated probable losses on the Kemper IGCC of $150 million and $418 million, respectively, were recorded at Southern Company. For year-to-date 2015 and 2014, estimated probable losses on the Kemper IGCC of $182 million and $798 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, partially offset by increases 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)interest expense, depreciation and excluding the cost of the lignite mineamortization, and equipment, the cost of the CO2 pipeline facilities, AFUDC,non-fuel operations 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).maintenance expenses. See FUTURE EARNINGS POTENTIAL – "Construction Program – 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.
Consolidated net income attributable to Southern Company was $2.2 billion ($2.37 per share) for year-to-date 2016 compared to $2.1 billion ($2.30 per share) for the corresponding period in 2015. The increase was primarily the result of an increase in retail electric revenues resulting from 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, partially offset by increases in interest expense and depreciation and amortization.
Although several individual income statement line items reflect variances resulting from the Merger on July 1, 2016 and the acquisition of PowerSecure International, Inc. (PowerSecure) on May 9, 2016, consolidated net income for the third quarter and year-to-date 2016 was not significantly impacted by these transactions.
See Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information on the Merger and the acquisition of PowerSecure.
Retail Electric Revenues
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $107 | | 2.3 | | $(26) | | (0.2) |
In the third quarter 2016, retail electric revenues were $4.8 billioncompared to $4.7 billion for the corresponding period in 2015. For year-to-date 2016, retail electric revenues decreased slightly compared to the corresponding period in 2015.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Allowance for Equity Funds Used During ConstructionDetails of the changes in retail electric revenues were as follows:
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(3) | | (4.8) | | $(19) | | (10.4) |
|
| | | | | | | | | | | | | |
| | Third Quarter 2016 | | Year-to-Date 2016 |
| | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail electric – prior year | $ | 4,701 |
| | | | $ | 11,958 |
| | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 84 |
| | 1.8 |
| | 379 |
| | 3.2 |
|
| Sales growth (decline) | (18 | ) | | (0.4 | ) | | (14 | ) | | (0.1 | ) |
| Weather | 169 |
| | 3.6 |
| | 82 |
| | 0.7 |
|
| Fuel and other cost recovery | (128 | ) | | (2.7 | ) | | (473 | ) | | (4.0 | ) |
| Retail electric – current year | $ | 4,808 |
| | 2.3 | % | | $ | 11,932 |
| | (0.2 | )% |
ForRevenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2015, AFUDC equity was $163 million2016 when compared to $182 million for the corresponding periodperiods in 2014. The decrease was2015 primarily due to increases in base tariffs at Georgia Power under the 2013 ARP and the NCCR tariff and increased revenues at Alabama Power under Rate CNP Compliance, all effective January 1, 2016. Also contributing to the increase in rates and pricing for year-to-date 2016 was the 2015 correction of a Georgia Power billing error to a small number of large commercial and industrial customers and the implementation of rates at Mississippi Power placing the combined cycle and the associated common facilities portion of thefor certain Kemper IGCC in service in August 2014, partially offset by environmental and transmission projects under construction by the traditional operating companies. in-service assets, effective September 2015.
See Note (B)3 to the Condensed Financial Statementsfinancial 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" herein for additional information regarding theCycle – Rate Recovery of Kemper IGCC.
Interest Expense, Net of Amounts Capitalized
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $11 | | 5.3 | | $(11) | | (1.8) |
In the third quarter 2015, interest expense, net of amounts capitalized was $218 million compared to $207 millionIGCC Costs" in the corresponding period in 2014. The increase was primarily due to an increase in outstanding long-term debt.
For year-to-date 2015, interest expense, net of amounts capitalized was $612 million compared to $623 million in the corresponding period in 2014. The decrease was primarily due to a $50 million decrease related to the terminationItem 8 of the asset purchase agreement (APA) between Mississippi PowerForm 10-K and SMEPA which also required the return of SMEPA's deposits at a lower rate of interest than accrued, partially offset by an increase in outstanding long-term debt. See Note (E)(B) 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
Revenues attributable to SMEPA" herein for additional information.
Other Income (Expense), Net |
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(14) | | N/M | | $(21) | | N/M |
N/M – Not meaningful
Inchanges in sales decreased in the third quarter 2015, other income (expense), net was $(21) million2016 when compared to $(7) million for the corresponding period in 2014.2015. Industrial KWH sales decreased 3.3% in the third quarter 2016 primarily in the primary metals, paper, chemicals, pipelines, and stone, clay, and glass sectors. A strong dollar, low oil prices, and weak global economic conditions have constrained growth in the industrial sector. Weather-adjusted commercial KWH sales decreased 0.7% in the third quarter 2016 primarily due to decreased customer usage resulting from an increase in energy saving initiatives, partially offset by customer growth. Weather-adjusted residential KWH sales decreased 0.4% in the third quarter 2016 primarily due to decreased customer usage primarily resulting from an increase in multi-family housing and efficiency improvements in residential appliances and lighting, partially offset by customer growth.
Revenues attributable to changes in sales decreased for year-to-date 2016 when compared to the corresponding period in 2015. Industrial KWH sales decreased 2.1% for year-to-date 2016 primarily in the primary metals, chemicals, pipelines, and stone, clay, and glass sectors. A strong dollar, low oil prices, and weak global economic conditions have constrained growth in the industrial sector. Weather-adjusted commercial KWH sales decreased 0.6% for year-to-date 2016 primarily due to decreased customer usage resulting from an increase in energy saving initiatives, partially offset by customer growth. Weather-adjusted residential KWH sales increased 0.2% for year-to-date 2016 due to customer growth, partially offset by decreased customer usage primarily resulting from an increase in multi-family housing and efficiency improvements in residential appliances and lighting.
In the first quarter 2015, Mississippi Power updated the methodology to estimate the unbilled revenue allocation among customer classes. This change did not have a significant impact on net income. The change wasKWH sales variances discussed above reflect an adjustment to the estimated allocation of Mississippi Power's unbilled first quarter 2015 KWH sales among customer classes that is consistent with the actual allocation in 2016. Without this adjustment, year-to-date 2016 weather-adjusted residential sales increased 0.3%, weather-adjusted commercial sales decreased 0.5%, and industrial KWH sales decreased 2.0% as compared to the corresponding period in 2015.
Fuel and other cost recovery revenues decreased $128 million and $473 million in the third quarter and year-to-date 2016, respectively, when compared to the corresponding periods in 2015 primarily due to a decrease in sales of non-utility property in 2015 at Alabama Power.
For year-to-date 2015, other income (expense), net was $(41) million compared to $(20) millionfuel prices. Electric rates for the corresponding periodtraditional electric operating companies include provisions to adjust billings for fluctuations in 2014. The change was primarily due to an increase in donations and a decrease in sales of non-utility property in 2015 at Alabama Power.
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $108 | | 27.6 | | $187 | | 21.0 |
In the third quarter 2015, income taxes were $500 million compared to $392 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 and higher pre-tax earnings.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2015, income taxes were $1.1 billionfuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of PPA costs, and do not affect net income. The traditional electric operating companies each have one or more regulatory mechanisms to recover other costs such as environmental and other compliance costs, storm damage, new plants, and PPA capacity costs.
Wholesale Electric Revenues
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $93 | | 17.9 | | $20 | | 1.4 |
Wholesale electric revenues consist of PPAs primarily with investor-owned utilities and electric cooperatives and short-term opportunity sales. Wholesale electric revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues 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 $889the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Solar and wind PPAs do not have a capacity charge and customers purchase the energy output of a dedicated renewable facility through an energy charge. Wholesale electric revenues at Mississippi Power include FERC-regulated municipal and rural association sales as well as market-based sales. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system's variable cost to produce the energy.
In the third quarter 2016, wholesale electric revenues were $613 million compared to $520 million for the corresponding period in 2014. The2015. This increase was primarily reflects a reduction in tax benefits related to the estimated probable losses on Mississippi Power's construction of the Kemper IGCC recordeda $121 million increase in 2014 and beneficial changes that impacted 2014 state income taxes,energy revenues, partially offset by state income tax benefits realizeda $28 million decrease in 2015 and increased federal income tax benefitscapacity revenues. For year-to-date 2016, wholesale electric revenues were $1.46 billion compared to $1.44 billion for the corresponding period in 2015. This increase was primarily related to ITCs ona $112 million increase in energy revenues, partially offset by a $92 million decrease in capacity revenues. The increases in energy revenues were primarily due to an increase in short-term sales and renewable energy sales at Southern Power, solar projectspartially offset by lower fuel prices. The decreases in 2015.
See Note (G)capacity revenues were primarily due to the Condensed Financial Statementselimination 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, partially offset by an increase due to a new wholesale contract at Alabama Power. Additionally, the year-to-date 2016 decrease in capacity revenues was due to unit retirements at Georgia Power.
See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Gulf Power" herein for additional information.
FUTURE EARNINGS POTENTIAL
The resultsinformation regarding the expiration 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 allowlong-term sales agreements at Gulf Power 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 UnitsScherer Unit 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 and other energy projects. Future earnings for the electricity business in the near termwhich 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 regulatory matters, creditworthiness of customers, total generating capacity available and related costs, future acquisitions and construction of generating facilities, including the impact of ITCs, and the successful remarketing of capacity as current contracts expire. Demand for electricity for the traditional operating companies and Southern Power is partially 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. For additional information relatingwholesale earnings, and Gulf Power's request to these issues, see RISK FACTORSrededicate its ownership interest 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 NoteScherer Unit 3 to the financial statements of Southern Company under "Environmental Matters" in Item 8 of the Form 10-K for additional information.retail jurisdiction.
New Source Review ActionsOther Electric Revenues
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $12 | | 7.1 | | $35 | | 7.1 |
For year-to-date 2016, other electric revenues were $529 million compared to 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 August 24, 2015, the U.S. District Court$494 million for the Northern District of Alabama entered an order approving the joint stipulation among Alabama Power, the EPA,corresponding period in 2015. The increase was primarily due to increases in customer temporary facilities services revenues, outdoor lighting revenues, and the U.S. Department of Justice modifying the 2006 consent decree to resolve all remaining claims for relief alleged in the case. Under the modified consent decree, Alabama Power will, without admitting liability, operate certain units subject to emission rates and an annual emissions cap; use only natural gassolar application fee revenues at certain other units, including a unit co-owned by Mississippi Power; retire certain units atGeorgia Power.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Plants GorgasNatural Gas Revenues
Natural gas revenues represent sales from the seven natural gas distribution utilities and Barry; pay a $100,000 civil penalty; and invest $1.5 million in electric transportation infrastructure projects over three years.
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"certain non-regulated operations of Southern Company Gas. Following the Merger, $518 million of natural gas revenues are included in Item 7the consolidated statements of income for the third quarter and year-to-date 2016.
See Note 3(I) to the financial statements ofCondensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
Other Revenues
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $133 | | N/M | | $247 | | N/M |
N/M - Not meaningful
In the third quarter 2016, other revenues were $144 million compared to $11 million for the corresponding period in 2015. For year-to-date 2016, other revenues were $281 million compared to $34 million for the corresponding period in 2015. These increases were primarily due to $91 million and $150 million for the third quarter and year-to-date 2016, respectively, of revenues from products and services at PowerSecure, which was acquired on May 9, 2016, and $25 million of revenues from gas marketing products and services at Southern Company Gas following the Merger. Additionally, for the third quarter and year-to-date 2016, revenues from certain non-regulated sales of products and services by the traditional electric operating companies of $17 million and $63 million, respectively, were reclassified as other revenues for consistency of presentation on a consolidated basis. In prior periods, these revenues were included in other income (expense), net.
See Note (I) to the Condensed Financial Statements under "Other Matters "–Southern Company Sierra Club Settlement Agreement" in Item 8 of the Form 10-K" herein for additional information on planned unit retirementsthe Merger and fuel conversions at Alabama Power, Georgia Power, and Mississippi Power.the acquisition of PowerSecure.
Air QualityFuel and Purchased Power Expenses
|
| | | | | | | | | | | |
| | Third Quarter 2016
vs.
Third Quarter 2015 | | Year-to-Date 2016
vs.
Year-to-Date 2015 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | (120 | ) | | (7.9) | | $ | (598 | ) | | (15.2) |
| Purchased power | 34 |
| | 17.6 | | 74 |
| | 14.6 |
| Total fuel and purchased power expenses | $ | (86 | ) | | | | $ | (524 | ) | | |
In the third quarter 2016, total fuel and purchased power expenses were $1.6 billion compared to $1.7 billion for the corresponding period in 2015. The decrease was primarily the result of a $209 million decrease in the average cost of fuel and purchased power primarily due to lower coal prices, partially offset by a $123 million increase in the volume of KWHs generated and purchased.
For year-to-date 2016, total fuel and purchased power expenses were $3.9 billion compared to $4.4 billion for the corresponding period in 2015. The decrease was primarily the result of a $573 million decrease in the average cost of fuel and purchased power primarily due to lower coal and natural gas prices, partially offset by a $49 million net increase in the volume of KWHs generated and purchased.
Fuel and purchased power energy transactions at the traditional electric operating companies are generally offset by fuel revenues and do not have a significant impact on net income. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "–Regulatory Matters "Environmental Matters– –Fuel Cost Recovery Environmental Statutes and Regulations – Air Quality" of" herein for additional information. Fuel expenses incurred under Southern Company in Item 7Power's PPAs are generally the responsibility 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, the Cross State Air Pollution Rule (CSAPR),counterparties and the eight-hour National Ambient Air Quality Standard (NAAQS) for ozone.do not significantly impact net income.
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 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.
On October 26, 2015, the EPA published a more stringent eight-hour NAAQS for ozone. This new standard could potentially require additional emission controls, improvements in control efficiency, and operational fuel changes and could affect the siting of new generating facilities. The ultimate impact of this matter will depend on any legal challenges and implementation of the final rule 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' rule revising the definition of waters of the U.S. under the Clean Water Act (CWA) and the EPA's revisions to effluent guidelines.
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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
of transmission and distribution lines. The rule became effective August 28, 2015, but on October 9, 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order staying implementation of the final rule. The ultimate impact of the final rule will depend on the outcome of this and other pending legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the rule and cannot be determined at this time.
On November 3, 2015, the EPA published final revisions to technology-based limits for certain wastestreams from steam electric power plants. These revisions impose stringent steam effluent guidelines and technology requirements for wastewater discharges at affected units. Compliance with these revisions could result in significant additional capital expenditures and could affect future unit retirement and replacement decisions. The ultimate impactDetails of these revisions will depend on any legal challenges and implementation of the final revisions 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, which became effective on October 19, 2015. Based on initial cost estimates for closure in place and groundwater monitoring of ash ponds pursuant to the CCR Rule, during the second quarter 2015, Southern Company recorded incremental asset retirement obligations (ARO) of approximately $700 million related to the CCR Rule. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, the traditional operating companies expect to continue to periodically update these estimates. 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. See Note (A) to the Condensed Financial Statements herein for additional information regarding Southern Company's AROs as of September 30, 2015.
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.
On October 23, 2015, two final actions by the EPA that would limit CO2 emissions from fossil fuel-fired electric generating units were published in the Federal Register. One of the final actions contains specific emission standards governing CO2 emissions from new, modified, and reconstructed units. The other final action 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, a proposed federal plan and proposed model rule were published 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, including legal challenges filed by the traditional operating companies; individual state implementation of the EPA's final guidelines, including the potential that state plans impose different
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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;purchased power were as follows:
|
| | | | | | | |
| | Third Quarter 2016 | | Third Quarter
2015 | | Year-to-Date 2016 | | Year-to-Date 2015 |
Total generation (in billions of KWHs) | 56 | | 53 | | 145 | | 146 |
Total purchased power (in billions of KWHs) | 5 | | 4 | | 13 | | 10 |
Sources of generation (percent) — | | | | | | | |
| Coal | 38 | | 40 | | 33 | | 37 |
| Nuclear | 15 | | 15 | | 16 | | 16 |
| Gas | 44 | | 43 | | 46 | | 44 |
| Hydro | 1 | | 1 | | 3 | | 2 |
| Other Renewables | 2 | | 1 | | 2 | | 1 |
Cost of fuel, generated (in cents per net KWH) — | | | | | | | |
| Coal | 2.97 | | 3.86 | | 3.10 | | 3.65 |
| Nuclear | 0.81 | | 0.84 | | 0.82 | | 0.78 |
| Gas | 2.74 | | 2.71 | | 2.40 | | 2.72 |
Average cost of fuel, generated (in cents per net KWH) | 2.54 | | 2.90 | | 2.38 | | 2.78 |
Average cost of purchased power (in cents per net KWH)(*) | 5.57 | | 5.95 | | 5.31 | | 6.13 |
| |
| (*) | 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 impact of future decisions regarding unit retirement and replacement, includingthird quarter 2016, fuel expense was $1.4 billion compared to $1.5 billion for the type and amount of any such replacement capacity; and the time periods over which compliance will be required.
FERC Matters
corresponding period in 2015. The traditional operating companies and Southern Power have authority from the FERCdecrease was primarily due 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, changes23.1% decrease 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 fuelaverage cost balances. On September 18, 2015, Georgia Power filed a rate request with the Georgia PSC to lower total annual billingsof coal per KWH generated, partially offset by approximately $268 million effective January 1, 2016. The Georgia PSC is scheduled to vote on this matter on December 15, 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 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.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 $50 million of non-environmental compliance costs during the first nine 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.
On August 14, 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2015-13, allowing 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. The new accounting guidance will have no impact on Southern Company's financial statements.
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. On August 24, 2015, the U.S. District Court for the Northern District of Alabama entered an order approving the joint stipulation in the New Source Review (NSR) action. In accordance with the joint stipulation, Alabama Power retired Plant Barry Unit 3 (225 MWs) and it is no longer available for generation. See Note (B) to the Condensed Financial Statements 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, and recovered through Rate CNP. As a result, these decisions will not have a significant impact on Southern Company's financial statements. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Rate CNP" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Alabama Power – Rate CNP" herein for additional information.
Renewable Energy
On September 1, 2015, the Alabama PSC approved Alabama Power's petition for a Renewable Generation Certificate. This will allow 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.
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 "Construction Program – Nuclear Construction" and "Retail Regulatory Matters – Retail Fuel Cost Recovery" herein for additional information regarding Georgia Power's recent NCCR tariff filing and fuel rate request, respectively. 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.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 an up to 46-MW solar generation facility at a U.S. Marine Corps base in Albany, Georgia by the end of 2016.
Rate Plans
In accordance with the terms of the 2013 ARP, on October 2, 2015, Georgia Power filed the following tariff adjustments with the Georgia PSC to become effective January 1, 2016 pending its approval:
increase in traditional base tariffs by approximately $49 million;
8.7% increase in the environmental compliancevolume of KWHs generated by natural gas.
For year-to-date 2016, fuel expense was $3.3 billion compared to $3.9 billion for the corresponding period in 2015. The decrease was primarily due to a 15.1% decrease in the average cost recovery tariffof coal per KWH generated, an 11.9% decrease in the volume of KWHs generated by approximately $75 million;
coal, and an 11.8% decrease in the average cost of natural gas per KWH generated, partially offset by a 6.1% increase in the demand-side management tariffsvolume of KWHs generated by approximately $7 million; and
increase in the municipal franchise fee tariff by approximately $13 million.
The ultimate outcome of this matter cannot be determined at this time.
Integrated Resource Plan
To comply with the April 16, 2015 effective date of the MATS rule, Plant Branch Units 1, 3, and 4 (1,266 MWs), Plant Yates Units 1 through 5 (579 MWs), and Plant McManus Units 1 and 2 (122 MWs) were retired 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. On October 13, 2015, Plant Kraft Units 1 through 4 (316 MWs) were retired.gas.
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. On August 13, 2015, the Mississippi PSC approved the implementation of interim rates designed to collect approximately $159 million annually. 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
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $171 | | 17.8 | | $130 | | 6.2 |
Consolidated net income attributable to Southern Company was $1.1 billion ($1.17 per share) for the third quarter 2016 compared to $959 million ($1.05 per share) for the third quarter 2015. The increase was primarily the result of an increase in retail electric revenues resulting from warmer weather and base rate increases, a decrease in income taxes primarily from income tax benefits at Southern Power, and lower charges related to revisions of the estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC, partially offset by increases in interest expense, depreciation and amortization, and non-fuel operations and maintenance expenses. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Consolidated net income attributable to Southern Company was $2.2 billion ($2.37 per share) for year-to-date 2016 compared to $2.1 billion ($2.30 per share) for the corresponding period in 2015. The increase was primarily the result of an increase in retail electric revenues resulting from 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, partially offset by increases in interest expense and depreciation and amortization.
Although several individual income statement line items reflect variances resulting from the Merger on July 1, 2016 and the acquisition of PowerSecure International, Inc. (PowerSecure) on May 9, 2016, consolidated net income for the third quarter and year-to-date 2016 was not significantly impacted by these transactions.
See Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information on the Merger and the acquisition of PowerSecure.
Retail Electric Revenues
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $107 | | 2.3 | | $(26) | | (0.2) |
In the third quarter 2016, retail electric revenues were $4.8 billioncompared to $4.7 billion for the corresponding period in 2015. For year-to-date 2016, retail electric revenues decreased slightly compared to the corresponding period in 2015.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of the changes in retail electric revenues were as follows:
|
| | | | | | | | | | | | | |
| | Third Quarter 2016 | | Year-to-Date 2016 |
| | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail electric – prior year | $ | 4,701 |
| | | | $ | 11,958 |
| | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 84 |
| | 1.8 |
| | 379 |
| | 3.2 |
|
| Sales growth (decline) | (18 | ) | | (0.4 | ) | | (14 | ) | | (0.1 | ) |
| Weather | 169 |
| | 3.6 |
| | 82 |
| | 0.7 |
|
| Fuel and other cost recovery | (128 | ) | | (2.7 | ) | | (473 | ) | | (4.0 | ) |
| Retail electric – current year | $ | 4,808 |
| | 2.3 | % | | $ | 11,932 |
| | (0.2 | )% |
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2016 when compared to the corresponding periods in 2015 primarily due to increases in base tariffs at Georgia Power under the 2013 ARP and the NCCR tariff and increased revenues at Alabama Power under Rate CNP Compliance, all effective January 1, 2016. Also contributing to the increase in rates and pricing for year-to-date 2016 was the 2015 correction of a Georgia Power billing error to a small number of large commercial and industrial customers and the implementation of rates at Mississippi Power for certain Kemper IGCC in-service assets, effective September 2015.
See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power," "Retail Regulatory Matters – Georgia Power – Rate Plans" and " – Nuclear Construction," and "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.
Revenues attributable to changes in sales decreased in the third quarter 2016 when compared to the corresponding period in 2015. Industrial KWH sales decreased 3.3% in the third quarter 2016 primarily in the primary metals, paper, chemicals, pipelines, and stone, clay, and glass sectors. A strong dollar, low oil prices, and weak global economic conditions have constrained growth in the industrial sector. Weather-adjusted commercial KWH sales decreased 0.7% in the third quarter 2016 primarily due to decreased customer usage resulting from an increase in energy saving initiatives, partially offset by customer growth. Weather-adjusted residential KWH sales decreased 0.4% in the third quarter 2016 primarily due to decreased customer usage primarily resulting from an increase in multi-family housing and efficiency improvements in residential appliances and lighting, partially offset by customer growth.
Revenues attributable to changes in sales decreased for year-to-date 2016 when compared to the corresponding period in 2015. Industrial KWH sales decreased 2.1% for year-to-date 2016 primarily in the primary metals, chemicals, pipelines, and stone, clay, and glass sectors. A strong dollar, low oil prices, and weak global economic conditions have constrained growth in the industrial sector. Weather-adjusted commercial KWH sales decreased 0.6% for year-to-date 2016 primarily due to decreased customer usage resulting from an increase in energy saving initiatives, partially offset by customer growth. Weather-adjusted residential KWH sales increased 0.2% for year-to-date 2016 due to customer growth, partially offset by decreased customer usage primarily resulting from an increase in multi-family housing and efficiency improvements in residential appliances and lighting.
In the first quarter 2015, Mississippi Power updated the methodology to estimate the unbilled revenue allocation among customer classes. This change did not have a significant impact on net income. The KWH sales variances discussed above reflect an adjustment to the estimated allocation of Mississippi Power's unbilled first quarter 2015 KWH sales among customer classes that is consistent with the actual allocation in 2016. Without this adjustment, year-to-date 2016 weather-adjusted residential sales increased 0.3%, weather-adjusted commercial sales decreased 0.5%, and industrial KWH sales decreased 2.0% as compared to the corresponding period in 2015.
Fuel and other cost recovery revenues decreased $128 million and $473 million in the third quarter and year-to-date 2016, respectively, when compared to the corresponding periods in 2015 primarily due to a decrease in fuel prices. Electric rates for the traditional electric operating companies include provisions to adjust billings for fluctuations in
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of PPA costs, and do not affect net income. The traditional electric operating companies each have one or more regulatory mechanisms to recover other costs such as environmental and other compliance costs, storm damage, new plants, and PPA capacity costs.
Wholesale Electric Revenues
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $93 | | 17.9 | | $20 | | 1.4 |
Wholesale electric revenues consist of PPAs primarily with investor-owned utilities and electric cooperatives and short-term opportunity sales. Wholesale electric revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues 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 electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Solar and wind PPAs do not have a capacity charge and customers purchase the energy output of a dedicated renewable facility through an energy charge. Wholesale electric revenues at Mississippi Power include FERC-regulated municipal and rural association sales as well as market-based sales. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system's variable cost to produce the energy.
In the third quarter 2016, wholesale electric revenues were $613 million compared to $520 million for the corresponding period in 2015. This increase was primarily related to a $121 million increase in energy revenues, partially offset by a $28 million decrease in capacity revenues. For year-to-date 2016, wholesale electric revenues were $1.46 billion compared to $1.44 billion for the corresponding period in 2015. This increase was primarily related to a $112 million increase in energy revenues, partially offset by a $92 million decrease in capacity revenues. The increases in energy revenues were primarily due to an increase in short-term sales and renewable energy sales at Southern Power, partially offset by lower fuel prices. The decreases in capacity revenues were primarily due to the elimination in consolidation of a Southern Power PPA that was 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, partially offset by an increase due to a new wholesale contract at Alabama Power. Additionally, the year-to-date 2016 decrease in capacity revenues was due to unit retirements at Georgia Power.
See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Gulf Power" herein for additional information regarding the expiration of long-term sales agreements at Gulf Power for Plant Scherer Unit 3, which will impact future wholesale earnings, and Gulf Power's request to rededicate its ownership interest in Scherer Unit 3 to the retail jurisdiction.
Other Electric Revenues
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $12 | | 7.1 | | $35 | | 7.1 |
For year-to-date 2016, other electric revenues were $529 million compared to $494 million for the corresponding period in 2015. The increase was primarily due to increases in customer temporary facilities services revenues, outdoor lighting revenues, and solar application fee revenues at Georgia Power.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Natural Gas Revenues
Natural gas revenues represent sales from the seven natural gas distribution utilities and certain non-regulated operations of Southern Company Gas. Following the Merger, $518 million of natural gas revenues are included in the consolidated statements of income for the third quarter and year-to-date 2016.
See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
Other Revenues
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $133 | | N/M | | $247 | | N/M |
N/M - Not meaningful
In the third quarter 2016, other revenues were $144 million compared to $11 million for the corresponding period in 2015. For year-to-date 2016, other revenues were $281 million compared to $34 million for the corresponding period in 2015. These increases were primarily due to $91 million and $150 million for the third quarter and year-to-date 2016, respectively, of revenues from products and services at PowerSecure, which was acquired on May 9, 2016, and $25 million of revenues from gas marketing products and services at Southern Company Gas following the Merger. Additionally, for the third quarter and year-to-date 2016, revenues from certain non-regulated sales of products and services by the traditional electric operating companies of $17 million and $63 million, respectively, were reclassified as other revenues for consistency of presentation on a consolidated basis. In prior periods, these revenues were included in other income (expense), net.
See Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information on the Merger and the acquisition of PowerSecure.
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | |
| | Third Quarter 2016
vs.
Third Quarter 2015 | | Year-to-Date 2016
vs.
Year-to-Date 2015 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | (120 | ) | | (7.9) | | $ | (598 | ) | | (15.2) |
| Purchased power | 34 |
| | 17.6 | | 74 |
| | 14.6 |
| Total fuel and purchased power expenses | $ | (86 | ) | | | | $ | (524 | ) | | |
In the third quarter 2016, total fuel and purchased power expenses were $1.6 billion compared to $1.7 billion for the corresponding period in 2015. The decrease was primarily the result of a $209 million decrease in the average cost of fuel and purchased power primarily due to lower coal prices, partially offset by a $123 million increase in the volume of KWHs generated and purchased.
For year-to-date 2016, total fuel and purchased power expenses were $3.9 billion compared to $4.4 billion for the corresponding period in 2015. The decrease was primarily the result of a $573 million decrease in the average cost of fuel and purchased power primarily due to lower coal and natural gas prices, partially offset by a $49 million net increase in the volume of KWHs generated and purchased.
Fuel and purchased power energy transactions at the traditional electric operating companies are generally offset by fuel revenues and do not have a significant impact on net income. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Fuel Cost Recovery" herein for additional information. Fuel expenses incurred under Southern Power's PPAs are generally the responsibility of the counterparties and do not significantly impact net income.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of the Southern Company system's generation and purchased power were as follows:
|
| | | | | | | |
| | Third Quarter 2016 | | Third Quarter
2015 | | Year-to-Date 2016 | | Year-to-Date 2015 |
Total generation (in billions of KWHs) | 56 | | 53 | | 145 | | 146 |
Total purchased power (in billions of KWHs) | 5 | | 4 | | 13 | | 10 |
Sources of generation (percent) — | | | | | | | |
| Coal | 38 | | 40 | | 33 | | 37 |
| Nuclear | 15 | | 15 | | 16 | | 16 |
| Gas | 44 | | 43 | | 46 | | 44 |
| Hydro | 1 | | 1 | | 3 | | 2 |
| Other Renewables | 2 | | 1 | | 2 | | 1 |
Cost of fuel, generated (in cents per net KWH) — | | | | | | | |
| Coal | 2.97 | | 3.86 | | 3.10 | | 3.65 |
| Nuclear | 0.81 | | 0.84 | | 0.82 | | 0.78 |
| Gas | 2.74 | | 2.71 | | 2.40 | | 2.72 |
Average cost of fuel, generated (in cents per net KWH) | 2.54 | | 2.90 | | 2.38 | | 2.78 |
Average cost of purchased power (in cents per net KWH)(*) | 5.57 | | 5.95 | | 5.31 | | 6.13 |
| |
| (*) | 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 third quarter 2016, fuel expense was $1.4 billion compared to $1.5 billion for the corresponding period in 2015. The decrease was primarily due to a 23.1% decrease in the average cost of coal per KWH generated, partially offset by an 8.7% increase in the volume of KWHs generated by natural gas.
For year-to-date 2016, fuel expense was $3.3 billion compared to $3.9 billion for the corresponding period in 2015. The decrease was primarily due to a 15.1% decrease in the average cost of coal per KWH generated, an 11.9% decrease in the volume of KWHs generated by coal, and an 11.8% decrease in the average cost of natural gas per KWH generated, partially offset by a 6.1% increase in the volume of KWHs generated by natural gas.
Purchased Power
In the third quarter 2016, purchased power expense was $227 million compared to $193 million for the corresponding period in 2015. The increase was primarily due to a 24.1% increase in the volume of KWHs purchased, partially offset by a 6.4% decrease in the average cost per KWH purchased, primarily as a result of lower fuel prices.
For year-to-date 2016, purchased power expense was $581 million compared to $507 million for the corresponding period in 2015. The increase was primarily due to a 29.4% increase in the volume of KWHs purchased, partially offset by a 13.4% decrease in the average cost per KWH purchased, primarily as a result of lower fuel prices.
Energy purchases will vary depending on demand for energy within the Southern Company system's electric service territory, the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, and the availability of the Southern Company system's generation.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Cost of Natural Gas
Cost of natural gas represents the cost of natural gas sold by the seven natural gas distribution utilities and certain non-regulated operations of Southern Company Gas. Following the Merger, $133 million of natural gas costs is included in the consolidated statements of income for the third quarter and year-to-date 2016.
See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
Cost of Other Sales
In the third quarter and year-to-date 2016, cost of other sales were $84 million and $161 million, respectively. These costs were primarily related to sales of products and services by PowerSecure, which was acquired on May 9, 2016, of $69 million and $111 million for the third quarter and year-to-date 2016, respectively. Additionally, for the third quarter and year-to-date 2016, costs of $11 million and $43 million, respectively, related to certain non-regulated sales of products and services by the traditional electric operating companies were reclassified as cost of other sales for consistency of presentation on a consolidated basis. In prior periods, these costs were included in other income (expense), net.
See "Other Revenues" herein and Note (I) to the Condensed Financial Statements under "Southern Company – Acquisition of PowerSecure International, Inc." herein for additional information.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $314 | | 28.6 | | $296 | | 8.9 |
In the third quarter 2016, other operations and maintenance expenses were $1.4 billion compared to $1.1 billion for the corresponding period in 2015. The increase was primarily related to $251 million in operations and maintenance expenses at Southern Company Gas following the Merger, a $26 million charge in connection with an employee attrition plan at Georgia Power, a $19 million increase in transmission and distribution expenses primarily related to overhead line maintenance at Georgia Power, $18 million in operations and maintenance expenses at PowerSecure, and a $9 million increase at Southern Power associated with new solar and wind facilities placed in service in 2015 and 2016, partially offset by an $11 million net decrease in employee compensation and benefits, including pension costs.
For year-to-date 2016, other operations and maintenance expenses were $3.6 billion compared to $3.3 billion for the corresponding period in 2015. The increase was primarily due to $251 million in operations and maintenance expenses at Southern Company Gas following the Merger, $28 million in operations and maintenance expenses at PowerSecure since the acquisition closed on May 9, 2016, a $28 million increase in transaction fees related to the Merger and the acquisition of PowerSecure, a $27 million increase in transmission and distribution expenses primarily related to overhead line maintenance and integrated transmission system billings at Georgia Power, a $26 million charge in connection with an employee attrition plan at Georgia Power, and a $22 million increase at Southern Power associated with new solar and wind facilities placed in service in 2015 and 2016. The increase was partially offset by a $53 million decrease in scheduled outage and maintenance costs at generation facilities and a $48 million net decrease in employee compensation and benefits, including pension costs.
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.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Depreciation and Amortization
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $167 | | 31.6 | | $290 | | 19.1 |
In the third quarter 2016, depreciation and amortization was $695 million compared to $528 million for the corresponding period in 2015. For year-to-date 2016, depreciation and amortization was $1.8 billion compared to $1.5 billion for the corresponding period in 2015. Following the Merger, $116 million in depreciation and amortization for Southern Company Gas is included in the consolidated financial statements for the third quarter and year-to-date 2016. Additionally, the increases were due to additional plant in service at the traditional electric operating companies and Southern Power.
See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
Taxes Other Than Income Taxes
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $45 | | 17.0 | | $60 | | 7.9 |
In the third quarter 2016, taxes other than income taxes were $309 million compared to $264 million for the corresponding period in 2015. For year-to-date 2016, taxes other than income taxes were $821 million compared to $761 million for the corresponding period in 2015. Following the Merger, $29 million in taxes other than income taxes associated with Southern Company Gas is included in the consolidated financial statements for the third quarter and year-to-date 2016. Additionally, property taxes at the traditional electric operating companies increased for the third quarter and year-to-date 2016 primarily due to an increase in the assessed value of property.
See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
Estimated Loss on Kemper IGCC
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(62) | | (41.3) | | $40 | | 22.0 |
In the third quarter 2016 and 2015, estimated probable losses on the Kemper IGCC of $88 million and $150 million, respectively, were recorded at Southern Company. For year-to-date 2016 and 2015, estimated probable losses on the Kemper IGCC of $222 million and $182 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
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $156 | | 71.6 | | $301 | | 49.2 |
In the third quarter 2016, interest expense, net of amounts capitalized was $374 million compared to $218 million in the corresponding period in 2015. For year-to-date 2016, interest expense, net of amounts capitalized was $913 million compared to $612 million in the corresponding period in 2015. These increases were primarily due to an increase in average outstanding long-term debt primarily related to the financing of the Merger. In addition, following the Merger, $39 million in interest expense of Southern Company Gas is included in the consolidated financial statements for the third quarter and year-to-date 2016. Also contributing to the year-to-date 2016 increase was the May 2015 termination of an asset purchase agreement between Mississippi Power and SMEPA and the resulting reversal of accrued interest on related deposits.
See Note (E) to the Condensed Financial Statements herein for additional information.
Other Income (Expense), Net |
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $42 | | N/M | | $3 | | 7.3 |
N/M - Not meaningful
In the third quarter 2016, other income (expense), net was $21 million compared to $(21) million for the corresponding period in 2015. For year-to-date 2016, other income (expense), net was $(38) million compared to $(41) million for the corresponding period in 2015. Following the Merger, $38 million in other income of Southern Company Gas is included in the consolidated financial statements for the third quarter and year-to-date 2016, primarily related to $27 million of earnings from the equity method investment in Southern Natural Gas Company, L.L.C. (SNG) in September 2016. Additionally, in the third quarter 2016, revenues and costs associated with certain non-regulated sales of products and services by the traditional electric operating companies were reclassified to other revenues and cost of other sales for consistency of presentation on a consolidated basis following the PowerSecure acquisition. For the third quarter and year-to-date 2016, net amounts reclassified were $6 million and $20 million, respectively. The year-to-date 2016 increase was partially offset by fees associated with the Bridge Agreement for the Merger.
See "Other Revenues" and "Cost of Other Sales" herein and Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information. Also see 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.
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(52) | | (10.4) | | $(134) | | (12.5) |
In the third quarter 2016, income taxes were $448 million compared to $500 million for the corresponding period in 2015. The decrease was primarily due to increased federal income tax benefits from ITCs and PTCs at Southern Power, partially offset by a reduction in tax benefits related to the estimated probable losses on Mississippi Power's construction of the Kemper IGCC and an increase in pre-tax earnings.
For year-to-date 2016, income taxes were $942 million compared to $1.1 billion for the corresponding period in 2015. The decrease was primarily due to increased federal income tax benefits from ITCs and PTCs at Southern
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Power, partially offset by an increase in pre-tax earnings and an increase related to state income tax benefits realized in 2015.
See Note (G) to the Condensed Financial Statements herein 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 a result of closing the Merger, the distribution of natural gas. 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 and customers 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 electric 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' gas marketing services and wholesale gas services businesses to capture value from locational and seasonal spreads. Additionally, changes in commodity prices subject a significant portion of Southern Company Gas' operations to earnings variability.
As part of its ongoing effort to adapt to changing market conditions, Southern Company continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, partnerships, and acquisitions involving other utility or non-utility businesses or properties, disposition of certain assets, internal restructuring, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations, risks, and financial condition of Southern Company.
On July 10, 2016, Southern Company and Kinder Morgan, Inc. (Kinder Morgan) entered into a definitive agreement for Southern Company to acquire a 50% equity interest in SNG, which is the owner of a 7,000-mile pipeline system connecting natural gas supply basins in Texas, Louisiana, Mississippi, and Alabama to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee. In addition, the agreement committed Southern Company and Kinder Morgan to cooperatively pursue specific growth opportunities to develop natural gas infrastructure through SNG. On August 31, 2016, Southern Company assigned its rights and obligations under the definitive agreement to a wholly-owned, indirect subsidiary of Southern Company Gas. On September 1, 2016, Southern Company Gas completed the acquisition for a purchase price of approximately $1.4 billion. The investment in SNG is accounted for using the equity method.
For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Company in Item 7 of the Form 10-K and RISK FACTORS in Item 1A herein.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis or through market-based contracts. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for 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, regional haze regulations, fine particulate matter National Ambient Air Quality Standards (NAAQS), and the Cross State Air Pollution Rule (CSAPR).
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 completed the measures necessary to achieve compliance with the MATS rule by the applicable deadlines.
Also on April 25, 2016, the EPA issued proposed revisions to the regional haze regulations. The ultimate impact of the proposed revisions will depend on their ultimate adoption, implementation, and any legal challenges and cannot be determined at this time.
On September 6, 2016, the EPA designated all remaining areas within Georgia Power's and Gulf Power's service territories as attainment for the 2012 annual fine particulate matter NAAQS. Following the EPA's decision, all areas within the traditional electric operating companies' service territory have now been designated as attainment for the 2012 fine particulate matter NAAQS.
On October 26, 2016, the EPA published a final rule that updates the CSAPR ozone season nitrogen oxide program, including revising ozone-season emissions budgets in Alabama, Mississippi, and Texas and removing Florida and North Carolina from the program. The ultimate impact of this rule will depend on the outcome of any legal challenges and implementation at the state level and cannot be determined at this time.
Coal Combustion 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 October 26, 2016, the Georgia Department of Natural Resources approved amendments to its state solid waste regulations to incorporate the requirements of the EPA's Disposal of Coal Combustion Residuals from Electric Utilities Rule (CCR Rule) and establish additional requirements for all of Georgia Power's onsite storage units consisting of landfills and surface impoundments. The final State of Georgia regulations are not anticipated to have a material impact on the Southern Company system's compliance obligations under the CCR Rule. See Note (A) to
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
the Condensed Financial Statements herein for information regarding Southern Company's asset retirement obligations (ARO) as of September 30, 2016.
Environmental Remediation
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – EnvironmentalRemediation" of Southern Company in Item 7 of the Form 10-K for additional information.
As a result of closing the Merger, Southern Company's Consolidated Balance Sheet at September 30, 2016 includes the environmental remediation liabilities of Southern Company Gas. See Note (B) to the Condensed Financial Statements under "Environmental Remediation" herein for additional information. See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information regarding the Merger.
Regulatory Matters
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 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.
In accordance with the Alabama PSC order approving up to 500 MWs of renewable projects, Alabama Power has entered into agreements to purchase power from or to build renewable generation sources, including a 72-MW solar PPA approved by the Alabama PSC in June 2016. Alabama Power is marketing the associated renewable energy credits (REC) generated by this solar PPA to customers interested in supporting renewable energy development. The terms of the renewable agreements permit Alabama Power to use the energy and retire the associated RECs in service of its customers or to sell RECs, separately or bundled with energy.
As part of the Georgia Power Advanced Solar Initiative (ASI), four PPAs totaling 149 MWs of Georgia Power's solar contracted capacity from Southern Power began in the first quarter 2016. During the second quarter 2016, Georgia Power executed PPAs to purchase an additional 41 MWs of solar capacity under the ASI. Ownership of any associated RECs is specified in each respective PPA. The party that owns the RECs retains the right to use them.
On October 4, 2016, two 30-MW solar generating facilities at Fort Gordon and Fort Stewart Army bases began commercial operation. These solar generating facilities were approved by the Georgia PSC in 2014.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The Florida PSC issued a final approval order on Gulf Power's Community Solar Pilot Program on April 15, 2016. The program will offer all Gulf Power customers an opportunity to voluntarily contribute to the construction and operation of a solar photovoltaic facility with electric generating capacity of up to 1 MW through annual subscriptions. The energy generated from the solar facility is expected to provide power to all of Gulf Power's customers.
On October 11, 2016, the Florida PSC preliminarily approved Gulf Power's energy purchase agreement for up to 94 MWs of wind generation in central Oklahoma. Purchases under this agreement will be for energy only and will be recovered through Gulf Power's fuel cost recovery clause.
In November 2015, the Mississippi PSC issued orders approving three solar facilities for a combined total of approximately 105 MWs. Mississippi Power will purchase all of the energy produced by the solar facilities for the 25-year term under each of the three PPAs. The projects are expected to be in service 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.
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.
Environmental Accounting Order
In April 2016, as part of its environmental compliance strategy, Alabama Power ceased using coal at Plant Greene County Units 1 and 2 (300 MWs representing Alabama Power's ownership interest) and began operating Units 1 and 2 solely on natural gas in June 2016 and July 2016, respectively.
Georgia Power
Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, Environmental Compliance Cost Recovery tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to the construction of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through separate fuel cost recovery tariffs. See Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" 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 NCCR tariff. Also see Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" herein for additional information regarding Georgia Power's fuel cost recovery.
Pursuant to the terms and conditions of a settlement agreement related to Southern Company's acquisition of Southern Company Gas approved by the Georgia PSC on April 14, 2016, Georgia Power's 2013 ARP will continue in effect until December 31, 2019, and Georgia Power will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, Georgia Power and Atlanta Gas Light Company (collectively, Utilities) each will retain their respective merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, such net merger savings applicable to each utility will be shared on a 60/40 basis between their respective customers and the Utilities; thereafter, all merger savings will be retained by customers.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power" in Item 8 of the Form 10-K for additional information regarding the 2013 ARP and Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information regarding the Merger.
Integrated Resource Plan
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory 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. On August 31, 2016, Georgia Power sold its 33% ownership interest in the Intercession City unit to Duke Energy Florida, Inc.
Additionally, the Georgia PSC approved Georgia Power's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures taken to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4.
The Georgia PSC approved the reclassification of the remaining net book value of Plant Mitchell Unit 3 and costs associated with materials and supplies remaining at the unit retirement date to a regulatory asset. Recovery of the unit's net book value will continue through December 31, 2019, as provided in the 2013 ARP. The timing of the recovery of the remaining balance of the unit's net book value as of December 31, 2019 and costs associated with materials and supplies remaining at the unit retirement date will be deferred for consideration in Georgia Power's base rate case required to be filed by July 1, 2019.
The Georgia PSC also approved the Renewable Energy Development Initiative to procure an additional 1,200 MWs of renewable resources primarily utilizing market-based prices established through a competitive bidding process with expected in-service dates between 2018 and 2021. Additionally, 200 MWs of self-build capacity for use by Georgia Power was approved, as well as consideration for no more than 200 MWs of capacity as part of a renewable commercial and industrial program.
The Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve the nuclear 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.
Storm Damage Recovery
As of September 30, 2016, the balance in Georgia Power's regulatory asset related to storm damage was $94 million. During October 2016, Hurricane Matthew caused significant damage to Georgia Power's transmission and distribution facilities. The total amount of restoration costs related to this hurricane is estimated to be between $130 million and $155 million, which will be charged to capital accounts or to the storm damage reserve. Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, to the storm damage reserve to cover the operating and maintenance costs of damages from major storms to its transmission and distribution facilities, which is recoverable through base rates. The rate of recovery of storm damage costs after December 31, 2019 is expected to be adjusted in Georgia Power's base rate case required to be filed by July 1, 2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's financial statements. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Storm Damage Recovery" in Item 8 of the Form 10-K for additional information regarding Georgia Power's storm damage reserve.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Gulf Power
Through 2015, long-term non-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 cover approximately 24% of Gulf Power's ownership of the unit through 2019. The expiration of these contracts is not expected to have a material impact on Southern Company's earnings. On May 5, 2016, Gulf Power delivered a letter to the Florida PSC requesting recognition of Gulf Power's ownership in Plant Scherer Unit 3 as being in service to retail customers when and as its existing wholesale contracts expire. As a result, on September 13, 2016, the Florida PSC instructed Gulf Power to file its monthly earnings surveillance reports both including and excluding its share of investment and expenses related to Plant Scherer Unit 3 that is not covered by contracts.
On October 12, 2016, Gulf Power filed a petition (2016 Rate Case) with the Florida PSC requesting an increase in retail rates and charges of $106.8 million based on the projected test year of January 1, 2017 through December 31, 2017 and a retail ROE of 11% compared to the current retail ROE of 10.25%. The recoverability of the costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 will be decided in this matter. The Florida PSC is expected to make a decision on the 2016 Rate Case in the second quarter 2017. Gulf Power has requested that the increase in base rates, if approved by the Florida PSC, become effective in July 2017.
On November 2, 2016, the Florida PSC approved Gulf Power's annual rate clause request for its cost recovery clause factors for 2017. The fuel and environmental factors include certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3. See Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters– Gulf Power– Cost Recovery Clauses" herein for additional information.
The ultimate outcome of these matters cannot be determined at this time.
Southern Company Gas
Natural Gas Cost Recovery
Southern Company Gas has established natural gas cost recovery rates approved by the relevant state regulatory agencies in the states in which it serves. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow.
Regulatory Infrastructure Programs
Southern Company Gas' natural gas distribution utilities are involved in ongoing capital projects associated with infrastructure improvement programs that have been previously approved by their applicable state regulatory agencies and provide an appropriate return on invested capital. These infrastructure improvement programs update or expand the natural gas distribution systems of the utilities to improve safety and reliability and meet operational flexibility and growth. Southern Company Gas currently has approved infrastructure improvement programs in six different states with initial program lengths ranging from four to 10 years, with the longest set to expire in 2025. The average annual spend under these programs ranges from $10 million to $250 million.
Southern Company Gas currently has proposed infrastructure improvement programs pending approval by the applicable state regulatory agencies in Georgia and New Jersey requesting average annual spending of $44 million through 2020 and $110 million through 2027, respectively. The ultimate outcome of these matters 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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
its strategy of developing and constructing new electric generating facilities, as well as adding or changing fuel sources for certain existing units, adding environmental control equipment, expanding the electric transmission and distribution systems, and updating and expanding the transmission andnatural gas distribution systems. For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. Southern Company Gas is engaged in various infrastructure programs that update or expand its natural gas distribution systems to improve reliability and ensure the safety of its utility infrastructure and recovers in rates its investment and a return associated with these infrastructure programs.
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. See Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters– Southern Company Gas– Regulatory Infrastructure Programs" herein for additional information regarding infrastructure improvement programs at Southern Company Gas' natural gas distribution utilities.
Also see FINANCIAL CONDITION AND LIQUIDITY – "Capital"Capital Requirements and Contractual Obligations"Obligations" herein for additional information regarding Southern Company's capital requirements for its subsidiaries' construction programs.
Integrated Coal Gasification Combined Cycle
From 2013 through September 30, 2015, Southern Company recorded pre-tax charges totaling $2.23Mississippi Power's current cost estimate for the Kemper IGCC in total is approximately $6.82 billion, ($1.4which includes approximately $5.52 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 $2.63 billion ($1.63 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through September 30, 2016. Mississippi Power's current cost estimate includes costs through December 31, 2016.
The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." On October 11, 2016, the Kemper IGCC began testing using clean syngas from gasifier "A" and the related gas clean-up systems to produce electricity. On November 2, 2016, Mississippi Power determined a maintenance outage of gasifier "A" is needed to make improvements to the ash removal systems. The remaining schedule reflects the time expected to achieve production of electricity using gasifier "B," complete gasifier "A" outage activities, and resume electricity production using gasifier "A," as well as to complete the integration of all systems necessary for both combustion turbines to simultaneously generate electricity with syngas.
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 reversed the Mississippi PSC's March 2013 order that authorized Mississippi Power's collection of $156 million annually to be recorded as Mirror CWIP and directed the Mississippi PSC to enter an order requiring Mississippi Power to refund the Mirror CWIP amounts collected. The Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015. Refunds of $342 million collected by Mississippi Power through July 2015 billings plus associated carrying costs will begin in November 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.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 $369 million of Mirror CWIP rate collections, including associated carrying costs through September 30, 2015, the termination of the Mirror CWIP rates, and the likely repayment to the IRS of approximately $235 million of unrecognized tax benefits associated with the ITCs that were allocated to the Kemper IGCC under Section 48A (Phase II) of the Internal Revenue Code if the in-service date of the Kemper IGCC extends beyond April 19, 2016 have adversely impacted Mississippi Power's financial condition.
As a result of the Mississippi Supreme Court's decision and these financial impacts, on July 10, 2015, Mississippi Power submitted a filing with the Mississippi PSC that included a request for interim rates, until such time as the Mississippi PSC renders a final decision on permanent 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 (In-Service Asset Proposal). These interim rates are designed to collect approximately $159 million annually. On August 13, 2015, the Mississippi PSC approved the implementation of the interim rates that became effective with the first billing cycle in September (on August 19), subject to refund and certain other conditions. In addition, the Mississippi PSC reserved the right to modify or terminate the interim rates based upon a material change in circumstances. The Mississippi PSC is scheduled to issue a final order on or before December 8, 2015 related to permanent rates for the In-Service Asset Proposal. The ultimate outcome of these matters cannot be determined at this time.
Nuclear Construction
On April 15, 2015, the Georgia PSC issued a procedural order in connection with the twelfth Vogtle Construction Monitoring (VCM) report, which included a requested amendment (Requested Amendment) to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 (second quarter of 2019 and second quarter of 2020, respectively) as well as to include the estimated owner's costs associated with the proposed 18-month Contractor delay and to increase the estimated total in-service capital cost of Plant Vogtle Units 3 and 4 to $5.0 billion. Pursuant to 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 up to the certified amount will be collected through 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.
On August 28, 2015, Georgia Power filed its thirteenth VCM report with the Georgia PSC covering the period from January 1 through June 30, 2015, which requested approval for an additional $148 million of construction capital costs incurred during that period and reflected estimated financing costs during the construction period to total approximately $2.4 billion.
On October 30, 2015, Georgia Power filed to increase the NCCR tariff by approximately $19 million, effective January 1, 2016, pending Georgia PSC approval.
On October 27, 2015, Westinghouse and Chicago Bridge & Iron Company, N.V. (CB&I) announced an agreement under which Westinghouse or one of its affiliates will acquire CB&I Stone & Webster, Inc. (S&W) (formerly known as Stone & Webster, Inc.) from CB&I, subject to satisfaction of certain conditions to closing. In addition, on October 27, 2015, Westinghouse and the Vogtle Owners entered into a term sheet (Term Sheet) setting forth the terms of a settlement agreement to resolve disputes between the Vogtle Owners and the Contractor under the engineering, procurement, and construction agreement between the Vogtle Owners and the Contractor (Vogtle 3 and 4 Agreement), including the litigation pending in the U.S. District Court for the Southern District of Georgia between the Contractor and the Vogtle Owners (Vogtle Construction Litigation).
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In accordanceLitigation
On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. On August 12, 2016, Southern Company and Mississippi Power removed the case to the U.S. District Court for the Southern District of Mississippi, where the case is currently pending. However, the plaintiffs have filed a request to remand the case back to state court. 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 Midstream Services, LLC (Treetop) and other related parties filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint relates to the cancelled CO2 contract with Treetop and alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the Term Sheet, the Vogtle Ownerspart of Mississippi Power, Southern Company, and the Contractor will enter into mutual releasesSCS and seeks compensatory damages of all open claims which have been asserted, including any potential extension of such open claims,$100 million, as well as future claims based on events occurring priorunspecified punitive damages. Southern Company, Mississippi Power, and SCS have moved to compel arbitration pursuant to the effective date of the release that potentially could have been asserted under the original terms of the Vogtle 3CO2 contract.
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 4 Agreement, including the Vogtle Construction Litigation, whichliquidity. Southern Company will be dismissed with prejudice. In addition, among other items, the Term Sheet provides that the guaranteed substantial completion dates under the Vogtle 3 and 4 Agreement will be revised to match the current estimated in-service dates of June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4 and Georgia Power, based on its ownership interest, will pay to the Contractor and capitalize to the project cost approximately $350 million, of which approximately $120 million has been paid previously under the dispute resolution procedures of the Vogtle 3 and 4 Agreement. The settlement of the pending disputes between the Vogtle Ownersvigorously defend itself in these matters, and the Contractor, including the Vogtle Construction Litigation, is subject to consummation of Westinghouse's proposed acquisition of S&W. If this proposed acquisition is not completed, the Vogtle Construction Litigation will continue and the Contractor may from time to time continue to assert that it is entitled to additional payments with respect to its allegations, any of which could be substantial.
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 MattersNuclear Construction
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Southern Company in Item 7On October 20, 2016, Georgia Power and the Georgia PSC Staff entered into a settlement agreement (Vogtle Cost Settlement Agreement) resolving the following prudence and cost recovery matters related to Plant Vogtle Units 3 and 4: (i) none of the Form 10-K$3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth Vogtle Construction Monitoring report will be disallowed from rate base on the basis of imprudence; (ii) the definitive settlement agreement entered into on December 31, 2015 by Westinghouse and the Vogtle Owners (Contractor Settlement Agreement) is reasonable and prudent and none of the amounts paid or to be paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) financing costs on verified and approved capital costs will be deemed prudent provided they are incurred prior to December 31, 2019 and December 31, 2020 for additional information.
Investment Tax Credits
The IRS allocated $279Plant Vogtle Units 3 and 4, respectively; and (iv) (a) the in-service capital cost forecast will be adjusted to $5.680 billion (Revised Forecast), which includes a contingency of $240 million (Phase II)above Georgia Power's current forecast of Internal Revenue Code Section 48A tax credits$5.440 billion, (b) capital costs incurred up to Mississippi Power in connectionthe Revised Forecast will be presumed to be reasonable and prudent with the Kemper IGCC. These tax creditsburden of proof on any party challenging such costs, and (c) Georgia Power would have the burden to show that any capital costs above the Revised Forecast are dependent upon meetingreasonable and prudent. Under the IRS certification requirements, including anterms of the Vogtle Cost Settlement Agreement, the certified in-service date no later than April 19, 2016capital cost for purposes of calculating the NCCR tariff will remain at $4.418 billion. Construction capital costs above $4.418 billion will accrue AFUDC through commercial operation. The ROE used to calculate the NCCR tariff will be reduced from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016. For purposes of the AFUDC calculation, the ROE on costs between $4.418 billion and $5.440 billion will also be 10.00% and the captureROE on any amounts above $5.440 billion would be Georgia Power's average cost of long-term debt. If the Georgia PSC adjusts Georgia Power's ROE rate setting point in a rate case prior to Plant Vogtle Units 3 and sequestration (via enhanced oil recovery)4 being placed into retail rate base, then the ROE for purposes of at least 65% of the CO2 produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. Through September 30, 2015, Southern Company had recorded tax benefits totaling $276 million for the Phase II credits, of which approximately $235 million had been utilized. While the in-service date for the remainder of the Kemper IGCC is currently expected to occur in the first half of 2016, Mississippi Power now anticipates the in-service date to occur subsequent to April 19, 2016, but has not made a final determination to that effect. Due to this uncertainty, Southern Company has reflected these tax credits as unrecognized tax benefits and reclassified the Phase II credits to a current liability on its September 30, 2015 balance sheet, with no impact to net income. Repayment to the IRS would occur with the quarterly estimated tax payment following a final determination that the in-service date would occur subsequent to April 19, 2016. Any cash funding requirements necessary for Mississippi Power to make this repayment are expected to be provided by Southern Company. See Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Unrecognized Tax Benefits – Investment Tax Credits," respectively, herein for additional information. The ultimate outcome of this tax matter cannot be determined at this time.calculating both
Section 174 Research and Experimental Deduction
Southern Company reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations for 2013, 2014, and 2015. In May 2015, Southern Company amended its 2008 through 2013 federal income tax returns to include deductions for Kemper IGCC-related R&E expenditures. Due to the uncertainty related to this tax position, Southern Company had unrecognized tax benefits associated with these R&E deductions totaling approximately $414 million as of September 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"
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
the NCCR tariff and AFUDC will likewise be 95 basis points lower than the revised ROE rate setting point. If Plant Vogtle Units 3 and 4 are not commercially operational by December 31, 2020, then (i) the ROE for purposes of calculating the NCCR tariff will be reduced an additional 300 basis points, and may, at the Georgia PSC's discretion, be accrued to be used for the benefit of customers, until such time as the units reach commercial operation and (ii) the ROE used to calculate AFUDC will be Georgia Power's average cost of long-term debt.
Under the terms of the Vogtle Cost Settlement Agreement, Plant Vogtle Units 3 and 4 will be placed into retail rate base on December 31, 2020 or upon reaching commercial operation, whichever is later. The Georgia PSC will determine for retail ratemaking purposes the process of transitioning Plant Vogtle Units 3 and 4 from a construction project to an operating plant no later than Georgia Power's base rate case required to be filed by July 1, 2019.
The Vogtle Cost Settlement Agreement is subject to approval by the Georgia PSC, which is scheduled to vote on this matter on December 20, 2016. Accordingly, the terms of the Vogtle Cost Settlement Agreement are subject to change and the terms of any final agreement approved by the Georgia PSC may differ materially from the terms of the Vogtle Cost Settlement Agreement. If approved, the Vogtle Cost Settlement Agreement is expected to reduce Georgia Power's revenues for the years 2016 through 2020 by a total of approximately $325 million ($115 million reduction in net income).
See Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters– Georgia Power– Nuclear Construction" for additional information.
The ultimate outcome of these matters cannot be determined at this time.
Income Tax Matters
Bonus Depreciation
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Bonus Depreciation" of Southern Company in Item 7 of the Form 10-K for additional information.
The extension of 50% bonus depreciation included in the PATH Act is expected to result in approximately $1.7 billion of positive cash flows for the 2016 tax year, which may not all be realized in 2016 due to a projected consolidated net operating loss for Southern Company. Approximately $370 million of the benefit is dependent upon placing the remainder of the Kemper IGCC in service by December 31, 2016. See Note (B) tothe Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Unrecognized Tax Benefits Note (G) tothe Condensed Financial Statements under "–Current and Deferred Income Taxes Section 174 Research and Experimental Deduction,– Net Operating Loss" 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 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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 $88 million ($54 million after tax) in the third quarter 2016, $81 million ($50 million after tax) in the second quarter 2016, $53 million ($33 million after tax) in the first quarter 2016, $183 million ($113 million after tax) in the fourth quarter 2015, $150 million ($93 million after tax) in the third quarter 2015, $23 million ($14 million after tax) in the second quarter 2015, $9 million ($6 million after tax) in the first quarter 2015, $70 million ($43 million after tax) in the fourth quarter 2014, $418 million ($258 million after tax) in the third quarter 2014, $380 million ($235 million after tax) in the first quarter 2014, $40 million ($25 million after tax) in the fourth quarter 2013, $150 million ($93 million after tax) in the third quarter 2013, $450 million ($278 million after tax) in the second quarter 2013, and $540 million ($333 million after tax) in the first quarter 2013. In the aggregate, Southern Company has incurred charges of $2.23$2.63 billion ($1.41.63 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through September 30, 2015.2016.
Mississippi Power's revised cost estimate reflects an expected in-service date of December 31, 2016 and includes certain post-in-service costs which are expected to be subject to the cost cap. Mississippi Power has experienced, and may continue to experience, material changes in the cost estimate for the Kemper IGCC. Further cost increases and/or extensions of the expected in-service date may result from factors including, but not limited to, difficulties integrating the systems required for sustained operations, sustaining nitrogen supply, major equipment failure, unforeseen engineering or design problems including any repairs and/or modifications to systems, and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). In addition, during the start-up and commissioning process, Mississippi Power is also identifying
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Mississippi Power has experienced,potential improvement projects that ultimately may be completed subsequent to placing the remainder of the Kemper IGCC in service. If completed, such improvement projects would be expected to enhance plant performance, safety, and/or operations. The related potential costs have yet to be fully evaluated, have not been included in the current cost estimates, and may continuebe subject to experience, material changes in the $2.88 billion cost estimate for the Kemper IGCC.cap. 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 further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including, but not limited to, additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC).
Mississippi Power's revised cost estimate includes costs through June 30, 2016. Any extension of the in-service date beyond JuneDecember 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 extension of the in-service date with respect to the Kemper IGCC beyond June 30,December 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 $12$15 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting fees and legal fees a portion of which are being deferred as regulatory assets and are estimated to total approximately $6$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 ObligationsGoodwill and Other Intangible Assets
AROs are computedSouthern Company accounts for acquisitions using the acquisition method of accounting, which requires the assets acquired and liabilities assumed to be recorded at the date of acquisition at their respective estimated fair values. Southern Company recognizes goodwill as of the acquisition date, as a residual over the fair valuevalues of the ultimate costsidentifiable net assets acquired. Goodwill will be tested for impairment on an asset's future retirement and are recordedannual basis in the period in which the liability is incurred. The costs are capitalized as partfourth quarter of the related long-lived assetyear as well as on an interim basis as events and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniqueschanges in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities.
The liability for AROs primarily relates to the decommissioning of the nuclear facilities - Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2 - and facilities that are subject to the CCR Rule, primarily ash ponds. In addition, the Southern Company system has retirement obligations related 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 with the Southern Company system's rail lines and natural gas pipelines, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, 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.
Ascircumstances occur. Primarily as a result of the final CCR Rule discussed above, Alabama Power, Gulf Power,acquisitions of Southern Company Gas and Mississippi Power recorded new AROsPowerSecure in 2016, goodwill totaled approximately $6.2 billion at September 30, 2016.
Definite-lived intangible assets acquired are amortized over the estimated useful lives of the respective assets to reflect the pattern in which the economic benefits of the intangible assets are consumed. Whenever events or changes in circumstances indicate that the carrying amount of the intangible assets may not be recoverable, the intangible assets will be reviewed for facilities that are subject to the CCR Rule. Georgia Power had previously recorded AROsimpairment. Primarily as a result of state requirementsthe acquisitions of Southern Company Gas and PowerSecure in Georgia which closely align with2016, other intangible assets, net of amortization totaled approximately $0.9 billion at September 30, 2016.
The judgments made in determining the requirementsestimated fair value assigned to each class of assets acquired and liabilities assumed, as well as asset lives, can significantly impact Southern Company's results of operations. Fair values and useful lives are determined based on, among other factors, the expected future period of benefit of the CCR Rule. The costasset, the various characteristics of the asset, and projected cash flows. As the determination of an asset's fair value and useful life involves management making certain estimates areand because these estimates form the basis for the determination of whether or not an impairment charge should be recorded, Southern Company considers these estimates to be critical accounting estimates.
See Note (A) to the Condensed Financial Statements under "Goodwill and Other Intangible Assets" herein for additional information regarding Southern Company's goodwill and other intangible assets as of September 30, 2016 and Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information related to Southern Company's recent acquisitions.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Derivatives and Hedging Activities
Derivative instruments are recorded on the balance sheets as either assets or liabilities measured at their fair value, unless the transactions qualify for the normal purchases or normal sales scope exception and are instead subject to traditional accrual accounting. For those transactions that do not qualify as a normal purchase or normal sale, changes in the derivatives' fair values are recognized concurrently in earnings unless specific hedge accounting criteria are met. If the derivatives meet those criteria, derivative gains and losses offset related results of the hedged item in the income statement in the case of a fair value hedge, or gains and losses are deferred in OCI until the hedged transaction occurs in the case of a cash flow hedge. Certain subsidiaries of Southern Company enter into energy-related derivatives that are designated as regulatory hedges where gains and losses are initially recorded as regulatory liabilities and assets and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through billings to customers.
Southern Company uses derivative instruments to reduce the impact to the results of operations due to the risk of changes in the price of natural gas, to manage fuel hedging programs per guidelines of state regulatory agencies, and to mitigate residual changes in the price of electricity, weather, interest rates, and foreign currency exchange rates. The fair value of commodity derivative instruments used to manage exposure to changing prices reflects the estimated amounts that Southern Company would receive or pay to terminate or close the contracts at the reporting date. To determine the fair value of the derivative instruments, Southern Company utilizes market data or assumptions that market participants would use in pricing the derivative asset or liability, including assumptions about risk and the risks inherent in the inputs of the valuation technique.
Southern Company classifies derivative assets and liabilities based on information usingthe lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The determination of the fair value of the derivative instruments incorporates various assumptions related to closure and post-closure costs, timingfactors required under the guidance. These factors include:
the creditworthiness of future cash outlays, inflation and discount rates,the counterparties involved and the potential methods for complying with impact of credit enhancements (such as cash deposits and letters of credit);
events specific to a given counterparty; and
the CCR Rule requirements for closure in place. As further analysis is performed, including evaluationimpact of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, the traditional operating companies expect to continue to periodically update these estimates.Southern Company's nonperformance risk on its liabilities.
Given the significant judgment involvedassumptions used in estimating AROs,pricing the derivative asset or liability, Southern Company considers the valuation of derivative assets and liabilities for AROs to bea critical accounting estimates.
estimate. See Note 1 to the financial statements of Southern Company under "Asset Retirement Obligations"Quantitative and Other Costs of Removal" and "Nuclear Decommissioning"Qualitative Disclosures About Market Risk" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations"3 herein for additionalmore 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,February 25, 2016, the FASB issued 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 and there is no change to the accounting for existing leveraged leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2015.2018, 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 required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. Southern Company currently recognizes any excess tax benefits and deficiencies related to the exercise and vesting of stock
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
compensation as additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016. Early adoption is permitted and Southern Company intends to adopt the ASU in the fourth quarter 2015.2016. The ASUadoption is requirednot expected to be applied retrospectively to all periods presented beginning in the year of adoption. 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 September 30, 2015.2016. Through September 30, 2015,2016, Southern Company has incurred non-recoverable cash expenditures of $1.8$2.42 billion and is expected to incur approximately $0.4$0.21 billion in additional non-recoverable cash expenditures through completion of the construction and start-up of the Kemper IGCC.IGCC, which includes certain post-in-service costs expected to be subject to the cost cap. 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 $5.1$4.3 billion for the first nine months of 2015, an increase2016, a decrease of $0.4$0.8 billion from the corresponding period in 2014.2015. The increasedecrease in net cash provided from operating activities was primarily due to an increase in fuel cost recovery, partially offset by timing of accounts payable.unutilized ITCs and PTCs. Net cash used for investing activities totaled $4.9$16.6 billion for the first nine months of 20152016 primarily due to gross property additions forthe closing of the Merger, the construction of electric generation, transmission, and distribution facilities and installation of equipment to comply with environmental standards, and Southern Power's acquisitions and construction of generation, transmission, and distribution facilities, and acquisitions of solarrenewable facilities. Net cash provided from financing activities totaled $0.2$13.6 billion for the first nine months of 20152016 primarily due to issuances of long-term debt and common stock associated with financing and completing the Merger and Southern Company Gas' investment in SNG, partially offset by common stock dividend payments and redemptions of long-term debt and preferred and preference stock. Fluctuations in cash flowcommon stock dividend payments. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Significant balance sheet changes for the first nine months of 20152016 include an increase of $3.4$14.4 billion in total property, plant, and equipment primarily related to the inclusion of Southern Company Gas as a result of the Merger, construction to comply with environmental standards, and construction of electric generation, transmission, and distribution facilities; a $0.4an increase of $6.2 billion in goodwill related to the acquisitions of Southern Company Gas and PowerSecure; an increase of $1.5 billion in income taxes receivable, non-currentequity investments in unconsolidated subsidiaries primarily related to Southern Company Gas' investment in SNG; increases of $1.5 billion in other regulatory assets, deferred and a $0.4$0.8 billion increasein AROs primarily related to changes in ash pond closure strategy principally for Georgia Power; increases of $16.9 billion in long-term debt and $4.0 billion in total common stockholder's equity primarily associated with financing and completing the Merger and Southern Company Gas' investment in SNG; and increases of $1.9 billion in accumulated deferred income taxes for deductions primarily related to R&E expenditures for the Kemper IGCC; an increase of $0.4and $1.6 billion in accounts receivable primarily related to increases in customer billings; a $1.5 billion increase in short-term and long-term debt to fund the subsidiaries' continuous construction programs and for other general corporate purposes; and a $0.8 billion increase in AROscost of removal obligations primarily related to the CCR Rule.inclusion of Southern Company Gas as a result of the Merger. See Notes (A), (B), and (G)(I) to the Condensed Financial Statements herein under "Asset Retirement Obligations" and "Southern Company," respectively, for additional information regarding AROs, the Kemper IGCC, and R&E expenditures, respectively.information.
At the end of the third quarter 2015,2016, the market price of Southern Company's common stock was $44.70$51.30 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $22.73$25.05 per share, representing a market-to-book ratio of 197%205%, 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 third quarter 20152016 was $0.5425$0.560 per share compared to $0.5250$0.5425 per share in the third 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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
description of Southern Company's capital requirements for the construction programs of the Southern Company system, including estimated capital expenditures for new electric generating facilities and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, trust funding requirements, and unrecognized tax benefits. Approximately $3.3Subsequent to September 30, 2016, Mississippi Power repaid at maturity $300 million aggregate principal amount of its Series 2011A 2.35% Senior Notes due October 15, 2016 and Southern Company Gas repaid at maturity $120 million aggregate principal amount of Series A Floating Rate Senior Notes due October 27, 2016. An additional $1.8 billion will be required through September 30, 20162017 to fund maturities of long-term debt. During the nine months ended September 30, 2016, and subsequent to that date, Southern Power entered into new long-term service agreements, which begin between 2017 and 2020 and result in additional future commitments totaling approximately $927 million. See "Sources"Sources of Capital"Capital" herein for additional information. Subsequent to September 30, 2015, Alabama Power repaid at maturity $400 million aggregate principal amount of its Series 2012B 0.550% Senior Notes due October 15, 2015.
The Southern Company system's construction program is currently estimated to be $7.7total $10.2 billion for 2015, $5.62016, $8.9 billion for 2017, $8.2 billion for 2018, $7.6 billion for 2019, $7.3 billion for 2020, and $6.6 billion for 2021. These amounts include expenditures of approximately $0.7 billion for 2016 and $4.3$0.1 billion for 2017 which includes expenditures related to the construction and start-up of the Kemper IGCCIGCC; $0.6 billion for 2016, $0.6 billion for 2017, $0.7 billion for 2018, $0.4 billion for 2019, and $0.1 billion for 2020 to continue and complete construction of $834 million for 2015Plant Vogtle Units 3 and $281 million4; and $4.4 billion for 2016 and approximately $2.2$1.5 billion per year for 2017 through 2021 for Southern Power's acquisitions and/or construction of new Southern Power generating facilities in 2015.facilities. These estimated expenditures do not include potential compliance costs that may arise from the EPA's final rules and guidelines or subsequently approved state plans that would limit CO2 emissions from existing, new, modified, or reconstructed fossil-fuel-fired electric generating units.
The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in 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; PSCstate regulatory agency approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Additionally, planned expenditures for plant acquisitions may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. See Note 112 to the financial statements of Southern Company under "Acquisitions""Southern Power" in Item 8 of the Form 10-K and Note (I) to the Condensed Financial Statements under "Southern Power""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.
In addition to the Merger Consideration to be paid by Southern Company at the Effective Time, in connection with the Merger, Southern Company will also assume AGL Resources' outstanding indebtedness (approximately $4
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
billion on June 30, 2015). See OVERVIEW herein for additional information regardingAs a result of closing the Merger, including the Merger Consideration.funding requirements of the Southern Company system include the contractual obligations of Southern Company Gas. The following table details the amounts related to Southern Company Gas as of September 30, 2016:
|
| | | | | | | | | | | | | | | | | | | |
| | 2016 | | 2017- 2018 | | 2019- 2020 | | After 2020 | | Total |
| | (in millions) |
Long-term debt(a) — | | | | | | | | | |
| Principal | $ | 120 |
| | $ | 177 |
| | $ | 350 |
| | $ | 4,185 |
| | $ | 4,832 |
|
| Interest | 48 |
| | 412 |
| | 382 |
| | 2,641 |
| | 3,483 |
|
Pipeline charges, storage capacity, and gas supply(b) | 308 |
| | 1,350 |
| | 806 |
| | 2,913 |
| | 5,377 |
|
Operating leases(c) | 6 |
| | 44 |
| | 31 |
| | 52 |
| | 133 |
|
Asset management agreements(d) | 2 |
| | 15 |
| | 2 |
| | — |
| | 19 |
|
Standby letters of credit, performance/surety bonds(e) | 33 |
| | 51 |
| | — |
| | — |
| | 84 |
|
Financial derivative obligations(f) | 195 |
| | 211 |
| | 21 |
| | 2 |
| | 429 |
|
Pension and other postretirement benefit plans(g) | 5 |
| | 44 |
| | — |
| | — |
| | 49 |
|
Purchase commitments — | | | | | | | | | |
Capital(h) | 401 |
| | 3,540 |
| | 3,058 |
| | 1,221 |
| | 8,220 |
|
Other(i) | 11 |
| | 53 |
| | — |
| | — |
| | 64 |
|
| Total | $ | 1,129 |
| | $ | 5,897 |
| | $ | 4,650 |
| | $ | 11,014 |
| | $ | 22,690 |
|
| |
| (a) | Amounts are reflected based on final maturity dates. Variable rate interest obligations are estimated based on rates as of September 30, 2016. |
| |
| (b) | Includes charges recoverable through a natural gas cost recovery mechanism or alternatively billed to marketers and demand charges associated with wholesale gas services. |
| |
| (c) | Certain operating leases have provisions for step rent or escalation payments and certain lease concessions are accounted for by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms. |
| |
| (d) | Represents fixed-fee minimum payments for asset management agreements at wholesale gas services. |
| |
| (e) | Guarantees are provided to certain municipalities and other agencies and certain natural gas suppliers of SouthStar Energy Services, LLC (SouthStar) in support of payment obligations. |
| |
| (f) | Includes derivative liabilities related to energy-related derivatives. |
| |
| (g) | Estimated benefit payments for Southern Company Gas' retirement benefit plans are provided through 2018. No mandatory contributions to the plans are anticipated during this period. |
| |
| (h) | Estimated capital expenditures are provided through 2021. |
| |
| (i) | Primarily consists of contractual environmental remediation liabilities that are primarily recoverable through base rates or rate rider mechanisms. |
Sources of Capital
Southern Company intends to meet its future capital needs through operating cash flows, short-term debt, term loans, and external security issuances. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings. The amount and timing of additional equity capital and debt 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 capital requirements. See "Capital Requirements and Contractual Obligations" herein for additional information.
Except as described herein, the traditional electric operating companies, Southern Power, and Southern PowerCompany Gas plan to obtain the funds required for construction and other purposes from operating cash flows, external security issuances, term loans, short-term borrowings, and equity contributions or loans from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS –
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Company in Item 7 of the Form 10-K for additional information.
In addition, Georgia Power may make borrowings 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 September 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 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 September 30, 2015,2016, Southern Company's current liabilities exceeded current assets by $3.4$0.9 billion, primarily due to long-term debt that is due within one year of $2.3 billion, including approximately $0.8 billion at the parent company, $0.2 billion at Alabama Power, $0.5 billion at Georgia Power, $0.2 billion at Gulf Power, $0.3 billion at Mississippi Power, $0.1 billion at Southern Power, and $0.1 billion at Southern Company $0.6 billion at Alabama Power, $1.4 billion at Georgia Power, $0.4 billion at Mississippi Power, and $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.Gas. 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, Southern Power, and Southern Power,Company Gas, equity contributions and/or loans from Southern Company to meet their short-term capital needs. In addition, for the remainder of 2015, Georgia Power expects to utilize borrowings through the FFB Credit Facility as an additional source of long-term borrowed funds.
The financial condition of Mississippi Power and its ability to obtain funds needed for normal business operations and completion of the construction and start-up of the Kemper IGCC were adversely affected by the return of approximately $301 million of interest bearing refundable deposits to SMEPA in June 2015 in connection with the termination of the APA, the required refund of Mirror CWIP rate collections beginning in early November 2015 of approximately $369 million, including associated carrying costs, the termination of the Mirror CWIP rate, and the likely repayment of unrecognized tax benefits associated with the Phase II tax credits of $235 million. On August
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
13, 2015, the Mississippi PSC approved the implementation of interim rates, subject to refund and certain other conditions, and is scheduled to issue a final order on or before December 8, 2015 related to permanent rates for the In-Service Asset Proposal. 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.
At September 30, 2015,2016, Southern Company and its subsidiaries had approximately $1.1$2.7 billion of cash and cash equivalents. Committed credit arrangements with banks at September 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 | | 2020 | | 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 (a) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1,000 |
| | $ | 1,250 |
| | $ | 2,250 |
| | $ | 2,250 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | — |
| $ | — |
| $ | 1,000 |
| $ | 1,250 |
| | $ | 2,250 |
| | $ | 2,250 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Alabama Power | | — |
| | 40 |
| | — |
| | 500 |
| | 800 |
| | 1,340 |
| | 1,339 |
| | — |
| | — |
| | — |
| | 40 |
| — |
| 35 |
| 500 |
| 800 |
| | 1,335 |
| | 1,335 |
| | — |
| | — |
| | — |
| | 35 |
|
| Georgia Power | | — |
| | — |
| | — |
| | — |
| | 1,750 |
| | 1,750 |
| | 1,732 |
| | — |
| | — |
| | — |
| | — |
| — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,732 |
| | — |
| | — |
| | — |
| | — |
|
| Gulf Power | | 20 |
| | 225 |
| | 30 |
| | — |
| | — |
| | 275 |
| | 275 |
| | 50 |
| | — |
| | 50 |
| | 195 |
| 50 |
| 65 |
| 165 |
| — |
| | 280 |
| | 280 |
| | 45 |
| | — |
| | 45 |
| | 70 |
|
Mississippi Power (b) | | 15 |
| | 220 |
| | — |
| | — |
| | — |
| | 235 |
| | 210 |
| | 30 |
| | 30 |
| | 60 |
| | 175 |
| 100 |
| 75 |
| — |
| — |
| | 175 |
| | 150 |
| | — |
| | 15 |
| | 15 |
| | 160 |
|
Southern Power (c) | | — |
| | — |
| | — |
| | — |
| | 600 |
| | 600 |
| | 567 |
| | — |
| | — |
| | — |
| | — |
| |
Southern Power Company(b) | | — |
| — |
| — |
| 600 |
| | 600 |
| | 532 |
| | — |
| | — |
| | — |
| | — |
|
Southern Company Gas(c) | | — |
| 75 |
| 1,925 |
| — |
| | 2,000 |
| | 1,947 |
| | — |
| | — |
| | — |
| | — |
|
| Other | | — |
| | 70 |
| | — |
| | — |
| | — |
| | 70 |
| | 70 |
| | — |
| | — |
| | — |
| | 70 |
| — |
| 55 |
| — |
| — |
| | 55 |
| | 55 |
| | 20 |
| | — |
| | 20 |
| | 35 |
|
| Total | | $ | 35 |
| | $ | 555 |
| | $ | 30 |
| | $ | 1,500 |
| | $ | 4,400 |
| | $ | 6,520 |
| | $ | 6,443 |
| | $ | 80 |
| | $ | 30 |
| | $ | 110 |
| | $ | 480 |
| |
| Southern Company Consolidated | | $ | 150 |
| $ | 305 |
| $ | 3,590 |
| $ | 4,400 |
| | $ | 8,445 |
| | $ | 8,281 |
| | $ | 65 |
| | $ | 15 |
| | $ | 80 |
| | $ | 300 |
|
| |
| (a) | ExcludesRepresents the $8.1 billion Bridge Agreement entered into in September 2015 that will be funded only to the extent necessary to provide financing for the Merger as discussed herein.Southern Company parent entity. |
| |
| (b) | Subsequent to September 30, 2015, a $15 million bankExcludes credit arrangement expired pursuant to its terms. |
| |
(c) | Excludes the Tranquillityagreements (Project Credit AgreementFacilities) assumed with the acquisition of Tranquillity on August 28, 2015,certain solar facilities, which isare non-recourse to Southern Power Company, the proceeds of which are being used to finance project costs related to Tranquillity'ssuch solar facilityfacilities currently under construction in California.construction. See Note (I) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding Tranquillity.information. |
| |
| (c) | Southern Company Gas guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.3 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $700 million restricted for working capital needs of Nicor Gas. |
See Note 6 to the financial statements of Southern Company under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank"Bank Credit Arrangements"Arrangements" herein for additional information.
As reflected inOn May 24, 2016, the table above, in August 2015, Southern Company, Alabama Power, Georgia Power, and Southern Power Company each amended and restated their multi-year credit arrangements, which, among other things, extended the maturity dates from 2018 to 2020. Southern Company and Southern Power Company increased their borrowing ability under these arrangements to $1.25$8.1 billion from $1.0 billion and to $600 million from $500 million, respectively. Georgia Power increased its borrowing ability by $150 million under its facility maturing in 2020 and terminated its aggregate $150 million facilities maturing in 2016. In September 2015, Southern Company entered into an additional multi-year credit arrangement for $1.0 billion with a maturity date of 2018. Also in September 2015, Alabama Power entered into a new $500 million three-year credit arrangement which replaced a majority of Alabama Power's bi-lateral credit arrangements.
A portion of the unused credit with banks is allocatedBridge 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 September 30, 2015extent necessary, was approximately $1.8 billion. In addition, at September 30, 2015, the traditional operating companies had approximately $354 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months, of which $120 million were remarketed subsequent to September 30, 2015.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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
indebtedness of the individual company. Such cross default provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness or guarantee obligations over a specified threshold. Such cross acceleration provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness, the payment of which was then accelerated. Southern Company, the traditional electric operating companies, Southern Power Company, and Southern PowerCompany Gas 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.
Southern Company intends to initially fund the cash consideration for the Merger using approximately $7.0 billion of debt and $1.0 billion of equity. Southern Company expects to issue approximately $2.0 billion of additional equity through 2019 to offset aA portion of the debt issued to fund the cash consideration for the Merger. In addition, Southern Company entered into the $8.1 billion Bridge Agreement on September 30, 2015unused credit with banks is allocated to provide financing forliquidity support to the Merger in the event long-term financing is not available.
traditional electric operating companies' pollution control revenue bonds and commercial paper programs. The Bridge Agreement provides for total loan commitments in an aggregate amount of $8.1 billion to fund the payment of the cash consideration payable under the Merger Agreement and other cash payments required in connection with the consummation of the Merger, the Bridge Agreement and the borrowings thereunder, the other financing transactions related to the Merger, and the payment of fees and expenses incurred in connection with the foregoing. If funded, the loan under the Bridge Agreement will mature and be payable in full on the date that is 364 days after the funding of the commitments under the Bridge Agreement (Closing Date).
In connection with the Bridge Agreement, Southern Company will pay a ticking fee for the benefit of the lenders thereto, accruing from November 21, 2015, in an amount equal to 0.125% per annum of the aggregate commitments under the Bridge Agreement, which fee will accrue through the earlier of (i) the date of termination of the commitments and (ii) the Closing Date. If the loan is funded, Southern Company will pay (i) interest at a fluctuatingvariable rate per annum equal to, at its election, the base rate or euro-dollar rate plus, in each case, an applicable margin, calculatedpollution control revenue bonds outstanding requiring liquidity support as provided in the Bridge Agreement and (ii) on each of the dates set forth below, a duration fee equal to the applicable percentage set forth below of the aggregate principal amount of the loan outstanding on such date:
|
| |
Date | Duration Fee |
90 days after the Closing Date | 0.50% |
180 days after the Closing Date | 0.75% |
270 days after the Closing Date | 1.00% |
Additionally, under the terms of the Bridge Agreement, Southern Company is required to pay certain customary fees to the lenders as set forth in related letters. As of September 30, 2015, Southern Company had no outstanding loans under the Bridge Agreement.
Southern Company,2016 was approximately $1.9 billion. In addition, at September 30, 2016, the traditional electric operating companies and Southern Power make short-term borrowings primarily through commercial paper programshad approximately $358 million of fixed rate pollution control revenue bonds outstanding that havewere required to be reoffered within the liquidity support of the committed bank credit arrangements described above, excluding the Bridge Agreement. Southern Company, the traditional operating companies, and Southern Power may also borrow through various other arrangements with banks. Commercial paper and short-term bank term loans are included in notes payable in the balance sheets.next 12 months.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas may also borrow through various other arrangements with banks. Short-term borrowings are included in notes payable in the balance sheets.
Details of short-term borrowings were as follows:
| | | | | Short-term Debt at September 30, 2015 | | Short-term Debt During the Period(*) | | Short-term Debt at September 30, 2016 | | Short-term Debt During the Period(*) |
| | | Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding | | 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 | | $ | 990 |
| | 0.5 | % | | $ | 826 |
| | 0.4 | % | | $ | 1,406 |
| | $ | 717 |
| | 0.7 | % | | $ | 756 |
| | 0.7 | % | | $ | 1,499 |
|
| Short-term bank debt | | 500 |
| | 1.4 | % | | 543 |
| | 1.1 | % | | 555 |
| | 125 |
| | 1.5 | % | | 125 |
| | 1.4 | % | | 127 |
|
| Total | | $ | 1,490 |
| | 0.8 | % | | $ | 1,369 |
| | 0.8 | % | | | | $ | 842 |
| | 0.8 | % | | $ | 881 |
| | 0.8 | % | | |
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2015.2016. |
In addition to the short-term borrowings in the table above, the Project Credit Facilities had total amounts outstanding as of September 30, 2016 of $828 million at a weighted average interest rate of 2.05%. For the three-month period ended September 30, 2016, these credit agreements had a maximum amount outstanding of $828 million and an average amount outstanding of $805 million at a weighted average interest rate of 2.02%.
Furthermore, in connection with the acquisition of a solar facility on July 1, 2016, a subsidiary of Southern Power assumed a $217 million construction loan, which was fully repaid prior to September 30, 2016. For the three-month period ended September 30, 2016, this credit agreement had a maximum amount outstanding of $217 million and an average amount outstanding of $137 million at a weighted average interest rate of 2.21%.
Southern 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 September 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/or Baa2 or below. These contracts are for physical electricity and natural gas purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, interest rate management, and construction of new generation at Plant Vogtle Units 3 and 4.
The maximum potential collateral requirements under these contracts at September 30, 20152016 were as follows:
| | | Credit Ratings | Maximum Potential Collateral Requirements | Maximum Potential
Collateral
Requirements |
| | (in millions) | (in millions) |
| At BBB and/or Baa2 | $ | 12 |
| $ | 31 |
|
| At BBB- and/or Baa3 | 504 |
| $ | 665 |
|
| Below BBB- and/or Baa3 | 2,348 |
| $ | 2,570 |
|
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Company and its subsidiaries to access capital markets, and would be likely to impact the cost at which they do so.
On 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.
On August 14, 2015,May 13, 2016, Moody's downgraded the senior unsecured debt rating of Mississippi Power to Baa2 from Baa1. Moody's maintained the negative ratings outlook for Mississippi Power.
On August 17, 2015, S&P downgraded the consolidated long-term issuerdebt rating of Southern Company (including Alabama Power, Georgia Power,to Baa2 from Baa1 and Gulf Power)revised the ratings outlook from negative to stable.
On July 11, 2016, S&P raised Southern Company Gas' and Nicor Gas' corporate and senior unsecured long-term debt ratings from BBB+ to A- and revised their ratings outlooks from A. Also onpositive to negative.
Financing Activities
On May 11, 2016, Southern Company issued 18.3 million shares of common stock in an underwritten offering for an aggregate purchase price of approximately $889 million. Of the 18.3 million shares, approximately 2.6 million were issued from treasury and the remainder were newly issued shares. The proceeds were used to fund a portion of the consideration for the Merger and for other general corporate purposes.
On August 17, 2015, S&P downgraded19, 2016, Southern Company issued 32.5 million shares of common stock in an underwritten offering for an aggregate purchase price of approximately $1.6 billion. The proceeds were used to fund a portion of the issuer ratingpurchase price for the SNG investment and related transaction costs and for other general corporate purposes.
In addition, during the first nine months of Mississippi Power to BBB+ from A. S&P revised its credit rating outlook2016, Southern Company issued approximately 17.5 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $782 million.
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the traditional operating companies to stable from negative. Separately, on August 24, 2015, S&P revised its credit rating outlook for Southern Company and the traditional operating companies from stable to negative following the announcementfirst nine months of the Merger.2016:
|
| | | | | | | | | | | | | | | | | | | |
| Company | Senior Note Issuances | | Senior Note Maturities and Redemptions | | Revenue Bond Maturities, Redemptions, and Repurchases | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(a) |
| | (in millions) |
Southern Company(b) | $ | 8,500 |
| | $ | 500 |
| | $ | — |
| | $ | 800 |
| | $ | — |
|
| Alabama Power | 400 |
| | 200 |
| | — |
| | 45 |
| | — |
|
| Georgia Power | 650 |
| | 700 |
| | 4 |
| | 300 |
| | 5 |
|
| Gulf Power | — |
| | 125 |
| | — |
| | 2 |
| | — |
|
| Mississippi Power | — |
| | — |
| | — |
| | 1,100 |
| | 652 |
|
| Southern Power | 1,531 |
| | — |
| | — |
| | 63 |
| | 84 |
|
Southern Company Gas(c) | 900 |
| | 300 |
| | — |
| | — |
| | — |
|
| Other | — |
| | — |
| | — |
| | — |
| | 60 |
|
Elimination(d) | — |
| | — |
| | — |
| | (200 | ) | | (225 | ) |
| Southern Company Consolidated | $ | 11,981 |
| | $ | 1,825 |
| | $ | 4 |
| | $ | 2,110 |
| | $ | 576 |
|
| |
| (a) | Includes reductions in capital lease obligations resulting from cash payments under capital leases. |
| |
| (b) | Represents the Southern Company parent entity. |
| |
| (c) | Reflects only long-term debt financing activities occurring subsequent to completion of the Merger. The senior notes were issued by Southern Company Gas Capital and guaranteed by Southern Company Gas. |
| |
| (d) | Intercompany loans from Southern Company to Mississippi Power eliminated in Southern Company's Consolidated Financial Statements. |
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Also following the announcement of the Merger, on August 24, 2015, Moody's affirmed the rating ofIn February 2016, Southern Company and revised its credit rating outlook from stableentered into $700 million notional amount of forward-starting interest rate swaps to negative. On the same date, Fitch placed the ratings of Southern Company on ratings watch negative.hedge exposure to interest rate changes related to anticipated debt issuances. These interest rate swaps were settled in May 2016.
Financing Activities
During the first nine months of 2015,In May 2016, Southern Company issued approximately 3.7 million sharesthe following series of common stock primarily through the employee equity compensation plansenior 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 received
$2.0 billion of 4.40% Senior Notes due July 1, 2046.
The net proceeds of approximately $136 million. During the first nine months of 2015, all sales under the Southern Investment Plan and the employee savings plan were funded with shares acquired on the open market by independent plan administrators. In October 2015, Southern Company began issuing shares of common stock through the Southern Investment Plan and the employee savings plan.
On March 2, 2015, Southern Company announced a programused to repurchase up to 20 million shares of Southern Company common stock to offset all orfund 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 were repurchased through September 30, 2015 at a total cost of approximately $115 million. There were no repurchases during the three months ended September 30, 2015 and no further repurchases under the program are anticipated.
The following table outlines the long-term debt financing activities for Southern Company and its subsidiariesconsideration for the first nine months of 2015:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Company | Senior Note Issuances | | Senior Note Redemptions | | Revenue Bond Issuances and Reofferings of Purchased Bonds(a) | | Revenue Bond Maturities and Repurchases | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(b) |
| | (in millions) |
| Southern Company | $ | 600 |
| | $ | 400 |
| | $ | — |
| | $ | — |
| | $ | 400 |
| | $ | — |
|
| Alabama Power | 975 |
| | 250 |
| | 80 |
| | 134 |
| | — |
| | — |
|
| Georgia Power | — |
| | 525 |
| | 274 |
| | 268 |
| | 600 |
| | 20 |
|
| Gulf Power | — |
| | 60 |
| | 13 |
| | 13 |
| | — |
| | — |
|
| Mississippi Power | — |
| | — |
| | — |
| | — |
| | — |
| | 352 |
|
| Southern Power | 650 |
| | 525 |
| | — |
| | — |
| | 400 |
| | 3 |
|
| Other | — |
| | — |
| | — |
| | — |
| | — |
| | 13 |
|
| Total | $ | 2,225 |
| | $ | 1,760 |
| | $ | 367 |
| | $ | 415 |
| | $ | 1,400 |
| | $ | 388 |
|
(a) Includes a reoffering by Alabama Power of $80 million aggregate principal amount of revenue bonds purchasedMerger and held since April 2015; reofferings by Georgia Power of $104.6 million and $65 million aggregate principal amount of revenue bonds purchased and held since 2013 and April 2015, respectively; and a reoffering by Gulf Power of $13 million aggregate principal amount of revenue bonds purchased and held in July 2015. Also includes repurchases and reofferings by Georgia Power of $94.6 million and $10 million aggregate principal amount of revenue bonds in August 2015 in connection with optional tenders.
| |
(b) | Includes reductions in capital lease obligations resulting from cash payments under capital leases. |
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.
In September 2015,2016, Southern Company entered into a $400 million aggregate principal amount 18-month floating rate bank loan bearing interest based on one-month LIBOR. The proceeds were used for working capital and other general corporate purposes.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Also in September 2015, Southern Company repaid at maturity $400issued $800 million aggregate principal amount of its Series 2010A 2.375% Senior Notes due September 15, 2015.
Subsequent to September 30, 2015, Southern Company issued $1.0 billion aggregate principal amount of Series 2015A 6.25%2016A 5.25% Junior Subordinated Notes due October 15, 2075.1, 2076. The proceeds were used to pay a portionrepay short-term indebtedness that was incurred to repay at maturity $500 million aggregate principal amount of Southern Company's outstanding short-term indebtednessSeries 2011A 1.95% Senior Notes due September 1, 2016 and for other general corporate purposes.
Except as described herein, Southern Company's subsidiaries used the proceeds of the debt issuances shown in the table above for their redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including their continuous construction programs and, for Southern Power, its growth strategy.
A portionOn March 8, 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicate of financial institutions for an aggregate amount of $1.2 billion. Mississippi Power borrowed $900 million on March 8, 2016 under the term loan agreement and the remaining $300 million on October 7, 2016. Mississippi Power used the initial proceeds to repay $900 million in maturing bank loans on March 8, 2016 and the remaining $300 million to repay at maturity Mississippi Power's Series 2011A 2.35% Senior Notes due October 15, 2016. The term loan pursuant to this agreement matures on April 1, 2018 and bears interest based on one-month LIBOR.
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 and the proceeds of Alabama Power's senior note issuances were used in May 2015 to redeem 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.other general corporate purposes.
Georgia Power's "Other Long-Term Debt Issuances" reflected in the table above include borrowings in June 2016 under the FFB Credit Facility in an aggregate principal amount of $600$300 million in June 2015. Theat a 2.571% interest rate applicable to the $600 million principal amount is 3.283% for an interest period that extends tothrough 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 nine months ended September 30, 2016, Southern Power's subsidiaries incurred an additional $691 million of short-term borrowings pursuant to the Project Credit Facilities at a weighted average interest rate swaps related to this borrowing for a payment of approximately $6 million, which will be amortized to interest expense over 10 years.
In March 2015, Georgia Power entered into a $250 million aggregate principal amount three-month floating rate bank loan bearing interest based on one-month LIBOR. The loan was repaid at maturity.
In April 2015, Mississippi Power entered into two short-term floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. A portion of the proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016.
In June 2015, Gulf Power entered into a $40 million aggregate principal amount three-month floating rate bank loan bearing interest based on one-month LIBOR. The loan was repaid at maturity.
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 interest2.05%. Furthermore, in connection with the terminationacquisition of the APA. On June 3, 2015,a solar facility, a subsidiary of Southern Company, pursuant to its guarantee obligation, returned approximately $301Power assumed a $217 million to SMEPA. Subsequently, Mississippi Power issued an 18-month floating rate promissory note to Southern Company in an aggregate principal amount of approximately $301 million bearing interest based on one-month LIBOR. 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.
Subsequentconstruction loan, which was fully repaid prior to September 30, 2015, Alabama2016. In addition, on October 14, 2016, Southern Power repaid at maturity $400$246 million of Project Credit Facility debt.
In June 2016, Southern Power issued €600 million aggregate principal amount of its Series 2012B 0.550%2016A 1.00% Senior Notes due October 15, 2015.
Also subsequent to September 30, 2015, Gulf Power entered into forward-starting interest rate swaps to hedge exposure to interest rate changes related to an anticipated debt issuance. The notionalJune 20, 2022 and €500 million aggregate principal amount of Series 2016B 1.85% Senior Notes due June 20, 2026. The proceeds are being allocated to renewable energy generation projects. Southern Power's obligations under its euro-denominated fixed-rate notes were effectively converted to fixed-rate U.S. dollars at issuance through cross-currency swaps, removing foreign currency exchange risk associated with the swaps totaled $80 million.interest and principal payments. See
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Note (H) to the Condensed Financial Statements under "Foreign Currency Derivatives" herein for additional information.
In September 2016, Southern Power repaid $80 million of an outstanding $400 million floating rate bank loan and extended the maturity date of the remaining $320 million from September 2016 to September 2018. In addition, Southern Power entered into a $60 million aggregate principal amount floating rate bank loan bearing interest based on one-month LIBOR due September 2017. The proceeds were used to repay existing indebtedness and for other general corporate purposes.
In September 2016, Southern Company Gas Capital issued $350 million aggregate principal amount of 2.45% Senior Notes due October 1, 2023 and $550 million aggregate principal amount of 3.95% Senior Notes due October 1, 2046, both of which are guaranteed by Southern Company Gas. The proceeds were used to repay a $360 million promissory note issued to Southern Company for the purpose of funding a portion of the purchase price for Southern Company Gas' 50% equity interest in SNG, to fund Southern Company Gas' purchase of Piedmont Natural Gas Company, Inc.'s (Piedmont) interest in SouthStar, to make a voluntary pension contribution, to repay at maturity $120 million aggregate principal amount of Series A Floating Rate Senior Notes due October 27, 2016, and for general corporate purposes. See Note (I) to the Condensed Financial Statements under "Southern Company– Investment in Southern Natural Gas" and " – Acquisition of Remaining Interest in SouthStar" herein for additional information regarding Southern Company Gas' investment in SNG and purchase of Piedmont's interest in SouthStar, respectively.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company and its subsidiaries plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
PART I
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
DuringOther than the changes resulting from the Merger discussed below, during the nine months ended September 30, 2015,2016, there were no material changes to each registrant'sSouthern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, or Southern Power'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 (C) and Note (H) to the Condensed Financial Statements herein for information relating to derivative instruments.
As a result of closing the Merger, the Southern Company system's exposure to market risks includes Southern Company Gas. Southern Company Gas is exposed to market risks, primarily commodity price risk, interest rate risk, and weather risk. Due to various cost recovery mechanisms, the natural gas distribution utilities of Southern Company Gas that sell natural gas directly to their end-use customers have limited exposure to market volatility of natural gas prices. Certain natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs implemented per the guidelines of their respective state regulatory agencies to hedge the impact of market fluctuations in natural gas prices for customers. For the weather risk associated with Nicor Gas, Southern Company Gas has a corporate weather hedging program that utilizes weather derivatives to reduce the risk of lower operating margins potentially resulting from significantly warmer-than-normal weather. In addition, certain non-regulated operations routinely utilize various types of derivative instruments to economically hedge certain commodity price and weather risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and over-the-counter energy contracts, such as forward contracts, futures contracts, options contracts, and swap agreements. Some of these economic hedge activities may not qualify, or are not designated, for hedge accounting treatment. If there is a significant change in the underlying market prices or pricing assumptions Southern Company uses to price the derivative assets or liabilities, such changes may have a significant impact on Southern Company's financial position, results of operations, and cash flows.
Item 4. Controls and Procedures.
| |
| (a) | Evaluation of disclosure controls and procedures. |
As of the end of the period covered by this quarterly report,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. |
ThereOther than the changes resulting from the Merger discussed below, 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'sPower'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 third 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'sPower'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 conducting control reviews pursuant to Section 404 of the Sarbanes-Oxley
Act of 2002. See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information regarding the Merger.
ALABAMA POWER COMPANY
ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
| | | | For the Three Months
Ended September 30, | | For the Nine Months
Ended September 30, | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | | | | | | | | |
| Retail revenues | $ | 1,558 |
| | $ | 1,512 |
| | $ | 4,151 |
| | $ | 4,058 |
| $ | 1,629 |
| | $ | 1,558 |
| | $ | 4,139 |
| | $ | 4,151 |
|
| Wholesale revenues, non-affiliates | 65 |
| | 72 |
| | 188 |
| | 222 |
| 82 |
| | 65 |
| | 211 |
| | 188 |
|
| Wholesale revenues, affiliates | 20 |
| | 31 |
| | 55 |
| | 168 |
| 18 |
| | 20 |
| | 49 |
| | 55 |
|
| Other revenues | 52 |
| | 54 |
| | 157 |
| | 166 |
| 56 |
| | 52 |
| | 162 |
| | 157 |
|
| Total operating revenues | 1,695 |
| | 1,669 |
| | 4,551 |
| | 4,614 |
| 1,785 |
| | 1,695 |
| | 4,561 |
| | 4,551 |
|
| Operating Expenses: | | | | | | | | | | | | | | |
| Fuel | 408 |
| | 442 |
| | 1,061 |
| | 1,288 |
| 410 |
| | 408 |
| | 973 |
| | 1,061 |
|
| Purchased power, non-affiliates | 56 |
| | 57 |
| | 142 |
| | 153 |
| 63 |
| | 56 |
| | 139 |
| | 142 |
|
| Purchased power, affiliates | 51 |
| | 54 |
| | 153 |
| | 140 |
| 41 |
| | 51 |
| | 129 |
| | 153 |
|
| Other operations and maintenance | 371 |
| | 334 |
| | 1,140 |
| | 989 |
| 348 |
| | 371 |
| | 1,097 |
| | 1,140 |
|
| Depreciation and amortization | 163 |
| | 174 |
| | 481 |
| | 521 |
| 177 |
| | 163 |
| | 524 |
| | 481 |
|
| Taxes other than income taxes | 91 |
| | 88 |
| | 275 |
| | 265 |
| 96 |
| | 91 |
| | 286 |
| | 275 |
|
| Total operating expenses | 1,140 |
| | 1,149 |
| | 3,252 |
| | 3,356 |
| 1,135 |
| | 1,140 |
| | 3,148 |
| | 3,252 |
|
| Operating Income | 555 |
| | 520 |
| | 1,299 |
| | 1,258 |
| 650 |
| | 555 |
| | 1,413 |
| | 1,299 |
|
| Other Income and (Expense): | | | | | | | | | | | | | | |
| Allowance for equity funds used during construction | 14 |
| | 15 |
| | 43 |
| | 36 |
| 7 |
| | 14 |
| | 23 |
| | 43 |
|
| Interest expense, net of amounts capitalized | (71 | ) | | (63 | ) | | (205 | ) | | (188 | ) | (77 | ) | | (71 | ) | | (224 | ) | | (205 | ) |
| Other income (expense), net | (7 | ) | | 3 |
| | (24 | ) | | (5 | ) | (5 | ) | | (7 | ) | | (16 | ) | | (24 | ) |
| Total other income and (expense) | (64 | ) | | (45 | ) | | (186 | ) | | (157 | ) | (75 | ) | | (64 | ) | | (217 | ) | | (186 | ) |
| Earnings Before Income Taxes | 491 |
| | 475 |
| | 1,113 |
| | 1,101 |
| 575 |
| | 491 |
| | 1,196 |
| | 1,113 |
|
| Income taxes | 192 |
| | 183 |
| | 427 |
| | 429 |
| 221 |
| | 192 |
| | 466 |
| | 427 |
|
| Net Income | 299 |
| | 292 |
| | 686 |
| | 672 |
| 354 |
| | 299 |
| | 730 |
| | 686 |
|
| Dividends on Preferred and Preference Stock | 4 |
| | 10 |
| | 21 |
| | 30 |
| 4 |
| | 4 |
| | 13 |
| | 21 |
|
| Net Income After Dividends on Preferred and Preference Stock | $ | 295 |
| | $ | 282 |
| | $ | 665 |
| | $ | 642 |
| $ | 350 |
| | $ | 295 |
| | $ | 717 |
| | $ | 665 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months
Ended September 30, | | For the Nine Months
Ended September 30, |
| | 2015 | | 2014 | | 2015 | | 2014 |
| | (in millions) | | (in millions) |
| Net Income | $ | 299 |
| | $ | 292 |
| | $ | 686 |
| | $ | 672 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
| Changes in fair value, net of tax of $(4), $-, $(4) and $-, respectively | (6 | ) | | — |
| | (6 | ) | | — |
|
Reclassification adjustment for amounts included in net income,
net of tax of $-, $1, $1 and $1, respectively | — |
| | — |
| | 1 |
| | 1 |
|
| Total other comprehensive income (loss) | (6 | ) | | — |
| | (5 | ) | | 1 |
|
| Comprehensive Income | $ | 293 |
| | $ | 292 |
| | $ | 681 |
| | $ | 673 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
|
| | | | | | | |
| | For the Nine Months
Ended September 30, |
| | 2015 | | 2014 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 686 |
| | $ | 672 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 585 |
| | 631 |
|
| Deferred income taxes | 85 |
| | 68 |
|
| Allowance for equity funds used during construction | (43 | ) | | (36 | ) |
| Other, net | 23 |
| | (33 | ) |
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (160 | ) | | (139 | ) |
| -Fossil fuel stock | 69 |
| | 106 |
|
| -Materials and supplies | 18 |
| | (8 | ) |
| -Other current assets | (28 | ) | | (32 | ) |
| -Accounts payable | (106 | ) | | (64 | ) |
| -Accrued taxes | 371 |
| | 210 |
|
| -Accrued compensation | (32 | ) | | 18 |
|
| -Retail fuel cost over recovery | 81 |
| | 2 |
|
| -Other current liabilities | 30 |
| | 3 |
|
| Net cash provided from operating activities | 1,579 |
| | 1,398 |
|
| Investing Activities: | | | |
| Property additions | (938 | ) | | (966 | ) |
| Nuclear decommissioning trust fund purchases | (349 | ) | | (178 | ) |
| Nuclear decommissioning trust fund sales | 349 |
| | 178 |
|
| Cost of removal, net of salvage | (41 | ) | | (50 | ) |
| Change in construction payables | (48 | ) | | 39 |
|
| Other investing activities | (22 | ) | | (26 | ) |
| Net cash used for investing activities | (1,049 | ) | | (1,003 | ) |
| Financing Activities: | | | |
| Proceeds — | | | |
| Senior notes issuances | 975 |
| | 400 |
|
| Capital contributions from parent company | 13 |
| | 20 |
|
| 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 | (27 | ) | | (30 | ) |
| Payment of common stock dividends | (428 | ) | | (412 | ) |
| Other financing activities | (11 | ) | | (6 | ) |
| Net cash used for financing activities | (194 | ) | | (28 | ) |
| Net Change in Cash and Cash Equivalents | 336 |
| | 367 |
|
| Cash and Cash Equivalents at Beginning of Period | 273 |
| | 295 |
|
| Cash and Cash Equivalents at End of Period | $ | 609 |
| | $ | 662 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid during the period for — | | | |
| Interest (net of $15 and $13 capitalized for 2015 and 2014, respectively) | $ | 192 |
| | $ | 174 |
|
| Income taxes, net | 47 |
| | 227 |
|
| Noncash transactions — Accrued property additions at end of period | 88 |
| | 57 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At September 30,
2015 | | At December 31,
2014 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 609 |
| | $ | 273 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 460 |
| | 345 |
|
| Unbilled revenues | | 134 |
| | 138 |
|
| Under recovered regulatory clause revenues | | 67 |
| | 74 |
|
| Other accounts and notes receivable | | 34 |
| | 23 |
|
| Affiliated companies | | 43 |
| | 37 |
|
| Accumulated provision for uncollectible accounts | | (9 | ) | | (9 | ) |
| Fossil fuel stock, at average cost | | 199 |
| | 268 |
|
| Materials and supplies, at average cost | | 398 |
| | 406 |
|
| Vacation pay | | 65 |
| | 65 |
|
| Prepaid expenses | | 79 |
| | 244 |
|
| Other regulatory assets, current | | 118 |
| | 84 |
|
| Other current assets | | 9 |
| | 5 |
|
| Total current assets | | 2,206 |
| | 1,953 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 23,922 |
| | 23,080 |
|
| Less accumulated provision for depreciation | | 8,623 |
| | 8,522 |
|
| Plant in service, net of depreciation | | 15,299 |
| | 14,558 |
|
| Nuclear fuel, at amortized cost | | 325 |
| | 348 |
|
| Construction work in progress | | 1,117 |
| | 1,006 |
|
| Total property, plant, and equipment | | 16,741 |
| | 15,912 |
|
| Other Property and Investments: | | | | |
| Equity investments in unconsolidated subsidiaries | | 69 |
| | 66 |
|
| Nuclear decommissioning trusts, at fair value | | 712 |
| | 756 |
|
| Miscellaneous property and investments | | 91 |
| | 84 |
|
| Total other property and investments | | 872 |
| | 906 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 530 |
| | 525 |
|
| Deferred under recovered regulatory clause revenues | | 66 |
| | 31 |
|
| Other regulatory assets, deferred | | 1,055 |
| | 1,063 |
|
| Other deferred charges and assets | | 163 |
| | 162 |
|
| Total deferred charges and other assets | | 1,814 |
| | 1,781 |
|
| Total Assets | | $ | 21,633 |
| | $ | 20,552 |
|
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2016 | | 2015 | | 2016 | | 2015 |
| | (in millions) | | (in millions) |
| Net Income | $ | 354 |
| | $ | 299 |
| | $ | 730 |
| | $ | 686 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
Changes in fair value, net of tax of $-, $(4), $(1), and $(4),
respectively | — |
| | (6 | ) | | (2 | ) | | (6 | ) |
Reclassification adjustment for amounts included in net income,
net of tax of $1, $-, $2, and $1, respectively | 1 |
| | — |
| | 3 |
| | 1 |
|
| Total other comprehensive income (loss) | 1 |
| | (6 | ) | | 1 |
| | (5 | ) |
| Comprehensive Income | $ | 355 |
| | $ | 293 |
| | $ | 731 |
| | $ | 681 |
|
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 September 30,
2015 | | At December 31,
2014 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 600 |
| | $ | 454 |
|
| Accounts payable — | | | | |
| Affiliated | | 272 |
| | 248 |
|
| Other | | 272 |
| | 443 |
|
| Customer deposits | | 88 |
| | 87 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 105 |
| | 2 |
|
| Other accrued taxes | | 117 |
| | 37 |
|
| Accrued interest | | 67 |
| | 66 |
|
| Accrued vacation pay | | 54 |
| | 54 |
|
| Accrued compensation | | 103 |
| | 131 |
|
| Other current liabilities | | 118 |
| | 82 |
|
| Total current liabilities | | 1,796 |
| | 1,604 |
|
| Long-term Debt | | 6,699 |
| | 6,176 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 3,965 |
| | 3,874 |
|
| Deferred credits related to income taxes | | 70 |
| | 72 |
|
| Accumulated deferred investment tax credits | | 120 |
| | 125 |
|
| Employee benefit obligations | | 319 |
| | 326 |
|
| Asset retirement obligations | | 1,288 |
| | 829 |
|
| Other cost of removal obligations | | 742 |
| | 744 |
|
| Other regulatory liabilities, deferred | | 152 |
| | 239 |
|
| Deferred over recovered regulatory clause revenues | | 128 |
| | 47 |
|
| Other deferred credits and liabilities | | 73 |
| | 79 |
|
| Total deferred credits and other liabilities | | 6,857 |
| | 6,335 |
|
| Total Liabilities | | 15,352 |
| | 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 | | 2,328 |
| | 2,304 |
|
| Retained earnings | | 2,483 |
| | 2,255 |
|
| Accumulated other comprehensive loss | | (33 | ) | | (29 | ) |
| Total common stockholder's equity | | 6,000 |
| | 5,752 |
|
| Total Liabilities and Stockholder's Equity | | $ | 21,633 |
| | $ | 20,552 |
|
|
| | | | | | | |
| | For the Nine Months Ended September 30, |
| | 2016 | | 2015 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 730 |
| | $ | 686 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 634 |
| | 585 |
|
| Deferred income taxes | 267 |
| | 85 |
|
| Allowance for equity funds used during construction | (23 | ) | | (43 | ) |
| Other, net | (23 | ) | | 23 |
|
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (4 | ) | | (160 | ) |
| -Fossil fuel stock | 18 |
| | 69 |
|
| -Other current assets | (46 | ) | | (10 | ) |
| -Accounts payable | (113 | ) | | (106 | ) |
| -Accrued taxes | 203 |
| | 371 |
|
| -Retail fuel cost over recovery | (104 | ) | | 81 |
|
| -Other current liabilities | (4 | ) | | (2 | ) |
| Net cash provided from operating activities | 1,535 |
| | 1,579 |
|
| Investing Activities: | | | |
| Property additions | (947 | ) | | (938 | ) |
| Nuclear decommissioning trust fund purchases | (275 | ) | | (349 | ) |
| Nuclear decommissioning trust fund sales | 275 |
| | 349 |
|
| Cost of removal, net of salvage | (70 | ) | | (41 | ) |
| Change in construction payables | (37 | ) | | (48 | ) |
| Other investing activities | (28 | ) | | (22 | ) |
| Net cash used for investing activities | (1,082 | ) | | (1,049 | ) |
| Financing Activities: | | | |
| Proceeds — | | | |
| Senior notes | 400 |
| | 975 |
|
| Capital contributions from parent company | 253 |
| | 13 |
|
| Pollution control revenue bonds | — |
| | 80 |
|
| Other long-term debt | 45 |
| | — |
|
| Redemptions and repurchases — |
|
| |
|
| Preferred and preference stock | — |
| | (412 | ) |
| Pollution control revenue bonds | — |
| | (134 | ) |
| Senior notes | (200 | ) | | (250 | ) |
| Payment of common stock dividends | (574 | ) | | (428 | ) |
| Other financing activities | (15 | ) | | (38 | ) |
| Net cash used for financing activities | (91 | ) | | (194 | ) |
| Net Change in Cash and Cash Equivalents | 362 |
| | 336 |
|
| Cash and Cash Equivalents at Beginning of Period | 194 |
| | 273 |
|
| Cash and Cash Equivalents at End of Period | $ | 556 |
| | $ | 609 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
| Interest (net of $8 and $15 capitalized for 2016 and 2015, respectively) | $ | 215 |
| | $ | 192 |
|
| Income taxes, net | (70 | ) | | 47 |
|
| Noncash transactions — Accrued property additions at end of period | 84 |
| | 88 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At September 30, 2016 | | At December 31, 2015 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 556 |
| | $ | 194 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 440 |
| | 332 |
|
| Unbilled revenues | | 155 |
| | 119 |
|
| Under recovered regulatory clause revenues | | 52 |
| | 43 |
|
| Income taxes receivable, current | | — |
| | 142 |
|
| Other accounts and notes receivable | | 43 |
| | 20 |
|
| Affiliated | | 30 |
| | 50 |
|
| Accumulated provision for uncollectible accounts | | (9 | ) | | (10 | ) |
| Fossil fuel stock | | 220 |
| | 239 |
|
| Materials and supplies | | 420 |
| | 398 |
|
| Vacation pay | | 66 |
| | 66 |
|
| Prepaid expenses | | 56 |
| | 83 |
|
| Other regulatory assets, current | | 73 |
| | 115 |
|
| Other current assets | | 9 |
| | 10 |
|
| Total current assets | | 2,111 |
| | 1,801 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 25,800 |
| | 24,750 |
|
| Less accumulated provision for depreciation | | 9,018 |
| | 8,736 |
|
| Plant in service, net of depreciation | | 16,782 |
| | 16,014 |
|
| Nuclear fuel, at amortized cost | | 345 |
| | 363 |
|
| Construction work in progress | | 473 |
| | 801 |
|
| Total property, plant, and equipment | | 17,600 |
| | 17,178 |
|
| Other Property and Investments: | | | | |
| Equity investments in unconsolidated subsidiaries | | 67 |
| | 71 |
|
| Nuclear decommissioning trusts, at fair value | | 781 |
| | 737 |
|
| Miscellaneous property and investments | | 105 |
| | 96 |
|
| Total other property and investments | | 953 |
| | 904 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 518 |
| | 522 |
|
| Deferred under recovered regulatory clause revenues | | 87 |
| | 99 |
|
| Other regulatory assets, deferred | | 1,070 |
| | 1,114 |
|
| Other deferred charges and assets | | 118 |
| | 103 |
|
| Total deferred charges and other assets | | 1,793 |
| | 1,838 |
|
| Total Assets | | $ | 22,457 |
| | $ | 21,721 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholder's Equity | | At September 30, 2016 | | At December 31, 2015 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 236 |
| | $ | 200 |
|
| Accounts payable — | | | | |
| Affiliated | | 309 |
| | 278 |
|
| Other | | 233 |
| | 410 |
|
| Customer deposits | | 88 |
| | 88 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 73 |
| | — |
|
| Other accrued taxes | | 125 |
| | 38 |
|
| Accrued interest | | 69 |
| | 73 |
|
| Accrued vacation pay | | 55 |
| | 55 |
|
| Accrued compensation | | 97 |
| | 119 |
|
| Liabilities from risk management activities | | 10 |
| | 55 |
|
| Other regulatory liabilities, current | | 1 |
| | 240 |
|
| Other current liabilities | | 65 |
| | 39 |
|
| Total current liabilities | | 1,361 |
| | 1,595 |
|
| Long-term Debt | | 6,859 |
| | 6,654 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 4,505 |
| | 4,241 |
|
| Deferred credits related to income taxes | | 67 |
| | 70 |
|
| Accumulated deferred investment tax credits | | 112 |
| | 118 |
|
| Employee benefit obligations | | 366 |
| | 388 |
|
| Asset retirement obligations | | 1,501 |
| | 1,448 |
|
| Other cost of removal obligations | | 695 |
| | 722 |
|
| Other regulatory liabilities, deferred | | 95 |
| | 136 |
|
| Deferred over recovered regulatory clause revenues | | 157 |
| | — |
|
| Other deferred credits and liabilities | | 56 |
| | 76 |
|
| Total deferred credits and other liabilities | | 7,554 |
| | 7,199 |
|
| Total Liabilities | | 15,774 |
| | 15,448 |
|
| Redeemable Preferred Stock | | 85 |
| | 85 |
|
| Preference Stock | | 196 |
| | 196 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, par value $40 per share — | | | | |
| Authorized — 40,000,000 shares | | | | |
| Outstanding — 30,537,500 shares | | 1,222 |
| | 1,222 |
|
| Paid-in capital | | 2,607 |
| | 2,341 |
|
| Retained earnings | | 2,604 |
| | 2,461 |
|
| Accumulated other comprehensive loss | | (31 | ) | | (32 | ) |
| Total common stockholder's equity | | 6,402 |
| | 5,992 |
|
| Total Liabilities and Stockholder's Equity | | $ | 22,457 |
| | $ | 21,721 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRD QUARTER 20152016 vs. THIRD 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
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 |
| Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) |
| (change in millions) |
| (% change) |
| $13 | | 4.6 | | $23 | | 3.6 |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) |
| (% change) |
| (change in millions) |
| (% change) |
| $55 | | 18.6 | | $52 | | 7.8 |
Alabama Power's net income after dividends on preferred and preference stock for the third quarter 20152016 was $295$350 million compared to $282$295 million for the corresponding period in 2014.2015. The increase in net income was primarily related to an increase in ratesrevenue primarily due to warmer weather in the third quarter 2016 as compared to the corresponding period in 2015, an increase in retail revenues under rate stabilization and equalization (Rate RSE) effective January 1, 2015Rate CNP Compliance, and a decrease in depreciation,non-fuel operations and maintenance expenses. These increases to income were partially offset by increasesa decrease in other operating expenses. AFUDC and an increase in depreciation and amortization.
Alabama Power's net income after dividends on preferred and preference stock for year-to-date 20152016 was $665$717 million compared to $642$665 million for the corresponding period in 2014.2015. The increase was primarily related to an increase in retail revenues under Rate RSE, a decrease in depreciation,CNP Compliance and a decrease in dividends on preferred and preference stock, partially offset by an increasedecreases in non-fuel operations and maintenance expenses and dividends on preferred and preference stock for year-to-date 2016 compared to the corresponding period in 2015. These increases to income were partially offset by a decrease in AFUDC and increases in interest expense.expense and depreciation and amortization.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Retail Revenues
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $46 | | 3.0 | | $93 | | 2.3 |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $71 | | 4.6 | | $(12) | | (0.3) |
In the third quarter 2015,2016, retail revenues were $1.56$1.63 billion compared to $1.51$1.56 billion for the corresponding period in 2014.2015. For year-to-date 2015,2016, retail revenues were $4.15$4.14 billion compared to $4.06$4.15 billion for the corresponding period in 2014.2015.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of the changes in retail revenues were as follows:
| | | | | Third Quarter
2015 |
| Year-to-Date 2015 | Third Quarter 2016 |
| Year-to-Date 2016 |
| | | (in millions) |
| (% change) |
| (in millions) |
| (% change) | (in millions) |
| (% change) |
| (in millions) |
| (% change) |
| Retail – prior year | | $ | 1,512 |
| | | | $ | 4,058 |
| | | $ | 1,558 |
| | | | $ | 4,151 |
| | |
| Estimated change resulting from – | | | | | | | | | | | | | | | |
| Rates and pricing | | 69 |
| | 4.5 |
| | 172 |
| | 4.2 |
| 42 |
| | 2.7 |
| | 119 |
| | 2.9 |
|
| Sales growth (decline) | | (2 | ) | | (0.1 | ) | | 8 |
| | 0.2 |
| (14 | ) | | (0.9 | ) | | (15 | ) | | (0.4 | ) |
| Weather | | 2 |
| | 0.1 |
| | — |
| | — |
| 52 |
| | 3.4 |
| | 5 |
| | 0.1 |
|
| Fuel and other cost recovery | | (23 | ) | | (1.5 | ) | | (87 | ) | | (2.1 | ) | (9 | ) | | (0.6 | ) | | (121 | ) | | (2.9 | ) |
| Retail – current year | | $ | 1,558 |
| | 3.0 | % | | $ | 4,151 |
| | 2.3 | % | $ | 1,629 |
| | 4.6 | % | | $ | 4,139 |
| | (0.3 | )% |
Revenues associated with changes in rates and pricing increased in the third 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 growth remained relatively flatdeclined in the third quarter 2015 and increased slightly year-to-date 20152016 when compared to the corresponding periods in 2014. Weather-adjusted residential2015. Industrial KWH sales decreased 6.3% and commercial KWH energy sales both increased 0.2%5.1% for the third quarter and year-to-date 20152016, respectively, when compared to the corresponding periodperiods in 2014. Industrial KWH energy sales decreased 0.3% for year-to-date 2015 as a result of a decrease in demand resulting from changes in production levels primarily in the primary metals, sector.chemicals, pipelines, paper, and stone, clay, and glass sectors. A strong dollar, low oil prices, and weak global growtheconomic conditions have constrained growth in the industrial sector. Weather-adjusted residential KWH sales decreased 2.4% for the third quarter 2016 due to lower customer usage primarily resulting from an increase in efficiency improvements in residential appliances and lighting, partially offset by customer growth, and remained relatively flat year-to-date 2016. Weather-adjusted commercial KWH sales remained relatively flat for the third quarter and year-to-date 2016.
Revenues resulting from changes in weather increased in the third quarter 2016 due to warmer weather experienced in Alabama Power's service territory compared to the corresponding period in 2015. For the third quarter 2016, the resulting increases were 6.2% and 2.3% for residential and commercial sales revenue, respectively.
Fuel and other cost recovery revenues decreased in the third quarter 2015 and year-to-date 20152016 when compared to the corresponding periodsperiod in 20142015 primarily due to a decrease in the average cost of fuel.
Fuel and other cost recovery revenues decreased year-to-date 2016 when compared to the corresponding period in 2015 primarily due to a decrease in KWH generation and a 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
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(7) | | (9.7) | | $(34) | | (15.3) |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $17 | | 26.2 | | $23 | | 12.2 |
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Alabama Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact onaffect net income.
In the third quarter 2015,2016, wholesale revenues from sales to non-affiliates were $65$82 million compared to $72$65 million for the corresponding period in 2014.2015. The decreaseincrease was primarily due to a 5.7% decrease45.3% increase in KWH sales andas the result of a 4.3%new wholesale contract effective December 2015, partially offset by a 13.4% decrease in the price of energy.energy as a result of lower gas prices. For year-to-date 2015,2016, wholesale revenues from sales to non-affiliates were $188$211 million compared to $222$188 million for the corresponding period in 2014.2015. The decrease was primarily due to an 8.7% decrease in KWH sales and a 7.3% decrease in the price of energy.
In 2014, Alabama Power's fuel diversity led to increased sales to non-affiliates due to higher natural gas prices. In 2015, lower natural gas prices and decreased availability of hydro generation resulted in lower sales of Alabama Power's generation to non-affiliates.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale Revenues – Affiliates
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(11) | | (35.5) | | $(113) | | (67.3) |
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 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 third quarter 2015, wholesale revenues from sales to affiliates were $20 million compared to $31 million for the corresponding period in 2014. The decreaseincrease was primarily due to a 22.9%29.7% increase in KWH sales as a result of a new wholesale contract effective December 2015, partially offset by a 13.1% decrease in the price of energy andas a 13.8% decrease in KWH sales. For year-to-date 2015, wholesale revenues from sales to affiliates were $55 million compared to $168 million for the corresponding period in 2014. The decrease was primarily due to a 52.8% decrease in KWH sales and a 30.6% decrease in the priceresult of energy.
In 2014, Alabama Power's fuel diversity led to increased sales to affiliates due to higher naturallower gas prices. In 2015, lower natural gas prices and decreased availability of hydro generation resulted in lower sales of Alabama Power's generation to affiliates..
Fuel and Purchased Power Expenses
| | | | | Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015
vs.
Year-to-Date 2014 | | Third Quarter 2016
vs.
Third 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 | | $ | (34 | ) | | (7.7) | | $ | (227 | ) | | (17.6 | ) | | $ | 2 |
| | 0.5 | | $ | (88 | ) | | (8.3 | ) |
| Purchased power – non-affiliates | | (1 | ) | | (1.8) | | (11 | ) | | (7.2 | ) | | 7 |
| | 12.5 | | (3 | ) | | (2.1 | ) |
| Purchased power – affiliates | | (3 | ) | | (5.6) | | 13 |
| | 9.3 |
| | (10 | ) | | (19.6) | | (24 | ) | | (15.7 | ) |
| Total fuel and purchased power expenses | | $ | (38 | ) | | $ | (225 | ) | | | | $ | (1 | ) | | $ | (115 | ) | | |
In the third quarter 2015, totalFor year-to-date 2016, fuel and purchased power expenses were $515 million$1.24 billion compared to $553 million$1.36 billion for the corresponding period in 2014.2015. The decrease was primarily due to a $36$56 million decrease inrelated to the average cost of fuel, a $43 million decrease related to the average cost of purchased power, and a $9$35 million decrease related to the volume of KWHs purchased,generated. These decreases were partially offset by a $5$19 million increase in the average cost of purchased power and a $2 million increase related to the volume of KWHs generated.
For year-to-date 2015, fuel and purchased power expenses were $1.36 billion compared to $1.58 billion for the corresponding period in 2014. The decrease was primarily due to a $159 million decrease in the average cost of fuel, a $68 million decrease related to the volume of KWHs generated, and a $41 million decrease in the average cost of purchased power, partially offset by a $43 million increase related to the volume of KWHs purchased.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Alabama Power's energy cost recovery clause. Alabama Power, along with the Alabama PSC, continuously monitors the under/over recovered balance to determine whether adjustments to billing rates are required. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate ECR" in Item 8 of the Form 10-K for additional information.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of Alabama Power's generation and purchased power were as follows:
| | | | | Third Quarter 2015 | | Third Quarter
2014 | | Year-to-Date 2015 |
| Year-to-Date 2014 | Third Quarter 2016 | | Third Quarter 2015 | | Year-to-Date 2016 |
| Year-to-Date 2015 |
Total generation (billions of KWHs) | | 17 | | 17 | | 46 | | 50 | |
Total purchased power (billions of KWHs) | | 2 | | 2 | | 5 | | 5 | |
Total generation (in billions of KWHs) | | 18 | | 17 | | 46 | | 46 |
Total purchased power (in billions of KWHs) | | 2 | | 2 | | 6 | | 5 |
Sources of generation (percent) — | | |
| Coal | | 61 | | 59 | | 56 | | 55 | 59 | | 61 | | 51 | | 56 |
| Nuclear | | 23 | | 23 | | 23 | | 23 | 22 | | 23 | | 24 | | 23 |
| Gas | | 14 | | 16 | | 16 | | 16 | 18 | | 14 | | 19 | | 16 |
| Hydro | | 2 | | 2 | | 5 | | 6 | 1 | | 2 | | 6 | | 5 |
Cost of fuel, generated (cents per net KWH) — | | |
Cost of fuel, generated (in cents per net KWH) — | | |
| Coal | | 2.79 | | 3.04 | | 2.85 | | 3.24 | 2.73 | | 2.79 | | 2.80 | | 2.85 |
| Nuclear | | 0.81 | | 0.81 | | 0.81 | | 0.84 | 0.77 | | 0.81 | | 0.78 | | 0.81 |
| Gas | | 3.11 | | 3.54 | | 3.08 | | 3.83 | 2.85 | | 3.11 | | 2.62 | | 3.08 |
Average cost of fuel, generated (cents per net KWH)(a) | | 2.39 | | 2.61 | | 2.40 | | 2.75 | |
Average cost of purchased power (cents per net KWH)(b) | | 6.90 | | 6.56 | | 5.56 | | 6.32 | |
Average cost of fuel, generated (in cents per net KWH)(a) | | 2.32 | | 2.39 | | 2.25 | | 2.40 |
Average cost of purchased power (in cents per net KWH)(b) | | 5.70 | | 6.90 | | 4.81 | | 5.56 |
| |
(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 third quarter 2015,For year-to-date 2016, fuel expense was $408 million$0.97 billion compared to $442 million$1.06 billion for the corresponding period in 2014.2015. The decrease was primarily due to a 12.1%14.9% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, an 8.1%and a 10.4% decrease in the volume of KWHs generated by natural gas, and an 8.1% decrease in the average cost of coal, per KWH generated.
For year-to-date 2015, fuel expense was $1.06 billion compared to $1.29 billion for the corresponding period in 2014. The decrease was primarily due to a 19.7% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, an 11.8% decrease in the average cost of coal per KWH generated, and a 6.7% decrease in the volume of KWHs generated. The decrease was partially offset by a 20.0% decrease17.4% increase in the volume of KWHs generated by hydro facilities.natural gas.
Purchased Power – Non-Affiliates
For year-to-date 2015,In the third quarter 2016, purchased power expense from non-affiliates was $142$63 million compared to $153$56 million for the corresponding period in 2014.2015. The decreaseincrease was relatedprimarily due to a 19.5% decrease in the average cost per KWH purchased as a result of lower natural gas prices partially offset by a 15.3%47.8% increase in the amount of energy purchased due to the availability of lower cost generation as a result of lower natural gas prices.cost generation, partially offset by a 23.5% decrease in the average cost of purchased power per KHW due to a decrease in transmission capacity charges.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
For year-to-date 2015,In the third quarter 2016, purchased power expense from affiliates was $153$41 million compared to $140$51 million for the corresponding period in 2014.2015. The increasedecrease was relatedprimarily due to a 13.9% increase14.4% decrease in the average cost of purchased power per KWH as a result of lower capacity charges and a 4.4% decrease in the amount of energy purchased primarily due to the availability of Southern Company's lower cost generation sources andenergy.
For year-to-date 2016, purchased power expense from affiliates was $129 million compared to $153 million for the decreased availabilitycorresponding period in 2015. The decrease was primarily related to a 17.3% decrease in the average cost of purchased power per KWH as a result of lower natural gas prices.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
of hydro generation. The increase was partially offset by a 3.6% decrease in the average cost per KWH purchased due to 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 or other contractual agreements, as approved by the FERC.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $37 | | 11.1 | | $151 | | 15.3 |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(23) | | (6.2) | | $(43) | | (3.8) |
In the third quarter 2015,2016, other operations and maintenance expenses were $371$348 million compared to $334$371 million for the corresponding period in 2014.2015. The increasedecrease was primarily due to an increasea net decrease of $18$8 million in employee benefit costscompensation and benefits, including pension costs. In addition, the implementation of an accounting order in 2014 allowed the deferral of non-nuclearscheduled other power generation outage costs. Alabama Power deferred approximately $16 million of non-nuclear outage expenditures in the third quarter 2014. Nuclear generation costs increased $9 million primarily due to outage amortization costs and labor costs.uncollectible customer account expenses decreased $8 million and $3 million, respectively.
For year-to-date 2015,2016, other operations and maintenance expenses were $1.14$1.10 billion compared to $989 million$1.14 billion for the corresponding period in 2014. Alabama Power deferred approximately $57 million of non-nuclear outage expenditures in the first nine months of 2014. In addition, employee benefit costs including pension costs increased $49 million and steam generation costs increased $27 million2015. The decrease was primarily due to labor costs, maintenance costs,a net decrease of $22 million in employee compensation and benefits, including pension costs. In addition, scheduled steam and other general operating expenses.power generation outage costs decreased $18 million.
See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Non-Nuclear Outage Accounting Order" and "– 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
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(11) | | (6.3) | | $(40) | | (7.7) |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $14 | | 8.6 | | $43 | | 8.9 |
In the third quarter 2015,2016, depreciation and amortization was $163$177 million compared to $174$163 million for the corresponding period in 2014.2015. For year-to-date 2015,2016, depreciation and amortization was $481$524 million compared to $521$481 million for the corresponding period in 2014.2015. These decreasesincreases were primarily due to a decreasethe result of an increase in depreciation ratesof compliance related steam equipment. See Note 3 to environmental, steam generation, transmission, and distribution assets effective January 1, 2015, as authorized by the FERC, partially offset by increasesfinancial statements of Alabama Power under "Retail Regulatory Matters – Rate CNP" in plant in service.Item 8 of the Form 10-K for additional information.
Interest Expense, Net of Amounts CapitalizedTaxes Other Than Income Taxes
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $8 | | 12.7 | | $17 | | 9.0 |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $5 | | 5.5 | | $11 | | 4.0 |
In the third quarter 2015, interest expense, net of amounts capitalized was $712016, taxes other than income taxes were $96 million compared to $63$91 million for the corresponding period in 2014.2015. For year-to-date 2015, interest expense, net of amounts capitalized was $2052016, taxes other than income taxes were $286 million compared to $188$275 million for the corresponding period in 2014.2015. These increases were primarily due to new debt issuances, a portionincreases in state and municipal utility license tax bases and increases in ad valorem taxes primarily due to an increase in assessed value of which were used to redeem long-term debt, preferred stock, and preference stock.property.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Allowance for Equity Funds Used During Construction
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(7) | | (50.0) | | $(20) | | (46.5) |
In the third quarter 2016, AFUDC equity was $7 million compared to $14 million for the corresponding period in 2015. For year-to-date 2016, AFUDC equity was $23 million compared to $43 million for the corresponding period in 2015. These decreases were primarily associated with environmental compliance and steam generation capital projects being placed in service in 2016.
Interest Expense, Net of Amounts Capitalized
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $6 | | 8.5 | | $19 | | 9.3 |
In the third quarter 2016, interest expense, net of amounts capitalized was $77 million compared to $71 million for the corresponding period in 2015. The increase was primarily due to an increase in debt outstanding and a reduction in amounts capitalized.
For year-to-date 2016, interest expense, net of amounts capitalized was $224 million compared to $205 million for the corresponding period in 2015. The increase was primarily due to an increase in debt outstanding and a reduction in amounts capitalized. See "Allowance for Equity Funds Used During Construction" herein, FUTURE EARNINGS POTENTIAL – "Financing Activities – Financial Condition and Liquidity" herein, and Note 6 to the financial statements of Alabama Power under "Senior Notes" in Item 8 of the Form 10-K for additional information.
Other Income (Expense), Net
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(10) | | N/M | | $(19) | | N/M |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $2 | | 28.6 | | $8 | | 33.3 |
N/M – Not meaningful
In the third quarter 2015,For year-to-date 2016, other income (expense), net was $(7)$(16) million compared to $3$(24) million for the corresponding period in 2014.2015. The change was primarily due to a decrease in sales of non-utility property in 2015.
For year-to-date 2015, other income (expense), net was $(24) million compared to $(5) million for the corresponding period in 2014. The change was primarily due to an increase in donations, andpartially offset by a decrease in sales of non-utility property in 2016.
Income Taxes
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $29 | | 15.1 | | $39 | | 9.1 |
In the third quarter 2016, income taxes were $221 million compared to $192 million for the corresponding period in 2015. The increase was primarily due to higher pre-tax earnings in 2016.
For year-to-date 2016, income taxes were $466 million compared to $427 million for the corresponding period in 2015. The increase was primarily due to higher pre-tax earnings and state tax credits taken in 2015.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Dividends on Preferred and Preference Stock
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $— | | — | | $(8) | | (38.1) |
For year-to-date 2016, dividends on preferred and preference stock were $13 million compared to $21 million for the corresponding period in 2015. This decrease was primarily due to the redemption in May 2015 of certain series of preferred and preference stock. See Note 6 to the financial statements 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. Demand for electricity for Alabama Power is partiallyprimarily 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. 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.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 and "Retail Regulatory Matters – Rate CNP" herein 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 ActionsEnvironmental Statutes and Regulations
Air Quality
See Note 3 to the financial statementsMANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Alabama Power under "Environmental Matters – New Source Review Actions" in Item 87 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.information regarding the EPA's final MATS rule, regional haze regulations, and the Cross State Air Pollution Rule (CSAPR).
On August 24,April 25, 2016, in response to a June 2015 the U.S. DistrictSupreme Court for the Northern District of Alabama entered an order approving the joint stipulation among Alabama Power,opinion, the EPA andpublished its supplemental finding regarding consideration of costs in support of the U.S. Department of Justice modifying the 2006 consent decree to resolve all remaining claims for relief alleged in the case. Under the modified consent decree, Alabama Power will, without admitting liability, operate certain units subject to emission rates and an annual emissions cap;MATS rule. This finding does not impact MATS rule
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
use only natural gas at certain other units, including a unit co-owned by Mississippi Power; retire certain units at Plants Gorgascompliance requirements, costs, or deadlines, and Barry; pay a $100,000 civil penalty; and invest $1.5 million in electric transportation infrastructure projects over three years.
Environmental Statutes and Regulations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations" and – "Retail Regulatory Matters – Environmental Accounting Order" ofall Alabama Power in Item 7units that are subject to the MATS rule completed the measures necessary to achieve compliance with the MATS rule by the applicable deadlines.
Also on April 25, 2016, the EPA issued proposed revisions to the regional haze regulations. The ultimate impact of the Form 10-Kproposed revisions will depend on their ultimate adoption, implementation, and "Retail Regulatory Matters – Environmental Accounting Order" herein for additional information regarding Alabama Power's plan for compliance with environmental statutesany legal challenges and regulations.cannot be determined at this time.
Air Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Alabama 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, the Cross State Air Pollution Rule (CSAPR), and the eight-hour National Ambient Air Quality Standard (NAAQS) for ozone.
On June 12, 2015,October 26, 2016, the EPA published a final rule requiring affected states (including Alabama) to revise or remove state implementation plan (SIP) provisions regarding excessthat updates the CSAPR ozone season nitrogen oxide program, including revising ozone-season emissions that occur during periods of SSM by no later than November 22, 2016.budgets in Alabama. The ultimate impact of the finalthis rule will depend on the outcome of any legal challenges and implementation at the development and approval of SIPs by the affected statesstate level and cannot be determined at this time.
FERC Matters
See BUSINESS – "Regulation – Federal Power Act" in Item 1 of the Form 10-K for a discussion of Alabama Power's hydroelectric developments on the Coosa River. On June 29, 2015,April 21, 2016, the FERC issued an order granting in part and denying in part Alabama Power's rehearing request of the new license for Alabama Power's seven hydroelectric developments on the Coosa River. The order also denied rehearing requests filed by Alabama Rivers Alliance, American Rivers, the Georgia Environmental Protection Division, and the Atlanta Regional Commission. On May 17, 2016, Alabama Rivers Alliance and American Rivers filed an additional rehearing request and also filed a petition for review by the U.S. Supreme Court of Appeals for the District of Columbia Circuit. On September 12, 2016, the FERC issued a decision finding thatan order denying the EPA had failed to properly consider costs in its decision to regulate hazardous air pollutant emissions from electric generating units undersecond rehearing request, and Alabama Rivers Alliance and American Rivers filed an appeal of the MATS rule and remanded the caseApril 21, 2016 order 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.
On October 26, 2015, the EPA published a more stringent eight-hour NAAQS for ozone. This new standard could potentially require additional emission controls, improvements in control efficiency, and operational fuel changes and could affect the siting of new generating facilities. The ultimate impact of this matter will depend on any legal challenges and implementation of the final rule 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' rule revising the definition of waters of the U.S. under the Clean Water Act (CWA) and the EPA's revisions to effluent guidelines.
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 became effective August 28, 2015, but on October 9, 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order staying implementation of the final rule. The ultimate impact
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of the final rule will depend on the outcome of this and other pending legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the rule and cannot be determined at this time.
On November 3, 2015, the EPA published final revisions to technology-based limits for certain wastestreams from steam electric power plants. These revisions impose stringent steam effluent guidelines and technology requirements for wastewater discharges at affected units. Compliance with these revisions could result in significant additional capital expenditures and could affect future unit retirement and replacement decisions. The ultimate impact of these revisions will depend on any legal challenges and implementation of the final revisions 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, which became effective on October 19, 2015. Based on initial cost estimates for closure in place and groundwater monitoring of ash ponds pursuant to the CCR Rule, during the second quarter 2015, Alabama Power recorded incremental asset retirement obligations (ARO) of approximately $401 million related to the CCR Rule. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, Alabama Power expects to continue to periodically update these estimates. 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. See Note (A) to the Condensed Financial Statements herein for additional information regarding Alabama Power's AROs as of September 30, 2015.
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 October 23, 2015, two final actions by the EPA that would limit CO2 emissions from fossil fuel-fired electric generating units were published in the Federal Register. One of the final actions contains specific emission standards governing CO2 emissions from new, modified, and reconstructed units. The other final action 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, a proposed federal plan and proposed model rule were published 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, including legal challenges filed by Alabama Power; 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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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 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 CNPEnvironmental Accounting Order
See Note 3 to the financial statements of Alabama Power underMANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate CNP" and " – Non-Environmental Federal Mandated CostsEnvironmental Accounting Order" of Alabama Power in Item 87 of the Form 10-K for additional information regarding the 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 developmentownership interest) and began operating Units 1 and 2 solely on natural gas in June 2016 and July 2016, respectively.
Renewables
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Renewables" of a revised cost recovery mechanism andAlabama Power in Item 7 of the normal purchases and normal sales (NPNS) exceptionForm 10-K for wind PPAs.information regarding renewable energy projects.
On March 3, 2015,In accordance with the Alabama PSC approved a modificationorder approving up 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.500 MWs of renewable projects, Alabama Power incurred $50 million of non-environmental compliance costs duringhas entered into agreements to purchase power from or to build renewable generation sources, including a 72-MW solar PPA approved by the first nine months of 2015 and will be limitedAlabama PSC in June 2016. Alabama Power is marketing the associated renewable energy credits (REC) generated by this solar PPA 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.customers interested in supporting renewable energy development. The
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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On August 14, 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2015-13, allowing 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. The new accounting guidance will have no impact on Alabama Power's financial statements.
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. On August 24, 2015, the U.S. District Court for the Northern District of Alabama entered an order approving the joint stipulation in the New Source Review (NSR) action. In accordance with the joint stipulation, Alabama Power retired Plant Barry Unit 3 (225 MWs) and it is no longer available for generation. See Note (B) to the Condensed Financial Statements 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, and recovered through Rate CNP. As a result, these decisions will not have a significant impact on Alabama Power's financial statements. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate CNP" in Item 8terms of the Form 10-K and "Retail Regulatory Matters – Rate CNP" herein for additional information.
Renewable Energy
On September 1, 2015, the Alabama PSC approved Alabama Power's petition for a Renewable Generation Certificate. This will allowrenewable 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.sell RECs, separately or bundled with energy.
Other Matters
Alabama Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Alabama Power is subject to certain claims and legal actions arising in the ordinary course of business. Alabama Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
TheultimateoutcomeofsuchpendingorpotentiallitigationagainstAlabama Powercannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)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
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
As a result of the final CCR Rule discussed above, Alabama Power recorded new AROs for facilities that are subject to the CCR Rule. The cost estimates are based on information using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure in place. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, Alabama Power expects to continue 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. Early2018, with early adoption is permitted andpermitted. Alabama Power intendsis currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to adopthave 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 fourth quarter 2015. The ASU is required to be applied retrospectively to all periods presented beginning in the year of adoption.income statement. Alabama Power currently reflects unamortized debt issuance costs in other deferred chargesrecognizes any excess tax benefits and assets on its balance sheet. Upon adoption,deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016. Early
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adoption is permitted and Alabama 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 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 September 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"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 $1.6$1.5 billion for the first nine months of 2015, an increase2016, a decrease of $181$44 million as compared to the first nine months of 2014.2015. The increasedecrease in net cash provided from operating activities was primarily due to the timing oflower fuel cost recovery revenues during 2016, partially offset by lower income tax payments and the receipt of income tax refunds associated withas a result of bonus depreciation and collection of fuel cost recovery revenues, partially offset by the timing of payments of accounts payable.depreciation. Net cash used for investing activities totaled $1.0$1.1 billion for the first nine months of 20152016 primarily due to gross property additions related to environmental, distribution, environmental, transmission,steam generation, and steam generation.transmission. Net cash used for financing activities totaled $194$91 million for the first nine months of 20152016 primarily due to the redemptionscommon stock dividend payments and repurchasesa redemption of long-term debt, and payments of common stock dividends, partially offset by issuances of long-term debt. Fluctuations in cash flowdebt and additional capital contributions 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 nine months of 20152016 include increases of $829$422 million in property, plant, and equipment, primarily due to additions to environmental, distribution, environmental,nuclear generation, and transmission, and steam generation, $336$362 million in cash and cash equivalents, $523$266 million in additional paid-in capital due to capital contributions from Southern Company, $264 million in accumulated deferred income taxes related to bonus depreciation, and $205 million in long-term debt primarily due to the issuance of additional senior notes, and $459 million in AROs associated with the CCR Rule. See Note (A) to the Condensed Financial Statements herein for additional information related to AROs.notes. Other significant changes include decreases of $404$239 million in redeemable preferred and preference stockother regulatory liabilities, current, primarily due to redemptionsthe timing of fuel cost recovery and $177 million in other accounts payable primarily due to the second quarter 2015.timing of vendor payments.
See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information regarding Alabama Power's rate mechanisms.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Alabama Power in Item 7 of the Form 10-K for a description of Alabama Power's capital requirements for its construction program, including estimated capital expenditures to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. Approximately $600$236 million will be required through September 30, 20162017 to fund maturities of long-term debt. Subsequent to September 30, 2015, Alabama Power repaid at maturity $400 million aggregate principal amount of its Series 2012B 0.550% Senior Notes due October 15, 2015.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – General" and " – Global Climate Issues" of Alabama Power in Item 7 of the Form 10-K for additional information on Alabama Power's environmental compliance strategy.
Alabama Power's approved construction program is currently estimated to total $1.9 billion for 2017, $1.6 billion for 2018, $1.2 billion for 2019, $1.3 billion for 2020, and $1.2 billion for 2021. The construction program includes capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreements. Estimated capital expenditures to comply with environmental statutes and
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regulations included in these amounts are $0.5 billion for 2017, $0.3 billion for 2018, $0.1 billion for 2019, $0.1 billion for 2020, and $0.2 billion for 2021. These estimated expenditures include anticipated costs for compliance with the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) and the EPA's final effluent guidelines rule. These estimated expenditures do not include potential compliance costs that may arise from the EPA's final rules and guidelines or subsequently approved state plans that would limit CO2 emissions from existing, new, modified, or reconstructed fossil-fuel-fired electric generating units.
Alabama Power also anticipates costs associated with closure in place and ground water monitoring of ash ponds in accordance with the CCR Rule, which are not reflected in the capital expenditures above as these costs are associated with Alabama Power's asset retirement obligation liabilities. These costs, which will change as Alabama Power continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance, are estimated to be $31 million for 2017, $26 million for 2018, $100 million for 2019, $105 million for 2020, and $107 million for 2021. See Note 1 to the financial statements of Alabama Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information. Costs associated with the CCR Rule are expected to be recovered through Rate CNP Compliance.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; 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
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impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Sources of Capital
Alabama Power plans to obtain the funds to meet its future capital needs 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'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 September 30, 2015,2016, Alabama Power had approximately $609$556 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 20152016 were as follows:
| | | Expires | Expires | | | | | | Due Within One Year | Expires | | | | | | Due Within One Year |
| 2016 | | 2018 | | 2020 | | Total | | Unused | | Term Out | | No Term Out | |
| 2017 | | 2017 | | 2018 | | 2020 | | Total | | Unused | | Term Out | | No Term Out |
| (in millions) | (in millions) | | | | (in millions) | | (in millions) | (in millions) | | (in millions) | | (in millions) |
| $ | 40 |
| | $ | 500 |
| | $ | 800 |
| | $ | 1,340 |
| | $ | 1,339 |
| | $ | — |
| | $ | 40 |
| 35 |
| | $ | 500 |
| | $ | 800 |
| | $ | 1,335 |
| | $ | 1,335 |
| | $ | — |
| | $ | 35 |
|
See Note 6 to the financial statements of Alabama Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank"Bank Credit Arrangements"Arrangements" herein for additional information.
As reflected in the table above, in August 2015, Alabama Power amended and restated its multi-year credit arrangement, which, among other things, extended the maturity date from 2018 to 2020. In addition, Alabama Power entered into a new $500 million three-year credit arrangement which replaced a majority of Alabama Power's bi-lateral credit arrangements.
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 September 30, 2015 was approximately $810 million. In addition, at September 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, of which $120 million were remarketed subsequent to September 30, 2015.
Most of these bank credit arrangements, as well as Alabama Power's term loan arrangements, contain covenants that limit debt levels and contain cross acceleration provisions to other indebtedness (including guarantee obligations) of Alabama Power. Such cross acceleration provisions to other indebtedness would trigger an event of default if
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Alabama Power defaulted on indebtedness, 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 September 30, 2016 was approximately $890 million. In addition, at September 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
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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.
Alabama Power had no commercial paper orDetails of short-term debt outstanding during the three-month period ended September 30, 2015.borrowings were as follows:
|
| | | | | | | | | | | |
| | | Short-term Debt During the Period(*) |
| | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) |
| Commercial paper | | $ | 15 |
| | 0.6 | % | | $ | 100 |
|
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2016. No short-term debt was outstanding at September 30, 2016. |
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 and/or Baa2 or below. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, energy price risk management, and transmission. The maximum potential collateral requirements under these contracts at September 30, 20152016 were as follows:
| | | Credit Ratings | Maximum Potential Collateral Requirements | Maximum Potential Collateral Requirements |
| | (in millions) | (in millions) |
| At BBB and/or Baa2 | $ | 1 |
| $ | 1 |
|
| At BBB- and/or Baa3 | 2 |
| $ | 2 |
|
| Below BBB- and/or Baa3 | 372 |
| $ | 347 |
|
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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, a credit rating downgrade could impact the ability of Alabama Power to access capital markets, and would be likely to impact the cost at which it does so.
On August 17, 2015, S&P downgraded the consolidated long-term issuer rating of Southern Company (including Alabama Power) to A- from A. S&P revised its credit rating outlook from negative to stable. Separately, on August 24, 2015, S&P revised its credit rating outlook from stable to negative following the announcement of the Merger.
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.
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 in May 2015 to redeem 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
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
Subsequent to September 30, 2015, Alabama Power repaid at maturity $400 million aggregate principal amount of its Series 2012B 0.550% Senior Notes due October 15, 2015.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 September 30, | | For the Nine Months
Ended September 30, | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | | | | | | | | |
| Retail revenues | $ | 2,537 |
| | $ | 2,452 |
| | $ | 6,223 |
| | $ | 6,502 |
| $ | 2,540 |
| | $ | 2,537 |
| | $ | 6,164 |
| | $ | 6,223 |
|
| Wholesale revenues, non-affiliates | 55 |
| | 80 |
| | 173 |
| | 269 |
| 49 |
| | 55 |
| | 131 |
| | 173 |
|
| Wholesale revenues, affiliates | 5 |
| | 7 |
| | 18 |
| | 38 |
| 9 |
| | 5 |
| | 24 |
| | 18 |
|
| Other revenues | 94 |
| | 92 |
| | 271 |
| | 277 |
| 100 |
| | 94 |
| | 302 |
| | 271 |
|
| Total operating revenues | 2,691 |
| | 2,631 |
| | 6,685 |
| | 7,086 |
| 2,698 |
| | 2,691 |
| | 6,621 |
| | 6,685 |
|
| Operating Expenses: | | | | | | | | | | | | | | |
| Fuel | 706 |
| | 684 |
| | 1,735 |
| | 2,055 |
| 575 |
| | 706 |
| | 1,390 |
| | 1,735 |
|
| Purchased power, non-affiliates | 90 |
| | 77 |
| | 227 |
| | 219 |
| 102 |
| | 90 |
| | 277 |
| | 227 |
|
| Purchased power, affiliates | 148 |
| | 172 |
| | 411 |
| | 522 |
| 142 |
| | 148 |
| | 392 |
| | 411 |
|
| Other operations and maintenance | 462 |
| | 456 |
| | 1,405 |
| | 1,334 |
| 496 |
| | 462 |
| | 1,393 |
| | 1,405 |
|
| Depreciation and amortization | 214 |
| | 211 |
| | 633 |
| | 628 |
| 215 |
| | 214 |
| | 639 |
| | 633 |
|
| Taxes other than income taxes | 107 |
| | 111 |
| | 302 |
| | 320 |
| 114 |
| | 107 |
| | 311 |
| | 302 |
|
| Total operating expenses | 1,727 |
| | 1,711 |
| | 4,713 |
| | 5,078 |
| 1,644 |
| | 1,727 |
| | 4,402 |
| | 4,713 |
|
| Operating Income | 964 |
| | 920 |
| | 1,972 |
| | 2,008 |
| 1,054 |
| | 964 |
| | 2,219 |
| | 1,972 |
|
| Other Income and (Expense): | | | | | | | | | | | | | | |
| Interest expense, net of amounts capitalized | (90 | ) | | (88 | ) | | (272 | ) | | (262 | ) | (98 | ) | | (90 | ) | | (290 | ) | | (272 | ) |
| Other income (expense), net | 18 |
| | 14 |
| | 34 |
| | 29 |
| 11 |
| | 18 |
| | 35 |
| | 34 |
|
| Total other income and (expense) | (72 | ) | | (74 | ) | | (238 | ) | | (233 | ) | (87 | ) | | (72 | ) | | (255 | ) | | (238 | ) |
| Earnings Before Income Taxes | 892 |
| | 846 |
| | 1,734 |
| | 1,775 |
| 967 |
| | 892 |
| | 1,964 |
| | 1,734 |
|
| Income taxes | 337 |
| | 317 |
| | 657 |
| | 660 |
| 365 |
| | 337 |
| | 737 |
| | 657 |
|
| Net Income | 555 |
| | 529 |
| | 1,077 |
| | 1,115 |
| 602 |
| | 555 |
| | 1,227 |
| | 1,077 |
|
| Dividends on Preferred and Preference Stock | 4 |
| | 4 |
| | 13 |
| | 13 |
| 4 |
| | 4 |
| | 13 |
| | 13 |
|
| Net Income After Dividends on Preferred and Preference Stock | $ | 551 |
| | $ | 525 |
| | $ | 1,064 |
| | $ | 1,102 |
| $ | 598 |
| | $ | 551 |
| | $ | 1,214 |
| | $ | 1,064 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months
Ended September 30, | | For the Nine Months
Ended September 30, |
| | 2015 | | 2014 | | 2015 | | 2014 |
| | (in millions) | | (in millions) |
| Net Income | $ | 555 |
| | $ | 529 |
| | $ | 1,077 |
| | $ | 1,115 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
Changes in fair value, net of tax of $(7), $-, $(7) and $-,
respectively | (11 | ) | | — |
| | (10 | ) | | — |
|
Reclassification adjustment for amounts included in net
income, net of tax of $-, $1, $1 and $1, respectively | 1 |
| | — |
| | 2 |
| | 1 |
|
| Total other comprehensive income (loss) | (10 | ) | | — |
| | (8 | ) | | 1 |
|
| Comprehensive Income | $ | 545 |
| | $ | 529 |
| | $ | 1,069 |
| | $ | 1,116 |
|
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED) |
| | | | | | | |
| | For the Nine Months
Ended September 30, |
| | 2015 | | 2014 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 1,077 |
| | $ | 1,115 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 766 |
| | 757 |
|
| Deferred income taxes | 12 |
| | 121 |
|
| Allowance for equity funds used during construction | (24 | ) | | (29 | ) |
| Retail fuel cost over recovery — long-term | — |
| | (44 | ) |
| Deferred expenses | (45 | ) | | (35 | ) |
| Pension, postretirement, and other employee benefits | 40 |
| | 28 |
|
| Other, net | 30 |
| | 24 |
|
| Changes in certain current assets and liabilities — | | | |
| -Receivables | 37 |
| | (377 | ) |
| -Fossil fuel stock | 141 |
| | 337 |
|
| -Prepaid income taxes | 244 |
| | 19 |
|
| -Other current assets | (17 | ) | | (24 | ) |
| -Accounts payable | (118 | ) | | (7 | ) |
| -Accrued taxes | 54 |
| | 148 |
|
| -Accrued compensation | (34 | ) | | 20 |
|
| -Retail fuel cost over recovery — short-term | — |
| | (14 | ) |
| -Other current liabilities | (3 | ) | | 29 |
|
| Net cash provided from operating activities | 2,160 |
| | 2,068 |
|
| Investing Activities: | | | |
| Property additions | (1,321 | ) | | (1,364 | ) |
| Nuclear decommissioning trust fund purchases | (815 | ) | | (457 | ) |
| Nuclear decommissioning trust fund sales | 810 |
| | 455 |
|
| Cost of removal, net of salvage | (57 | ) | | (39 | ) |
| Change in construction payables, net of joint owner portion | 44 |
| | 16 |
|
| Prepaid long-term service agreements | (60 | ) | | (66 | ) |
| Other investing activities | 11 |
| | (3 | ) |
| Net cash used for investing activities | (1,388 | ) | | (1,458 | ) |
| Financing Activities: | | | |
| Decrease in notes payable, net | (26 | ) | | (836 | ) |
| Proceeds — | | | |
| Capital contributions from parent company | 41 |
| | 39 |
|
| Pollution control revenue bonds | 274 |
| | 40 |
|
| FFB loan | 600 |
| | 1,000 |
|
| Short-term borrowings | 250 |
| | — |
|
| Redemptions and repurchases — | | | |
| Pollution control revenue bonds | (268 | ) | | (37 | ) |
| Senior notes | (525 | ) | | — |
|
| Short-term borrowings | (250 | ) | | — |
|
| Payment of preferred and preference stock dividends | (13 | ) | | (13 | ) |
| Payment of common stock dividends | (776 | ) | | (715 | ) |
| FFB loan issuance costs | — |
| | (49 | ) |
| Other financing activities | (18 | ) | | (6 | ) |
| Net cash used for financing activities | (711 | ) | | (577 | ) |
| Net Change in Cash and Cash Equivalents | 61 |
| | 33 |
|
| Cash and Cash Equivalents at Beginning of Period | 24 |
| | 30 |
|
| Cash and Cash Equivalents at End of Period | $ | 85 |
| | $ | 63 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid during the period for — | | | |
| Interest (net of $10 and $13 capitalized for 2015 and 2014, respectively) | $ | 251 |
| | $ | 235 |
|
| Income taxes, net | 311 |
| | 309 |
|
| Noncash transactions — Accrued property additions at end of period | 192 |
| | 220 |
|
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At September 30,
2015 | | At December 31,
2014 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 85 |
| | $ | 24 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 758 |
| | 553 |
|
| Unbilled revenues | | 243 |
| | 201 |
|
| Joint owner accounts receivable | | 52 |
| | 121 |
|
| Other accounts and notes receivable | | 47 |
| | 61 |
|
| Affiliated companies | | 22 |
| | 18 |
|
| Accumulated provision for uncollectible accounts | | (7 | ) | | (6 | ) |
| Fossil fuel stock, at average cost | | 298 |
| | 439 |
|
| Materials and supplies, at average cost | | 439 |
| | 438 |
|
| Vacation pay | | 90 |
| | 91 |
|
| Prepaid income taxes | | 24 |
| | 278 |
|
| Other regulatory assets, current | | 124 |
| | 136 |
|
| Other current assets | | 94 |
| | 74 |
|
| Total current assets | | 2,269 |
| | 2,428 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 31,546 |
| | 31,083 |
|
| Less accumulated provision for depreciation | | 11,046 |
| | 11,222 |
|
| Plant in service, net of depreciation | | 20,500 |
| | 19,861 |
|
| Other utility plant, net | | 10 |
| | 211 |
|
| Nuclear fuel, at amortized cost | | 544 |
| | 563 |
|
| Construction work in progress | | 4,390 |
| | 4,031 |
|
| Total property, plant, and equipment | | 25,444 |
| | 24,666 |
|
| Other Property and Investments: | | | | |
| Equity investments in unconsolidated subsidiaries | | 62 |
| | 58 |
|
| Nuclear decommissioning trusts, at fair value | | 761 |
| | 789 |
|
| Miscellaneous property and investments | | 38 |
| | 38 |
|
| Total other property and investments | | 861 |
| | 885 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 678 |
| | 698 |
|
| Deferred under recovered regulatory clause revenues | | — |
| | 197 |
|
| Other regulatory assets, deferred | | 2,075 |
| | 1,753 |
|
| Other deferred charges and assets | | 399 |
| | 403 |
|
| Total deferred charges and other assets | | 3,152 |
| | 3,051 |
|
| Total Assets | | $ | 31,726 |
| | $ | 31,030 |
|
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2016 | | 2015 | | 2016 | | 2015 |
| | (in millions) | | (in millions) |
| Net Income | $ | 602 |
| | $ | 555 |
| | $ | 1,227 |
| | $ | 1,077 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
| Changes in fair value, net of tax of $-, $(7), $-, and $(7), respectively | — |
| | (11 | ) | | — |
| | (10 | ) |
Reclassification adjustment for amounts included in net
income, net of tax of $-, $-, $1, and $1, respectively | 1 |
| | 1 |
| | 2 |
| | 2 |
|
| Total other comprehensive income (loss) | 1 |
| | (10 | ) | | 2 |
| | (8 | ) |
| Comprehensive Income | $ | 603 |
| | $ | 545 |
| | $ | 1,229 |
| | $ | 1,069 |
|
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 September 30,
2015 | | At December 31,
2014 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 1,362 |
| | $ | 1,154 |
|
| Notes payable | | 130 |
| | 156 |
|
| Accounts payable — | | | | |
| Affiliated | | 444 |
| | 451 |
|
| Other | | 515 |
| | 555 |
|
| Customer deposits | | 260 |
| | 253 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 75 |
| | 1 |
|
| Other accrued taxes | | 311 |
| | 332 |
|
| Accrued interest | | 99 |
| | 96 |
|
| Accrued vacation pay | | 62 |
| | 63 |
|
| Accrued compensation | | 120 |
| | 153 |
|
| Other current liabilities | | 345 |
| | 256 |
|
| Total current liabilities | | 3,723 |
| | 3,470 |
|
| Long-term Debt | | 8,709 |
| | 8,683 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 5,493 |
| | 5,507 |
|
| Deferred credits related to income taxes | | 101 |
| | 106 |
|
| Accumulated deferred investment tax credits | | 188 |
| | 196 |
|
| Employee benefit obligations | | 893 |
| | 903 |
|
| Asset retirement obligations | | 1,332 |
| | 1,223 |
|
| Other deferred credits and liabilities | | 266 |
| | 255 |
|
| Total deferred credits and other liabilities | | 8,273 |
| | 8,190 |
|
| Total Liabilities | | 20,705 |
| | 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 | | 6,251 |
| | 6,196 |
|
| Retained earnings | | 4,123 |
| | 3,835 |
|
| Accumulated other comprehensive loss | | (17 | ) | | (8 | ) |
| Total common stockholder's equity | | 10,755 |
| | 10,421 |
|
| Total Liabilities and Stockholder's Equity | | $ | 31,726 |
| | $ | 31,030 |
|
|
| | | | | | | |
| | For the Nine Months Ended September 30, |
| | 2016 | | 2015 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 1,227 |
| | $ | 1,077 |
|
| Adjustments to reconcile net income to net cash provided from operating activities -- | | | |
| Depreciation and amortization, total | 794 |
| | 766 |
|
| Deferred income taxes | 346 |
| | 12 |
|
| Allowance for equity funds used during construction | (36 | ) | | (24 | ) |
| Deferred expenses | (40 | ) | | (45 | ) |
| Pension, postretirement, and other employee benefits | (14 | ) | | 40 |
|
| Settlement of asset retirement obligations | (93 | ) | | (18 | ) |
| Other, net | 4 |
| | 48 |
|
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (162 | ) | | 37 |
|
| -Fossil fuel stock | 128 |
| | 141 |
|
| -Prepaid income taxes | 45 |
| | 244 |
|
| -Other current assets | 17 |
| | (17 | ) |
| -Accounts payable | 39 |
| | (118 | ) |
| -Accrued taxes | (22 | ) | | 54 |
|
| -Accrued compensation | (26 | ) | | (34 | ) |
| -Other current liabilities | 53 |
| | (3 | ) |
| Net cash provided from operating activities | 2,260 |
| | 2,160 |
|
| Investing Activities: | | | |
| Property additions | (1,566 | ) | | (1,321 | ) |
| Nuclear decommissioning trust fund purchases | (563 | ) | | (815 | ) |
| Nuclear decommissioning trust fund sales | 558 |
| | 810 |
|
| Cost of removal, net of salvage | (45 | ) | | (57 | ) |
| Change in construction payables, net of joint owner portion | (139 | ) | | 44 |
|
| Prepaid long-term service agreements | (27 | ) | | (60 | ) |
| Other investing activities | 24 |
| | 11 |
|
| Net cash used for investing activities | (1,758 | ) | | (1,388 | ) |
| Financing Activities: | | | |
| Decrease in notes payable, net | (63 | ) | | (26 | ) |
| Proceeds — | | | |
| Capital contributions from parent company | 294 |
| | 41 |
|
| Pollution control revenue bonds | — |
| | 274 |
|
| Senior notes | 650 |
| | — |
|
| FFB loan | 300 |
| | 600 |
|
| Short-term borrowings | — |
| | 250 |
|
| Redemptions and repurchases — | | | |
| Pollution control revenue bonds | (4 | ) | | (268 | ) |
| Senior notes | (700 | ) | | (525 | ) |
| Short-term borrowings | — |
| | (250 | ) |
| Payment of common stock dividends | (979 | ) | | (776 | ) |
| Other financing activities | (20 | ) | | (31 | ) |
| Net cash used for financing activities | (522 | ) | | (711 | ) |
| Net Change in Cash and Cash Equivalents | (20 | ) | | 61 |
|
| Cash and Cash Equivalents at Beginning of Period | 67 |
| | 24 |
|
| Cash and Cash Equivalents at End of Period | $ | 47 |
| | $ | 85 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid during the period for — | | | |
| Interest (net of $15 and $10 capitalized for 2016 and 2015, respectively) | $ | 277 |
| | $ | 251 |
|
| Income taxes, net | 188 |
| | 311 |
|
| Noncash transactions — Accrued property additions at end of period | 226 |
| | 192 |
|
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At September 30, 2016 | | At December 31, 2015 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 47 |
| | $ | 67 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 718 |
| | 541 |
|
| Unbilled revenues | | 298 |
| | 188 |
|
| Joint owner accounts receivable | | 46 |
| | 227 |
|
| Income taxes receivable, current | | — |
| | 114 |
|
| Other accounts and notes receivable | | 55 |
| | 57 |
|
| Affiliated | | 15 |
| | 18 |
|
| Accumulated provision for uncollectible accounts | | (2 | ) | | (2 | ) |
| Fossil fuel stock | | 274 |
| | 402 |
|
| Materials and supplies | | 470 |
| | 449 |
|
| Vacation pay | | 90 |
| | 91 |
|
| Prepaid income taxes | | 111 |
| | 156 |
|
| Other regulatory assets, current | | 115 |
| | 123 |
|
| Other current assets | | 89 |
| | 92 |
|
| Total current assets | | 2,326 |
| | 2,523 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 33,394 |
| | 31,841 |
|
| Less accumulated provision for depreciation | | 11,234 |
| | 10,903 |
|
| Plant in service, net of depreciation | | 22,160 |
| | 20,938 |
|
| Other utility plant, net | | — |
| | 171 |
|
| Nuclear fuel, at amortized cost | | 556 |
| | 572 |
|
| Construction work in progress | | 4,888 |
| | 4,775 |
|
| Total property, plant, and equipment | | 27,604 |
| | 26,456 |
|
| Other Property and Investments: | | | | |
| Equity investments in unconsolidated subsidiaries | | 61 |
| | 64 |
|
| Nuclear decommissioning trusts, at fair value | | 835 |
| | 775 |
|
| Miscellaneous property and investments | | 42 |
| | 43 |
|
| Total other property and investments | | 938 |
| | 882 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 675 |
| | 679 |
|
| Other regulatory assets, deferred | | 2,530 |
| | 2,152 |
|
| Other deferred charges and assets | | 175 |
| | 173 |
|
| Total deferred charges and other assets | | 3,380 |
| | 3,004 |
|
| Total Assets | | $ | 34,248 |
| | $ | 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 September 30, 2016 | | At December 31, 2015 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 458 |
| | $ | 712 |
|
| Notes payable | | 95 |
| | 158 |
|
| Accounts payable — | | | | |
| Affiliated | | 451 |
| | 411 |
|
| Other | | 464 |
| | 750 |
|
| Customer deposits | | 265 |
| | 264 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 14 |
| | 12 |
|
| Other accrued taxes | | 310 |
| | 325 |
|
| Accrued interest | | 110 |
| | 99 |
|
| Accrued vacation pay | | 62 |
| | 62 |
|
| Accrued compensation | | 118 |
| | 142 |
|
| Asset retirement obligations, current | | 313 |
| | 179 |
|
| Over recovered regulatory clause revenues, current | | 125 |
| | 10 |
|
| Other current liabilities | | 197 |
| | 171 |
|
| Total current liabilities | | 2,982 |
| | 3,295 |
|
| Long-term Debt | | 10,114 |
| | 9,616 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 5,969 |
| | 5,627 |
|
| Deferred credits related to income taxes | | 103 |
| | 105 |
|
| Accumulated deferred investment tax credits | | 199 |
| | 204 |
|
| Employee benefit obligations | | 906 |
| | 949 |
|
| Asset retirement obligations, deferred | | 2,241 |
| | 1,737 |
|
| Other deferred credits and liabilities | | 203 |
| | 347 |
|
| Total deferred credits and other liabilities | | 9,621 |
| | 8,969 |
|
| Total Liabilities | | 22,717 |
| | 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 | | 6,585 |
| | 6,275 |
|
| Retained earnings | | 4,295 |
| | 4,061 |
|
| Accumulated other comprehensive loss | | (13 | ) | | (15 | ) |
| Total common stockholder's equity | | 11,265 |
| | 10,719 |
|
| Total Liabilities and Stockholder's Equity | | $ | 34,248 |
| | $ | 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
THIRD QUARTER 20152016 vs. THIRD 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.
On October 20, 2016, Georgia Power and the Georgia PSC Staff entered into a settlement agreement resolving certain prudence and cost recovery matters related to Plant Vogtle Units 3 and 4. The settlement agreement is subject to approval by the Georgia PSC. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.
Pursuant to the terms and conditions of a settlement agreement related to Southern Company's acquisition of Southern Company Gas approved by the Georgia PSC on April 14, 2016, Georgia Power's 2013 ARP will continue in effect until December 31, 2019, and Georgia Power will be required to file its next base rate case by July 1, 2019. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" herein for additional information.
Georgia Power continues to focus on several key performance indicators. These indicators include, but are not limited to, customer satisfaction, plant availability, system reliability, the execution of major construction projects, and net income after dividends on preferred and preference stock. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Georgia Power in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $26 | | 5.0 | | $(38) | | (3.4) |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $47 | | 8.5 | | $150 | | 14.1 |
Georgia Power's net income after dividends on preferred and preference stock was $598 million for the third quarter 2015 was $551 million2016 compared to $525$551 million for the corresponding period in 2014. For year-to-date 2015, net income after dividends on preferred and preference stock was $1.06 billion compared to $1.10 billion for the corresponding period in 2014.2015. The increase in the third quarter 2015 was primarily due to an increase in retail base revenues effective January 1, 2015,2016, as authorized by the Georgia PSC, and higher retail revenues due to warmer weather as compared to the corresponding period in 2015, partially offset by higher non-fuel operating expenses.
For year-to-date 2016, net income after dividends on preferred and preference stock was $1.21 billion compared to $1.06 billion for the corresponding period in 2015. The decrease in year-to-date 2015increase was primarily due to higher non-fuel operating 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 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 increaseshigher retail revenues in retail base revenues effective January 1, 2015, as authorized by the Georgia PSC.third quarter
See Note (A) to the Condensed Financial Statements herein for additional information.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
2016 due to warmer weather as compared to the corresponding period in 2015, and lower non-fuel operating expenses. Partially offsetting the increase were lower retail revenues in the first quarter 2016 due to milder weather as compared to the corresponding period in 2015.
Retail Revenues
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) |
| (% change) |
| $85 | | 3.5 | | $(279) | | (4.3) |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $3 | | 0.1 | | $(59) | | (0.9) |
InRetail revenues increased slightly in the third quarter 2015,2016 compared to the corresponding period in 2015. For year-to-date 2016, retail revenues were $2.54$6.16 billion compared to $2.45$6.22 billion for the corresponding period in 2014. For year-to-date 2015, retail revenues were $6.22 billion compared to $6.50 billion for the corresponding period in 2014.2015.
Details of the changes in retail revenues were as follows:
| | | | | Third Quarter
2015 | | Year-to-Date 2015 | Third Quarter 2016 | | Year-to-Date 2016 |
| | | (in millions) |
| (% change) | | (in millions) | | (% change) | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | | $ | 2,452 |
| | | | $ | 6,502 |
| | | $ | 2,537 |
| | | | $ | 6,223 |
| | |
| Estimated change resulting from – | | | | | | | | | | | | | | | |
| Rates and pricing | | 29 |
| | 1.2 |
| | 32 |
| | 0.5 |
| 22 |
| | 0.9 |
| | 167 |
| | 2.7 |
|
| Sales growth | | 13 |
| | 0.5 |
| | 49 |
| | 0.7 |
| 1 |
| | — |
| | 3 |
| | — |
|
| Weather | | 44 |
| | 1.8 |
| | 50 |
| | 0.8 |
| 105 |
| | 4.1 |
| | 75 |
| | 1.2 |
|
| Fuel cost recovery | | (1 | ) | | — |
| | (410 | ) | | (6.3 | ) | (125 | ) | | (4.9 | ) | | (304 | ) | | (4.9 | ) |
| Retail – current year | | $ | 2,537 |
| | 3.5 | % | | $ | 6,223 |
| | (4.3 | )% | $ | 2,540 |
| | 0.1 | % | | $ | 6,164 |
| | (1.0 | )% |
Revenues associated with changes in rates and pricing increased in the third quarter 2015and year-to-date 2016 when compared to the corresponding periodperiods in 20142015 primarily due to increases in base tariff increasestariffs 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 bothall effective January 1, 2015 as well as higher contributions from variable demand-driven pricing from commercial and industrial customers. Revenues associated with changes in rates and pricing increased2016. Also contributing to the increase for year-to-date 2015 when compared to2016 was the corresponding period in 2014 primarily due to the base tariff increases and increases in collections for financing costs described above, partially offset by the2015 correction of an error affecting billings since 2013 to a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing. See Note 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 increasedwere essentially flat in the third quarter andyear-to-date 20152016 when compared to the corresponding periods in 2014.2015. Weather-adjusted residential KWH sales increased 0.1%1.7%, weather-adjusted commercial KWH sales increased 1.8%decreased 0.7%, and weather-adjusted industrial KWH sales decreased 0.3%3.4% in the third quarter 20152016 when compared to the corresponding period in 2014.2015. For year-to-date 2015,2016, weather-adjusted residential KWH sales increased 1.1%1.0%, weather-adjusted commercial KWH sales increased 1.3%decreased 0.6%, and weather-adjusted industrial KWH sales increased 1.2%decreased 0.5% when compared to the corresponding period in 2014.2015. An increase of approximately 26,00029,000 residential customers since September 30, 20142015 contributed to the increase in weather-adjusted residential KWH sales. Increasedsales, partially offset by a decline in average customer usage primarily resulting from an increase in multi-family housing and efficiency improvements in residential appliances and lighting. A decline in average customer usage resulting from an increase in energy saving initiatives contributed to the decrease in weather-adjusted commercial KWH sales, partially offset by an increase of approximately 3,000 commercial customers since September 30, 2014 contributed to the increase in weather-adjusted commercial sales. Increased2015. Decreased demand in the paper,pipeline, textiles, and stone, clay, and glass food processing, transportation, rubber, and pipeline sectors was the main contributor to the year-to-date increasedecrease in weather-adjusted industrial KWH sales, partially offset by a decreaseincreased demand in the chemicals and primary metals sectors. A strong dollar, low oil prices, and weak global growth conditions have constrained growth in the industrialnon-manufacturing sector.
Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues decreased $1$125 million and $410$304 million in the third quarter and year-to-date 2015,2016, respectively, when compared to the corresponding periods in 20142015 primarily due to lower natural gas costs.fuel prices. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
Wholesale Revenues – Non-Affiliates
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(25) | | (31.3) | | $(96) | | (35.7) |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(6) | | (10.9) | | $(42) | | (24.3) |
Wholesale revenues from sales to non-affiliates consist of PPAs and short-term opportunity sales. Wholesale revenues from PPAs have both capacity and energy components. Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amounts billable under the contract terms and provide for recovery of fixed costs and a return on investment. Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Georgia Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above Georgia Power's variable cost to produce the energy.
In the third quarter 2015,2016, wholesale revenues from sales to non-affiliates were $55$49 million compared to $80$55 million for the corresponding period in 20142015 related to an $8 million decrease in energy revenues and a $17$7 million decrease in capacity revenues, partially offset by a $1 million increase in energy revenues. For year-to-date 2015,2016, wholesale revenues from sales to non-affiliates were $173$131 million compared to $269$173 million for the corresponding period in 20142015 related to a $57$28 million decrease in capacity revenues and a $14 million decrease in energy revenues and a $39 million decrease in capacity revenues. The decreases in energy revenues were primarily due to lower natural gas prices. 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 since March 31, 2015 as a result of Georgia Power's environmental compliance strategy. The decrease in energy revenues for year-to-date 2016 was primarily due to lower fuel prices. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" and "Retail Regulatory Matters – Integrated Resource Plan" of Georgia Power in Item 7 of the 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
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $(2) | | (28.6) | | $(20) | | (52.6) |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $6 | | 6.4 | | $31 | | 11.4 |
WholesaleFor year-to-date 2016, other 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.
In the third quarter 2015, wholesale revenues from sales to affiliates were $5$302 million compared to $7$271 million for the corresponding period in 2014. For year-to-date 2015, wholesale revenues from sales to affiliates were $18 million compared to $38 million for the corresponding period in 2014.2015. The decreases were due to lower natural gas prices and a 41.7% and 52.9% decrease in KWH sales in the third quarter 2015 and year-to-date 2015, respectively,increase was primarily due to the higher cost ofa $14 million increase related to customer temporary facilities services revenues, a $9 million increase in outdoor lighting revenues, and a $3 million increase in solar application fee revenues. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Renewables" herein for additional information on Georgia Power-owned generation as compared to the market cost of available energy.Power's solar renewable energy program.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel and Purchased Power Expenses
| | | | | Third Quarter 2015
vs.
Third Quarter 2014 | | Year-to-Date 2015
vs.
Year-to-Date 2014 | | Third Quarter 2016
vs.
Third 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 | | $ | 22 |
| | 3.2 |
| | $ | (320 | ) | | (15.6 | ) | | $ | (131 | ) | | (18.6 | ) | | $ | (345 | ) | | (19.9 | ) |
| Purchased power – non-affiliates | | 13 |
| | 16.9 |
| | 8 |
| | 3.7 |
| | 12 |
| | 13.3 |
| | 50 |
| | 22.0 |
|
| Purchased power – affiliates | | (24 | ) | | (14.0 | ) | | (111 | ) | | (21.3 | ) | | (6 | ) | | (4.1 | ) | | (19 | ) | | (4.6 | ) |
| Total fuel and purchased power expenses | | $ | 11 |
| | | | $ | (423 | ) | | | | $ | (125 | ) | | | | $ | (314 | ) | | |
In the third quarter 2015,2016, total fuel and purchased power expenses were $944$819 million compared to $933$944 million in the corresponding period in 2014.2015. The increasedecrease in the third quarter 20152016 was primarily due to an increase of $44 million in the volume of KWHs purchased due to lower natural gas prices and a $37 million increase in the average cost of fuel related to higher coal prices, partially offset by a $35 million decrease in the average cost of purchased power due to lower natural gas prices and a $35 million decrease in the volume of KWHs generated due to higher coal prices.
For year-to-date 2015, total fuel and purchased power expenses were $2.37 billion compared to $2.80 billion in the corresponding period in 2014. The decrease in year-to-date 2015 was primarily due to a $394net decrease of $189 million decrease in the average cost of fuel and purchased power related to lower natural gas prices and a $135 million decrease in the volume of KWHs generated due to higher coal prices, partially offset by a $106$64 million increase related to the volume of KWHs generated and purchased as a result of warmer weather as compared to the corresponding period in 2015 resulting in higher customer demand.
For year-to-date 2016, total fuel and purchased power expenses were $2.06 billion compared to $2.37 billion in the corresponding period in 2015. The decrease in year-to-date 2016 was primarily due to a decrease of $326 million in the average cost of fuel and purchased power related to lower coal and natural gas prices and a $20 million decrease related to the volume of KWHs generated, partially offset by a $32 million increase related to the volume of KWHs purchased dueprimarily as a result of warmer weather in the third quarter 2016 as compared to lower natural gas prices.the corresponding period in 2015 resulting in higher customer demand.
Fuel and purchased power energy transactions do not have a significant impact on earnings since these fuel expenses are generally offset by fuel revenues through Georgia Power's fuel cost recovery mechanism. See 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:
| | | | | Third Quarter
2015 | | Third Quarter
2014 | | Year-to-Date 2015 |
| Year-to-Date 2014 | Third Quarter 2016 | | Third Quarter 2015 | | Year-to-Date 2016 | | Year-to-Date 2015 |
Total generation (billions of KWHs) | | 19 | | 19 | | 53 | | 55 | |
Total purchased power (billions of KWHs) | | 7 | | 6 | | 18 | | 16 | |
Total generation (in billions of KWHs) | | 20 | | 19 | | 53 | | 53 |
Total purchased power (in billions of KWHs) | | 7 | | 7 | | 19 | | 18 |
Sources of generation (percent) — | | |
| Coal | | 41 | | 45 | | 38 | | 45 | 44 | | 41 | | 37 | | 38 |
| Nuclear | | 22 | | 20 | | 23 | | 21 | 22 | | 22 | | 23 | | 23 |
| Gas | | 36 | | 34 | | 37 | | 32 | 34 | | 36 | | 38 | | 37 |
| Hydro | | 1 | | 1 | | 2 | | 2 | — | | 1 | | 2 | | 2 |
Cost of fuel, generated (cents per net KWH) — | | |
Cost of fuel, generated (in cents per net KWH) — | | |
| Coal | | 5.42 | | 4.19 | | 4.65 | | 4.49 | 3.16 | | 5.42 | | 3.32 | | 4.65 |
| Nuclear | | 0.86 | | 0.86 | | 0.76 | | 0.90 | 0.85 | | 0.86 | | 0.85 | | 0.76 |
| Gas | | 2.57 | | 3.41 | | 2.62 | | 3.84 | 2.61 | | 2.57 | | 2.27 | | 2.62 |
Average cost of fuel, generated (cents per net KWH) | | 3.37 | | 3.25 | | 2.98 | | 3.51 | |
Average cost of purchased power (cents per net KWH)(*) | | 4.54 | | 5.03 | | 4.50 | | 5.42 | |
Average cost of fuel, generated (in cents per net KWH) | | 2.47 | | 3.37 | | 2.34 | | 2.98 |
Average cost of purchased power (in cents per net KWH)(*) | | 4.57 | | 4.54 | | 4.46 | | 4.50 |
| |
| (*) | Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider. |
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel
In the third quarter 2015,2016, fuel expense was $706$575 million compared to $684$706 million in the corresponding period in 2014.2015. The increasedecrease was primarily due to a 29.4% increase in the average cost of coal per KWH generated, partially offset by a 24.6%26.7% decrease in the average cost of natural gasfuel per KWH generated primarily resulting from lower coal prices, partially offset by a 6.6% increase in the volume of KWHs generated due to warmer weather as compared to the corresponding period in 2015.
For year-to-date 2016, fuel expense was $1.39 billion compared to $1.74 billion in the corresponding period in 2015. The decrease was primarily due to a 21.5% decrease in the average cost of fuel per KWH generated primarily resulting from lower coal and an 11.5%natural gas prices and a 3.0% decrease in the volume of KWHs generated by coal.
For year-to-date 2015, fuel expense was $1.74 billion compared to $2.06 billion in the corresponding period in 2014. The decrease was primarily due to a 15.1% decrease in the average cost of fuel per KWH generated and an 18.5% decrease in the volume of KWHs generated by coal, partially offset by a 9.5% increase in the volume of KWHs generated by natural gas.
Purchased Power – Non-Affiliates
In the third quarter 2015,2016, purchased power expense from non-affiliates was $90$102 million compared to $77$90 million in the corresponding period in 2014.2015. The increase was primarily due to a 42.9%an 18.3% increase in the volume of KWHs purchased due to meet customer demand,warmer weather as compared to the corresponding period in 2015, partially offset by a 15.0%5.6% 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 $227$277 million compared to $219$227 million in the corresponding period in 2014.2015. The increase was primarily due to a 46.0%29.8% increase in the volume of KWHs purchased, to meet customer demand, partially offset by a 26.4%10.4% decrease in the average cost per KWH purchased primarily resulting from 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 electric service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the third quarter 2015,2016, purchased power expense from affiliates was $148$142 million compared to $172$148 million in the corresponding period in 2014. 2015. The decrease was the result of a 2.4% decrease in the volume of KWHs purchased as Georgia Power's units generally dispatched at a lower cost than other available Southern Company system resources, partially offset by a 1.8% increase in the average cost per KWH purchased.
For year-to-date 2015,2016, purchased power expense from affiliates was $411$392 million compared to $522$411 million in the corresponding period in 2014.2015. The decreases weredecrease was primarily the result of a 2.7% decrease in the volume of KWHs purchased due to decreasesthe lower market cost of 11.0% and 17.2% in the average cost per KWH purchased in the third quarter 2015 and year-to-date 2015, respectively, primarily resulting from lower natural gas prices.available energy as compared to Southern Company system resources.
Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $6 | | 1.3 | | $71 | | 5.3 |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $34 | | 7.4 | | $(12) | | (0.9) |
In the third quarter 2015,2016, other operations and maintenance expenses were $462$496 million compared to $456$462 million in the corresponding period in 2014.2015. The increase was primarily due to increases of $10a $26 million charge in connection with an employee compensationattrition plan associated with cost containment activities, an $11 million increase in scheduled generation outage and benefits including pensionmaintenance costs, and $5an $11 million primarily related to customer incentive and demand-side management costs due to additional customer participation, partially offset by a decrease of $10 millionincrease in transmission and distribution overhead line maintenance. See Note (F) to the Condensed Financial Statements herein for additional information related tomaintenance, partially offset by a $9 million decrease in pension costs.
For year-to-date 2015,2016, other operations and maintenance expenses were $1.41$1.39 billion compared to $1.33$1.41 billion in the corresponding period in 2014.2015. The increasedecrease was primarily due to increasesdecreases of $39 million in employee compensation and benefits including pension costs, $13$31 million in scheduled outage-relatedgeneration outage and maintenance costs and $17$28 million in pension costs, partially offset by a $26 million charge
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
primarilyin connection with an employee attrition plan associated with cost containment activities, an increase of $16 million in transmission and distribution overhead line maintenance, and an increase of $9 million for integrated transmission system billings.
See FUTURE EARNINGS POTENTIAL – "Other Matters" and Note (F) to the Condensed Financial Statements herein for additional information related to customer incentivethe employee attrition plan and demand-side managementpension costs, due to additional customer participation.respectively.
Depreciation and Amortization
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $3 | | 1.4 | | $5 | | 0.8 |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1 | | 0.5 | | $6 | | 0.9 |
For year-to-date 2015,2016, depreciation and amortization was $633$639 million compared to $628$633 million in the corresponding period in 2014.2015. The increase was primarily due to a $16$25 million increase related to additional plant in service and a $9 million increase in other cost of removal, partially offset by a $9decrease of $14 million decrease related to other costamortization of removalnuclear construction financing costs that was completed in December 2015 and a $3decrease of $13 million decrease duerelated to a change in useful lives.unit retirements.
Taxes Other Than Income Taxes
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(4) | | (3.6) | | $(18) | | (5.6) |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $7 | | 6.5 | | $9 | | 3.0 |
In the third quarter 2015,2016, taxes other than income taxes were $107$114 million compared to $111$107 million in the corresponding period in 2014.2015. For the year-to-date 2015,2016, taxes other than income taxes were $302$311 million compared to $320$302 million in the corresponding period in 2014.2015. The decrease in year-to-date 2015 wasincreases were primarily due to decreasesincreases in property taxes of $9$5 million and $8 million in municipal franchise fees related to lower retail revenuesthe third quarter and $7 millionyear-to-date 2016, respectively, as a result of an increase in property taxes.the assessed value of property.
Interest Expense, Net of Amounts Capitalized
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $2 | | 2.3 | | $10 | | 3.8 |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $8 | | 8.9 | | $18 | | 6.6 |
In the third quarter 2015,2016, interest expense, net of amounts capitalized was $90$98 million compared to $88$90 million in the corresponding period in 2014. 2015. The increase was primarily due to a $7 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.
For year-to-date 2015,2016, interest expense, net of amounts capitalized was $272$290 million compared to $262$272 million in the corresponding period in 2014.2015. The increase was primarily due to a $27 million increase in interest due to additional long-term borrowings from the FFB and higher interest rates on obligations for pollution control revenue bonds remarketed in 2015, partially offset by an increase of $5 million in AFUDC debt and a decrease of $4 million in interest due to lower interest rates on obligations for senior notes.
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Income Taxes
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $28 | | 8.3 | | $80 | | 12.2 |
In the third quarter 2016, income taxes were $365 million compared to $337 million in the corresponding period in 2015. For year-to-date 2016, income taxes were $737 million compared to $657 million in the corresponding period in 2015. The increases were primarily due to increased outstanding long-term debt borrowings from the FFB.
Income Taxes
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $20 | | 6.3 | | $(3) | | (0.5) |
In the third quarter 2015, income taxes were $337 million compared to $317 million in the corresponding period in 2014. For year-to-date 2015, income taxes were $657 million compared to $660 million in the corresponding period in 2014. The increase in the third quarter 2015 was primarily due to higher pre-tax earnings. The decrease in year-to-date 2015 was due to lower pre-tax earnings, partially offset by the recognition in 2014 of tax benefits related to emission allowances and state apportionment and lower non-taxable AFUDC equity.
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
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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. Demand for electricity for Georgia Power is partiallyprimarily 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. 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.
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, regional haze regulations, fine particulate matter National Ambient Air Quality Standards (NAAQS), and the Cross State Air Pollution Rule (CSAPR), and the eight-hour National Ambient Air Quality Standard (NAAQS) for ozone..
On April 25, 2016, in response to a June 12, 2015 U.S. Supreme Court opinion, the EPA published a final rule requiring affected states (including Georgia, Alabama, and Florida) to revise or remove state implementation plan (SIP) provisionsits supplemental finding regarding excess emissions that occur during periodsconsideration of SSM by no later than November 22, 2016. The ultimate impactcosts in support of the 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 decisionMATS rule. This finding that the EPA had failed to properly consider costs in its decision to regulate hazardous air pollutant emissions from electric generating units under thedoes not impact 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
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compliance requirements, costs, or deadlines, and all Georgia Alabama, and Florida. The court's decision leaves the emissions trading program in place and remands the rulePower units that are subject to the EPA for further action consistentMATS rule completed the measures necessary to achieve compliance with the court's decision. The court rejected all other pending challengesMATS rule by the applicable deadlines.
Also on April 25, 2016, the EPA issued proposed revisions to the rule.regional haze regulations. The ultimate impact of this decisionthe proposed revisions will depend on additional rulemakingtheir ultimate adoption, implementation, and any legal challenges and cannot be determined at this time.
On September 6, 2016, the EPA designated all remaining areas within Georgia Power's service territory as attainment for the 2012 annual fine particulate matter NAAQS.
On October 26, 2015,2016, the EPA published a more stringent eight-hour NAAQS for ozone. This new standard could potentially require additionalfinal rule that updates the CSAPR ozone season nitrogen oxide program, including revising ozone-season emissions budgets in Alabama and certain other states. The State of Georgia's emission controls, improvements in control efficiency, and operational fuel changes and could affectbudget was not affected by the siting of new generating facilities.revisions but interstate emissions trading is restricted unless the state decides to voluntarily adopt a reduced budget. The ultimate impact of this matter will depend on any legal challenges and implementation of the final rule 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' rule revising the definition of waters of the U.S. under the Clean Water Act (CWA) and the EPA's revisions to effluent guidelines.
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 became effective August 28, 2015, but on October 9, 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order staying implementation of the final rule. The ultimate impact of the final rule will depend on the outcome of this and other pending legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the rule and cannot be determined at this time.
On November 3, 2015, the EPA published final revisions to technology-based limits for certain wastestreams from steam electric power plants. These revisions impose stringent steam effluent guidelines and technology requirements for wastewater discharges at affected units. Compliance with these revisions could result in significant additional capital expenditures and could affect future unit retirement and replacement decisions. The ultimate impact of these revisions will depend on any legal challenges and implementation ofat the final revisionsstate level and cannot be determined at this time.
Coal Combustion Residuals
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters –Environmental Statutes and Regulations – Coal Combustion Residuals" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA's regulation of CCR.
On 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 October 26, 2016, the Georgia Department of Natural Resources approved amendments to its state solid waste regulations to incorporate the requirements of the EPA's Disposal of Coal Combustion Residuals from Electric Utilities final ruleRule (CCR Rule) in the Federal Register, which became effective on October 19, 2015. Based on initial cost estimatesand establish additional requirements for closure in placeall of Georgia Power's onsite storage units consisting of landfills and groundwater monitoringsurface impoundments. The final State of ash ponds pursuantGeorgia regulations are not anticipated to the CCR Rule, during the second quarter 2015, Georgia Power recorded incremental asset retirement obligations (ARO) of approximately $82 million related to the CCR Rule. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, Georgia Power expects to continue to periodically update these estimates. The ultimatehave 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.Rule. See Note (A) to the Condensed Financial Statements herein for additional information regarding Georgia Power's AROsasset retirement obligations (ARO) as of September 30, 2015.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA's proposed regulation of CO2 from fossil-fuel-fired electric generating units.
On October 23, 2015, two final actions by the EPA that would limit CO2 emissions from fossil fuel-fired electric generating units were published in the Federal Register. One of the final actions contains specific emission standards governing CO2 emissions from new, modified, and reconstructed units. The other final action 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, a proposed federal plan and proposed model rule were published 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, including legal challenges filed by Georgia Power; 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 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 and 4 are being collected through the NCCR tariff and fuel costs are collected through separate fuel cost recovery tariffs. See "Nuclear Construction" herein and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the NCCR tariff. Also see "Fuel Cost Recovery" herein for additional information regarding fuel cost recovery.
Pursuant to the terms and conditions of a settlement agreement related to Southern Company's acquisition of Southern Company Gas approved by the Georgia PSC on April 14, 2016, Georgia Power's 2013 ARP will continue in effect until December 31, 2019, and Georgia Power will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, Georgia Power and Atlanta Gas Light Company (collectively, Utilities) each will retain their respective merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, such net merger savings applicable to each utility will be shared on a 60/40 basis between their respective customers and the Utilities; thereafter, all merger savings will be retained by customers. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.information regarding the 2013 ARP.
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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 owns the RECs retains the right to use them.
On October 4, 2016, two 30-MW solar generating facilities at Fort Gordon and Fort Stewart Army bases began commercial operation. These solar generating facilities were approved by the Georgia PSC in 2014 and provide for the purchase2014.
Integrated Resource Plan
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Integrated Resource Plan" 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 MWsin Item 7 of the 515 MWs of contracted capacity will be purchased from solar facilities owned or under development by Southern Power.Form 10-K for additional information regarding Georgia Power's triennial Integrated Resource Plan (2016 IRP).
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 byJuly 28, 2016, the Georgia PSC on April 15, 2015.voted to approve the 2016 IRP including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 combustion turbine (17 MWs), as well as the decertification of the Intercession City unit (143 MWs total capacity). On August 2, 2016, the Plant Mitchell and Plant Kraft units were retired. On August 31, 2016, Georgia Power also entered into an energy-only PPA forsold its 33% ownership interest in the remaining 21 MWs from the same facility.Intercession City unit to Duke Energy Florida, Inc.
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,comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and operatePlant Hammond Units 1 through 4.
The Georgia PSC approved the reclassification of the remaining net book value of Plant Mitchell Unit 3 and costs associated with materials and supplies remaining at the unit retirement date to a regulatory asset. Recovery of the unit's net book value will continue through December 31, 2019, as provided in the 2013 ARP. The timing of the recovery of the remaining balance of the unit's net book value as of December 31, 2019 and costs associated with materials and supplies remaining at the unit retirement date will be deferred for consideration in Georgia Power's base rate case required to be filed by July 1, 2019.
The Georgia PSC also approved the Renewable Energy Development Initiative to procure an additional 1,200 MWs of renewable resources primarily utilizing market-based prices established through a competitive bidding process with expected in-service dates between 2018 and 2021. Additionally, 200 MWs of self-build capacity for use by Georgia Power was approved, as well as consideration for no more than 200 MWs of capacity as part of a renewable commercial and industrial program.
The Georgia PSC also approved recovery of costs up to 46-MW solar generation facility$99 million through June 30, 2019 to preserve the nuclear option at a U.S. Marine Corps basefuture generation site in Albany, GeorgiaStewart County, Georgia. The timing of cost recovery will be determined by the end of 2016.
Rate Plans
In accordance with the terms of the 2013 ARP, on October 2, 2015, Georgia Power filed the following tariff adjustments with the Georgia PSC to become effective January 1, 2016 pending its approval:
increase in traditionala future base tariffs by approximately $49 million;
increase in the environmental compliance cost recovery tariff by approximately $75 million;
increase in the demand-side management tariffs by approximately $7 million; and
increase in the municipal franchise fee tariff by approximately $13 million.
rate case. The ultimate outcome of this matter cannot be determined at this time.
Integrated Resource PlanFuel Cost Recovery
To comply with the April 16, 2015 effective dateSee MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" of Georgia Power in Item 7 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 primaryForm 10-K for information regarding 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. On October 13, 2015, Plant Kraft Units 1 through 4 (316 MWs) were retired.
Fuel Cost Recoverycost recovery.
Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. On September 18, 2015, Georgia Power filed a rate request withMay 17, 2016, the Georgia PSC approved Georgia Power's request to lower totaldecrease fuel rates by 15% effective June 1, 2016, which will
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reduce annual billings by approximately $268 million effective January 1, 2016. The$313 million. Georgia PSCPower is currently scheduled to vote onfile its next fuel case by February 28, 2017.
Storm Damage Recovery
As of September 30, 2016, the balance in Georgia Power's regulatory asset related to storm damage was $94 million. During October 2016, Hurricane Matthew caused significant damage to Georgia Power's transmission and distribution facilities. The total amount of restoration costs related to this matter onhurricane is estimated to be between $130 million and $155 million, which will be charged to capital accounts or to the storm damage reserve. Georgia Power is accruing $30 million annually through December 15, 2015.31, 2019, as provided in the 2013 ARP, to the storm damage reserve to cover the operating and maintenance costs of damages from major storms to its transmission and distribution facilities, which is recoverable through base rates. The ultimate outcomerate of recovery of storm damage costs after December 31, 2019 is expected to be adjusted in Georgia Power's base rate case required to be filed by July 1, 2019. As a result of this matter cannot be determined at this time.
Fuel cost recovery revenuesregulatory treatment, costs related to storms are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not expected to have a significant effectmaterial impact on Georgia Power's revenues or net income, but will affect cash flow.financial statements. See Note (B)1 to the Condensed Financial Statements under "Retail Regulatory Matters –financial statements of Georgia Power – Fuel Costunder "Storm Damage Recovery" hereinin Item 8 of the Form 10-K for additional information.information regarding Georgia Power's storm damage reserve.
Nuclear Construction
See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the construction of Plant Vogtle Units 3 and 4, Vogtle Construction Monitoring (VCM) reports, the NCCR tariff, the Vogtle Construction Litigation (as defined below), and 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,
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construct, and test Plant Vogtle Units 3 and 4. Current anticipated in-service dates for Plant Vogtle Units4 (Vogtle 3 and 4 are the second quarter 2019 and the second quarter 2020, respectively.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, 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. (S&W) (formerly known as Stone & Webster, Inc.)WECTEC under the Vogtle 3 and 4 Agreement arewere originally guaranteed by Toshiba Corporation (Toshiba)(Westinghouse's parent company) and The Shaw Group Inc. (Shaw Group) (a(which is now a subsidiary of Chicago Bridge & Iron Company, N.V. (CBCB&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
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Agreement under certain circumstances, including certain Vogtle Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.
In 2009, the NRC issued an Early Site Permit and Limited Work Authorization which allowed limited workGeorgia PSC voted 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 may arise 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. 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. On March 10, 2015, the U.S. Court of Appeals for the District of Columbia Circuit affirmed the decision of the U.S. District Court for the District of Columbia, which had dismissed the Contractor's suit, ruling that the proper venue is the U.S. District Court for the Southern District of Georgia. The case is pending in the U.S. District Court for the Southern District of Georgia (Vogtle Construction Litigation). 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 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
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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).
On October 27, 2015, Westinghouse and CB&I announced an agreement under which Westinghouse or one of its affiliates will acquire S&W from CB&I, subject to satisfaction of certain conditions to closing. In addition, on October 27, 2015, Westinghouse and the Vogtle Owners entered into a term sheet (Term Sheet) setting forth the terms of a settlement agreement to resolve disputes between the Vogtle Owners and the Contractor under the Vogtle 3 and 4 Agreement, including the Vogtle Construction Litigation.
In accordance with the Term Sheet: (i) the Vogtle Owners and the Contractor will enter into mutual releases of all open claims which have been asserted, including any potential extension of such open claims, as well as future claims based on events occurring prior to the effective date of the release that potentially could have been asserted under the original terms of the Vogtle 3 and 4 Agreement, including the Vogtle Construction Litigation, which will be dismissed with prejudice; (ii) the Vogtle 3 and 4 Agreement will be amended to 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; (iii) enhanced dispute resolution procedures will be implemented; (iv) the guaranteed substantial completion dates under the Vogtle 3 and 4 Agreement will be revised to match the current estimated in-service dates of June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4 (as discussed below); (v) delay liquidated damages will now commence from the current estimated nuclear fuel loading date for each unit, which is December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4, rather than the original guaranteed substantial completion dates under the Vogtle 3 and 4 Agreement; and (vi) Georgia Power, based on its ownership interest, will pay to the Contractor and capitalize to the project cost approximately $350 million, of which approximately $120 million has been paid previously under the dispute resolution procedures of the Vogtle 3 and 4 Agreement. In addition, the Vogtle Owners and the Contractor resolved 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 proposed settlement and in connection with Westinghouse's proposed acquisition of S&W: (i) the Vogtle Owners will terminate the parent guarantee of Shaw Group with respect to certain obligations of S&W, subject to obtaining the consent of the DOE under loan guarantee agreements relating to Plant Vogtle Units 3 and 4, while the parent guarantee of Toshiba with respect to certain obligations of Westinghouse will remain in place; (ii) Westinghouse will make provisions to engage Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor; and (iii) the Vogtle Owners, CB&I, and Shaw Group also will enter into mutual releases of any and all claims against each other arising out of thecertify construction of Plant Vogtle Units 3 and 4.
The settlement of the pending disputes between the Vogtle Owners and the Contractor, including the Vogtle Construction Litigation, is subject to consummation of Westinghouse's proposed acquisition of S&W. If this proposed acquisition is not completed, the Vogtle Construction Litigation will continue and the Contractor may from time to time continue to assert that it is entitled to additional payments with respect to its allegations, any of which could be substantial.
Georgia Power will submit the ultimate settlement agreement terms and the related amendments to the Vogtle 3 and 4 Agreement to the Georgia PSC for its review.
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 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 to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate until the completion of Plant Vogtle Unit 3 or earlier if deemed appropriate by the Georgia PSC and Georgia Power.
On April 15, 2015, the Georgia PSC issued a procedural order in connection with the twelfth VCM report, which included a requested amendment (Requested Amendment) to the Plant Vogtle Units 3 and 4 certificate to reflect the
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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 owner-related costs, which include approximately $10 million per month, including property taxes, oversight costs, compliance costs, and other operational readiness costs to include the estimated owner's costs associated with the proposed 18-month Contractor delay and to increase the estimated total in-service capital cost of Plant Vogtle Units 3 and 4 to $5.0 billion. Pursuant to thisthe Georgia PSC's procedural order, the Georgia PSC deemed the Requested Amendment unnecessary and withdrawn until the completion of construction of Plant Vogtle Unit 3 consistent with the 2013 Stipulation. The Georgia PSC recognized that the certified cost and the 2013 Stipulation do not constitute a cost recovery cap. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by Georgia Power in excess of the certified amount will be included in rate base, provided Georgia Power shows the costs to be reasonable and prudent. Financing costs up
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 certified amountVogtle 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 be collected throughcommence from the NCCR tariff untilcurrent 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 units are placed in service, while financing costs on any construction-related costs in excessContractor and capitalize to the project cost approximately $350 million, of which approximately $256 million had been paid as of September 30, 2016. In addition, the Contractor Settlement Agreement provides for the resolution of other open existing items relating to the scope of the $4.4 billion certified amount are expected to be recovered through AFUDC.project under the Vogtle 3 and 4 Agreement, including cyber security, for which costs were reflected in Georgia Power's previously disclosed in-service cost estimate. Further, as part of the settlement and Westinghouse's acquisition of WECTEC: (i) Westinghouse engaged Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor; and (ii) the Vogtle Owners, CB&I, and The Shaw Group Inc. entered into mutual releases of any and all claims arising out of events or circumstances in connection with the construction of Plant Vogtle Units 3 and 4 that occurred on or before the date of the Contractor Settlement Agreement. On January 5, 2016, the Vogtle Construction Litigation was dismissed with prejudice.
The Georgia PSC has approved twelvefourteen VCM reports covering the periods through December 31, 2014,2015, including construction capital costs incurred, which through that date totaled $3.0$3.3 billion. On August 28, 2015,January 21, 2016, Georgia Power submitted the Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement
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to the Georgia PSC for its review. In accordance with the Georgia PSC's subsequent order, on April 5, 2016, Georgia Power filed its thirteenthsupplemental 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.
On October 20, 2016, Georgia Power and the Georgia PSC Staff entered into a settlement agreement (Vogtle Cost Settlement Agreement) resolving the following prudence matters: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report will be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement is reasonable and prudent and none of the amounts paid or to be paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) financing costs on verified and approved capital costs will be deemed prudent provided they are incurred prior to December 31, 2019 and December 31, 2020 for Plant Vogtle Units 3 and 4, respectively; and (iv) (a) the in-service capital cost forecast will be adjusted to $5.680 billion (Revised Forecast), which includes a contingency of $240 million above Georgia Power's current forecast of $5.440 billion, (b) capital costs incurred up to the Revised Forecast will be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, and (c) Georgia Power would have the burden to show that any capital costs above the Revised Forecast are reasonable and prudent. Under the terms of the Vogtle Cost Settlement Agreement, the certified in-service capital cost for purposes of calculating the NCCR tariff will remain at $4.418 billion. Construction capital costs above $4.418 billion will accrue AFUDC through commercial operation. The ROE used to calculate the NCCR tariff will be reduced from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016. For purposes of the AFUDC calculation, the ROE on costs between $4.418 billion and $5.440 billion will also be 10.00% and the ROE on any amounts above $5.440 billion would be Georgia Power's average cost of long-term debt. If the Georgia PSC adjusts Georgia Power's ROE rate setting point in a rate case prior to Plant Vogtle Units 3 and 4 being placed into retail rate base, then the ROE for purposes of calculating both the NCCR tariff and AFUDC will likewise be 95 basis points lower than the revised ROE rate setting point. If Plant Vogtle Units 3 and 4 are not commercially operational by December 31, 2020, then (i) the ROE for purposes of calculating the NCCR tariff will be reduced an additional 300 basis points, and may, at the Georgia PSC's discretion, be accrued to be used for the benefit of customers, until such time as the units reach commercial operation and (ii) the ROE used to calculate AFUDC will be Georgia Power's average cost of long-term debt.
Under the terms of the Vogtle Cost Settlement Agreement, Plant Vogtle Units 3 and 4 will be placed into retail rate base on December 31, 2020 or upon reaching commercial operation, whichever is later. The Georgia PSC will determine for retail ratemaking purposes the process of transitioning Plant Vogtle Units 3 and 4 from a construction project to an operating plant no later than Georgia Power's base rate case required to be filed by July 1, 2019.
The Vogtle Cost Settlement Agreement is subject to approval by the Georgia PSC, which is scheduled to vote on this matter on December 20, 2016. Accordingly, the terms of the Vogtle Cost Settlement Agreement are subject to change and the terms of any final agreement approved by the Georgia PSC may differ materially from the terms of the Vogtle Cost Settlement Agreement. If approved, the Vogtle Cost Settlement Agreement is expected to reduce Georgia Power's revenues for the years 2016 through 2020 by a total of approximately $325 million ($115 million reduction in net income).
On August 31, 2016, Georgia Power filed the fifteenth VCM report with the Georgia PSC covering the period from January 1 through June 30, 2015, which requested2016 requesting approval for an additional $148of $141 million of construction capital costs incurred during that periodperiod. Georgia Power's CWIP balance for Plant Vogtle Units 3 and reflected estimated4 was $3.8 billion as of September 30, 2016. Estimated financing costs during the construction period to total approximately $2.4 billion.billion, of which $1.2 billion had been incurred through September 30, 2016.
On November 1, 2016, Georgia Power will continue to incur financing costssubmitted its 2017 NCCR tariff filing requesting that the current NCCR tariff rate remain effective for 2017 if the Georgia PSC approves the Vogtle Cost Settlement Agreement. As required under the current order, Georgia Power concurrently submitted a 2017 NCCR tariff rate calculated using the current authorized 10.95% ROE, which would result in an increase of approximately $30 million per month until$70 million.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, are placed in service.
On October 30, 2015, Georgia Power filed to increaseat the NCCR tariff by approximately $19 million, effective January 1, 2016, pending Georgia PSC approval.
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 issuesmatters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Vogtle Owners or the Contractor or to both.
As construction continues, the risk remains that ongoing challenges with Contractor performance including additional challenges in itslabor productivity, fabrication, delivery, assembly, delivery, and installation of the shield buildingplant systems, structures, and structural modules, delays in the receipt of the remaining permits necessary for the operation of Plant Vogtle Units 3 and 4,components, or other issues could arise and may further impact project schedule and cost. Contractor performance and progress in recent months, primarily associated with Unit 3, has resulted in additional current schedule pressure of approximately three to four months and has increased the likelihood of further schedule impacts to that unit. Georgia Power expects the Contractor to employ mitigation efforts to maintain the current project schedule and believes the Contractor is responsible for any related costs under the Vogtle 3 and 4 Agreement. Should Unit 3 be placed in service after June 2019, Georgia Power estimates its financing costs to be approximately $22 million per month. Additionally, Georgia Power estimates its owner's costs to be approximately $2 million per month, net of delay liquidated damages and certain incentive payments that would no longer be required to be paid per the Contractor Settlement Agreement. The Contractor's progress on Unit 4 indicates that the current estimated in-service date of June 2020 remains achievable. In addition, the IRS has allocated production tax credits to each of Plant Vogtle Units 3 and 4, which require the applicable unit to be placed in service before 2021.
Future claims by the Contractor or Georgia Power (on behalf of the Vogtle Owners) could arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement but alsoand, under the enhanced dispute resolution procedures, may be resolved through litigation.litigation after the completion of nuclear fuel load for both units.
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
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Georgia Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion
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of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
Georgia Power regularly evaluates its operations and costs. Primarily in response to changing customer expectations and payment patterns, including electronic payments and alternative payment locations, and on-going efforts to increase overall operating efficiencies, Georgia Power initiated cost containment activities throughout the enterprise in July 2016, including the announced closure of 104 local offices and an employee attrition plan affecting approximately 300 positions. Charges associated with the cost containment activities are not expected to have a material impact on Georgia Power's results of operations, financial position, or cash flows. The cost containment activities are expected to reduce operating costs in 2017.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Georgia Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Georgia Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Georgia Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Georgia Power in Item 7 of the Form 10-K for a complete discussion of Georgia Power's critical accounting policies and estimates related to Electric Utility Regulation, 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 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.
Georgia Power previously recorded AROs as a result of state requirements in Georgia which closely align with the requirements of the CCR Rule discussed above. The cost estimates are based on information using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure in place. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential
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for closing ash ponds prior to the end of their currently anticipated useful life, Georgia Power expects to continue 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.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. 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,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. 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 (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions. Most significantly, entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. Georgia Power currently recognizes any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016. Early adoption is permitted and Georgia Power intends to adopt the ASU in the fourth quarter 2015.2016. The ASUadoption is requirednot expected to be applied retrospectively to all periods presented beginning in the year of adoption. Georgia Power currently reflects unamortized debt issuance costs in other deferred charges and assets 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 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 September 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 Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $2.16 billion for the first nine months of 2015 compared to $2.07 billion for the corresponding period in 2014. The increase was primarily due to increased fuel cost recovery, partially offset by lower deferred taxes. Net cash used for investing activities totaled $1.39 billion for the first nine months of 2015 compared to $1.46 billion for the corresponding period in 2014 primarily related to installation of equipment to comply with environmental standards and construction of transmission and distribution facilities. Net cash used for financing activities totaled $711 million for the first nine months of 2015 compared to $577 million in the corresponding period in 2014. The increase in cash used for financing activities is primarily due to an increase in common stock dividends, lower borrowings from the FFB for the construction of Plant Vogtle 3 and 4, and a redemption and a maturity of senior notes in 2015. Fluctuations in cash flow 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 nine months of 2015 include increases of $778 million in property, plant, and equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities and an increase in other regulatory assets, deferred of $322 million primarily related to AROs and deferred plant retirement costs.
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"Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $2.26 billion for the first nine months of 2016 compared to $2.16 billion for the corresponding period in 2015. The increase was primarily due to the timing of vendor payments. Net cash used for investing activities totaled $1.76 billion for the first nine months of 2016 compared to $1.39 billion for the corresponding period in 2015 primarily related to installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities. Net cash used for financing activities totaled $522 million for the first nine months of 2016 compared to $711 million in the corresponding period in 2015. The decrease in cash used for financing activities is primarily due to higher capital contributions received from Southern Company and senior note issuances, partially offset by higher common stock dividends and lower borrowings from the FFB for construction of Plant Vogtle Units 3 and 4. 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 nine months of 2016 include an increase in property, plant, and equipment of $1.1 billion to comply with environmental standards and construction of generation, transmission, and distribution facilities and increases in current and deferred ARO liabilities of $638 million and other regulatory assets, deferred of $378 million primarily related to changes in ash pond closure strategy. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Residuals" herein for additional information regarding changes in ash pond closure strategy.
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 $1.4 billion$458 million will be required through September 30, 20162017 to fund maturities of long-term debt. See "Sources"Sources of Capital"Capital" herein for additional information.
Georgia Power's construction program is currently estimated to total $2.6 billion for 2017, $2.7 billion for 2018, $2.3 billion for 2019, $2.2 billion for 2020, and $1.8 billion for 2021. These amounts include expenditures of approximately $0.6 billion for 2017, $0.7 billion for 2018, $0.4 billion for 2019, and $0.1 billion for 2020 to continue and complete construction of Plant Vogtle Units 3 and 4. These estimated expenditures do not include potential compliance costs that may arise from the EPA's final rules and guidelines or subsequently approved state plans that would limit CO2 emissions from existing, new, modified, or reconstructed fossil-fuel-fired electric generating units.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Sources of Capital
Except as described below with respect to the DOE loan guarantees, Georgia Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, external security issuances, term loans, and equity contributions from Southern Company. 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 September 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 September 30, 2015,2016, Georgia Power's current liabilities exceeded current assets by $1.45 billion$656 million primarily due to approximately $1.49 billionscheduled maturities of long-term debt due within one year and notes payable.debt. Georgia Power 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
At September 30, 2015,2016, Georgia Power had approximately $85$47 million of cash and cash equivalents. CommittedGeorgia Power's committed credit arrangementsarrangement with banks at September 30, 2015 were as follows:
|
| | | | | | | | | | | | | | | | | | |
| Expires | | | | Due Within One Year |
| 2020 | | Total | | Unused | | Term Out | | No Term Out |
| (in millions) | | (in millions) | | (in millions) |
| $ | 1,750 |
| | $ | 1,750 |
| | $ | 1,732 |
| | $ | — |
| | $ | — |
|
See Note 6 to the financial statements2016 was $1.75 billion of Georgia Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
As reflected in the table above, in August 2015, Georgia Power amended and restated its multi-yearwhich $1.73 billion was unused. This credit arrangement which, among other things, extended the maturity date from 2018 toexpires in 2020. Georgia Power increased its borrowing ability by $150 million under its facility maturing in 2020 and terminated its aggregate $150 million facilities maturing in 2016.
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 September 30, 2015 was approximately $872 million. In addition, at September 30, 2015, Georgia Power had $121 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.
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 a 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.
Subject to applicable market conditions, Georgia Power expects to renew or replace this credit arrangement, as needed, prior to expiration. In connection therewith, Georgia Power may extend the maturity date and/or increase or decrease the lending commitments thereunder.
See Note 6 to the financial statements of Georgia Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
A portion of the unused credit with banks is allocated to provide liquidity support to Georgia Power's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of September 30, 2016 was approximately $868 million. In addition, at September 30, 2016, Georgia Power had $250 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.
Georgia Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Georgia Power and the other traditional electric operating
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
companies. Proceeds from such issuances for the benefit of Georgia Power are loaned directly to Georgia Power. The obligations of each company under these arrangements are several and there is no cross-affiliate credit support.
Details of short-term borrowings were as follows:
|
| | | | | | | | | | | | | | | | | | |
| | | Short-term Debt at September 30, 2015 | | 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 | | $ | 130 |
| | 0.5 | % | | $ | 193 |
| | 0.4 | % | | $ | 325 |
|
|
| | | | | | | | | | | | | | | | | | |
| | | Short-term Debt at September 30, 2016 | | Short-term Debt During the Period (*) |
| | |
Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) | | | | (in millions) |
| Commercial paper | | $ | 95 |
| | 0.8 | % | | $ | 59 |
| | 0.8 | % | | $ | 197 |
|
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 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.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, and construction of new generation at Plant Vogtle Units 3 and 4.
The maximum potential collateral requirements under these contracts at September 30, 20152016 were as follows:
| | | Credit Ratings | Maximum Potential
Collateral
Requirements | Maximum Potential
Collateral
Requirements |
| | (in millions) | (in millions) |
| At BBB- and/or Baa3 | $ | 102 |
| $ | 93 |
|
| Below BBB- and/or Baa3 | 1,287 |
| $ | 1,222 |
|
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, a credit rating downgrade could impact the ability of Georgia Power to access capital markets and would be likely to impact the cost at which it does so.
On August 17, 2015, S&P downgraded the consolidated long-term issuer rating of Southern Company (including Georgia Power) to A- from A. S&P revised its credit rating outlook from negative to stable. Separately, on August 24, 2015, S&P revised its credit rating outlook from stable to negative following the announcement of the Merger.
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 generating facilities or electric vehicle charging infrastructure, or payments under PPAs served by solar or wind generating 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
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
repay a portion of Georgia Power's short-term indebtedness, and for 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 since 2013.matured.
In June 2015,2016, Georgia Power made additional borrowings under the FFB Credit Facility in an aggregate principal amount of $600 million. The$300 million at a 2.571% interest rate applicable to the $600 million principal amount is 3.283% for an interest period that extends tothrough 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 a payment of approximately $6 million, which will be amortized to interest expense over 10 years.
In July 2015, $97.925 million aggregate principal amount of the Development Authority of Putnam County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Branch Project), First Series 1996, First Series 1997, Second Series 1997, and First Series 1998 were redeemed.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In August 2015,2016, Georgia Power's $400$200 million aggregate principal amount of Series 2012C 0.75%2013C Floating Rate Senior Notes matured.
Also in August 2015, in connection with optional tenders, Georgia Power repurchased and reoffered to the public $94.6 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2009 and $10 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2013.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Georgia Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
GULF POWER COMPANY
GULF POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
| | | | For the Three Months
Ended September 30, | | For the Nine Months
Ended September 30, | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2015 |
| 2014 | | 2015 | | 2014 | 2016 |
| 2015 | | 2016 | | 2015 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | | | | | | | | |
| Retail revenues | $ | 363 |
| | $ | 366 |
| | $ | 983 |
| | $ | 979 |
| $ | 377 |
| | $ | 363 |
| | $ | 978 |
| | $ | 983 |
|
| Wholesale revenues, non-affiliates | 30 |
| | 34 |
| | 82 |
| | 104 |
| 17 |
| | 30 |
| | 48 |
| | 82 |
|
| Wholesale revenues, affiliates | 17 |
| | 21 |
| | 52 |
| | 97 |
| 23 |
| | 17 |
| | 59 |
| | 52 |
|
| Other revenues | 19 |
| | 17 |
| | 53 |
| | 49 |
| 19 |
| | 19 |
| | 51 |
| | 53 |
|
| Total operating revenues | 429 |
| | 438 |
| | 1,170 |
| | 1,229 |
| 436 |
| | 429 |
| | 1,136 |
| | 1,170 |
|
| Operating Expenses: | | | | | | | | | | | | | | |
| Fuel | 143 |
| | 164 |
| | 375 |
| | 478 |
| 141 |
| | 143 |
| | 342 |
| | 375 |
|
| Purchased power, non-affiliates | 26 |
| | 27 |
| | 76 |
| | 57 |
| 33 |
| | 26 |
| | 95 |
| | 76 |
|
| Purchased power, affiliates | 4 |
| | 4 |
| | 22 |
| | 19 |
| 3 |
| | 4 |
| | 9 |
| | 22 |
|
| Other operations and maintenance | 90 |
| | 85 |
| | 274 |
| | 251 |
| 86 |
| | 90 |
| | 239 |
| | 274 |
|
| Depreciation and amortization | 40 |
| | 38 |
| | 100 |
| | 109 |
| 49 |
| | 40 |
| | 129 |
| | 100 |
|
| Taxes other than income taxes | 35 |
| | 31 |
| | 91 |
| | 84 |
| 34 |
| | 35 |
| | 93 |
| | 91 |
|
| Total operating expenses | 338 |
| | 349 |
| | 938 |
| | 998 |
| 346 |
| | 338 |
| | 907 |
| | 938 |
|
| Operating Income | 91 |
| | 89 |
| | 232 |
| | 231 |
| 90 |
| | 91 |
| | 229 |
| | 232 |
|
| Other Income and (Expense): | | | | | | | | | | | | | | |
| Allowance for equity funds used during construction | 3 |
| | 3 |
| | 11 |
| | 8 |
| |
| Interest expense, net of amounts capitalized | (12 | ) | | (13 | ) | | (38 | ) | | (39 | ) | (11 | ) | | (12 | ) | | (36 | ) | | (38 | ) |
| Other income (expense), net | (1 | ) | | (1 | ) | | (3 | ) | | (2 | ) | (2 | ) | | 2 |
| | (4 | ) | | 8 |
|
| Total other income and (expense) | (10 | ) | | (11 | ) | | (30 | ) | | (33 | ) | (13 | ) | | (10 | ) | | (40 | ) | | (30 | ) |
| Earnings Before Income Taxes | 81 |
| | 78 |
| | 202 |
| | 198 |
| 77 |
| | 81 |
| | 189 |
| | 202 |
|
| Income taxes | 31 |
| | 29 |
| | 75 |
| | 74 |
| 30 |
| | 31 |
| | 74 |
| | 75 |
|
| Net Income | 50 |
| | 49 |
| | 127 |
| | 124 |
| 47 |
| | 50 |
| | 115 |
| | 127 |
|
| Dividends on Preference Stock | 2 |
| | 2 |
| | 7 |
| | 7 |
| 2 |
| | 2 |
| | 7 |
| | 7 |
|
| Net Income After Dividends on Preference Stock | $ | 48 |
| | $ | 47 |
| | $ | 120 |
| | $ | 117 |
| $ | 45 |
| | $ | 48 |
| | $ | 108 |
| | $ | 120 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months
Ended September 30, | | For the Nine Months
Ended September 30, |
| | 2015 | | 2014 | | 2015 | | 2014 |
| | (in millions) | | (in millions) |
| Net Income | $ | 50 |
| | $ | 49 |
| | $ | 127 |
| | $ | 124 |
|
| Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
|
| Comprehensive Income | $ | 50 |
| | $ | 49 |
| | $ | 127 |
| | $ | 124 |
|
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.
GULF POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
|
| | | | | | | |
| | For the Nine Months
Ended September 30, |
| | 2015 | | 2014 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 127 |
| | $ | 124 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 105 |
| | 115 |
|
| Deferred income taxes | 58 |
| | 29 |
|
| Allowance for equity funds used during construction | (11 | ) | | (8 | ) |
| Other, net | 16 |
| | 5 |
|
| Changes in certain current assets and liabilities — | | | |
| -Receivables | 18 |
| | (46 | ) |
| -Fossil fuel stock | 18 |
| | 44 |
|
| -Prepaid income taxes | 31 |
| | 9 |
|
| -Other current assets | 1 |
| | 3 |
|
| -Accounts payable | (13 | ) | | 10 |
|
| -Accrued taxes | 46 |
| | 22 |
|
| -Accrued compensation | (3 | ) | | 5 |
|
| -Over recovered regulatory clause revenues | 10 |
| | 7 |
|
| -Other current liabilities | 8 |
| | 5 |
|
| Net cash provided from operating activities | 411 |
| | 324 |
|
| Investing Activities: | | | |
| Property additions | (189 | ) | | (254 | ) |
| Cost of removal, net of salvage | (9 | ) | | (9 | ) |
| Change in construction payables | (29 | ) | | 2 |
|
| Other investing activities | (6 | ) | | (7 | ) |
| Net cash used for investing activities | (233 | ) | | (268 | ) |
| Financing Activities: | | | |
| Decrease in notes payable, net | (34 | ) | | (44 | ) |
| Proceeds — | | | |
| Common stock issued to parent | 20 |
| | 50 |
|
| Pollution control revenue bonds | 13 |
| | 42 |
|
| Senior notes | — |
| | 200 |
|
Redemptions and repurchases —
| | | |
| Pollution control revenue bonds | (13 | ) | | (29 | ) |
| Senior notes | (60 | ) | | — |
|
| Payment of preference stock dividends | (7 | ) | | (7 | ) |
| Payment of common stock dividends | (98 | ) | | (92 | ) |
| Other financing activities | 3 |
| | (1 | ) |
| Net cash provided from (used for) financing activities | (176 | ) | | 119 |
|
| Net Change in Cash and Cash Equivalents | 2 |
| | 175 |
|
| Cash and Cash Equivalents at Beginning of Period | 39 |
| | 22 |
|
| Cash and Cash Equivalents at End of Period | $ | 41 |
| | $ | 197 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
| Interest (net of $5 and $4 capitalized for 2015 and 2014, respectively) | $ | 27 |
| | $ | 29 |
|
| Income taxes, net | (37 | ) | | 36 |
|
| Noncash transactions — Accrued property additions at end of period | 17 |
| | 35 |
|
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.
GULF POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At September 30,
2015 | | At December 31,
2014 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 41 |
| | $ | 39 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 100 |
| | 73 |
|
| Unbilled revenues | | 68 |
| | 58 |
|
| Under recovered regulatory clause revenues | | 17 |
| | 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 | | 84 |
| | 101 |
|
| Materials and supplies, at average cost | | 57 |
| | 56 |
|
| Other regulatory assets, current | | 81 |
| | 74 |
|
| Prepaid expenses | | 13 |
| | 40 |
|
| Other current assets | | 1 |
| | 2 |
|
| Total current assets | | 473 |
| | 516 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 4,640 |
| | 4,495 |
|
| Less accumulated provision for depreciation | | 1,273 |
| | 1,296 |
|
| Plant in service, net of depreciation | | 3,367 |
| | 3,199 |
|
| Other utility plant, net | | 64 |
| | — |
|
| Construction work in progress | | 407 |
| | 465 |
|
| Total property, plant, and equipment | | 3,838 |
| | 3,664 |
|
| Other Property and Investments | | 15 |
| | 15 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 61 |
| | 56 |
|
| Other regulatory assets, deferred | | 430 |
| | 416 |
|
| Other deferred charges and assets | | 44 |
| | 41 |
|
| Total deferred charges and other assets | | 535 |
| | 513 |
|
| Total Assets | | $ | 4,861 |
| | $ | 4,708 |
|
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2016 | | 2015 | | 2016 | | 2015 |
| | (in millions) | | (in millions) |
| Net Income | $ | 47 |
| | $ | 50 |
| | $ | 115 |
| | $ | 127 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
| Changes in fair value, net of tax of $-, $-, $(3), and $-, respectively | — |
| | — |
| | (4 | ) | | — |
|
| Total other comprehensive income (loss) | — |
| | — |
| | (4 | ) | | — |
|
| Comprehensive Income | $ | 47 |
| | $ | 50 |
| | $ | 111 |
| | $ | 127 |
|
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 September 30,
2015 | | At December 31,
2014 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Notes payable | | $ | 76 |
| | $ | 110 |
|
| Accounts payable — | | | | |
| Affiliated | | 65 |
| | 87 |
|
| Other | | 40 |
| | 56 |
|
| Customer deposits | | 36 |
| | 35 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 22 |
| | — |
|
| Other accrued taxes | | 33 |
| | 9 |
|
| Accrued interest | | 20 |
| | 11 |
|
| Accrued compensation | | 20 |
| | 23 |
|
| Deferred capacity expense, current | | 22 |
| | 22 |
|
| Liabilities from risk management activities | | 41 |
| | 37 |
|
| Other current liabilities | | 44 |
| | 23 |
|
| Total current liabilities | | 419 |
| | 413 |
|
| Long-term Debt | | 1,310 |
| | 1,370 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 870 |
| | 800 |
|
| Employee benefit obligations | | 120 |
| | 121 |
|
| Other cost of removal obligations | | 226 |
| | 235 |
|
| Other regulatory liabilities, deferred | | 49 |
| | 49 |
|
| Deferred capacity expense | | 147 |
| | 163 |
|
| Other deferred credits and liabilities | | 216 |
| | 101 |
|
| Total deferred credits and other liabilities | | 1,628 |
| | 1,469 |
|
| Total Liabilities | | 3,357 |
| | 3,252 |
|
| Preference Stock | | 147 |
| | 147 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, without par value — | | | | |
| Authorized — 20,000,000 shares | | | | |
| Outstanding — September 30, 2015: 5,642,717 shares | | | | |
| — December 31, 2014: 5,442,717 shares | | 503 |
| | 483 |
|
| Paid-in capital | | 564 |
| | 560 |
|
| Retained earnings | | 290 |
| | 267 |
|
| Accumulated other comprehensive loss | | — |
| | (1 | ) |
| Total common stockholder's equity | | 1,357 |
| | 1,309 |
|
| Total Liabilities and Stockholder's Equity | | $ | 4,861 |
| | $ | 4,708 |
|
|
| | | | | | | |
| | For the Nine Months Ended September 30, |
| | 2016 | | 2015 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 115 |
| | $ | 127 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 134 |
| | 105 |
|
| Deferred income taxes | 15 |
| | 58 |
|
| Other, net | (4 | ) | | 5 |
|
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (9 | ) | | 18 |
|
| -Fossil fuel stock | 49 |
| | 18 |
|
| -Other current assets | 3 |
| | 32 |
|
| -Accrued taxes | 40 |
| | 46 |
|
| -Other current liabilities | 30 |
| | 2 |
|
| Net cash provided from operating activities | 373 |
| | 411 |
|
| Investing Activities: | | | |
| Property additions | (106 | ) | | (189 | ) |
| Cost of removal, net of salvage | (8 | ) | | (9 | ) |
| Change in construction payables | (7 | ) | | (29 | ) |
| Other investing activities | (6 | ) | | (6 | ) |
| Net cash used for investing activities | (127 | ) | | (233 | ) |
| Financing Activities: | | | |
| Decrease in notes payable, net | (42 | ) | | (34 | ) |
| Proceeds — | | | |
| Common stock issued to parent | — |
| | 20 |
|
| Pollution control revenue bonds | — |
| | 13 |
|
| Redemptions and repurchases — | | | |
| Pollution control revenue bonds | — |
| | (13 | ) |
| Senior notes | (125 | ) | | (60 | ) |
| Payment of common stock dividends | (90 | ) | | (98 | ) |
| Other financing activities | 6 |
| | (4 | ) |
| Net cash used for financing activities | (251 | ) | | (176 | ) |
| Net Change in Cash and Cash Equivalents | (5 | ) | | 2 |
|
| Cash and Cash Equivalents at Beginning of Period | 74 |
| | 39 |
|
| Cash and Cash Equivalents at End of Period | $ | 69 |
| | $ | 41 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
| Interest (net of $- and $5 capitalized for 2016 and 2015, respectively) | $ | 29 |
| | $ | 27 |
|
| Income taxes, net | 14 |
| | (37 | ) |
| Noncash transactions — Accrued property additions at end of period | 13 |
| | 17 |
|
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.
GULF POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At September 30, 2016 | | At December 31, 2015 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 69 |
| | $ | 74 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 94 |
| | 76 |
|
| Unbilled revenues | | 74 |
| | 54 |
|
| Under recovered regulatory clause revenues | | 2 |
| | 20 |
|
| Income taxes receivable, current | | — |
| | 27 |
|
| Other accounts and notes receivable | | 4 |
| | 9 |
|
| Affiliated | | 3 |
| | 1 |
|
| Accumulated provision for uncollectible accounts | | (1 | ) | | (1 | ) |
| Fossil fuel stock | | 59 |
| | 108 |
|
| Materials and supplies | | 56 |
| | 56 |
|
| Other regulatory assets, current | | 62 |
| | 90 |
|
| Other current assets | | 15 |
| | 22 |
|
| Total current assets | | 437 |
| | 536 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 5,073 |
| | 5,045 |
|
| Less accumulated provision for depreciation | | 1,387 |
| | 1,296 |
|
| Plant in service, net of depreciation | | 3,686 |
| | 3,749 |
|
| Other utility plant, net | | — |
| | 62 |
|
| Construction work in progress | | 64 |
| | 48 |
|
| Total property, plant, and equipment | | 3,750 |
| | 3,859 |
|
| Other Property and Investments | | 4 |
| | 4 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 59 |
| | 61 |
|
| Other regulatory assets, deferred | | 507 |
| | 427 |
|
| Other deferred charges and assets | | 45 |
| | 33 |
|
| Total deferred charges and other assets | | 611 |
| | 521 |
|
| Total Assets | | $ | 4,802 |
| | $ | 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 September 30, 2016 | | At December 31, 2015 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 195 |
| | $ | 110 |
|
| Notes payable | | 100 |
| | 142 |
|
| Accounts payable — | | | | |
| Affiliated | | 50 |
| | 55 |
|
| Other | | 41 |
| | 44 |
|
| Customer deposits | | 35 |
| | 36 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 19 |
| | 4 |
|
| Other accrued taxes | | 34 |
| | 9 |
|
| Accrued interest | | 19 |
| | 9 |
|
| Accrued compensation | | 20 |
| | 25 |
|
| Deferred capacity expense, current | | 22 |
| | 22 |
|
| Other regulatory liabilities, current | | 28 |
| | 22 |
|
| Liabilities from risk management activities | | 30 |
| | 49 |
|
| Other current liabilities | | 41 |
| | 40 |
|
| Total current liabilities | | 634 |
| | 567 |
|
| Long-term Debt | | 989 |
| | 1,193 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 904 |
| | 893 |
|
| Employee benefit obligations | | 125 |
| | 129 |
|
| Deferred capacity expense | | 125 |
| | 141 |
|
| Asset retirement obligations | | 119 |
| | 113 |
|
| Accrued environmental remediation | | 41 |
| | 42 |
|
| Other cost of removal obligations | | 248 |
| | 233 |
|
| Other regulatory liabilities, deferred | | 48 |
| | 47 |
|
| Other deferred credits and liabilities | | 41 |
| | 60 |
|
| Total deferred credits and other liabilities | | 1,651 |
| | 1,658 |
|
| Total Liabilities | | 3,274 |
| | 3,418 |
|
| Preference Stock | | 147 |
| | 147 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, without par value — | | | | |
| Authorized — 20,000,000 shares | | | | |
| Outstanding — 5,642,717 shares | | 503 |
| | 503 |
|
| Paid-in capital | | 579 |
| | 567 |
|
| Retained earnings | | 303 |
| | 285 |
|
| Accumulated other comprehensive loss | | (4 | ) | | — |
|
| Total common stockholder's equity | | 1,381 |
| | 1,355 |
|
| Total Liabilities and Stockholder's Equity | | $ | 4,802 |
| | $ | 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
THIRD QUARTER 20152016 vs. THIRD 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. 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 currently has long-termPower's remaining contracted sales agreements for 100%from the unit cover approximately 24% of Gulf Power's co-ownershipownership of the unit through 2019. The expiration of these contracts has had a material negative impact on Gulf Power's earnings in 2016. On May 5, 2016, Gulf Power delivered a letter to the Florida PSC requesting recognition of Gulf Power's ownership in Plant Scherer Unit 3 as being in service to retail customers when and as its existing wholesale contracts expire. As a result, on September 13, 2016, the Florida PSC instructed Gulf Power to file its monthly earnings surveillance reports both including and excluding its share of investment and expenses related to Plant Scherer Unit 3 that is not covered by contracts.
On October 12, 2016, Gulf Power filed a petition (2016 Rate Case) with the Florida PSC requesting an increase in retail rates and charges of $106.8 million based on the projected test year of January 1, 2017 through December 31, 2017 and a retail ROE of 11% compared to the current retail ROE of 10.25%. The recoverability of the costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 (205 MWs) through 2015 and 41% through 2019. These capacity revenues represented 82% of total wholesale capacity revenues for 2014.will be decided in this matter. The Florida PSC is expected to make a decision on the 2016 Rate Case in the second quarter 2017. Gulf Power has requested that the increase in base rates, if approved by the Florida PSC, become effective in July 2017.
On November 2, 2016, the Florida PSC approved Gulf Power's annual rate clause request for its cost recovery clause factors for 2017. The fuel and environmental factors include certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Cost Recovery Clauses" herein for additional information.
The ultimate outcome of these matters cannot be determined at this time. However, if the recovery of Plant Scherer Unit 3 costs is actively evaluating strategic alternatives relatednot resolved through the 2016 Rate Case, it could continue to this asset, including replacement wholesale contracts, but the expiration of current contracts could have a material negative impact on Gulf Power's earnings.earnings in future years until Gulf Power is able to find a suitable alternative related to this asset.
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
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1 | | 2.1 | | $3 | | 2.6 |
Gulf Power's net income after dividends on preference stock for the third quarter 2015 was $48 million compared to $47 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 $120 million compared to $117 million for the corresponding period in 2014. The increase was primarily due to higher retail revenues related to a base rate increase and a reduction in depreciation, as authorized by the Florida PSC, partially offset by higher operations and maintenance expenses.
Retail Revenues
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(3) | | (0.8) | | $4 | | 0.4 |
In the third quarter 2015, retail revenues were $363 million compared to $366 million for the corresponding period in 2014. For year-to-date 2015, retail revenues were $983 million compared to $979 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
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(3) | | (6.3) | | $(12) | | (10.0) |
Gulf Power's net income after dividends on preference stock for the third quarter 2016 was $45 million compared to $48 million for the corresponding period in 2015. The decrease was primarily due to lower non-affiliated wholesale capacity revenues and an increase in depreciation, partially offset by an increase in retail revenues primarily due to warmer weather and lower operations and maintenance expenses.
Gulf Power's net income after dividends on preference stock for year-to-date 2016 was $108 million compared to $120 million for the corresponding period in 2015. The decrease was primarily due to lower non-affiliated wholesale capacity revenues and an increase in depreciation, partially offset by lower operations and maintenance expenses.
Retail Revenues
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $14 | | 3.9 | | $(5) | | (0.5) |
In the third quarter 2016, retail revenues were $377 million compared to $363 million for the corresponding period in 2015. For year-to-date 2016, retail revenues were $978 million compared to $983 million for the corresponding period in 2015.
Details of the changes in retail revenues were as follows:
| | | | | Third Quarter
2015 | | Year-to-Date 2015 | Third Quarter 2016 | | Year-to-Date 2016 |
| | | (in millions) | | (% change) | | (in millions) | | (% change) | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | | $ | 366 |
| | | | $ | 979 |
| | | $ | 363 |
| | | | $ | 983 |
| | |
| Estimated change resulting from – | | | | | | | | | | | | | | | |
| Rates and pricing | | 8 |
| | 2.1 |
| | 18 |
| | 1.8 |
| 11 |
| | 3.0 |
| | 28 |
| | 2.8 |
|
| Sales decline | | (1 | ) | | (0.3 | ) | | (1 | ) | | (0.1 | ) | |
| Sales growth (decline) | | (1 | ) | | (0.3 | ) | | — |
| | — |
|
| Weather | | 4 |
| | 1.1 |
| | 8 |
| | 0.8 |
| 5 |
| | 1.4 |
| | (3 | ) | | (0.3 | ) |
| Fuel and other cost recovery | | (14 | ) | | (3.7 | ) | | (21 | ) | | (2.1 | ) | (1 | ) | | (0.3 | ) | | (30 | ) | | (3.1 | ) |
| Retail – current year | | $ | 363 |
| | (0.8 | )% | | $ | 983 |
| | 0.4 | % | $ | 377 |
| | 3.8 | % | | $ | 978 |
| | (0.6 | )% |
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 third quarter and year-to-date 20152016 when compared to the corresponding periods in 20142015 primarily due to an increase in retail base rates, as authorized in a settlement agreement for Gulf Power's 2013 base rate case, as well as an increase in the environmental andcost recovery clause rate, partially offset by a decrease in the energy conservation cost recovery clause rates,rate, both effective in January 2015.2016. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Cost Recovery Clauses" herein for additional information.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Revenues attributable to changes in sales decreased slightly in the third quarter and year-to-date 20152016 when compared to the corresponding periodsperiod in 2014.2015. For the third quarter and year-to-date 2015,2016, weather-adjusted KWH energy sales decreased 2.0% and 1.4%, respectively, to residential and commercial customers decreased 1.9% and decreased 0.6% and 0.3%0.5%, respectively, to commercial customers, due to lower customer usage primarily resulting from efficiency improvements in appliances and lighting, partially offset by customer growth. KWH energy sales to industrial customers decreased 2.9% and 2.8%increased 1.3% for the third quarter and year-to-date 2015, respectively,2016 primarily due to decreased customer co-generation and changes in customers' operations.
Revenues attributable to changes in sales remained essentially flat year-to-date 2016 when compared to the corresponding period in 2015. Weather-adjusted KWH sales to residential and commercial customers decreased 0.4% and 1.0%, respectively, due to lower customer usage primarily resulting from efficiency improvements in appliances and lighting, partially offset by customer growth. KWH sales to industrial customers increased 2.9% primarily due to decreased customer co-generation.co-generation, partially offset by changes in customers' operations.
Fuel and other cost recovery revenues decreased in the third quarter and year-to-date 20152016 when compared to the corresponding periodsperiod in 20142015, primarily due to lower recoverable costs under Gulf Power's environmental cost recovery clause, partially offset by higher recoverable costs under Gulf Power's energy conservation cost recovery clause. Fuel and other cost recovery revenues associated withdecreased year-to-date 2016 when compared to the corresponding period in 2015, primarily due to a decrease in fuel costs as thea result of decreased generation and lower purchased power energy costs. For year-to-date 2015, the decrease wasLower recoverable costs under Gulf Power's environmental cost recovery clause, partially offset by higher revenues associated with purchased power capacityrecoverable costs when comparedunder Gulf Power's energy conservation cost recovery clause, also contributed to the corresponding period in 2014.
this decrease. Fuel and other cost recovery provisions include fuel expenses, the energy component of purchased power costs, purchased power capacity costs, and the difference between projected and actual costs and revenues related to energy conservation and environmental compliance. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Retail Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.
Wholesale Revenues – Non-Affiliates
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(4) | | (11.8) | | $(22) | | (21.2) |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(13) | | (43.3) | | $(34) | | (41.5) |
Wholesale revenues from sales to non-affiliates consist of long-term sales agreements to other utilities in Florida and Georgia and short-term opportunity sales. Capacity revenues from long-term sales agreements represent the greatest contribution to 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
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
margin above Gulf Power's variable cost of energy. Wholesale energy revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Gulf Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.
In the third quarter 2015,2016, wholesale revenues from sales to non-affiliates were $30$17 million compared to $34$30 million for the corresponding period in 2014. The decrease was primarily due to a 20.2% decrease in KWH sales resulting from lower sales under the Plant Scherer Unit 3 long-term sales agreements due to lower natural gas prices that led to increased generation from customer-owned units.
2015. For year-to-date 2015,2016, wholesale revenues from sales to non-affiliates were $82$48 million compared to $104$82 million for the corresponding period in 2014. The decrease was2015. These decreases were primarily due to a 41.4%62.1% and 52.3% decrease in KWH salescapacity revenues for the third quarter and year-to-date 2016, respectively, resulting from lower sales under the expiration of Plant Scherer Unit 3 long-term sales agreements due to a planned outage and lower natural gas prices that led to increased generation from customer-owned units.agreements.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale Revenues – Affiliates
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(4) | | (19.0) | | $(45) | | (46.4) |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $6 | | 35.3 | | $7 | | 13.5 |
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 third quarter 2015,2016, wholesale revenues from sales to affiliates were $17$23 million compared to $21$17 million for the corresponding period in 2014.2015. The decreaseincrease was primarily due to a 17.7% decrease42.8% increase in KWH sales as a result of higher sales to the price of energy sold to affiliatespower pool due to lower power pool interchange rates resulting from lower natural gas prices.
greater Southern Company system load. For year-to-date 2015,2016, wholesale revenues from sales to affiliates were $52$59 million compared to $97$52 million for the corresponding period in 2014.2015. The decreaseincrease was primarily due to a 29.1% decrease33.7% increase in KWH sales that resultedresulting from lower planned unit outages for Gulf PowerPower's generation resources through the second quarter 2015 and a 24.4% decrease in the price of energy sold to affiliates due to lower power pool interchange rates resulting from lower natural gas prices.resources.
Fuel and Purchased Power Expenses
| | | | | Third Quarter 2015
vs.
Third Quarter 2014 | | Year-to-Date 2015
vs.
Year-to-Date 2014 | | Third Quarter 2016
vs.
Third 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 | | $ | (21 | ) | | (12.8 | ) | | $ | (103 | ) | | (21.5 | ) | | $ | (2 | ) | | (1.4 | ) | | $ | (33 | ) | | (8.8 | ) |
| Purchased power – non-affiliates | | (1 | ) | | (3.7 | ) | | 19 |
| | 33.3 |
| | 7 |
| | 26.9 |
| | 19 |
| | 25.0 |
|
| Purchased power – affiliates | | — |
| | — |
| | 3 |
| | 15.8 |
| | (1 | ) | | (25.0 | ) | | (13 | ) | | (59.1 | ) |
| Total fuel and purchased power expenses | | $ | (22 | ) | | | | $ | (81 | ) | | | | $ | 4 |
| | | | $ | (27 | ) | | |
In the third quarter 2015,2016, total fuel and purchased power expenses were $173$177 million compared to $195$173 million for the corresponding period in 2014.2015. The increase was primarily due to a $7 million net increase related to the volume of KWHs generated and purchased as a result of higher customer loads on Gulf Power's system, partially offset by a $3 million decrease in the average cost of fuel and purchased power.
For year-to-date 2016, total fuel and purchased power expenses were $446 million compared to $473 million for the corresponding period in 2015. The decrease was primarily the result of a $20 million decrease due to the lower average cost of fuel and purchased power and a $10 million decrease related to the volume of KWHs generated, partially offset by an $8 million increase in the volume of KWHs purchased.
For year-to-date 2015, total fuel and purchased power expenses were $473 million compared to $554 million for the corresponding period in 2014. The decrease was primarily the result of a $52 million decrease related to the volume
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
of KWHs generated and a $31$40 million decrease due to the lower average cost of fuel and purchased power, partially offset by a $2$13 million net increase related to the volume of KWHs purchased.purchased from Gulf Power's gas-fired PPA resource.
Fuel and purchased power transactions do not have a significant impact on earnings since energy and capacity expenses are generally offset by energy and capacity revenues through Gulf Power's fuel 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.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of Gulf Power's generation and purchased power were as follows:
| | | | | Third Quarter
2015 | | Third Quarter
2014 | | Year-to-Date 2015 | | Year-to-Date 2014 | Third Quarter 2016 | | Third Quarter 2015 | | Year-to-Date 2016 | | Year-to-Date 2015 |
Total generation (millions of KWHs) | | 2,839 | | 3,085 | | 7,435 | | 8,717 | |
Total purchased power (millions of KWHs) | | 1,637 | | 1,479 | | 4,231 | | 4,190 | |
Total generation (in millions of KWHs) | | 2,775 | | 2,839 | | 6,654 | | 7,435 |
Total purchased power (in millions of KWHs) | | 1,906 | | 1,637 | | 5,295 | | 4,231 |
Sources of generation (percent) – | | |
| Coal | | 64 | | 66 | | 61 | | 69 | 68 | | 64 | | 57 | | 61 |
| Gas | | 36 | | 34 | | 39 | | 31 | 32 | | 36 | | 43 | | 39 |
Cost of fuel, generated (cents per net KWH) – | | |
Cost of fuel, generated (in cents per net KWH) – | | |
| Coal | | 3.67 | | 3.83 | | 3.88 | | 4.08 | 3.55 | | 3.67 | | 3.80 | | 3.88 |
| Gas | | 4.32 | | 4.16 | | 4.22 | | 3.95 | 4.38 | | 4.32 | | 4.06 | | 4.22 |
Average cost of fuel, generated (cents per net KWH) | | 3.90 | | 3.94 | | 4.01 | | 4.04 | |
Average cost of purchased power (cents per net KWH)(*) | | 3.83 | | 4.96 | | 4.12 | | 4.83 | |
Average cost of fuel, generated (in cents per net KWH) | | 3.81 | | 3.90 | | 3.91 | | 4.01 |
Average cost of purchased power (in cents per net KWH)(*) | | 3.79 | | 3.83 | | 3.51 | | 4.12 |
| |
| (*) | Average cost of purchased power includes fuel purchased by Gulf Power for tolling agreements where power is generated by the provider. |
Fuel
In the third quarter 2015,2016, fuel expense was $143$141 million compared to $164$143 million for the corresponding period in 2014.2015. The decrease was primarily due to an 8.0%a 12.9% decrease in the volume of KWHs generated by Gulf Power's gas-fired generation resources due to higher planned maintenance and a 1.0%2.3% decrease in the average cost of fuel due to lower coal prices per KWH generated.fuel. The decreases were partially offset by a 3.6% increase in the volume of KWHs generated by Gulf Power's coal-fired generation resources.
For year-to-date 2015,2016, fuel expense was $375$342 million compared to $478$375 million for the corresponding period in 2014.2015. The decrease was primarily due to a 14.7%17.4% decrease in the volume of KWHs generated by Gulf Power's coal-fired generation resources due to planned outages for Gulf Power's generationthe lower cost of gas-fired resources and a resource contracted under a PPA and a 1.0%2.5% decrease in the average cost of fuel due to lower coal prices per KWH generated.fuel. The decreases were partially offset by a 0.5% increase in the volume of KWHs generated by Gulf Power's gas-fired generation resources.
Purchased Power – Non-Affiliates
In the third quarter 2015,2016, purchased power expense from non-affiliates was $26$33 million compared to $27$26 million for the corresponding period in 2014.2015. The decreaseincrease was primarily due to a 22.2%26.5% increase in the volume of KWHs purchased due to the availability of lower cost energy, partially offset by a 6.6% decrease in the average cost per KWH purchased due to lower natural gas prices, partially offset by a 7.7% increase in the volume of KWHs purchased.energy costs from gas-fired resources.
For year-to-date 2015,2016, purchased power expense from non-affiliates was $76$95 million compared to $57$76 million for the corresponding period in 2014.2015. The increase was primarily due to a $26 million46.6% 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 an 8.2% decrease in the volume of KWHs purchased due to the availability of lower cost energy, partially offset by a planned outage for a resource contracted under a PPA.21.0% decrease in the average cost per KWH purchased due to lower energy costs from gas-fired resources.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the third quarter 2016, purchased power expense from affiliates was $3 million compared to $4 million for the corresponding period in 2015. The decrease was primarily due to a 54.9% decrease in the volume of KWHs purchased due to an increase in coal-fired Gulf Power generation committed to serve territorial loads, partially offset by a 67.4% increase in the average cost per KWH purchased due to higher power pool interchange rates.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Purchased Power – Affiliates
In the third quarter 2015 and the corresponding period in 2014,For year-to-date 2016, purchased power expense from affiliates was $4 million.$9 million compared to $22 million for the corresponding period in 2015. The decrease was primarily due to a 54.6% decrease in the volume of KWHs purchased increased 37.9% due to decreased generation from Gulf Power resources. The increase was offset bylower territorial loads and a 13.0%10.8% decrease in the average cost per KWH purchased due to lower power pool interchange rates.
For year-to-date 2015, purchased power expense from affiliates was $22 million compared to $19 million for the corresponding period in 2014. The increase was primarily due torates as a 60.5% increase in the volumeresult of KWHs purchased due to planned outages for Gulf Power's generationlower fuel prices and a resource contracted under a PPA, offset by a 31.5% decrease in the average cost per KWH purchased due to lower power pool interchange rates.off-peak energy prices of renewable market resources.
Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $5 | | 5.9 | | $23 | | 9.2 |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(4) | | (4.4) | | $(35) | | (12.8) |
In the third quarter 2015,2016, other operations and maintenance expenses were $90$86 million compared to $85$90 million for the corresponding period in 2014. The increase was primarily due to increases of $3 million in employee compensation and benefits including pension costs, $1 million in customer service expenses, and $1 million in marketing programs.
2015. For year-to-date 2015,2016, other operations and maintenance expenses were $274$239 million compared to $251$274 million for the corresponding period in 2014. The increase was2015. These decreases were primarily due to increases of $9 milliondecreases in routine and planned maintenance expenses at generationgenerating facilities $5 million in employee compensation and benefits including pension costs, $2 million in customer servicelower expenses $2 million inrelated to marketing programs, and $2 million in energy services expenses.programs.
Expenses from marketing programs diddo not have a significant impact on earnings since they wereare generally offset by energy conservation revenues through Gulf Power's energy conservation cost recovery clause. Expenses from energy services did not have a significant impact on earnings since they were generally offset by associated revenues. See Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.
Depreciation and Amortization
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $2 | | 5.3 | | $(9) | | (8.3) |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $9 | | 22.5 | | $29 | | 29.0 |
For year-to-date 2015,In the third quarter 2016, depreciation and amortization was $100$49 million compared to $109$40 million for the corresponding period in 2014. As2015. For year-to-date 2016, depreciation and amortization was $129 million compared to $100 million for the corresponding period in 2015. The increases were primarily due to $7 million and $20 million less of a reduction in depreciation, as authorized in a settlement agreement approved by the Florida PSC in a settlement agreement,2013 (2013 Rate Case Settlement Agreement), in the third quarter and year-to-date 2016, respectively, compared to the corresponding periods in 2015. In the third quarter 2016, and in accordance with the 2013 Rate Case Settlement Agreement, Gulf Power reversed reductions previously recorded to depreciation. As a $20.5 million reduction in depreciation inresult, for the first nine months of 2015 as compared2016, the net reduction in depreciation was zero. Also contributing to $5.4 million in the corresponding period in 2014. The decrease was partially offset by increases of $6 million primarily attributable towere property additions at generation, transmission, and distribution facilities.facilities placed in service in 2015.
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Case" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail"Retail Regulatory Matters – Gulf Power – Retail Base Rate Case"Cases" herein for additional information.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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Taxes Other Than Income Taxes(Expense), Net
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $4 | | 12.9 | | $7 | | 8.3 |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(4) | | N/M | | $(12) | | N/M |
N/M - Not meaningful
In the third quarter 2015, taxes 2016, other than income taxes were $35(expense), net was $(2) million compared to $31$2 million for the corresponding period in 2014.2015. For year-to-date 2015, taxes2016, other than income taxes were $91 million compared to $84 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(expense), net income.
Allowance for Equity Funds Used During Construction
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $— | | — | | $3 | | 37.5 |
For year-to-date 2015, AFUDC equity was $11$(4) million compared to $8 million for the corresponding period in 2014. The increase was2015. These changes were primarily due to increased constructionlower AFUDC related to environmental control projects at generation facilities.generating 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 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.expire, and the outcome of the 2016 Rate Case related to Gulf Power's ownership of Plant Scherer Unit 3. Demand for electricity for Gulf Power is partiallyprimarily 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. 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.
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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 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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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, regional haze regulations, fine particulate matter National Ambient Air Quality Standards (NAAQS), and the Cross State Air Pollution Rule (CSAPR),.
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 Gulf Power units that are subject to the eight-hour National Ambient Air Quality Standard (NAAQS)MATS rule completed the measures necessary to achieve compliance with the MATS rule by the applicable deadlines.
Also on April 25, 2016, the EPA issued proposed revisions to the regional haze regulations. The ultimate impact of the proposed revisions will depend on their ultimate adoption, implementation, and any legal challenges and cannot be determined at this time.
On September 6, 2016, the EPA designated all remaining areas within Gulf Power's service territory as attainment for ozone.the 2012 annual fine particulate matter NAAQS.
On June 12, 2015,October 26, 2016, the EPA published a final rule requiring affected states (includingthat updates the CSAPR ozone season nitrogen oxide program, including revising ozone-season emissions budgets in Mississippi and removing Florida Georgia, and Mississippi) 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.from the CSAPR program. The ultimate impact of the finalthis rule will depend on the outcome of any legal challenges and implementation at the developmentstate level 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.
On October 26, 2015, the EPA published a more stringent eight-hour NAAQS for ozone. This new standard could potentially require additional emission controls, improvements in control efficiency, and operational fuel changes and could affect the siting of new generating facilities. The ultimate impact of this matter will depend on any legal challenges and implementation of the final rule and cannot be determined at this time.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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' rule revising the definition of waters of the U.S. under the Clean Water Act (CWA) and the EPA's revisions to effluent guidelines.
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 became effective August 28, 2015, but on October 9, 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order staying implementation of the final rule. The ultimate impact of the final rule will depend on the outcome of this and other pending legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the rule and cannot be determined at this time.
On November 3, 2015, the EPA published final revisions to technology-based limits for certain wastestreams from steam electric power plants. These revisions impose stringent steam effluent guidelines and technology requirements for wastewater discharges at affected units. Compliance with these revisions could result in significant additional capital expenditures and could affect future unit retirement and replacement decisions. The ultimate impact of these revisions will depend on any legal challenges and implementation of the final revisions 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, which became effective on October 19, 2015. Based on initial cost estimates for closure in place and groundwater monitoring of ash ponds pursuant to the CCR Rule, during the second quarter 2015, Gulf Power recorded incremental asset retirement obligations (ARO) of approximately $75 million related to the CCR Rule. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, Gulf Power expects to continue to periodically update these estimates. 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. See Note (A) to the Condensed Financial Statements herein for additional information regarding Gulf Power's AROs as of September 30, 2015.
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 October 23, 2015, two final actions by the EPA that would limit CO2 emissions from fossil fuel-fired electric generating units were published in the Federal Register. One of the final actions contains specific emission standards governing CO2 emissions from new, modified, and reconstructed units. The other final action 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, a proposed federal plan and proposed model rule were published that states can
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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, including legal challenges filed by Gulf Power; 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.
Gulf Power's wholesale business consists of two types of agreements. The first type, referred to as requirements service, provides that Gulf Power serves the customer's capacity and energy requirements from Gulf Power resources. The second type, referred to as a unit sale, is a wholesale customer purchase from a dedicated generating plant unit where a portion of that unit is reserved for the customer. These agreements are associated with Gulf Power's ownership of Plant Scherer Unit 3 and consist of both capacity and energy sales. Through 2015, long-term non-affiliate capacity sales from Gulf Power's ownership of the unit provided the majority of Gulf Power's wholesale earnings. The revenues from wholesale contracts covering 100% of this capacity represented 82% of wholesale capacity revenues in 2015. Following contract expirations at the end of 2015 and the end of May 2016, Gulf Power's remaining contracted sales from the unit cover approximately 24% of Gulf Power's ownership of the unit through 2019. The expiration of these contracts has had a material negative impact on Gulf Power's earnings in 2016. On May 5, 2016, Gulf Power delivered a letter to the Florida PSC requesting recognition of Gulf Power's ownership in Plant Scherer Unit 3 as being in service to retail customers when and as its existing wholesale contracts expire. As a result, on September 13, 2016, the Florida PSC instructed Gulf Power to file its monthly earnings surveillance reports both including and excluding its share of investment and expenses related to Plant Scherer Unit 3 that is not covered by contracts. See "Retail Base Rate CaseCases" and "Cost Recovery Clauses" herein for additional information.
In December 2013,
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The ultimate outcome of this matter cannot be determined at this time. However, if the Florida PSC approvedrecovery of Plant Scherer Unit 3 costs is not resolved through the 2016 Rate Case, it could continue to have a settlement agreement that providesmaterial negative impact on Gulf Power's earnings in future years until Gulf Power mayis able to find a suitable alternative related to this asset.
Retail Base Rate Cases
The 2013 Rate Case Settlement Agreement authorized Gulf Power to reduce depreciation 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. For 2014 and the first nine months of 2015, Gulf Power recognized reductions in depreciation expense of $8.4 million and $20.5$20.1 million, respectively. In the third quarter 2016 and in accordance with the 2013 Rate Case Settlement Agreement, Gulf Power reversed reductions previously recorded to depreciation. As a result, for the first nine months of 2016, the net reduction in depreciation was zero.
On October 12, 2016, Gulf Power filed the 2016 Rate Case with the Florida PSC requesting an increase in retail rates and charges of $106.8 million based on the projected test year of January 1, 2017 through December 31, 2017 and a retail ROE of 11% compared to the current retail ROE of 10.25%. The recoverability of the costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 will be decided in this matter. The Florida PSC is expected to make a decision on the 2016 Rate Case in the second quarter 2017. Gulf Power has requested that the increase in base rates, if approved by the Florida PSC, become effective in July 2017. The ultimate outcome of this matter cannot be determined at this time.
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
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K for additional information regarding Gulf Power's recovery of retail costs through various regulatory clauses and accounting orders. Gulf Power has four regulatory clauses which are approved by the Florida PSC. See Note (B) to the Condensed Financial Statements herein for additional information.
On November 2, 2015,2016, the Florida PSC approved Gulf Power's annual rate clause request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2016.2017. The net effect of the approved changes is a $49$41 million decrease in annual revenuerevenues for 2016. The2017. In general, the decreased revenues will not have a significant impact on net income since most of the revenues will be offset by lower expenses.
Renewables
On April 16, 2015, However, certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 were included in the environmental clause rate, which will have an impact of approximately $11 million and $14 million of additional revenue in 2016 and 2017, respectively. The final disposition of these costs, and the related impact on rates, is subject to the Florida PSC's ultimate ruling on whether costs associated with Plant Scherer Unit 3 are recoverable from retail customers, which is expected to be decided by the Florida PSC approved threein the 2016 Rate Case as discussed previously. The ultimate outcome of this matter cannot be determined at this time.
Renewables
The Florida PSC issued a final approval order on Gulf Power's Community Solar Pilot Program on April 15, 2016. The program will offer all Gulf Power customers an opportunity to voluntarily contribute to the construction and operation of a solar photovoltaic facility with electric generating capacity of up to 1 MW through annual subscriptions. The energy purchase agreements totaling 120 MWsgenerated from the solar facility is expected to provide power to all of utility-scale solar generation located at three military installations in northwest Florida. Gulf Power's customers.
On May 5, 2015,October 11, 2016, the Florida PSC preliminarily approved an energy purchase agreement for up to 17894 MWs of wind generation in central Oklahoma. Purchases under these agreementsthis agreement will be for energy only and will be recovered through Gulf Power's fuel cost recovery mechanism.clause.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Matters
As a result of the cost to comply with environmental regulations imposed by the EPA, Gulf Power retired its coal-fired generation at Plant Smith Units 1 and 2 (357 MWs) on March 31, 2016. Gulf Power filed a petition with the Florida PSC requesting permission to recover the remaining net book value of Plant Smith Units 1 and 2 and the remaining materials and supplies associated with these units as of the retirement date. In connection with this request, Gulf Power reclassified approximately $63 million to a regulatory asset, including the remaining net book value of the units and the associated materials and supplies. On August 29, 2016, the Florida PSC approved Gulf Power's request to create a regulatory asset and defer the recovery over a period to be decided in the 2016 Rate Case.
Gulf Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Gulf Power is subject to certain claims and legal actions arising in the ordinary course of business. Gulf Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
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, 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 lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. Gulf Power is currently 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
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a credit-adjusted risk-free rate. Estimates of the timingsignificantly, entities are required to recognize all excess tax benefits 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 facilities that are subjectdeficiencies related to the CCR Ruleexercise or vesting of stock compensation as income tax expense or benefit in the income statement. Gulf Power currently recognizes any excess tax benefits and deficiencies related to the closureexercise and vesting of an ash pond at Plant Scholz. In addition, Gulf Power has retirement obligations related to various landfill sites, a barge unloading dock, asbestos removal, disposal of polychlorinated biphenyls in certain transformers, and combustion turbines at its Pea Ridge facility. 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.
As a result of the final CCR Rule discussed above, Gulf Power recorded new AROs for facilities that are subject to the CCR Rule. The cost estimates are based on information using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure in place. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, suchstock compensation 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, Gulf Power expects to continue 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 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. 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, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs. Thepaid-in capital. 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 and2016-09 is effective for fiscal years beginning after December 15, 2015.2016. Early adoption is permitted and Gulf Power intends to adopt the ASU in the fourth quarter 2015.2016. The ASUadoption is requirednot expected to be applied retrospectively to all periods presented beginning in the year of adoption. Gulf Power currently reflects unamortized debt issuance costs in other deferred charges and assets 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 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 September 30, 2015.2016. Gulf Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital"Capital Requirements and Contractual Obligations," "Sources"Sources of Capital," and "Financing Activities""Financing Activities" herein for additional information.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Net cash provided from operating activities totaled $411$373 million for the first nine months of 20152016 compared to $324$411 million for the corresponding period in 2014.2015. The $87$38 million increasedecrease in net cash was primarily due to increaseda decrease in wholesale capacity revenue, collection related to cost recovery clauses and the timing of income tax payments and refunds associated with bonus depreciation, partially offset by the timing of payments for accounts payable and fossil fuel stock purchases.a federal income tax refund. Net cash used for investing activities totaled $233$127 million in the first nine months of 20152016 primarily due to property additions to utility plant. Net cash used for financing activities totaled $176$251 million for the first nine months of 20152016 primarily due to payments forthe redemption of long-term debt, payment of common stock dividends, and redemptions of long-term debt anda decrease in notes payable, partially offset by cash received for 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 nine months of 20152016 include increasesdecreases of $174$125 million in long-term debt due to a redemption and $109 million in net property, plant, and equipment $115 million in other deferred creditsprimarily due to the retirement of Plant Smith Units 1 and liabilities primarily related to AROs,2 and $70 millionan increase in accumulated deferred income tax liabilitiesprovision for depreciation primarily relateddue to bonus depreciation. Other significant changes include decreases of $60 millionenvironmental control projects at generating facilities and transmission projects placed in long-term debt, $40 millionservice in under recovered regulatory clause revenues, and $34 million in notes payable.2015.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Gulf Power in Item 7 of the Form 10-K for a description of Gulf Power's capital requirements for its construction program, including estimated capital expenditures to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, leases, derivative obligations, preference stock dividends, purchase commitments, and trust funding requirements, and unrecognized tax benefits. There are no scheduledrequirements. Approximately $195 million will be required through September 30, 2017 to fund maturities of long-term debt through September 30, 2016.debt. See "Financing Activities""Financing Activities" herein for additional information.
Gulf Power's construction program is currently estimated to total $0.2 billion for 2017, $0.2 billion for 2018, $0.2 billion for 2019, $0.3 billion for 2020, and $0.3 billion for 2021. These estimated expenditures do not include potential compliance costs that may arise from the EPA's final rules and guidelines or subsequently approved state plans that would limit CO2 emissions from existing, new, modified, or reconstructed fossil-fuel-fired electric generating units.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing 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
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
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 September 30, 2015,2016, Gulf Power had approximately $41$69 million of cash and cash equivalents. Committed credit arrangements with banks at September 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 |
| 50 |
| | $ | 65 |
| | $ | 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 are 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 September 30, 2015 was approximately $82 million. In addition, at September 30, 2015, Gulf Power had approximately $33 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 revenue bonds outstanding requiring liquidity support as of September 30, 2016 was approximately $82 million. In addition, at September 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.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of short-term borrowings were as follows:
| | | | | Short-term Debt at September 30, 2015 | | Short-term Debt During the Period(*) | | Short-term Debt at September 30, 2016 | | Short-term Debt During the Period(*) |
| | | Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding | | 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 | | $ | 76 |
| | 0.4 | % | | $ | 91 |
| | 0.4 | % | | $ | 125 |
| | $ | — |
| | — | % | | $ | 35 |
| | 0.8 | % | | $ | 88 |
|
| Short-term bank debt | | — |
| | — | % | | 30 |
| | 0.7 | % | | 40 |
| | 100 |
| | 1.3 | % | | 100 |
| | 1.2 | % | | 100 |
|
| Total | | $ | 76 |
| | 0.4 | % | | $ | 121 |
| | 0.4 | % | | | | $ | 100 |
| | 1.3 | % | | $ | 135 |
| | 1.1 | % | | |
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 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 September 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 |
| $ | 192 |
|
| Below BBB- and/or Baa3 | 485 |
| $ | 630 |
|
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, a credit rating downgrade could impact the ability of Gulf Power to access capital markets and would be likely to impact the cost at which it does so.
On August 17, 2015, S&P downgraded the consolidated long-term issuer rating of Southern Company (including Gulf Power) to A- from A and revised its credit rating outlook from negative to stable. Separately, on August 24, 2015, S&P revised its credit rating outlook from stable to negative following the announcement of the Merger.
Market Price Risk
Gulf Power's market risk exposure relative to interest rate changes for the third 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 ishad been limited because its long-term sales agreements shiftshifted substantially all fuel cost responsibility to the purchaser. However, Gulf Power could becomeis 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, On May 5, 2016, Gulf Power issued 200,000 shares of common stockdelivered a letter to Southern Company and realized proceeds of $20 million. The proceeds were used to repay a portionthe Florida PSC requesting recognition of Gulf Power's short-term debtownership in Plant Scherer Unit 3 as being in service to retail customers when and for other general corporate purposes, including Gulf Power's continuous construction program.
In June 2015,as its existing wholesale contracts expire. As a result, on September 13, 2016, the Florida PSC instructed Gulf Power entered into a $40 million aggregate principal amount three-month floating rate bank loan bearing interest based on one-month LIBOR. The proceeds were used for credit support, working capital, and other general corporate purposes. The loan was repaid at maturity.to file its monthly earnings surveillance
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In July 2015, Gulf Power purchasedreports both including and held $13 million aggregate principal amountexcluding its share 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.investment and expenses related to Plant Scherer Unit 3 that is not covered by contracts. The recoverability of the costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 is expected to be decided in the 2016 Rate Case. The ultimate outcome of this matter cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" herein for additional information.
Financing Activities
In September 2015,May 2016, Gulf Power redeemed $60$125 million aggregate principal amount of its Series L 5.65%2011A 5.75% Senior Notes due SeptemberJune 1, 2035.2051.
Subsequent to September 30, 2015,Also in May 2016, Gulf Power entered into forward-startingan 11-month floating rate bank loan bearing interest rate swapsbased on one-month LIBOR. This short-term loan was for $100 million aggregate principal amount and the proceeds were used to hedge exposure to interest rate changes related to an anticipated debt issuance. The notional amount of the swaps totaled $80 million.repay existing indebtedness and for working capital and other general corporate purposes.
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 September 30, | | For the Nine Months
Ended September 30, | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | | | | | | | | |
| Retail revenues | $ | 244 |
| | $ | 228 |
| | $ | 601 |
| | $ | 647 |
| $ | 263 |
| | $ | 244 |
| | $ | 652 |
| | $ | 601 |
|
| Wholesale revenues, non-affiliates | 76 |
| | 83 |
| | 216 |
| | 255 |
| 78 |
| | 76 |
| | 198 |
| | 216 |
|
| Wholesale revenues, affiliates | 18 |
| | 39 |
| | 63 |
| | 82 |
| 7 |
| | 18 |
| | 23 |
| | 63 |
|
| Other revenues | 3 |
| | 5 |
| | 13 |
| | 13 |
| 4 |
| | 3 |
| | 12 |
| | 13 |
|
| Total operating revenues | 341 |
| | 355 |
| | 893 |
| | 997 |
| 352 |
| | 341 |
| | 885 |
| | 893 |
|
| Operating Expenses: | | | | | | | | | | | | | | |
| Fuel | 130 |
| | 169 |
| | 359 |
| | 459 |
| 112 |
| | 130 |
| | 268 |
| | 359 |
|
| Purchased power, non-affiliates | 1 |
| | 3 |
| | 5 |
| | 16 |
| 3 |
| | 1 |
| | 4 |
| | 5 |
|
| Purchased power, affiliates | 1 |
| | 2 |
| | 6 |
| | 17 |
| 5 |
| | 1 |
| | 14 |
| | 6 |
|
| Other operations and maintenance | 63 |
| | 67 |
| | 206 |
| | 192 |
| 74 |
| | 63 |
| | 211 |
| | 206 |
|
| Depreciation and amortization | 38 |
| | 23 |
| | 95 |
| | 70 |
| 30 |
| | 38 |
| | 114 |
| | 95 |
|
| Taxes other than income taxes | 24 |
| | 22 |
| | 71 |
| | 63 |
| 31 |
| | 24 |
| | 81 |
| | 71 |
|
| Estimated loss on Kemper IGCC | 150 |
| | 418 |
| | 182 |
| | 798 |
| 88 |
| | 150 |
| | 222 |
| | 182 |
|
| Total operating expenses | 407 |
| | 704 |
| | 924 |
| | 1,615 |
| 343 |
| | 407 |
| | 914 |
| | 924 |
|
| Operating Income (Loss) | (66 | ) | | (349 | ) | | (31 | ) | | (618 | ) | 9 |
| | (66 | ) | | (29 | ) | | (31 | ) |
| Other Income and (Expense): | | | | | | | | | | | | | | |
| Allowance for equity funds used during construction | 29 |
| | 32 |
| | 82 |
| | 108 |
| 31 |
| | 29 |
| | 90 |
| | 82 |
|
| Interest expense, net of amounts capitalized | (13 | ) | | (9 | ) | | 6 |
| | (34 | ) | (15 | ) | | (13 | ) | | (46 | ) | | 6 |
|
| Other income (expense), net | (2 | ) | | (8 | ) | | (5 | ) | | (12 | ) | (1 | ) | | (2 | ) | | (4 | ) | | (5 | ) |
| Total other income and (expense) | 14 |
| | 15 |
| | 83 |
| | 62 |
| 15 |
| | 14 |
| | 40 |
| | 83 |
|
| Earnings (Loss) Before Income Taxes | (52 | ) | | (334 | ) | | 52 |
| | (556 | ) | 24 |
| | (52 | ) | | 11 |
| | 52 |
|
| Income taxes (benefit) | (31 | ) | | (139 | ) | | (11 | ) | | (253 | ) | (2 | ) | | (31 | ) | | (29 | ) | | (11 | ) |
| Net Income (Loss) | (21 | ) | | (195 | ) | | 63 |
| | (303 | ) | 26 |
| | (21 | ) | | 40 |
| | 63 |
|
| Dividends on Preferred Stock | — |
| | — |
| | 1 |
| | 2 |
| — |
| | — |
| | 1 |
| | 1 |
|
| Net Income (Loss) After Dividends on Preferred Stock | $ | (21 | ) | | $ | (195 | ) | | $ | 62 |
| | $ | (305 | ) | $ | 26 |
| | $ | (21 | ) | | $ | 39 |
| | $ | 62 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months
Ended September 30, | | For the Nine Months
Ended September 30, |
| | 2015 | | 2014 | | 2015 | | 2014 |
| | (in millions) | | (in millions) |
| Net Income (Loss) | $ | (21 | ) | | $ | (195 | ) | | $ | 63 |
| | $ | (303 | ) |
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $- and $-, respectively | — |
| | — |
| | 1 |
| | — |
|
| Total other comprehensive income (loss) | — |
| | — |
| | 1 |
| | — |
|
| Comprehensive Income (Loss) | $ | (21 | ) | | $ | (195 | ) | | $ | 64 |
| | $ | (303 | ) |
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED) |
| | | | | | | |
| | For the Nine Months
Ended September 30, |
| | 2015 | | 2014 |
| | (in millions) |
| Operating Activities: | | | |
| Net income (loss) | $ | 63 |
| | $ | (303 | ) |
| Adjustments to reconcile net income (loss) to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 94 |
| | 78 |
|
| Deferred income taxes | 518 |
| | 159 |
|
| Investment tax credits | 25 |
| | (108 | ) |
| Allowance for equity funds used during construction | (82 | ) | | (108 | ) |
| Regulatory assets associated with Kemper IGCC | (56 | ) | | (52 | ) |
| Estimated loss on Kemper IGCC | 182 |
| | 798 |
|
| Income taxes receivable, non-current | (544 | ) | | — |
|
| Other, net | 7 |
| | 10 |
|
| Changes in certain current assets and liabilities — | | | |
| -Receivables | 7 |
| | (48 | ) |
| -Fossil fuel stock | 5 |
| | 36 |
|
| -Prepaid income taxes | (1 | ) | | (90 | ) |
| -Other current assets | (8 | ) | | (4 | ) |
| -Accounts payable | (32 | ) | | 28 |
|
| -Accrued taxes | 24 |
| | (17 | ) |
| -Accrued interest | (6 | ) | | 24 |
|
| -Accrued compensation | (8 | ) | | 8 |
|
| -Over recovered regulatory clause revenues | 59 |
| | (18 | ) |
| -Mirror CWIP | 99 |
| | 112 |
|
| -Other current liabilities | 3 |
| | — |
|
| Net cash provided from operating activities | 349 |
| | 505 |
|
| Investing Activities: | | | |
| Property additions | (626 | ) | | (986 | ) |
| Construction payables | (31 | ) | | (40 | ) |
| Investment in restricted cash | — |
| | (11 | ) |
| Distribution of restricted cash | — |
| | 9 |
|
| Other investing activities | (29 | ) | | (22 | ) |
| Net cash used for investing activities | (686 | ) | | (1,050 | ) |
| Financing Activities: | | | |
| Increase in notes payable, net | 475 |
| | — |
|
| Proceeds — | | | |
| Capital contributions from parent company | 153 |
| | 311 |
|
| Bonds — Other | — |
| | 23 |
|
| Interest-bearing refundable deposit | — |
| | 75 |
|
| Long-term debt issuance to parent company | — |
| | 220 |
|
| Other long-term debt issuances | — |
| | 250 |
|
| Short-term borrowings | 30 |
| | — |
|
| Redemptions — | | | |
| Long-term debt to parent company | — |
| | (220 | ) |
| Other long-term debt | (350 | ) | | — |
|
| Payment of preferred stock dividends | (1 | ) | | (1 | ) |
| Return of capital | — |
| | (165 | ) |
| Other financing activities | (7 | ) | | (3 | ) |
| Net cash provided from financing activities | 300 |
| | 490 |
|
| Net Change in Cash and Cash Equivalents | (37 | ) | | (55 | ) |
| Cash and Cash Equivalents at Beginning of Period | 133 |
| | 145 |
|
| Cash and Cash Equivalents at End of Period | $ | 96 |
| | $ | 90 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
| Interest (paid $58 and $55, net of $52 and $50 capitalized for 2015 and 2014, respectively) | $ | 6 |
| | $ | 5 |
|
| Income taxes, net | (55 | ) | | (210 | ) |
| Noncash transactions — | | | |
| Accrued property additions at end of period | 83 |
| | 124 |
|
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 September 30,
2015 | | At December 31,
2014 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 96 |
| | $ | 133 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 51 |
| | 43 |
|
| Unbilled revenues | | 42 |
| | 35 |
|
| Other accounts and notes receivable | | 11 |
| | 11 |
|
| Affiliated companies | | 31 |
| | 51 |
|
| Accumulated provision for uncollectible accounts | | (1 | ) | | (1 | ) |
| Fossil fuel stock, at average cost | | 95 |
| | 100 |
|
| Materials and supplies, at average cost | | 72 |
| | 62 |
|
| Other regulatory assets, current | | 119 |
| | 73 |
|
| Prepaid income taxes | | 183 |
| | 191 |
|
| Other current assets | | 10 |
| | 6 |
|
| Total current assets | | 709 |
| | 704 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 4,475 |
| | 4,378 |
|
| Less accumulated provision for depreciation | | 1,215 |
| | 1,173 |
|
| Plant in service, net of depreciation | | 3,260 |
| | 3,205 |
|
| Construction work in progress | | 2,596 |
| | 2,161 |
|
| Total property, plant, and equipment | | 5,856 |
| | 5,366 |
|
| Other Property and Investments | | 6 |
| | 5 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 278 |
| | 226 |
|
| Other regulatory assets, deferred | | 460 |
| | 385 |
|
| Income taxes receivable, non-current | | 544 |
| | — |
|
| Other deferred charges and assets | | 60 |
| | 71 |
|
| Total deferred charges and other assets | | 1,342 |
| | 682 |
|
| Total Assets | | $ | 7,913 |
| | $ | 6,757 |
|
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2016 | | 2015 | | 2016 | | 2015 |
| | (in millions) | | (in millions) |
| Net Income (Loss) | $ | 26 |
| | $ | (21 | ) | | $ | 40 |
| | $ | 63 |
|
| Other comprehensive income (loss) |
| |
| |
| |
|
| Qualifying hedges: | | | | | | | |
| Changes in fair value, net of tax of $-, $-, $-, and $-, respectively | — |
| | — |
| | (1 | ) | | — |
|
Reclassification adjustment for amounts included in net
income, net of tax of $-, $-, $-, and $-, respectively | — |
| | — |
| | 1 |
| | 1 |
|
| Total other comprehensive income (loss) | — |
| | — |
| | — |
| | 1 |
|
| Comprehensive Income (Loss) | $ | 26 |
| | $ | (21 | ) | | $ | 40 |
| | $ | 64 |
|
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 September 30,
2015 | | At December 31,
2014 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 429 |
| | $ | 778 |
|
| Notes payable | | 500 |
| | — |
|
| Interest-bearing refundable deposits | | — |
| | 275 |
|
| Accounts payable — | | | | |
| Affiliated | | 91 |
| | 86 |
|
| Other | | 109 |
| | 178 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 288 |
| | 142 |
|
| Other accrued taxes | | 67 |
| | 84 |
|
| Accrued interest | | 15 |
| | 76 |
|
| Accrued compensation | | 18 |
| | 26 |
|
| Over recovered regulatory clause liabilities | | 60 |
| | 1 |
|
| Mirror CWIP | | 369 |
| | 271 |
|
| Other current liabilities | | 87 |
| | 61 |
|
| Total current liabilities | | 2,033 |
| | 1,978 |
|
| Long-term Debt: | | | | |
| Long-term debt, affiliated | | 301 |
| | — |
|
| Long-term debt, non-affiliated | | 1,621 |
| | 1,630 |
|
| Total Long-term Debt | | 1,922 |
| | 1,630 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 674 |
| | 285 |
|
| Accumulated deferred investment tax credits | | 5 |
| | 283 |
|
| Employee benefit obligations | | 147 |
| | 148 |
|
| Asset retirement obligations | | 150 |
| | 48 |
|
| Unrecognized tax benefits | | 361 |
| | 2 |
|
| Other cost of removal obligations | | 171 |
| | 166 |
|
| Other regulatory liabilities, deferred | | 66 |
| | 64 |
|
| Other deferred credits and liabilities | | 48 |
| | 36 |
|
| Total deferred credits and other liabilities | | 1,622 |
| | 1,032 |
|
| Total Liabilities | | 5,577 |
| | 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 | | 2,767 |
| | 2,612 |
|
| Accumulated deficit | | (496 | ) | | (559 | ) |
| Accumulated other comprehensive loss | | (6 | ) | | (7 | ) |
| Total common stockholder's equity | | 2,303 |
| | 2,084 |
|
| Total Liabilities and Stockholder's Equity | | $ | 7,913 |
| | $ | 6,757 |
|
|
| | | | | | | |
| | For the Nine Months Ended September 30, |
| | 2016 | | 2015 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 40 |
| | $ | 63 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 115 |
| | 94 |
|
| Deferred income taxes | 34 |
| | 518 |
|
| Investment tax credits | — |
| | 25 |
|
| Allowance for equity funds used during construction | (90 | ) | | (82 | ) |
| Regulatory assets associated with Kemper IGCC | (13 | ) | | (56 | ) |
| Estimated loss on Kemper IGCC | 222 |
| | 182 |
|
| Income taxes receivable, non-current | — |
| | (544 | ) |
| Other, net | 12 |
| | 7 |
|
| Changes in certain current assets and liabilities — | | | |
| -Prepaid income taxes | 38 |
| | (1 | ) |
| -Other current assets | 7 |
| | 4 |
|
| -Accounts payable | 5 |
| | (32 | ) |
| -Accrued taxes | 95 |
| | 24 |
|
| -Over recovered regulatory clause revenues | (20 | ) | | 59 |
|
| -Mirror CWIP | — |
| | 99 |
|
| -Customer liability associated with Kemper refunds | (73 | ) | | — |
|
| -Other current liabilities | — |
| | (11 | ) |
| Net cash provided from operating activities | 372 |
| | 349 |
|
| Investing Activities: | | | |
| Property additions | (592 | ) | | (626 | ) |
| Construction payables | (25 | ) | | (31 | ) |
| Capital grant proceeds | 137 |
| | — |
|
| Other investing activities | (29 | ) | | (29 | ) |
| Net cash used for investing activities | (509 | ) | | (686 | ) |
| Financing Activities: | | | |
| Increase in notes payable, net | — |
| | 475 |
|
| Proceeds — | | | |
| Capital contributions from parent company | 227 |
| | 153 |
|
| Long-term debt to parent company | 200 |
| | — |
|
| Other long-term debt | 900 |
| | — |
|
| Short-term borrowings | — |
| | 30 |
|
| Redemptions — | | | |
| Short-term borrowings | (475 | ) | | (5 | ) |
| Long-term debt to parent company | (225 | ) | | — |
|
| Other long-term debt | (425 | ) | | (350 | ) |
| Other financing activities | (4 | ) | | (3 | ) |
| Net cash provided from financing activities | 198 |
| | 300 |
|
| Net Change in Cash and Cash Equivalents | 61 |
| | (37 | ) |
| Cash and Cash Equivalents at Beginning of Period | 98 |
| | 133 |
|
| Cash and Cash Equivalents at End of Period | $ | 159 |
| | $ | 96 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
Interest (paid $72 and $58, net of $36 and $52 capitalized for 2016
and 2015, respectively) | $ | 36 |
| | $ | 6 |
|
| Income taxes, net | (231 | ) | | (55 | ) |
| Noncash transactions — | | | |
| Accrued property additions at end of period | 80 |
| | 83 |
|
Issuance of promissory note to parent related to repayment of interest-bearing refundable deposits and accrued interest | — |
| | 301 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At September 30, 2016 | | At December 31, 2015 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 159 |
| | $ | 98 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 39 |
| | 26 |
|
| Unbilled revenues | | 47 |
| | 36 |
|
| Income taxes receivable, current | | — |
| | 20 |
|
| Other accounts and notes receivable | | 6 |
| | 10 |
|
| Affiliated | | 17 |
| | 20 |
|
| Fossil fuel stock | | 96 |
| | 104 |
|
| Materials and supplies | | 75 |
| | 75 |
|
| Other regulatory assets, current | | 118 |
| | 95 |
|
| Prepaid income taxes | | — |
| | 39 |
|
| Other current assets | | 10 |
| | 8 |
|
| Total current assets | | 567 |
| | 531 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 4,835 |
| | 4,886 |
|
| Less accumulated provision for depreciation | | 1,259 |
| | 1,262 |
|
| Plant in service, net of depreciation | | 3,576 |
| | 3,624 |
|
| Construction work in progress | | 2,525 |
| | 2,254 |
|
| Total property, plant, and equipment | | 6,101 |
| | 5,878 |
|
| Other Property and Investments | | 12 |
| | 11 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 330 |
| | 290 |
|
| Other regulatory assets, deferred | | 510 |
| | 525 |
|
| Income taxes receivable, non-current | | 544 |
| | 544 |
|
| Other deferred charges and assets | | 101 |
| | 61 |
|
| Total deferred charges and other assets | | 1,485 |
| | 1,420 |
|
| Total Assets | | $ | 8,165 |
| | $ | 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 September 30, 2016 | | At December 31, 2015 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 343 |
| | $ | 728 |
|
| Notes payable | | 25 |
| | 500 |
|
| Accounts payable — | | | | |
| Affiliated | | 92 |
| | 85 |
|
| Other | | 126 |
| | 135 |
|
| Customer deposits | | 16 |
| | 16 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 110 |
| | — |
|
| Other accrued taxes | | 75 |
| | 85 |
|
| Accrued interest | | 20 |
| | 18 |
|
| Accrued compensation | | 21 |
| | 26 |
|
| Asset retirement obligations, current | | 36 |
| | 22 |
|
| Over recovered regulatory clause liabilities | | 76 |
| | 96 |
|
| Customer liability associated with Kemper refunds | | 1 |
| | 73 |
|
| Other current liabilities | | 37 |
| | 52 |
|
| Total current liabilities | | 978 |
| | 1,836 |
|
| Long-term Debt: | | | | |
| Long-term debt, affiliated | | 551 |
| | 576 |
|
| Long-term debt, non-affiliated | | 2,161 |
| | 1,310 |
|
| Total Long-term Debt | | 2,712 |
| | 1,886 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 823 |
| | 762 |
|
| Deferred credits related to income taxes | | 7 |
| | 8 |
|
| Employee benefit obligations | | 146 |
| | 153 |
|
| Asset retirement obligations, deferred | | 154 |
| | 154 |
|
| Unrecognized tax benefits | | 382 |
| | 368 |
|
| Other cost of removal obligations | | 172 |
| | 165 |
|
| Other regulatory liabilities, deferred | | 76 |
| | 71 |
|
| Other deferred credits and liabilities | | 54 |
| | 45 |
|
| Total deferred credits and other liabilities | | 1,814 |
| | 1,726 |
|
| Total Liabilities | | 5,504 |
| | 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 | | 3,124 |
| | 2,893 |
|
| Accumulated deficit | | (528 | ) | | (566 | ) |
| Accumulated other comprehensive loss | | (6 | ) | | (6 | ) |
| Total common stockholder's equity | | 2,628 |
| | 2,359 |
|
| Total Liabilities and Stockholder's Equity | | $ | 8,165 |
| | $ | 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
THIRD QUARTER 20152016 vs. THIRD 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 December 31, 2016. The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." On October 11, 2016, the Kemper IGCC began testing using clean syngas from gasifier "A" and the related gas clean-up systems to produce electricity. On November 2, 2016, Mississippi Power determined a maintenance outage of gasifier "A" is needed to make improvements to the ash removal systems. The remaining schedule reflects the time expected to achieve production of electricity using gasifier "B," complete gasifier "A" outage activities, and resume electricity production using gasifier "A," as well as to complete the integration of all systems necessary for both combustion turbines to simultaneously generate electricity with syngas.
Mississippi Power's current cost estimate for the Kemper IGCC in total is approximately $6.43$6.82 billion, which includes approximately $5.11$5.52 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 above the cost cap of $150totaling $88 million ($9354 million after tax) in the third quarter 20152016 and a total of $182$222 million ($112137 million after tax) for the nine months ended September 30, 2015.2016. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.23$2.63 billion ($1.41.63 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through September 30, 2015.2016.
In addition, during the start-up and commissioning process, Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC project in service in August 2014 and continuesis identifying potential improvement projects that ultimately may be completed subsequent to focus on completingplacing the remainder of the Kemper IGCC includingin service. If
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
completed, such improvement projects would be expected to enhance plant performance, safety, and/or operations. The related potential costs have yet to be fully evaluated, have not been included in the gasifiercurrent cost estimate, and may be subject to the gas clean-up facilities. While$2.88 billion cost cap. Any further changes in the expected in-service date for the remainderestimated costs of the Kemper IGCC issubject to the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Mississippi Power's statements of income and these changes could be material.
In December 2015, the first halfMississippi PSC issued an order (In-Service Asset Rate Order), based on a stipulation (2015 Stipulation) between Mississippi Power and the Mississippi Public Utilities Staff (MPUS), authorizing rates that provide for the recovery of approximately $126 million annually related to 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 In-Service Asset Rate Order.
On August 17, 2016, the Mississippi PSC issued an order establishing a discovery docket to manage all filings related to the prudence of the Kemper IGCC. On October 3, 2016, Mississippi Power nowmade a required compliance filing, which included a review and explanation of differences between the Kemper IGCC project estimate set forth in the 2010 CPCN proceeding and the most recent Kemper IGCC project estimate, as well as comparisons of current cost estimates and current expected plant operational parameters to the estimates presented in the 2010 CPCN proceedings for the first five years following the start of commercial operations. Certain costs, including operations and maintenance, are materially higher than the amounts presented in the CPCN proceedings. Additionally, while the current estimated operational availability estimates reflect ultimate results similar to those presented in the 2010 CPCN proceedings, the ramp up period for the current estimates reflects a lower starting point and a slower escalation rate. Mississippi Power expects the Mississippi PSC to address these issues in connection with its next rate request.
Mississippi Power anticipates that it will incur additional expenses in excess of current rates associated with operating the Kemper IGCC after it is placed in service until the Kemper IGCC cost recovery approach is finalized, which are expected to be material. Mississippi Power expects to request authority from the Mississippi PSC and the FERC to defer all Kemper IGCC costs incurred after the in-service date to occur subsequent to April 19, 2016, which would resultthat cannot be capitalized, are not included in Mississippi Power beingcurrent rates, and are not required to recapture the investment tax credits that were allocated to the Kemper IGCC under Section 48A (Phase II) of the Internal Revenue Code. The current cost estimate includes costs through June 30, 2016. Asbe charged against earnings as a result of the additional factors$2.88 billion cost cap until such time as the Mississippi PSC completes its review and includes the resulting allowable costs in rates. Mississippi Power is required to file its next rate request with the Mississippi PSC related to cost recovery for the Kemper IGCC by June 3, 2017. The ultimate outcome of these matters cannot be determined at this time.
Southern Company and Mississippi Power are defendants in two lawsuits that allege improper disclosure of important facts about the Kemper IGCC. While Mississippi Power believes that these lawsuits are without merit, an adverse outcome could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity. In addition, the 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 Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and "Other Matters" and Note (B) to the Condensed Financial Statements under "Integrated"Integrated Coal Gasification Combined Cycle"Cycle" herein.
On February 12, 2015,As of September 30, 2016, Mississippi Power's current liabilities exceeded current assets by approximately $411 million primarily due to the Mississippi Supreme Court (Court) reversed$300 million in senior notes which matured on October 15, 2016, as well as $65 million in short-term debt. In addition, if the Mississippi PSC's March 2013 order that authorized collection of $156 million annually (2013 MPSC Rate Order) to be recorded as Mirror CWIP and directed the Mississippi PSC to enter an order requiringKemper IGCC does not go into service by December 31, 2016, Mississippi Power would have to refund the Mirror CWIP amountsrepay approximately $250 million of tax benefits received as a result of quarterly income tax estimates through September 30, 2016.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
collected. Following the Court's rejection of both Mississippi Power's and the Mississippi PSC's motions for rehearing, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015. Refunds of the $342 million collected by Mississippi Power through July 2015 billings, plus carrying costs, will begin in early November 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, Mississippi Power filed a rate case on May 15, 2015 (2015 Rate Case) that 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).
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. In connection with the termination of the APA, on June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million ($275 million in deposits plus interest) 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 $369 million of Mirror CWIP rate collections, including associated carrying costs through September 30, 2015, the termination of the Mirror CWIP rates, and the likely repayment of approximately $235 million of unrecognized tax benefits associated with the Phase II tax credits to the IRS if the in-service date of the Kemper IGCC extends beyond April 19, 2016 have adversely impacted Mississippi Power's financial condition.
As a result of the Court's decision and these financial impacts, on July 10, 2015, Mississippi Power submitted a supplemental filing with the Mississippi PSC that included 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 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, and is designed to collect approximately $159 million annually. On August 13, 2015, the Mississippi PSC approved the implementation of interim rates that became effective with the first billing cycle in September (on August 19), subject to refund and certain other conditions. In addition, the Mississippi PSC reserved the right to modify or terminate the interim rates based upon a material change in circumstances. The Mississippi PSC is scheduled to issue a final order on or before December 8, 2015 related to permanent rates for the In-Service Asset Proposal. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Rate Case" herein for additional information.
As of September 30, 2015, Mississippi Power's current liabilities exceeded current assets by approximately $1.3 billion primarily due to $900 million of bank term loans scheduled to mature on April 1, 2016, the required refund of approximately $369 million in Mirror CWIP, which includes associated carrying costs through September 30, 2015, and the likely repayment of the Phase II tax credits of $235 million as of September 30, 2015. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Mississippi Supreme Court Decision" and Note (G) to the Condensed Financial Statements under "Unrecognized Tax Benefits – Investment Tax Credits" herein for additional information. Mississippi Power is primarily dependent upon Southern Company to meet its financing needs. 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.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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)
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $174 | | 89.2 | | $367 | | N/M |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $47 | | N/M | | $(23) | | (37.1) |
N/M –- Not meaningful
Mississippi Power's net lossincome after dividends on preferred stock for the third quarter 20152016 was $21$26 million compared to $195a net loss of $21 million for the corresponding period in 2014.2015. The changeincrease was primarily related to lower pre-tax charges of $88 million ($54 million after tax) in the third quarter 2016 compared to pre-tax charges of $150 million ($93 million after tax) in the third quarter 2015 compared to $418 million ($258 million after tax) in the third quarter 2014 for revisions of the estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC above the $2.88 billion cost cap established by the Mississippi PSC, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. The increase in net income was also relateddue to an increase in retail revenue due to the implementation of interim rates that became effective with the first billing cycle in September (on August 19), partially offset by revenues associated with the Kemper IGCC cost recovery recognized in 2014, prior to the 2015 Mississippi Supreme Court decision. The change in net income was also related toand a decrease in non-fuel operations and maintenance expenses, decrease in other income and deductions, a decrease in AFUDC, an increase in depreciation and amortization, andpartially offset by an increase in interest expense.other operations and maintenance expenses.
For year-to-date 2015,2016, net income after dividends on preferred stock was $62$39 million compared to a net loss of $305$62 million for the corresponding period in 2014.2015. The increasedecrease was primarily related to a decrease in interest on deposits in 2015 resulting from the termination of an asset purchase agreement between Mississippi Power and SMEPA in May 2015, higher depreciation and amortization, and higher pre-tax charges of $222 million ($137 million after tax) in 2016 compared to pre-tax charges of $182 million in pre-tax charges ($112 million after tax) in 2015 compared to $798 million in pre-tax charges ($493 million after tax) in 2014 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 increasedecrease in net income was also related topartially offset by an increase in retail revenue due to the implementation of interim rates that became effective with the first billing cycle in September (on August 19) and a decrease in interest expense primarily due to the SMEPA termination, partially offset by a decrease in Kemper revenues primarily resulting from the termination of the Mirror CWIP rate, a decrease in AFUDC equity, increases in non-fuel operations and maintenance expenses, and an increase in depreciation and amortization.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 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
Retail Revenues
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $19 | | 7.8 | | $51 | | 8.5 |
In the third quarter 2016, retail revenues were $263 million compared to $244 million for additional information.the corresponding period in 2015. For year-to-date 2016, retail revenues were $652 million compared to $601 million for the corresponding period in 2015.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Retail Revenues
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $16 | | 7.0 | | $(46) | | (7.1) |
In the third quarter 2015, retail revenues were $244 million compared to $228 million for the corresponding period in 2014. For year-to-date 2015, retail revenues were $601 million compared to $647 million for the corresponding period in 2014.
Details of the changes in retail revenues were as follows:
| | | | | Third Quarter
2015 | | Year-to-Date 2015 | Third Quarter 2016 | | Year-to-Date 2016 |
| | | (in millions) |
| (% change) | | (in millions) | | (% change) | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | | $ | 228 |
| | | | $ | 647 |
| | | $ | 244 |
| | | | $ | 601 |
| | |
| Estimated change resulting from – | | | | | | | | | | | | | | | |
| Rates and pricing | | 24 |
| | 10.5 |
| | 15 |
| | 2.3 |
| 8 |
| | 3.3 |
| | 66 |
| | 11.0 |
|
| Sales growth (decline) | | 1 |
| | 0.4 |
| | (4 | ) | | (0.6 | ) | (3 | ) | | (1.3 | ) | | (2 | ) | | (0.3 | ) |
| Weather | | — |
| | — |
| | 1 |
| | 0.2 |
| 7 |
| | 2.9 |
| | 5 |
| | 0.8 |
|
| Fuel and other cost recovery | | (9 | ) | | (3.9 | ) | | (58 | ) | | (9.0 | ) | 7 |
| | 2.9 |
| | (18 | ) | | (3.0 | ) |
| Retail – current year | | $ | 244 |
| | 7.0 | % | | $ | 601 |
| | (7.1 | )% | $ | 263 |
| | 7.8 | % | | $ | 652 |
| | 8.5 | % |
Revenues associated with changes in rates and pricing increased in the third quarter 2015and year-to-date 2016 when compared to the corresponding periodperiods in 2014,2015, primarily due to $28 million for the implementation of interim rates associated with thefor certain Kemper IGCC that became effective with the first billing cycle in September (on August 19), partially offset by $5 million associated with the Kemper IGCC cost recovery recognized in the third quarter 2014, prior to the 2015 Mississippi Supreme Court decision.
Revenues associated with changes in rates and pricing increased year-to-date 2015 when compared to the corresponding period in 2014, primarily due to $28 million for the implementation of interim rates associated with the Kemper IGCC that became effective with the first billing cycle in September (on August 19) and $3 million of net revenues associated with the new energy efficiency cost recovery rate, which began in the fourth quarter 2014. These increases were partially offset by $16 million associated with the Kemper IGCC cost recovery recognized in 2014, prior to the 2015 Mississippi Supreme Court decision.
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 increased in the third quarter 2015 when compared to the corresponding period in 2014. Weather-adjusted KWH sales to residential customers increased 0.4% in the third quarter 2015 due to an increase in customers and customer usage. Weather-adjusted KWH sales to commercial customers decreased 0.6% in the third quarter 2015 due to lower customer usage slightly offset by an increase in customers. KWH sales to industrial customers increased 0.8% in the third quarter 2015 due to increased usage by larger customers related to increased production.
Revenues attributable to changes in sales decreased year-to-date 2015in the third quarter 2016 when compared to the corresponding period in 2014.2015. Weather-adjusted KWH energy sales to residential customers decreased 0.6% due to lower customer usage, slightly offset by an increase in customers. Weather-adjusted KWH energy sales toand commercial customers decreased 0.3%6.7% and 0.9%, respectively, in the third quarter 2016 due to lowerdecreased customer usage slightlyprimarily resulting from efficiency improvements in residential appliances and lighting, partially offset by an increase in customers.customer growth. KWH energy sales to industrial customers increased 1.1%decreased 1.7% in the third quarter 2016 primarily due to increasedan unplanned outage by a large customer.
Revenues attributable to changes in sales decreased for year-to-date 2016 when compared to the corresponding period in 2015. Weather-adjusted KWH sales to residential and commercial customers decreased 2.6% and 1.5%, respectively, due to decreased customer usage primarily resulting from efficiency improvements in residential appliances and lighting, partially offset by larger customers.customer growth. KWH sales to industrial customers decreased 0.7% primarily due to an unplanned outage by a large customer.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 thirdfirst quarter and year-to-date 20142015 KWH sales among customer classes that is consistent with the actual allocation in 2015.2016. Without these adjustments, third quarter 2015this adjustment, year-to-date 2016 weather-adjusted residential KWH sales decreased 0.3%0.8%, weather-adjusted commercial KWH sales to commercial customers increased 3.8%0.6%, and industrial KWH sales increased 0.9%to industrial customers were relatively flat as compared to the corresponding period in 2014. Also, without these adjustments, year-to-date 2015 weather-adjusted residential KWH sales decreased 2.1%, weather-adjusted commercial KWH sales decreased 1.8%,2015.
Fuel and industrial KWH salesother cost recovery revenues increased 0.3% asin the third quarter 2016 when compared to the corresponding period in 2014.
2015, primarily as a result of revised ECO Plan rates which became effective with the first billing cycle for September 2016, partially offset by lower recoverable fuel costs. Fuel and other cost recovery revenues decreased in the third quarter andfor year-to-date 20152016 when compared to the corresponding periodsperiod in 2014,2015, primarily as a result of lower recoverable fuel costs.costs, partially offset by revised ECO Plan rates which became effective with the first billing cycle for September 2016. 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.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale Revenues – Non-Affiliates
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $(7) | | (8.4) | | $(39) | | (15.3) |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $2 | | 2.6 | | $(18) | | (8.3) |
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Mississippi Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. In addition, Mississippi Power 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""FERC Matters" herein for additional information.
In the third quarter 2015,For year-to-date 2016, wholesale revenues from sales to non-affiliates were $76$198 million compared to $83$216 million for the corresponding period in 2014. For year-to-date 2015, wholesale revenues from sales to non-affiliates were $216 million compared to $255 million for the corresponding period in 2014.2015. The decreases weredecrease was primarily due to a $16 million decrease in energy revenues primarily resulting from lower fuel prices.natural gas prices and decreased usage primarily resulting from milder weather.
Wholesale Revenues – Affiliates
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $(21) | | (53.8) | | $(19) | | (23.2) |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(11) | | (61.1) | | $(40) | | (63.5) |
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 third quarter 2016, wholesale revenues from sales to affiliates were $7 million compared to $18 million for the corresponding period in 2015. The decrease was due to a decrease in KWH sales primarily due to availability of lower cost alternatives.
For year-to-date 2016, wholesale revenues from sales to affiliates were $23 million compared to $63 million for the corresponding period in 2015. The decrease was due to a $35 million decrease in KWH sales primarily due to availability of lower cost alternatives and a $5 million decrease associated with lower natural gas prices.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In the third quarter 2015, wholesale revenues from sales to affiliates were $18 million compared to $39 million for the corresponding period in 2014. The decrease was due to a $16 million decrease in KWH sales resulting from a decrease in sales from coal generation and a $5 million decrease associated with lower natural gas prices.
For year-to-date 2015, wholesale revenues from sales to affiliates were $63 million compared to $82 million for the corresponding period in 2014. The decrease was due to a $20 million decrease associated with lower natural gas prices, partially offset by a $1 million increase in KWH sales due to an increase in generation partially as a result of the Kemper IGCC combined cycle being in service since August 2014.
Fuel and Purchased Power Expenses
| | | | | Third Quarter 2015
vs.
Third Quarter 2014 | | Year-to-Date 2015
vs.
Year-to-Date 2014 | | Third Quarter 2016
vs.
Third 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 | | $ | (39 | ) | | (23.1) | | $ | (100 | ) | | (21.8 | ) | | $ | (18 | ) | | (13.8) | | $ | (91 | ) | | (25.3) |
| Purchased power – non-affiliates | | (2 | ) | | (66.7) | | (11 | ) | | (68.8 | ) | | 2 |
| | N/M | | (1 | ) | | (20.0) |
| Purchased power – affiliates | | (1 | ) | | (50.0) | | (11 | ) | | (64.7 | ) | | 4 |
| | N/M | | 8 |
| | N/M |
| Total fuel and purchased power expenses | | $ | (42 | ) | | $ | (122 | ) | | | | $ | (12 | ) | | $ | (84 | ) | |
N/M - Not meaningful
In the third quarter 2015,2016, total fuel and purchased power expenses were $132$120 million compared to $174$132 million for the corresponding period in 2014.2015. The decrease was primarily due to a $22 millionnet decrease in the volume of KWHs generated and purchased andprimarily due to a $20 million decrease in the average cost of fuel.non-territorial sales.
For year-to-date 2015,2016, total fuel and purchased power expenses were $370$286 million compared to $492$370 million for the corresponding period in 2014.2015. The decrease was due to an $89a $49 million decrease in the average cost of fuel and purchased power and a $33 millionnet decrease in the volume of KWHs generated and purchased.purchased primarily due to a decrease in non-territorial sales and milder weather and a $35 million decrease due to lower natural gas prices.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Mississippi Power's fuel cost recovery clause.
Details of Mississippi Power's generation and purchased power were as follows:
|
| | | | | | | | |
| | | Third Quarter 2015 | | Third Quarter 2014 | | Year-to-Date 2015 | | Year-to-Date 2014 |
Total generation (millions of KWHs)(*) | | 4,681 | | 5,022 | | 13,136 | | 12,996 |
Total purchased power (millions of KWHs) | | 121 | | 125 | | 427 | | 591 |
Sources of generation (percent)(*) – | | | | | | | | |
| Coal | | 19 | | 43 | | 20 | | 45 |
| Gas | | 81 | | 57 | | 80 | | 55 |
Cost of fuel, generated (cents per net KWH) – | | | | | | | | |
| Coal | | 3.81 | | 3.97 | | 3.70 | | 4.12 |
Gas(*) | | 2.72 | | 3.20 | | 2.70 | | 3.45 |
Average cost of fuel, generated (cents per net KWH)(*) | | 2.93 | | 3.55 | | 2.91 | | 3.77 |
Average cost of purchased power (cents per net KWH)(*) | | 2.21 | | 4.36 | | 2.42 | | 5.55 |
|
| | | | | | | |
| | Third Quarter 2016 | | Third Quarter 2015 | | Year-to-Date 2016 | | Year-to-Date 2015 |
Total generation (in millions of KWHs) | 4,255 | | 4,681 | | 11,570 | | 13,136 |
Total purchased power (in millions of KWHs) | 288 | | 121 | | 877 | | 427 |
Sources of generation (percent) – | | | | | | | |
| Coal | 10 | | 19 | | 9 | | 20 |
| Gas | 90 | | 81 | | 91 | | 80 |
Cost of fuel, generated (in cents per net KWH) – | | | | | | | |
| Coal | 4.02 | | 3.81 | | 4.09 | | 3.70 |
| Gas | 2.64 | | 2.72 | | 2.34 | | 2.70 |
Average cost of fuel, generated (in cents per net KWH) | 2.79 | | 2.93 | | 2.50 | | 2.91 |
Average cost of purchased power (in cents per net KWH) | 2.59 | | 2.21 | | 2.04 | | 2.42 |
| |
(*) | Includes energy produced during the test period for the Kemper IGCC which is accounted for in accordance with FERC guidance. |
Fuel
In the third quarter 2015,2016, fuel expense was $130$112 million compared to $169$130 million for the corresponding period in 2014.2015. The decrease was due to a 17.4%10.2% decrease in the volume of KWHs generated primarily as a result of lower wholesale sales and a 4.8% decrease in the average cost of fuel per KWH generated primarily due to a 2.7% lower cost of natural gas.
For year-to-date 2016, total fuel expense was $268 million compared to $359 million for the corresponding period in 2015. The decrease was due to a 12.9% decrease in the volume of KWHs generated primarily as a result of lower wholesale sales and a 14.2% decrease in the average cost of fuel per KWH generated primarily due to a 13.6% lower cost of natural gas.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
higher gas-fired generation, including the Kemper IGCC combined cycle that was placed in service in August 2014, at lower natural gas prices and a 6.4% decrease in the volume of KWHs generated. The 6.4% decrease in volume included a decrease in coal-fired generation of 59.1%, partially offset by an increase in gas-fired generation of 36.6%.
For year-to-date 2015, total fuel expense was $359 million compared to $459 million for the corresponding period in 2014. The decrease was due to a 22.8% 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 1.2% increase in the volume of KWHs generated resulting from the availability of lower cost Mississippi Power units. The 1.2% increase in volume included an increase in gas-fired generation of 53.4%, partially offset by a decrease in coal-fired generation of 55.7%.
Purchased Power - Non-Affiliates
In the third quarter 2015,For year-to-date 2016, purchased power expense from non-affiliates was $1$4 million compared to $3$5 million for the corresponding period in 2014. For year-to-date 2015, purchased power expense from non-affiliates2015. The decrease was $5 million comparedprimarily due to $16 million for the corresponding period in 2014. The decreases were primarily the result of a 43.1% decrease in the average cost per KWH purchased asdue to lower energy costs from available gas-fired resources, partially offset by a result49.0% increase in the volume of KWHs purchased due to the availability of lower natural gas prices.cost energy.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.
Purchased Power - Affiliates
For year-to-date 2015,In the third quarter 2016, purchased power expense from affiliates was $6$5 million compared to $17$1 million for the corresponding period in 2014.2015. The decreaseincrease was primarily due to a 45.2% decrease234.7% increase in the volume of KWHs purchased due to increased Mississippi Power generation partiallythe availability of lower cost energy as a result of the Kemper IGCC combined cycle being placed in service in August 2014,compared to self-generation fuel cost and a 38.4%9.9% increase in the average cost per KWH purchased due to higher power pool interchange rates associated with higher natural gas prices.
For year-to-date 2016, purchased power expense from affiliates was $14 million compared to $6 million for the corresponding period in 2015. The increase was primarily due to a 163.8% increase in the volume of KWHs purchased due to the availability of lower cost energy as compared to self-generation fuel cost, partially offset by a 5.9% decrease in the average cost per KWH purchased due to lower power pool interchange rates as a result of lower natural gasfuel 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 or other contractual agreements, as approved by the FERC.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(4) | | (6.0) | | $14 | | 7.3 |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $11 | | 17.5 | | $5 | | 2.4 |
In the third quarter 2015,2016, other operations and maintenance expenses were $63$74 million compared to $67$63 million for the corresponding period in 2014. The decrease was primarily due to a $2 million decrease in transmission and distribution expenses mainly related to overhead line maintenance and vegetation management and a $2 million decrease primarily related to uncollectible expenses and customer incentives.
For year-to-date 2015, other operations and maintenance expenses were $206 million compared to $192 million for the corresponding period in 2014.2015. The increase was primarily due to a $7 million increase in generation maintenance expenses including scheduled outages, a $5 million increaserelated to the combined cycle and the associated common facilities portion of the Kemper IGCC that Mississippi Power began recognizing in employee compensation and benefits including pension,connection with interim rates associated with the Kemper IGCC in-service assets implemented in September 2015 and a $4 million increase related to uncollectible expenses and customer incentives, partially offset by a $2 million decrease in transmission and distribution expenses mainly related to overhead line maintenance and vegetation management.management expenses.
For year-to-date 2016, other operations and maintenance expenses were $211 million compared to $206 million for the corresponding period in 2015. The increase was primarily due to a $23 million increase in maintenance expenses related to the combined cycle and the associated common facilities portion of the Kemper IGCC that Mississippi Power began recognizing in connection with interim rates associated with the Kemper IGCC in-service assets implemented in September 2015, partially offset by a $15 million decrease in generation outage costs and a $4 million decrease primarily related to pension costs.
See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Rate Case" and " – Regulatory Assets and Liabilities" herein for additional information. See Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Depreciation and Amortization
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $15 | | 65.2 | | $25 | | 35.7 |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(8) | | (21.1) | | $19 | | 20.0 |
In the third quarter 2015,2016, depreciation and amortization was $38$30 million compared to $23$38 million for the corresponding period in 2014.2015. The decrease was primarily due to a $17 million deferral associated with the implementation of revised ECO Plan rates with the first billing cycle for September 2016, partially offset by an increase in depreciation and amortization of $9 million primarily related to the In-Service Asset Rate Order, ECO Plan, MATS rule compliance, and additional plant in service assets.
For year-to-date 2016, depreciation and amortization was $114 million compared to $95 million for the corresponding period in 2015. The increase was primarily due to a $9 million increase inadditional regulatory asset amortization of regulatory$16 million related to the In-Service Asset Rate Order, ECO Plan, and MATS rule compliance, $12 million primarily due to Kemper IGCC deferrals, and $8 million of depreciation for additional plant in service assets, primarily the Plant Daniel scrubbers. These increases were partially offset by a $17 million deferral associated with the Kemper IGCC primarily as a resultimplementation of interimrevised ECO Plan rates that became effective with the first billing cycle infor September (on August 19), and a $6 million increase in depreciation related to increases in generation, transmission and distribution plant in service.2016.
For year-to-date 2015, depreciation and amortization was $95 million compared to $70 million for the corresponding period in 2014. The increase was primarily due to a $10 million increase in depreciation related to increases in generation, transmission and distribution plant in service, a $10 million increase in amortization of regulatory assets associated with the Kemper IGCC as a result of interim rates that became effective with the first billing cycle in September (on August 19), and a $2 million increase related to regulatory deferrals associated with Plant Daniel Units 3 and 4.
See Note 1 to the financial statements of Mississippi Power under "Depreciation, Depletion, and Amortization" in Item 8 of the Form 10-K for additional information. Also, see Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated"Retail Regulatory Matters – Mississippi Power – Environmental Compliance Overview Plan" and "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
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $2 | | 9.1 | | $8 | | 12.7 |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $7 | | 29.2 | | $10 | | 14.1 |
In the third quarter 2015,2016, taxes other than income taxes were $24$31 million compared to $22$24 million for the corresponding period in 2014.2015. For year-to-date 2015,2016, taxes other than income taxes were $71$81 million compared to $63$71 million for the corresponding period in 2014.2015. The increases were primarily due to increases in ad valorem taxes.taxes of $4 million and $6 million for the third quarter and year-to-date 2016, respectively, due to an increase in the assessed value of property as well as increases in franchise taxes of $3 million and $4 million for the third quarter and year-to-date 2016, respectively.
The retail portion of ad valorem taxes is recoverable under Mississippi Power's ad valorem tax cost recovery clause and, therefore, does not affect net income.
Estimated Loss on Kemper IGCC
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $(268) | | (64.1) | | $(616) | | (77.2) |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(62) | | (41.3) | | $40 | | 22.0 |
In the third quarters of 20152016 and 2014,2015, estimated probable losses on the Kemper IGCC of $150$88 million and $418$150 million, respectively, were recorded at Mississippi Power. For year-to-date 20152016 and year-to-date 2014,2015, estimated probable losses on the Kemper IGCC of $182$222 million and $798$182 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 DOE Grants and excluding the Cost Cap Exceptions.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of the Initial DOE Grants and excluding the Cost Cap Exceptions.
See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated"Integrated Coal Gasification Combined Cycle"Cycle" herein for additional information.
Allowance for Equity Funds Used During Construction
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(3) | | (9.4) | | $(26) | | (24.1) |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $2 | | 6.9 | | $8 | | 9.8 |
In the third quarter 2015,of 2016, AFUDC equity was $29$31 million compared to $32$29 million for the corresponding period in 2014.2015. For year-to-date 2015,2016, AFUDC equity was $82$90 million compared to $108$82 million for the corresponding period in 2014.2015. The decreasesincreases were driven by a reduction in thehigher AFUDC rate and an increase in Kemper IGCC CWIP subject to AFUDC, 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 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
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $2 | | 15.4 | | $52 | | N/M |
N/M - Not meaningful
In the third quarter 2016, interest expense, net of amounts capitalized was $15 million compared to $13 million for the corresponding period in 2015. The increase was related to additional long-term debt and a decrease in amounts capitalized, partially offset by a decrease in interest accrued on the Mirror CWIP liability prior to refund.
For year-to-date 2016, interest expense, net of amounts capitalized was $46 million compared to $(6) million for the corresponding period in 2015. The increase was primarily due to a $31 million decrease in interest on deposits in 2015 resulting from the termination of an asset purchase agreement between Mississippi Power and SMEPA in May 2015. In addition, the increase was related to additional long-term debt and a decrease in amounts capitalized, partially offset by a decrease in interest accrued on the Mirror CWIP liability prior to refund.
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 regardingon the Kemper IGCC.Mirror CWIP refund.
Interest Expense, Net of Amounts CapitalizedIncome Taxes (Benefit)
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $4 | | 44.4 | | $(40) | | N/M |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $29 | | 93.5 | | $(18) | | N/M |
N/M –- Not meaningful
In the third quarter 2015, interest expense, net of amounts capitalized2016, income tax benefit was $13$(2) million compared to $9$(31) million for the corresponding period in 2014.2015. The increasechange was primarily due to a decreasethe reduction in the estimated probable losses on construction of $6 million in capitalized interest primarily resulting from placing the Kemper IGCC combined cycle in service in August 2014, a $3 million increase due to the issuances of new debt, and a $2 million increase related to the Mirror CWIP regulatory liability, partially offset by a $7 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.IGCC.
For year-to-date 2015, interest expense, net of amounts capitalized was $(6) million compared to $34 million for the corresponding period in 2014. The decrease was primarily due to a $50 million decrease related to the termination of the APA between Mississippi Power and SMEPA which also required the return of SMEPA's deposits at a lower rate of interest than accrued. Also contributing to the decrease was a $2 million increase in capitalized interest primarily resulting from carrying costs related to the Kemper IGCC, partially offset by increases of $7 million related to the Mirror CWIP regulatory liability and $5 million due to the issuances of new debt.
See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Other Income (Expense), Net
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $6 | | 75.0 | | $7 | | 58.3 |
In the third quarter 2015, other income (expense), net was $(2) million compared to $(8) million for the corresponding period in 2014. For year-to-date 2015, other income (expense), net was $(5) million compared to $(12) million for the corresponding period in 2014. These changes in expense were primarily due to a settlement
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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with the Sierra Club in 2014. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Sierra Club Settlement Agreement" of Mississippi Power in Item 8 of the Form 10-K for additional information.
Income Taxes (Benefit)
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $108 | | 77.7 | | $242 | | 95.7 |
In the third quarter 2015,For year-to-date 2016, income tax benefits were $31benefit was $(29) million compared to $139$(11) million for the corresponding period in 2014. For year-to-date 2015, income tax benefits were $11 million compared2015. The change was primarily due to $253 million for the corresponding periodincrease in 2014. The changes primarily reflect a reduction in tax benefits related to the estimated probable losses on construction of the Kemper IGCC and a decrease in non-taxable AFUDC equity relatedIGCC.
See Note (G) to placing the Kemper IGCC combined cycle in service in August 2014.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. Demand for electricity for Mississippi Power is partiallyprimarily 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. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Mississippi Power in Item 7 of the Form 10-K.
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis or through market-based contracts. 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, and has been reclassified to other regulatory assets, deferred, 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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters –
MISSISSIPPI POWER COMPANY
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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.
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 August 24, 2015, the U.S. District Court for the Northern District of Alabama entered an order approving the joint stipulation among Alabama Power, the EPA, and the U.S. Department of Justice modifying the 2006 consent decree to resolve all remaining claims for relief alleged in the case. Under the modified consent decree, Alabama Power will, without admitting liability, operate certain units subject to emission rates and an annual emissions cap; use only natural gas at certain other 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.
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, regional haze regulations, and the Cross State Air Pollution Rule (CSAPR), and the eight-hour National Ambient Air Quality Standard (NAAQS) for ozone..
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 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.
On October 26, 2015, the EPA published a more stringent eight-hour NAAQS for ozone. This new standard could potentially require additional emission controls, improvements in control efficiency, and operational fuel changes and could affect the siting of new generating facilities. The ultimate impact of this matter will depend on any legal challenges and implementation of the final rule and cannot be determined at this time.
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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' rule revising the definition of waters of the U.S. under the Clean Water Act (CWA) and the EPA's revisions to effluent guidelines.
On June 29, 2015,October 26, 2016, the EPA and the U.S. Army Corps of Engineers jointly published a final rule that updates the CSAPR ozone season nitrogen oxide program, including 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 CWAozone-season emissions budgets in Alabama and could have significant impacts on economic development projects which could affect customer demand growth. In addition, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines. The rule became effective August 28, 2015, but on October 9, 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order staying implementation of the final rule.Mississippi. The ultimate impact of the finalthis rule will depend on the outcome of this and other pendingany legal challenges and implementation at the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the rulestate level and cannot be determined at this time.
On November 3, 2015, the EPA published final revisions to technology-based limits for certain wastestreams from steam electric power plants. These revisions impose stringent steam effluent guidelines and technology requirements for wastewater discharges at affected units. Compliance with these revisions could result in significant additional capital expenditures and could affect future unit retirement and replacement decisions. The ultimate impact of these revisions will depend on any legal challenges and implementation of the final revisions 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 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, which became effective on October 19, 2015. Based on initial cost estimates for closure in place and groundwater monitoring of ash ponds pursuant to the CCR Rule, during the second quarter 2015, Mississippi Power recorded incremental asset retirement obligations (ARO) of approximately $95 million related to the CCR Rule. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, Mississippi Power expects to continue to periodically update these estimates. 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. See Note (A) to the Condensed Financial Statements herein for additional information regarding Mississippi Power's AROs as of September 30, 2015.
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 October 23, 2015, two final actions by the EPA that would limit CO2 emissions from fossil fuel-fired electric generating units were published in the Federal Register. One of the final actions contains specific emission standards governing CO2 emissions from new, modified, and reconstructed units. The other final action 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
MISSISSIPPI POWER COMPANY
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2030 and thereafter. At the same time, a proposed federal plan and proposed model rule were published 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, including legal challenges filed by Mississippi Power; 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.
Under a 2014 settlement agreement, an adjustment to Mississippi Power's wholesale revenue requirement was allowed in the event the Kemper IGCC, or any substantial portion thereof, was placed in service before or after December 1, 2014. Therefore,On March 31, 2016, Mississippi Power has recorded a regulatory asset as a result of a portion of the Kemper IGCC being placed in service prior to the projected date and is amortizing this regulatory asset over the nine months ending December 31, 2015.
On May 13, 2015, the FERC acceptedreached a settlement agreement between Mississippi Power andwith its wholesale customers to forgoand filed a request with the FERC for an increase in wholesale base revenues under the Municipal and Rural Associations (MRA) cost-based electric tariff, primarily as a result of placing scrubbers for Plant Daniel Units 1 and 2 in service in November 2015. The settlement agreement, accepted by the FERC, 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. 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 expense, and (iv) removing all of the Kemper IGCC CWIP from rate base with a corresponding increase by, among other things, increasing thein accrual of AFUDC and lowering the portion of CWIP in rate base, effective April 1, 2015.AFUDC. The additional resulting AFUDC is estimated to be approximately $13$11 million annually, of which $10 million relates tothrough the Kemper IGCC.IGCC's projected in-service date of December 31, 2016.
Fuel Cost Recovery
Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor and afactor. Effective with the first billing cycle for September 2016, fuel rates decreased $11 million annually for wholesale MRA emissions cost recovery factor. At September 30, 2015, the amount of over-recoveredcustomers and $1 million annually for wholesale MRA fuel costs included in the balance sheets was $14 million compared to $0.2 million at December 31, 2014. MB customers.
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory"FERC Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.
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
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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.
Retail Regulatory Matters
Mississippi Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Mississippi PSC. Mississippi Power's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased power, energy efficiency programs, ad valorem taxes, property damage, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are recovered through Mississippi Power's base rates. See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail"Retail Regulatory Matters"Matters – Mississippi Power" and "Integrated"Integrated Coal Gasification Combined Cycle"Cycle" herein for additional information.
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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,change in rates. The filing has been suspended for review by the Mississippi PSC suspended the filing to allow it more time for review. PSC.
The ultimate outcome of this matterthese matters cannot be determined at this time.
Environmental Compliance Overview Plan
On August 17, 2016, the Mississippi PSC approved Mississippi Power's revised ECO Plan filing for 2016, which requested the maximum 2% annual increase in revenues, approximately $18 million, primarily related to Plant Daniel Units 1 and 2 scrubbers being placed in service in November 2015. The revised rates became effective with the first billing cycle for September 2016. Approximately $22 million of related revenue requirements in excess of the 2% maximum was deferred for inclusion in the 2017 filing.
Fuel Cost Recovery
At September 30, 2015,2016, the amount of over recoveredover-recovered retail fuel costs included on itsthe balance sheet was $44$58 million compared to under recovered retail fuel costs of $2$71 million at December 31, 2014.2015.
Ad Valorem Tax Adjustment
The Mississippi PSC conditionally approved a decrease of $120 million annually in fuel cost recovery rates on January 5, 2016, effective with the first billing cycle for February 2016. On September 1, 2015,August 17, 2016, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment factor filing effective September 18, 2015, which requested an annual rateadditional decrease of 0.35%, or $2$51 million annually in annual retail revenues, primarily due to a decrease in average millage rates.fuel cost recovery rates effective with the first billing cycle for September 2016.
Integrated Coal Gasification Combined Cycle
See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding Mississippi Power's construction of the Kemper IGCC.
Kemper IGCC Overview
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)
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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.
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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 initial production of syngas began on July 14, 2016 for whichgasifier "B" and on September 13, 2016 for gasifier "A." On October 11, 2016, the Kemper IGCC began testing using clean syngas from gasifier "A" and the related gas clean-up systems to produce electricity. Late on October 31, 2016, gasifier "A" experienced challenges associated with the ash removal systems, and on November 2, 2016, Mississippi Power determined a maintenance outage on gasifier "A" is needed to make improvements to the ash removal systems. Therefore, Mississippi Power has re-sequenced activities, and gasifier "B" is now expected to progress through testing and begin producing electricity during the gasifier "A" outage. In light of these changes, Mississippi Power has determined that integrated operation of both gasifiers will not occur by mid-November and has revised the expected in-service date is currentlyfor the remainder of the Kemper IGCC to December 31, 2016. The remaining schedule reflects the time expected to occur inachieve production of electricity using gasifier "B," complete gasifier "A" outage activities, and resume electricity production using gasifier "A," as well as to complete the first halfintegration of 2016. all systems necessary for both combustion turbines to simultaneously generate electricity with syngas.
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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's decision)decision discussed herein under "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order"), and actual costs incurred as of September 30, 2015, as adjusted for the Court's decision,2016 are as follows:
| | | Cost Category | 2010 Project Estimate(f) | | Current Estimate(a) | | Actual Costs | 2010 Project Estimate(a) | | Current Cost Estimate(b) | | Actual Costs |
| | (in billions) | (in billions) |
Plant Subject to Cost Cap(g)(e) | $ | 2.40 |
| | $ | 5.11 |
| | $ | 4.66 |
| $ | 2.40 |
| | $ | 5.52 |
| | $ | 5.30 |
|
| 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 |
| | 0.11 |
|
AFUDC(c)(d) | 0.17 | | 0.66 | | 0.55 | 0.17 |
| | 0.75 |
| | 0.71 |
|
Combined Cycle and Related Assets Placed in Service – Incremental(d)(g) | — |
| | 0.02 |
| | — |
| |
Combined Cycle and Related Assets Placed in
Service – Incremental(e) | | — |
| | 0.04 |
| | 0.03 |
|
| General Exceptions | 0.05 | | 0.10 | | 0.08 | 0.05 |
| | 0.10 |
| | 0.09 |
|
Deferred Costs(g)(e) | — |
| | 0.20 | | 0.17 | — |
| | 0.21 |
| | 0.20 |
|
| Additional DOE Grants | | — |
| | (0.14 | ) | | (0.14 | ) |
| Total Kemper IGCC | $ | 2.97 |
| | $ | 6.43 |
| | $ | 5.80 |
| $ | 2.97 |
| | $ | 6.82 |
| | $ | 6.53 |
|
| |
| (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.
| Amounts in the Current Estimate reflect estimated costs through June 30, 2016. |
| |
| (b) | Amounts in the Current Cost Estimate include certain estimated post-in-service costs which are expected to be subject to the cost cap. |
| |
| (c) | The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. The Current Cost Estimate and the Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap and exclude post-in-service costs for the lignite mine. See "Rate"Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order"Order" herein for additional information. The Current Cost Estimate and the Actual Costs reflect 100% of the costs of the Kemper IGCC. See note (g)(e) for additional information. |
| |
(c)(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 estimateCurrent 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. |
| |
(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 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 estimate for the CO2 pipeline facilities which was approved in 2011 by the Mississippi PSC.
|
| |
(g) | Beginning in the third quarter 2015, certain costs, including debt carrying costs (associated with placed in service and other non-construction work in progress accounts), that previously were initially deferred as regulatory assetsassets. 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 estimateCurrent Cost Estimate and actual coststhe Actual Costs at September 30, 2015.2016. The wholesale portion of debt carrying costs, whether deferred or recognized through income, is not included in the Current Cost Estimate and the Actual Costs at September 30, 2016. See "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities" herein for additional information. |
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Of the total costs, including post-in-service costs for the lignite mine, incurred as of September 30, 2015, $3.452016, $3.70 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 $2.23$2.63 billion), $2$6 million in other property and investments, $62$81 million in fossil fuel stock, $43$46 million in materials and supplies, $50$33 million in other regulatory assets, current, $158$177 million in other regulatory assets, deferred, $4 million in other current assets, and $15$9 million in other deferred charges and assets in the balance sheet.
Mississippi Power does not intend to seek rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate above the cost cap of $150$88 million ($9354 million after tax) in the third quarter 2015,2016 and a total of $182$222 million ($112137 million after tax) for the nine months ended September 30, 2015. These amounts are2016. Since 2012, in addition tothe aggregate, Mississippi Power has incurred charges totaling $868 million ($536 million after tax), $1.10of $2.63 billion ($681 million after tax), and $78 million ($48 million1.63 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 September 30, 2016. The increasesincrease to the cost estimate in 2015the third quarter of 2016 primarily reflect costsreflects $53 million for the extension of the Kemper IGCC's projected in-service date from October 31, 2016 to December 31, 2016 and
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increased efforts related to equipment rework, scope modifications,operational readiness and the related additional labor costschallenges in support of start-up and operational readinesscommissioning activities, including the cost of repairs and modifications to gasifier "B" and mechanical improvements to coal feed and ash management systems, as well as additional schedulecertain post-in-service costs through June 30,expected to be subject to the cost cap. The year-to-date increase to the cost estimate also includes $78 million for the extension of the Kemper IGCC's projected in-service date from August 31, 2016 to October 31, 2016. In addition, during the start-up and commissioning process, Mississippi Power is identifying potential improvement projects that ultimately may be completed subsequent to placing the remainder of the Kemper IGCC in service. If completed, such improvement projects would be expected to enhance plant performance, safety, and/or operations. The related potential costs have yet to be fully evaluated, have not been included in the current cost estimate, includes costs through June 30, 2016. and may be subject to the $2.88 billion cost cap.
Any extension of the in-service date beyond June 30,December 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 extension of the in-service date with respect to the Kemper IGCC beyond June 30,December 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 $12$15 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees. Beginning in the third quarter 2015, in connection with the implementationfees of interim rate recovery, certain of these ongoing project costs are being expensed, with the remainder being deferred as regulatory assets and are estimated to total approximately $6$3 million per month. For additional information, see "2015"2015 Rate Case"Case" herein.
Mississippi Power’sPower's analysis of the time needed to complete the start-up and commissioning activities for the Kemper IGCC will continue until the remaining Kemper IGCC assets are placed in service. The next steps for the facility include the testing and production of electricity using clean syngas from gasifier "B," as well as the generation of electricity using clean syngas from gasifier "A," which are scheduled to occur by the end of November. If integrated operation of both gasifiers does not occur by mid-December, the expected in-service date and related cost estimate for the Kemper IGCC likely would require further revision. Further cost increases and/or extensions of the expected in-service date 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, sustaining nitrogen supply, 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
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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. See "Prudence" herein for additional information.
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 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 throughIGCC. Through September 30, 2016, AFUDC recorded since the original May 2014 estimated in-service date. Mississippi Power will not record AFUDC on any additional costs ofdate for the Kemper IGCC that exceedhas totaled $352 million. Mississippi Power has not recorded any AFUDC on Kemper IGCC costs in excess of the $2.88 billion cost cap, except for Cost Cap Exception amounts. 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. In addition, Mississippi Power 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.
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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. 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. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015. Through July 2015 billings, Mississippi Power had collectedand required the fourth quarter 2015 refund of the $342 million through ratescollected under the 2013 MPSC Rate Order, and had accrued $27 million inalong with associated carrying costs through September 30, 2015. Refunds will begin in early November 2015.of $29 million. The Court's decision did not impact the 2012 MPSC CPCN Order or the 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 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). In light of the Mississippi PSC's July 7, 2015 order, RMP 2019 is no longer viable as originally proposed by Mississippi Power.
Furthermore, 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 NoticePower'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 requested thatannually and became effective with the first billing cycle for September 2015, subject to refund and certain other conditions.
On December 3, 2015, the Mississippi PSC issued the In-Service Asset 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 MPUS regarding the In-Service Asset Proposal and requested that the Mississippi PSC establish a scheduling order for consideration of permanent rates under theProposal. The In-Service Asset Proposal.
Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The 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.
On August 13, 2015, the Mississippi PSC approved the implementation of interim rates that became effectiveevaluate its alternatives with respect to its investment and related costs associated with the first billing cycle in September (on August 19), subject to refund and certain other conditions. In addition, the Mississippi PSC reserved the right to modify or terminate the interim rates based upon a material change in circumstances. Through September 30, 2015, Mississippi Power had recognized $28 million under the interim rates. The Mississippi PSC is scheduled to issue a final order on or before December 8, 2015 related to permanent rates for the In-Service Asset Proposal.15% undivided interest.
Mississippi Power expects to seek additional rate relief to address recovery of the remaining Kemper IGCC assets. In addition to current estimated costs at September 30, 2015 of $6.43 billion, Mississippi Power anticipates that it will incur additional costs after the Kemper IGCC in-service date until the Kemper IGCC cost recovery approach is finalized. These costs include, but are not limited to, regulatory costs and additional carrying costs which could be material. Recovery of these costs would be subject to approval by the Mississippi PSC.
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Prudence Reviews
TheWith implementation of the new rates on December 17, 2015, the interim rates were terminated and, in March 2016, Mississippi PSC's reviewPower completed customer refunds of approximately $11 million for the difference between the interim rates collected and the permanent rates.
On July 27, 2016, the Court dismissed Greenleaf's motion for reconsideration of its previous decision to dismiss Greenleaf's appeal of the In-Service Asset Rate Order.
In addition to current estimated costs at September 30, 2016 of $6.82 billion, Mississippi Power anticipates that it will incur additional expenses in excess of current rates associated with operating the Kemper IGCC costsafter it 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 until the Kemper IGCC cost recovery approach is finalized, which are expected to be material. These costs include, but are not limited to, regulatory costs, operational costs in excess of current rates, taxes, and has demonstrated availability for a reasonable period of time as determined byadditional carrying costs. Mississippi Power expects to request authority from the Mississippi PSC and the Mississippi Public Utilities Staff (MPUS). TheFERC to defer all Kemper IGCC costs incurred after the in-service date that cannot be capitalized, are not included in current rates, and are not required to be charged against earnings as a result of the $2.88 billion cost cap until such time as the Mississippi PSC has encouragedcompletes its review and includes the parties to workresulting allowable costs in good faith to settle contested issues andrates. Mississippi Power is workingrequired to reach a mutually acceptable resolution.file its next rate request with the Mississippi PSC related to cost recovery for the Kemper IGCC by June 3, 2017. See "2015 Mississippi Supreme Court Decision""Regulatory Assets and "2015 Rate Case" hereinLiabilities" below for additional information. As part of that filing, Mississippi Power expects to request recovery of certain costs that the Mississippi PSC had excluded from the revenue requirement calculation for the in-service assets.
Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law in 2013. Mississippi Power expects to securitize prudently-incurred qualifying facility costs in excess of the certificated cost estimate of $2.4 billion. Qualifying facility costs include, but are not limited to, pre-construction costs, construction costs, regulatory costs, and accrued AFUDC. The Court's decision regarding the 2013 MPSC Rate Order did not impact Mississippi Power's ability to utilize alternate financing through securitization or the February 2013 legislation.
Prudence
On August 17, 2016, the Mississippi PSC issued an order establishing a discovery docket to manage all filings related to the prudence of the Kemper IGCC. On October 3, 2016, Mississippi Power made a required compliance filing, which included a review and explanation of differences between the Kemper IGCC project estimate set forth in the 2010 CPCN proceeding and the most recent Kemper IGCC project estimate, as well as comparisons of current cost estimates and current expected plant operational parameters to the estimates presented in the 2010 CPCN proceedings for the first five years following the start of commercial operations. Certain costs, including operations and maintenance, are materially higher than the amounts presented in the CPCN proceedings. Additionally, while the current estimated operational availability estimates reflect ultimate results similar to those presented in the 2010 CPCN proceedings, the ramp up period for the current estimates reflects a lower starting point and a slower escalation rate. Mississippi Power expects the Mississippi PSC to address these issues in connection with its next rate request.
Regulatory Assets and Liabilities
Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC issued an accounting order in 2011 granting Mississippi Power the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date, subject to review of such costs by the Mississippi PSC. Such costs include, but are not limited to, carrying costs on Kemper IGCC assets currently placed in service, costs associated with Mississippi PSC and MPUS consultants, prudence costs, legal fees, and operating expenses associated with assets placed in service.
In August 2014, Mississippi Power requested confirmation by the Mississippi PSC of Mississippi Power's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost
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recovery mechanism proceedings. Beginning in the third quarter 2015 and the second quarter 2016, in connection with the implementation of interimretail 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-construction work in progressnon-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 over a 24-month period.fees. The amortization periods for these regulatory assets vary from two years to 10 years as set forth in the In-Service Asset Rate Order and the settlement agreement with wholesale customers. As of September 30, 2015,2016, the balance associated with these regulatory assets was $117 million. The amortization period for these regulatory assets$105 million, of which $33 million is subject to the Mississippi PSC’s final orderincluded in the 2015 Rate Case.current assets. Other regulatory assets associated with the remainder of the Kemper IGCC totaled $91$105 million as of September 30, 2015.2016. The amortization period for these assets is expected to be determined by the Mississippi PSC in future rate proceedings following completion of construction and start-up of the Kemper IGCC and related prudence reviews.
Also see "2015 Mississippi Supreme Court Decision" See "FERC Matters" herein for information related to the July 7, 2016 settlement agreement with wholesale customers.
The In-Service Asset Rate Order requires Mississippi Power to submit an annual true-up calculation of its actual cost of capital, compared to the stipulated total cost of capital, with the first occurring as of May 31, 2016. At September 30, 2016, Mississippi Power's related regulatory liability included in its balance sheet totaled approximately $7 million. See "2015 Mississippi PSC order terminating the Mirror CWIP rate and requiring refund of collections under Mirror CWIP.Rate Case" herein for additional information.
See Note 1 to the financial statements of Mississippi Power under "Regulatory Assets and Liabilities" in Item 8 of the Form 10-K for additional information.
Lignite Mine and CO2 Pipeline Facilities
In conjunction with the Kemper IGCC, Mississippi Power will 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.
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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 has been engaged in ongoing discussions with its off-takers regarding the status of the CO2 delivery schedule as well as other issues related to the 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.Power. Any termination or material modification of these agreementsthe agreement with Denbury could impact the operations of the Kemper IGCC and result in a material reduction in future chemical product salesMississippi Power's revenues and could have a material financial impact on Mississippi Power to the extent Mississippi Power is not able to enter into other similar contractual arrangements.arrangements or otherwise sequester the CO2 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.
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.
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Investment Tax Credits
The IRS allocated $279 million (Phase II) of Internal Revenue Code Section 48A tax credits toLitigation
On April 26, 2016, a complaint against Mississippi Power was filed in connection withHarrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. On August 12, 2016, Southern Company and Mississippi Power removed the case to the U.S. District Court for the Southern District of Mississippi, where the case is currently pending. However, the plaintiffs have filed a request to remand the case back to state court. 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. These tax credits are dependent upon meetingIGCC and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the IRS certification requirements, includingCircuit 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 in-service date no later than April 19,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 capturestate court in Gwinnett County, Georgia. The complaint relates to the cancelled CO2 contract with Treetop and sequestration (via enhanced oil recovery)alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of at least 65%contract on the part of Mississippi Power, Southern Company, and SCS and seeks compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS have moved to compel arbitration pursuant to the terms of the CO2 produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. Through September 30, 2015, contract.
Mississippi Power had recorded tax benefits totaling $276 million forbelieves 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 Phase II credits,ultimate outcome of which approximately $235 million had been utilized. While the in-service date for the remainderthese matters cannot be determined at this time.
Income Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Mississippi Power in Item 7 of the Kemper IGCC is currently expected to occur in the first half of 2016, Mississippi Power now anticipates the in-service date to occur subsequent to April 19, 2016, but has not made a final determination to that effect. Due to this uncertainty, Mississippi Power has reflected these tax credits as unrecognized tax benefitsForm 10-K and reclassified the Phase II credits to a current liability on its September 30, 2015 balance sheet, with no impact to net income. Repayment to the IRS would occur with the quarterly estimated tax payment following a final determination that the in-service date would occur subsequent to April 19, 2016. Any cash funding requirements necessary for Mississippi Power to make this repayment are expected to be provided by Southern Company. See Notes (B) andNote (G) to the Condensed Financial Statements under "Integrated"Section 174 Research and Experimental Deduction" herein for additional information.
Bonus Depreciation
The extension of 50% bonus depreciation included in the PATH Act is expected to result in approximately $400 million of positive cash flows for the 2016 tax year, which may not all be realized in 2016 due to a projected consolidated net operating loss for Southern Company. Approximately $370 million of the benefit is dependent upon placing the remainder of the Kemper IGCC in service by December 31, 2016, of which $250 million has been received as of September 30, 2016 through quarterly income tax refunds. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle"Cycle" and "Unrecognized Tax BenefitsNote (G) to the Condensed Financial Statements under "Current and Deferred Income Taxes – Investment Tax Credits,Net Operating Loss" respectively, herein for additional information. The ultimate outcome of this tax 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, 2014, and 2015. In May 2015, Southern Company amended its 2008 through 2013 federal income tax returns to include deductions for Kemper IGCC-related R&E expenditures. Due to the uncertainty related to this tax position, Mississippi Power had unrecognized tax benefits associated with these R&E deductions totaling approximately $414 million as of September 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
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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
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 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 $88 million ($54 million after tax) in the third quarter 2016, $81 million ($50 million after tax) in the second quarter 2016, $53 million ($33 million after tax) in the first quarter 2016, $183 million ($113 million after tax) in the fourth quarter 2015, $150 million ($93 million after tax) in the third quarter 2015, $23 million ($14 million after tax) in the second quarter 2015, $9 million ($6 million after tax) in the first quarter 2015, $70 million ($43 million after tax) in the fourth quarter 2014, $418 million ($258 million after tax) in the third quarter 2014, $380 million ($235 million after tax) in the first quarter 2014, $40 million ($25 million after tax) in the fourth quarter 2013, $150 million ($93 million after tax) in the third quarter 2013, $450 million ($278 million after tax) in the second quarter 2013, $462 million ($285 million after tax) in the first quarter 2013, and $78 million ($48 million after tax) in the fourth quarter 2012. In the aggregate, Mississippi Power has
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
incurred charges of $2.23$2.63 billion ($1.41.63 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through September 30, 2015.2016.
Mississippi Power's revised cost estimate reflects an expected in-service date of December 31, 2016 and includes certain post-in-service costs which are expected to be subject to the cost cap. Mississippi Power has experienced, and may continue to experience, material changes in the cost estimate for the Kemper IGCC. Further cost increases and/or extensions of the expected in-service date may result from factors including, but not limited to, difficulties integrating the systems required for sustained operations, sustaining nitrogen supply, major equipment failure, unforeseen engineering or design problems including any repairs and/or modifications to systems, and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). In addition, during the start-up and commissioning process, Mississippi Power is also identifying potential improvement projects that ultimately may be completed subsequent to placing the remainder of the Kemper IGCC in service. If completed, such improvement projects would be expected to enhance plant performance, safety, and/or operations. The related potential costs have yet to be fully evaluated, have not been included in the current cost estimates, and may be subject to the $2.88 billion cost cap. 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 further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including, but not limited to, additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC).
Mississippi Power's revised cost estimate includes costs through June 30, 2016. Any extension of the in-service date beyond JuneDecember 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 extension of the in-service date with respect to the Kemper IGCC beyond June 30,December 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 $12$15 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting fees and legal fees a
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
portion of which are being deferred as regulatory assets and are estimated to total approximately $6$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 Mississippi Power's results of operations, Mississippi Power considers these items to be critical accounting estimates. See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated"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, and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.
As a result of the final CCR Rule discussed above, Mississippi Power recorded new AROs for facilities that are subject to the CCR Rule. The cost estimates are based on information using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure in place. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, Mississippi Power expects to continue 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. Early2018, with early adoption is permitted andpermitted. Mississippi Power intendsis currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to adopthave a significant impact on Mississippi Power's balance sheet.
On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation(Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions. Most significantly, entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the fourth quarter 2015. Theincome statement. Mississippi Power currently recognizes any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15,
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
required2016. Early adoption is permitted and Mississippi Power intends to be applied retrospectively to all periods presented beginningadopt the ASU in the year of adoption. Mississippi Power currently reflects unamortized debt issuance costs in other deferred charges and assets on its balance sheet. Uponfourth 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 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 and its ability to obtain financing needed for normal business operations and completion of construction and start-up of the Kemper IGCC were adversely affected by the return of approximately $301 million of interest bearing refundable deposits to SMEPA in June 2015 in connection with the termination of the APA, the required refund of Mirror CWIP rate collections beginning in early November 2015 of approximately $369 million, including associated carrying costs, the termination of the Mirror CWIP rate and the likely repayment of the Phase II tax credits of $235 million as of September 30, 2015. Earnings for the nine months ended September 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. 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," "– 2015 Rate Case," and – "Income Tax Matters – Investment Tax Credits" herein for additional information.IGCC.
Through September 30, 2015,2016, Mississippi Power has incurred non-recoverable cash expenditures of $1.8$2.42 billion and is expected to incur approximately $0.4$0.21 billion in additional non-recoverable cash expenditures through completion of the construction and start-up of the Kemper IGCC.
In addition to funding normal business operations and projected capital expenditures, Mississippi Power's cash requirements primarily consist of $900 million of bank term loans scheduled to mature on April 1, 2016, $25 million of short-term debt, and the required refund of approximately $369 million in Mirror CWIP,IGCC, which includes associated carrying costs. Forcertain post-in-service costs expected to be subject to the three-year period from 2015 through 2017, cost cap.
Mississippi Power's capital expenditures and debt maturities are expected to materially exceed operating cash flows.flows through 2021. 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, to add or change fuel sources for certain existing units, and to expand and improve transmission and distribution facilities.
On January 28, 2016, Mississippi Power is primarily dependent uponissued a promissory note for up to $275 million to Southern Company, which matures in December 2017, bearing interest based on one-month LIBOR. During the first nine months of 2016, Mississippi Power borrowed $100 million under this promissory note and an additional $100 million under a separate promissory note issued to meet its financing needs. Southern Company in November 2015. On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicate of financial institutions for an aggregate amount of $1.2 billion. Mississippi Power borrowed $900 million on March 8, 2016 under the term loan agreement and the remaining $300 million on October 7, 2016. Mississippi Power used the initial proceeds to repay $900 million in maturing bank loans on March 8, 2016 and the remaining $300 million to repay at maturity Mississippi Power's Series 2011A 2.35% Senior Notes due October 15, 2016. On June 27, 2016, Mississippi Power received a capital contribution from Southern Company for $225 million, the proceeds of which were used to repay to Southern Company a portion of the existing promissory note issued in November 2015. As of September 30, 2016, the amount of outstanding promissory notes to Southern Company totaled $551 million.
As of September 30, 2016, Mississippi Power's current liabilities exceeded current assets by approximately $411 million primarily due to the $300 million in senior notes which matured on October 15, 2016, as well as $65 million in short-term debt.
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'sthe remainder of its short-term capital needs. See "Capital"Capital Requirements and Contractual Obligations," "Sources"Sources of Capital," and "Financing"Financing Activities" herein for additional information.
During the first nine months of 2015, Mississippi Power received $150 million in equity contributions from Southern Company and issued an 18-month promissory note for $301 million to Southern Company. 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, 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 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.
Net cash provided from operating activities totaled $349$372 million for the first nine months of 2015, a decrease2016, an increase of $156$23 million as compared to the corresponding period in 2014.2015. The decreaseincrease in cash provided from operating activities is primarily due to income taxes receivable associated with research and experimental (R&E) deductions and accrued taxes, partially offset by lower R&E tax deductions, the cessation of Mirror CWIP collections and lower incremental benefitsubsequent refund payments, and higher recovery of ITCs fromregulatory fuel clause revenues. See Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" and "Unrecognized Tax Benefits – Section 174 Research and Experimental Deduction" herein for additional information. Net cash used for investing activities totaled $509 million for the first nine months of 2016 primarily due to gross property additions related to the Kemper IGCC, and timing of payments of accounts payable, partially offset by an increasereceipt of $137 million in fuel recovery, and a decreaseAdditional DOE Grants. Net cash provided from financing activities totaled $198 million for the first nine months
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
in receivables. See Notes (B) and Note (G) to the Condensed Financial Statements herein for additional information. Net cash used for investing activities totaled $686 million for the first nine months of 20152016 primarily due to gross property additions related to the Kemper IGCClong-term debt issuances and the Plant Daniel scrubber project. Net cash provided from financing activities totaled $300 million for the first nine months of 2015 primarily due to short-term bank loans, capital contributions from Southern Company, and short-term borrowings, partially offset by redemptions of long-term debt and short terma decrease in short-term borrowings. Fluctuations in cash flowCash 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 nine months of 20152016 include an increase in long-term debt of $826 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 primarily due to refinancing or replacing maturing long-term debt with short-term loans.decrease in notes payable. Additionally, long-term debtCWIP increased $292 million and interest-bearing refundable deposits decreased $275 million, due to an intercompany loan for the repayment of the SMEPA deposits and interest. See "Sources of Capital" herein for additional information. Total property, plant, and equipment increased $490 million and the Mirror CWIP regulatory liability increased $98 million primarily associated with construction and collections related to the Kemper IGCC. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information. Income taxes receivable, non-current increased $544 million, unrecognized tax benefits increased $359 million, and accumulated deferred income taxes increased $389 million primarily due to R&E tax deductions and the related reserve. Accumulated deferred ITCs decreased $278$271 million primarily due to the likely repayment of unrecognized tax benefitsKemper IGCC and the customer liability associated with Kemper IGCC refunds decreased $72 million. Other significant changes include a $110 million increase in accrued income taxes due to bonus depreciation, a $61 million increase in accumulated deferred income taxes (ADIT) due to transmission and distribution property-related ADITs and additional Section 174 R&E deduction, partially offset by ADITs associated with the Phase II tax credits related toestimated losses on the Kemper IGCC. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Investment Tax Credits" herein for additional information.IGCC construction, and a $39 million increase in prepaid income taxes. Total common stockholder's equity increased $219$269 million primarily due to the receipt of $150 million in capital contributions from Southern Company and net income duringfor the nine months ended September 30, 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 September 30, 20162017 to fund maturities of bank term loans scheduled to mature on April 1, 2016long-term debt, and $25 million in short-term debt. In addition, Mississippi Power will be required to refund its Mirror CWIP rate collectionsfund maturities of approximately $369 million, including associated carrying costs, beginning in November 2015.short-term debt. See "Sources"Sources of Capital"Capital" herein for additional information. Subsequent to September 30, 2016, Mississippi Power repaid at maturity $300 million aggregate principal amount of its Series 2011A 2.35% Senior Notes due October 15, 2016. If the Kemper IGCC does not go into service by December 31, 2016, Mississippi Power also would have to repay approximately $250 million of tax benefits received as a result of quarterly income tax estimates through September 30, 2016. See "Income Tax Matters" herein for additional information.
The construction program of Mississippi Power is currently estimated to be $1.0$0.8 billion in 2015, $477 million infor 2016, and $221 millionnet of the Additional DOE Grants, $0.3 billion for 2017, $0.2 billion for 2018, $0.2 billion for 2019, $0.3 billion for 2020, and $0.3 billion for 2021, which includes revised estimates for the Kemper IGCC, including post-in-service costs. The expenditures related to the construction and start-up of the Kemper IGCC are currently estimated to be $0.7 billion for 2016, net of $834 million in 2015the Additional DOE Grants, and $281 million in 2016.$0.1 billion for 2017. These estimated expenditures do not include potential compliance costs that may arise from the EPA's final rules and guidelines or subsequently approved state plans that would limit CO2 emissions from existing, new, modified, or reconstructed fossil-fuel-fired electric generating units.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing 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 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.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Sources of Capital
Except as described herein, 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. Mississippi Power's financial condition and its ability to obtain funds needed for normal business operations and completion of the construction and start-up of the Kemper IGCC were adversely affected by the return of approximately $301 million of interest bearing refundable deposits to SMEPA in June 2015 in connection with the termination of the APA, the required refund of Mirror CWIP rate collections beginning in early November 2015 of approximately $369 million, including associated carrying costs, the termination of the Mirror CWIP rate, and the likely repayment of unrecognized tax benefits associated with the Phase II tax credits of $235 million. On August 13,In December 2015, the Mississippi PSC approved the implementation of interim rates that became effective with the first billing cycle in September (on August 19), subject to refund and certain other conditions, and is scheduled to issue a final order on or before December 8, 2015 related to permanent rates for the In-Service Asset Proposal.Rate Order, which among other things, provided for retail rate recovery of an annual revenue requirement of approximately $126 million effective December 17, 2015. The amount, type, and timing of future financings will depend upon regulatory approval, prevailing market conditions, and other factors, which includes resolution of Kemper IGCC cost recovery. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" and – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order," " – 2015 Mississippi Supreme Court Decision,"Order" and " – 2015 Rate Case" of Mississippi Power in Item 7 of the Form 10-K and hereinfor 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 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 nine months of these loans were used for2016, Mississippi Power borrowed $100 million pursuant to the repayment of term loans in an aggregate principal amount of $275 million working capital,promissory note and other general corporate purposes. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425additional $100 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016. In addition, Mississippi Power issued an 18-monthunder a separate promissory note issued to Southern Company in theNovember 2015. 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. Mississippi Power borrowed $900 million relatedon March 8, 2016 under the term loan agreement and the remaining $300 million on October 7, 2016. Mississippi Power used the initial proceeds to repay $900 million in maturing bank loans on March 8, 2016 and the refundremaining $300 million to SMEPArepay at maturity Mississippi Power's Series 2011A 2.35% Senior Notes due October 15, 2016. The term loan pursuant to this agreement matures on April 1, 2018 and expectsbears 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 issue a similar promissory noterepay to Southern Company to funda portion of the Mirror CWIP refund. Any cash funding requirements necessary for Mississippi Power to repay the Phase II tax credits to the IRS are also expected to be provided by Southern Company.existing promissory note issued in November 2015. As of September 30, 2015, Mississippi Power's current liabilities exceeded current assets by approximately $1.3 billion primarily due2016, the amount of outstanding promissory notes to $900 million of bank term loans scheduled to mature on April 1, 2016, $25 million of short-term debt, the required refund of approximately $369 million in Mirror CWIP and associated carrying costs, and the likely repayment of unrecognized tax benefits associated with the Phase II tax credits of $235Southern Company totaled $551 million.
Mississippi Power intends to utilize operating cash flows and lines of credit (to the extent available) as well as loans and, under certain circumstances, equity contributions from Southern Company to fund Mississippi Power's short-term capital needs.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
At September 30, 2015,2016, Mississippi Power had approximately $96$159 million of cash and cash equivalents. Committed credit arrangements with banks at September 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) |
| $ | 15 |
| | $ | 220 |
| | $ | 235 |
| | $ | 210 |
| | $ | 30 |
| | $ | 30 |
| | $ | 60 |
| | $ | 175 |
| 100 |
| | $ | 75 |
| | $ | 175 |
| | $ | 150 |
| | $ | — |
| | $ | 15 |
| | $ | 15 |
| | $ | 160 |
|
| |
(*) | Subsequent to September 30, 2015, this $15 million bank credit arrangement expired pursuant to its terms. |
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.
A portion of the $210 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 September 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(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.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.
A portion of the $150 million unused credit arrangements with banks is allocated to provide liquidity support to Mississippi 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 September 30, 2016 was approximately $40 million.
Details of short-term borrowings were as follows:
|
| | | | | | | | | | | | | | | | |
| | | Short-term Debt at September 30, 2015 | | 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 | | $ | 500 |
| | 1.4% | | $ | 513 |
| | 1.3% | | $ | 515 |
|
|
| | | | | | | | | | | | | | | | |
| | | Short-term Debt at September 30, 2016 | | Short-term Debt During the Period(*) |
| | | Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) | | | | (in millions) |
| Short-term bank debt | | $ | 25 |
| | 2.2% | | $ | 25 |
| | 2.1% | | $ | 25 |
|
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 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 and/or Baa2 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, energy price risk management, and transmission. At September 30, 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 $286$259 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.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Additionally, a credit rating downgrade has impacted and may continue tocould impact the ability of Mississippi Power to access capital markets, and would be likely to impact the 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 for Mississippi Power.
On August 14, 2015, Moody's downgraded the senior unsecured debt rating of Mississippi Power to Baa2 from Baa1. Moody's maintained the negative ratings outlook for Mississippi Power.
On August 17, 2015, S&P downgraded the issuer rating of Mississippi Power to BBB+ from A. S&P revised its credit rating outlook from negative to stable. Separately, on August 24, 2015, S&P revised its consolidated credit rating outlook of Southern Company (including Mississippi Power) from stable to negative following the announcement of the Merger.
Financing Activities
In March 2015,On January 28, 2016, Mississippi Power repaid at maturityissued a $75promissory note for up to $275 million bank term loan.
In April 2015, Mississippi Power entered into two short-term floating rate bank loans with a maturity date of April 1, 2016,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 nine months 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.2016, Mississippi Power also amended three outstanding floating rate bank loansborrowed $100 million under this promissory note and an additional $100 million under a separate promissory note issued to Southern Company in November 2015. On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicate of financial institutions for an aggregate principal amount of $425
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
$1.2 billion. Mississippi Power borrowed $900 million which, among other things, extendedon March 8, 2016 under the term loan agreement and the remaining $300 million on October 7, 2016. Mississippi Power used the initial proceeds to repay $900 million in maturing bank loans on March 8, 2016 and the remaining $300 million to repay at maturity dates from various dates in 2015Mississippi Power's Series 2011A 2.35% Senior Notes due October 15, 2016. The term loan pursuant to this agreement matures on April 1, 2016.
In June 2015, Mississippi Power issued an 18-month floating rate promissory note to Southern Company bearing2018 and bears interest based on one-month LIBOR. ThisOn June 27, 2016, Mississippi Power received a capital contribution from Southern Company of $225 million, the proceeds of which were used to repay to Southern Company a portion of the promissory note was for an aggregate principalissued in November 2015. As of September 30, 2016, the amount of approximately $301 million, the amount paid byoutstanding promissory notes to Southern Company totaled $551 million.
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.
In September 2016, Mississippi Power entered into interest rate swaps to SMEPA pursuant to Southern Company's guaranteefix the variable interest rate on $900 million of the return of SMEPA's depositsterm loan entered into 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.March 2016.
SOUTHERN POWER COMPANY
AND SUBSIDIARY COMPANIES
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
| | | | For the Three Months
Ended September 30, | | For the Nine Months
Ended September 30, | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | | | | | | | | |
| Wholesale revenues, non-affiliates | $ | 295 |
| | $ | 332 |
| | $ | 776 |
| | $ | 870 |
| $ | 387 |
| | $ | 295 |
| | $ | 866 |
| | $ | 776 |
|
| Wholesale revenues, affiliates | 104 |
| | 103 |
| | 303 |
| | 243 |
| 110 |
| | 104 |
| | 313 |
| | 303 |
|
| Other revenues | 2 |
| | — |
| | 7 |
| | 2 |
| 3 |
| | 2 |
| | 10 |
| | 7 |
|
| Total operating revenues | 401 |
| | 435 |
| | 1,086 |
| | 1,115 |
| 500 |
| | 401 |
| | 1,189 |
| | 1,086 |
|
| Operating Expenses: | | | | | | | | | | | | | | |
| Fuel | 118 |
| | 178 |
| | 361 |
| | 421 |
| 154 |
| | 118 |
| | 341 |
| | 361 |
|
| Purchased power, non-affiliates | 17 |
| | 28 |
| | 52 |
| | 73 |
| 25 |
| | 17 |
| | 60 |
| | 52 |
|
| Purchased power, affiliates | 5 |
| | 13 |
| | 18 |
| | 58 |
| 8 |
| | 5 |
| | 16 |
| | 18 |
|
| Other operations and maintenance | 62 |
| | 46 |
| | 184 |
| | 168 |
| 81 |
| | 62 |
| | 246 |
| | 184 |
|
| Depreciation and amortization | 64 |
| | 60 |
| | 183 |
| | 163 |
| 93 |
| | 64 |
| | 247 |
| | 183 |
|
| Taxes other than income taxes | 6 |
| | 5 |
| | 17 |
| | 17 |
| 5 |
| | 6 |
| | 17 |
| | 17 |
|
| Total operating expenses | 272 |
|
| 330 |
| | 815 |
| | 900 |
| 366 |
|
| 272 |
| | 927 |
| | 815 |
|
| Operating Income | 129 |
| | 105 |
| | 271 |
| | 215 |
| 134 |
| | 129 |
| | 262 |
| | 271 |
|
| Other Income and (Expense): | | | | | | | | | | | | | | |
| Interest expense, net of amounts capitalized | (18 | ) | | (23 | ) | | (62 | ) | | (67 | ) | (35 | ) | | (18 | ) | | (78 | ) | | (62 | ) |
| Other income (expense), net | 1 |
| | 5 |
| | 1 |
| | 6 |
| 2 |
| | 1 |
| | 3 |
| | 1 |
|
| Total other income and (expense) | (17 | ) | | (18 | ) | | (61 | ) | | (61 | ) | (33 | ) | | (17 | ) | | (75 | ) | | (61 | ) |
| Earnings Before Income Taxes | 112 |
| | 87 |
| | 210 |
| | 154 |
| 101 |
| | 112 |
| | 187 |
| | 210 |
|
| Income taxes | 1 |
| | 22 |
| | 14 |
| | 22 |
| |
| Income taxes (benefit) | | (102 | ) | | 1 |
| | (167 | ) | | 14 |
|
| Net Income | 111 |
| | 65 |
| | 196 |
| | 132 |
| 203 |
| | 111 |
| | 354 |
| | 196 |
|
| Less: Net income attributable to noncontrolling interests | 9 |
| | 1 |
| | 15 |
| | 4 |
| 27 |
| | 9 |
| | 39 |
| | 15 |
|
| Net Income Attributable to Southern Power Company | $ | 102 |
| | $ | 64 |
| | $ | 181 |
| | $ | 128 |
| |
| Net Income Attributable to Southern Power | | $ | 176 |
| | $ | 102 |
| | $ | 315 |
| | $ | 181 |
|
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
| | | | For the Three Months
Ended September 30, | | For the Nine Months
Ended September 30, | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Net Income | $ | 111 |
| | $ | 65 |
| | $ | 196 |
| | $ | 132 |
| $ | 203 |
| | $ | 111 |
| | $ | 354 |
| | $ | 196 |
|
| Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| |
| Other comprehensive income (loss): | | | | | | | | |
| Qualifying hedges: | | | | | | | | |
| Changes in fair value, net of tax of $14, $-, $(1), and $-, respectively | | 23 |
| | — |
| | (1 | ) | | — |
|
Reclassification adjustment for amounts included in net
income, net of tax of $(1), $-, $7, and $-, respectively | | (1 | ) | | — |
| | 13 |
| | — |
|
| Total other comprehensive income (loss) | | 22 |
| | — |
| | 12 |
| | — |
|
| Less: Comprehensive income attributable to noncontrolling interests | 9 |
| | 1 |
| | 15 |
| | 4 |
| 27 |
| | 9 |
| | 39 |
| | 15 |
|
| Comprehensive Income Attributable to Southern Power Company | $ | 102 |
| | $ | 64 |
| | $ | 181 |
| | $ | 128 |
| |
| Comprehensive Income Attributable to Southern Power | | $ | 198 |
| | $ | 102 |
| | $ | 327 |
| | $ | 181 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
| | | | For the Nine Months
Ended September 30, | For the Nine Months Ended September 30, |
| | 2015 | | 2014 | 2016 | | 2015 |
| | (in millions) | (in millions) |
| Operating Activities: | | | | | | |
| Net income | $ | 196 |
| | $ | 132 |
| $ | 354 |
| | $ | 196 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | | | | |
| Depreciation and amortization, total | 187 |
| | 166 |
| 262 |
| | 187 |
|
| Deferred income taxes | 222 |
| | (6 | ) | (668 | ) | | 222 |
|
| Investment tax credits | 294 |
| | 38 |
| — |
| | 294 |
|
| Amortization of investment tax credits | (14 | ) | | (8 | ) | (25 | ) | | (14 | ) |
| Deferred revenues | 15 |
| | (2 | ) | 9 |
| | 15 |
|
| Collateral deposits | | (80 | ) | | — |
|
| Accrued income taxes, non-current | 100 |
| | — |
| — |
| | 100 |
|
| Other, net | 10 |
| | 3 |
| 10 |
| | 10 |
|
| Changes in certain current assets and liabilities — | | | | | | |
| -Receivables | (28 | ) | | (63 | ) | (82 | ) | | (28 | ) |
| -Fossil fuel stock | 6 |
| | (2 | ) | |
| -Prepaid income taxes | (116 | ) | | 39 |
| (16 | ) | | (116 | ) |
| -Other current assets | (5 | ) | | (4 | ) | 1 |
| | 1 |
|
| -Accounts payable | 1 |
| | 27 |
| 7 |
| | 1 |
|
| -Accrued taxes | (247 | ) | | 62 |
| 483 |
| | (247 | ) |
| -Other current liabilities | (12 | ) | | (11 | ) | 14 |
| | (12 | ) |
| Net cash provided from operating activities | 609 |
| | 371 |
| 269 |
| | 609 |
|
| Investing Activities: | | | | | | |
| Plant acquisitions | (1,128 | ) | | (218 | ) | |
| Business acquisitions | | (1,134 | ) | | (1,128 | ) |
| Property additions | (348 | ) | | (15 | ) | (1,702 | ) | | (348 | ) |
| Change in construction payables | 88 |
| | (3 | ) | (69 | ) | | 88 |
|
| Payments pursuant to long-term service agreements | (65 | ) | | (42 | ) | (58 | ) | | (65 | ) |
| Investment in restricted cash | | (750 | ) | | — |
|
| Distribution of restricted cash | | 746 |
| | — |
|
| Other investing activities | (1 | ) | | (10 | ) | (41 | ) | | (1 | ) |
| Net cash used for investing activities | (1,454 | ) | | (288 | ) | (3,008 | ) | | (1,454 | ) |
| Financing Activities: | | | | | | |
| Increase in notes payable, net | 18 |
| | 20 |
| 692 |
| | 18 |
|
| Proceeds — | | | | | | |
| Senior notes | 650 |
| | — |
| 1,531 |
| | 650 |
|
| Capital contributions | 226 |
| | (4 | ) | 800 |
| | 226 |
|
| Other long-term debt | 400 |
| | 10 |
| 63 |
| | 400 |
|
| Redemptions — Senior notes | (525 | ) | | — |
| |
| Redemptions — | | | | |
| Senior notes | | — |
| | (525 | ) |
| Other long-term debt | | (84 | ) | | (3 | ) |
| Distributions to noncontrolling interests | (6 | ) | | — |
| (22 | ) | | (6 | ) |
| Contributions from noncontrolling interests | 274 |
| | 7 |
| |
| Capital contributions from noncontrolling interests | | 367 |
| | 274 |
|
| Purchase of membership interests from noncontrolling interests | | (129 | ) | | — |
|
| Payment of common stock dividends | (98 | ) | | (98 | ) | (204 | ) | | (98 | ) |
| Other financing activities | (8 | ) | | — |
| (14 | ) | | (5 | ) |
| Net cash provided from (used for) financing activities | 931 |
| | (65 | ) | |
| Net cash provided from financing activities | | 3,000 |
| | 931 |
|
| Net Change in Cash and Cash Equivalents | 86 |
| | 18 |
| 261 |
| | 86 |
|
| Cash and Cash Equivalents at Beginning of Period | 75 |
| | 69 |
| 830 |
| | 75 |
|
| Cash and Cash Equivalents at End of Period | $ | 161 |
| | $ | 87 |
| $ | 1,091 |
| | $ | 161 |
|
| Supplemental Cash Flow Information: | | | | | | |
| Cash paid (received) during the period for — | | | | | | |
| Interest (net of $4 and $- capitalized for 2015 and 2014, respectively) | $ | 69 |
| | $ | 78 |
| |
| Interest (net of $32 and $4 capitalized for 2016 and 2015, respectively) | | $ | 49 |
| | $ | 69 |
|
| Income taxes, net | (215 | ) | | (91 | ) | 71 |
| | (215 | ) |
| Noncash transactions — Accrued property additions at end of period | 120 |
| | 1 |
| 210 |
| | 120 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
| | | Assets | | At September 30,
2015 | | At December 31,
2014 | | At September 30, 2016 | | At December 31, 2015 |
| | | (in millions) | | (in millions) |
| Current Assets: | | | | | | | | |
| Cash and cash equivalents | | $ | 161 |
| | $ | 75 |
| | $ | 1,091 |
| | $ | 830 |
|
| Receivables — | | | | | | | | |
| Customer accounts receivable | | 100 |
| | 77 |
| | 121 |
| | 75 |
|
| Other accounts receivable | | 35 |
| | 15 |
| | 25 |
| | 19 |
|
| Affiliated companies | | 50 |
| | 34 |
| |
| Fossil fuel stock, at average cost | | 16 |
| | 22 |
| |
| Materials and supplies, at average cost | | 60 |
| | 58 |
| |
| Affiliated | | | 67 |
| | 30 |
|
| Fossil fuel stock | | | 14 |
| | 16 |
|
| Materials and supplies | | | 163 |
| | 63 |
|
| Prepaid income taxes | | 136 |
| | 19 |
| | 61 |
| | 45 |
|
| Deferred income taxes, current | | — |
| | 306 |
| |
| Other current assets | | 19 |
| | 21 |
| | 32 |
| | 30 |
|
| Total current assets | | 577 |
| | 627 |
| | 1,574 |
| | 1,108 |
|
| Property, Plant, and Equipment: | | | | | | | | |
| In service | | 6,049 |
| | 5,657 |
| | 9,491 |
| | 7,275 |
|
| Less accumulated provision for depreciation | | 1,189 |
| | 1,035 |
| | 1,465 |
| | 1,248 |
|
| Plant in service, net of depreciation | | 4,860 |
| | 4,622 |
| | 8,026 |
| | 6,027 |
|
| Construction work in progress | | 977 |
| | 11 |
| | 1,652 |
| | 1,137 |
|
| Total property, plant, and equipment | | 5,837 |
| | 4,633 |
| | 9,678 |
| | 7,164 |
|
| Other Property and Investments: | | | | | | | | |
| Goodwill | | 2 |
| | 2 |
| | 2 |
| | 2 |
|
Other intangible assets, net of amortization of $11 and $8
at September 30, 2015 and December 31, 2014, respectively | | 318 |
| | 47 |
| |
Other intangible assets, net of amortization of $16 and $12
at September 30, 2016 and December 31, 2015, respectively | | | 389 |
| | 317 |
|
| Total other property and investments | | 320 |
| | 49 |
| | 391 |
| | 319 |
|
| Deferred Charges and Other Assets: | | | | | | | | |
| Prepaid long-term service agreements | | 157 |
| | 124 |
| | 151 |
| | 166 |
|
| Accumulated deferred income taxes | | | 199 |
| | — |
|
| Other deferred charges and assets — affiliated | | 3 |
| | 5 |
| | 3 |
| | 9 |
|
| Other deferred charges and assets — non-affiliated | | 146 |
| | 112 |
| | 355 |
| | 139 |
|
| Total deferred charges and other assets | | 306 |
| | 241 |
| | 708 |
| | 314 |
|
| Total Assets | | $ | 7,040 |
| | $ | 5,550 |
| | $ | 12,351 |
| | $ | 8,905 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
| | | Liabilities and Stockholders' Equity | | At September 30,
2015 | | At December 31,
2014 | | At September 30, 2016 | | At December 31, 2015 |
| | | (in millions) | | (in millions) |
| Current Liabilities: | | | | | | | | |
| Securities due within one year | | $ | 400 |
| | $ | 525 |
| | $ | 60 |
| | $ | 403 |
|
| Notes payable | | 213 |
| | 195 |
| | 828 |
| | 137 |
|
| Accounts payable — | | | | | | | | |
| Affiliated | | 69 |
| | 78 |
| | 91 |
| | 66 |
|
| Other | | 161 |
| | 30 |
| | 218 |
| | 327 |
|
| Accrued taxes — | | | | | |
| Accrued income taxes | | 3 |
| | 72 |
| | 147 |
| | 198 |
|
| Other accrued taxes | | | 16 |
| | 5 |
|
| Accrued interest | | 14 |
| | 30 |
| | 30 |
| | 23 |
|
| Contingent consideration | | | 30 |
| | 36 |
|
| Other current liabilities | | 56 |
| | 17 |
| | 97 |
| | 44 |
|
| Total current liabilities | | 916 |
| | 947 |
| | 1,517 |
| | 1,239 |
|
| Long-term Debt | | 1,742 |
| | 1,095 |
| | 4,548 |
| | 2,719 |
|
| Deferred Credits and Other Liabilities: | | | | | | | | |
| Accumulated deferred income taxes | | 779 |
| | 863 |
| | 140 |
| | 601 |
|
| Accumulated deferred investment tax credits | | 688 |
| | 601 |
| | 1,385 |
| | 889 |
|
| Accrued income taxes, non-current | | 100 |
| | — |
| | 109 |
| | 109 |
|
| Asset retirement obligations | | | 40 |
| | 21 |
|
| Deferred capacity revenues — affiliated | | 39 |
| | 15 |
| | 19 |
| | 17 |
|
| Other deferred credits and liabilities — affiliated | | — |
| | 1 |
| |
| Other deferred credits and liabilities — non-affiliated | | 25 |
| | 18 |
| |
| Other deferred credits and liabilities | | | 115 |
| | 3 |
|
| Total deferred credits and other liabilities | | 1,631 |
| | 1,498 |
| | 1,808 |
| | 1,640 |
|
| Total Liabilities | | 4,289 |
| | 3,540 |
| | 7,873 |
| | 5,598 |
|
| Redeemable Noncontrolling Interest | | 41 |
| | 39 |
| |
| Redeemable Noncontrolling Interests | | | 49 |
| | 43 |
|
| Common Stockholder's Equity: | | | | | | | | |
| Common stock, par value $.01 per share — | | | | | | | | |
| Authorized — 1,000,000 shares | | | | | | | | |
| Outstanding — 1,000 shares | | — |
| | — |
| | — |
| | — |
|
| Paid-in capital | | 1,401 |
| | 1,176 |
| | 2,620 |
| | 1,822 |
|
| Retained earnings | | 657 |
| | 573 |
| | 769 |
| | 657 |
|
| Accumulated other comprehensive income | | 3 |
| | 3 |
| |
| Accumulated other comprehensive income (loss) | | | 16 |
| | 4 |
|
| Total common stockholder's equity | | 2,061 |
| | 1,752 |
| | 3,405 |
| | 2,483 |
|
| Noncontrolling Interest | | 649 |
| | 219 |
| |
| Total Stockholders' Equity | | 2,710 |
| | 1,971 |
| |
| Noncontrolling interests | | | 1,024 |
| | 781 |
|
| Total stockholders' equity | | | 4,429 |
| | 3,264 |
|
| Total Liabilities and Stockholders' Equity | | $ | 7,040 |
| | $ | 5,550 |
| | $ | 12,351 |
| | $ | 8,905 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRD QUARTER 20152016 vs. THIRD QUARTER 20142015
AND
YEAR-TO-DATE 20152016 vs. YEAR-TO-DATE 20142015
OVERVIEW
Southern Power constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Power continually seeks opportunities to execute its strategy to create value through various transactions including acquisitions and sales of assets, construction of new power plants,generating facilities, and entry into PPAs primarily with investor-owned utilities, independent power producers, municipalities, electric cooperatives, and electric cooperatives.other load-serving entities. 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 nine months ended September 30, 2015,2016, Southern Power acquired or commenced construction of approximately 857758 MWs of additional solar and wind facilities including five Georgiaand, subsequent to September 30, 2016, acquired or commenced construction projects located in Taylorof approximately 977 MWs of wind and Decatur Counties, as well as four solar projects located in California.natural gas facilities. In addition, Southern Power has also entered into agreementscommitted to acquire approximately 450674 MWs of solar and wind facilities located in Oklahoma, contingent upon certain construction and project milestones. Subsequent to September 30, 2015, Southern Power acquired an additional 15-MW solar facility located in California.over the next several months. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Acquisitions"Acquisitions" and "Construction Projects""Construction Projects" herein for additional information.
At September 30, 2016, Southern Power had an average investment coverage ratio of 92% through 2020 and 91% 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
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $38 | | 59.4 | | $53 | | 41.4 |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $74 | | 72.5 | | $134 | | 74.0 |
Net income attributable to Southern Power for the third quarter 20152016 was $102$176 million compared to $64$102 million for the corresponding period in 2014. The increase was primarily due to increased revenues from PPAs, including solar, and lower income taxes primarily related to ITCs, partially offset by increased other operations and maintenance expenses due to new solar facilities.
2015. Net income attributable to Southern Power for year-to-date 20152016 was $181$315 million compared to $128$181 million for the corresponding period in 2014.2015. The increase wasincreases were primarily due to increased revenuesfederal income tax benefits from new PPAs, including solar ITCs and lower income taxes primarily related to ITCs,wind PTCs and increased renewable energy sales, partially offset by increasedincreases in depreciation, and other operations and maintenance expenses, primarily dueand interest expense from debt issuances, all related to new solar and wind facilities.
Wholesale Revenues–Non-Affiliates
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $(37) | | (11.1) | | $(94) | | (10.8) |
Wholesale revenues from sales to non-affiliates will vary depending on the energy demand of those customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Power's
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Operating Revenues
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $99 | | 24.7 | | $103 | | 9.5 |
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.
Capacity revenues are an integral component of Southern Power's natural gas and biomass PPAs. Energy under these PPAs is generally sold at variable cost or is indexed to published gas indices. Energy revenues also include fees for support services, fuel storage, and unit start charges.
Southern Power's electricity sales from solar and wind generating facilities are also through long-term PPAs; however, these solar and wind PPAs do not have a capacity charge and customers purchase the energy output of a dedicated renewable facility through an energy charge. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, and other factors.
|
| | | | | | | | | | | |
| | Third Quarter 2016
vs.
Third Quarter 2015 | | Year-to-Date 2016
vs.
Year-to-Date 2015 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| PPA capacity revenues | $ | (19 | ) | | (11.8) | | $ | (25 | ) | | (5.8) |
| PPA energy revenues | 62 |
| | 33.3 | | 79 |
| | 17.5 |
| Total PPA revenues | 43 |
| | 11.8 | | 54 |
| | 6.1 |
| Revenues not covered by PPAs | 55 |
| | 121.9 | | 46 |
| | 23.4 |
| Other revenues | 1 |
| | 50.0 | | 3 |
| | 42.9 |
| Total operating revenues | $ | 99 |
| | 24.7% | | $ | 103 |
| | 9.5% |
In the third quarter 2016, operating revenues were $500 million compared to $401 million for the corresponding period in 2015. The $99 million increase in operating revenues was primarily due to the following:
PPA capacity revenues decreased $19 million primarily due to the remarketing of generation capacity into the short-term markets as a result of PPA expirations.
PPA energy revenuesincreased $62 million primarily due to an increase in renewable energy sales from new solar and wind facilities.
Revenues not covered by PPAs increased $55 million primarily due to an increase in short-term sales to non-affiliates as a result of the remarketing of generation capacity from expired PPAs.
For year-to-date 2016, operating revenues were $1.2 billion compared to $1.1 billion for the corresponding period in 2015. The $103 million increase in operating revenues was primarily due to the following:
PPA capacity revenues decreased $25 million as a result of a $44 million decrease in non-affiliate capacity revenues primarily due to the remarketing of generation capacity into the short-term markets as a result of PPA expirations, partially offset by a $19 million increase in affiliate capacity revenues due to new PPAs.
PPA energy revenuesincreased $79 million primarily due to a $122 million increase in renewable energy sales arising from new solar and wind facilities, partially offset by a decrease of $43 million in fuel revenues related to natural gas facility PPAs.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Revenues not covered by PPAs increased $46 million due to a $70 million increase in short-term sales to non-affiliates as a result of the remarketing of generation capacity from expired PPAs, partially offset by a $24 million decrease in power pool revenue primarily associated with a reduction in available uncovered capacity.
Wholesale revenues will vary depending on the energy demand of Southern Power's customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Power's energy. Increases and decreases in revenues under PPAs that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.
Wholesale revenues from non-affiliates for the third quarter 2015 were $295 million compared to $332 million for the corresponding period in 2014. The decrease was due to a $27 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 new solar PPAs. The decrease in energy revenues reflects a 7% decrease in the average price of energy and a 6% decrease in KWH sales. In addition, capacity revenues decreased $10 million primarily due to PPA expirations.
Wholesale revenues from non-affiliates for year-to-date 2015 were $776 million compared to $870 million for the corresponding period in 2014. The decrease was due to a $71 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 new solar PPAs. The decrease in energy revenues reflects a 13% decrease in the average price of energy. In addition, capacity revenues decreased $23 million primarily due to PPA expirations.
Wholesale Revenues–Affiliates
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $1 | | 1.0 | | $60 | | 24.7 |
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 third quarter 2015 were $104 million compared to $103 million for the corresponding period in 2014. The increase was the result of a $20 million increase in capacity revenues, partially offset by a $19 million decrease in energy revenues. The increase in capacity revenues was primarily the result of new PPAs. The decrease in energy revenues was primarily the result of a 42% decrease in the average price of energy partially offset by a 28% increase in KWH sales primarily from new PPAs.
Wholesale revenues from affiliates for year-to-date 2015 were $303 million compared to $243 million for the corresponding period in 2014. The increase was the result of a $31 million increase in energy revenues and a $29 million increase in capacity revenues. The increase in energy revenues was 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, as well as new PPAs. The increase in energy revenues reflects a 71% increase in KWH sales, partially offset by a 29% decrease in the average price of energy. The increase in capacity revenues was primarily the result of new PPAs.
Fuel and Purchased Power Expenses
Fuel costs constitute the single largest expense for Southern Power. In addition, Southern Power purchases a portion of its electricity needs from the wholesale market and the power pool. Details of Southern Power's generation and purchased power were as follows:
|
| | | | | | | | | | | | |
| | | Third Quarter 2015
vs.
Third Quarter 2014 | | Year-to-Date 2015
vs.
Year-to-Date 2014 |
| | | (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| Fuel | | $ | (60 | ) | | (33.7) | | $ | (60 | ) | | (14.3) |
| Purchased power – non-affiliates | | (11 | ) | | (39.3) | | (21 | ) | | (28.8) |
| Purchased power – affiliates | | (8 | ) | | (61.5) | | (40 | ) | | (69.0) |
| Total fuel and purchased power expenses | | $ | (79 | ) | | | | $ | (121 | ) | | |
|
| | | | | |
| | Third Quarter 2016 | Third Quarter 2015 | | Year-to-Date 2016 | Year-to-Date 2015 |
| | (in billions of KWHs) |
| Generation | 11.1 | 9.4 | | 27.9 | 24.8 |
| Purchased power | 0.9 | 0.5 | | 2.5 | 1.5 |
| Total generation and purchased power | 12.0 | 9.9 | | 30.4 | 26.3 |
Total generation and purchased power excluding solar, wind, and tolling agreements | 6.7 | 5.2 | | 17.7 | 15.9 |
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 relating to all the energy delivered under such PPAs. Consequently, any increase or decreasechanges in such fuel cost iscosts are generally accompanied by an increase or decreasea corresponding change in related fuel revenues under the PPAs and doesdo not have a
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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, availability, and the availability and cost of generating resources throughout the Southern Company system and other contract resources. Load requirements are submitted to the power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power, Company,an affiliate companies,company, or external parties.
|
| | | | | | | | | | | | |
| | | Third Quarter 2016
vs.
Third Quarter 2015 | | Year-to-Date 2016
vs.
Year-to-Date 2015 |
| | | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | | $ | 36 |
| | 30.5 | | $ | (20 | ) | | (5.5) |
| Purchased power | | 11 |
| | 50.0 | | 6 |
| | 8.6 |
| Total fuel and purchased power expenses | | $ | 47 |
| | | | $ | (14 | ) | | |
In the third quarter 2015,2016, total fuel and purchased power expenses were $140$187 million compared to $219$140 million for the corresponding period in 2014.2015. The decreaseincrease was the result of a $46 million decrease in the average cost of fuel and purchased power primarily due to lower natural gas prices and a $33the following:
Fuel expense increased $36 million decrease in the total volume of KWHs generated and purchased; however, total KWHs generated increased 5% when taking into account generation for tolling and solar PPAs.
For year-to-date 2015, total fuel and purchased power expenses were $431 million compared to $552 million for the corresponding period in 2014. The decrease was a result of a $185 million decrease in the average cost of fuel and purchased power primarily due to lower natural gas prices, partially offset by a $64$27 million net increase in the total volume of KWHs generated and purchased primarily due to increased demand resulting from lower natural gas prices. Total KWHs generated increased 22% when taking into account generation for tolling and solar PPAs.
Fuel
In the third quarter 2015, fuel expense was $118 million compared to $178 million for the corresponding period in 2014. The decrease was due to a 27% decrease associated with the average cost of natural gas per KWH generated, and a 10% decrease associated with the volume of KWHs generated, which excludes tolling and solar PPAs.
For year-to-date 2015, fuel expense was $361 millioncompared to $421 million for the corresponding period in 2014. The decrease was due to a 34% decrease associated with the average cost of natural gas per KWH generated, partially offset by a 30% increase associated with the volume of KWHs generated primarily asand a result$9 million increase associated with average cost of increased demand resulting from lower natural gas prices, which excludes tolling and solar PPAs.per KWH generated.
Purchased Power – Non-Affiliates and Affiliates
In the third quarter 2015, purchased power expense was $22 million compared to $41 million for the corresponding period in 2014. For year-to-date 2015, purchased power expense was $70 million compared to $131 million for the corresponding period in 2014. The decreases were primarily the result of 38% and 43% decreases in the volume of KWHs purchased in the third quarter 2015 and year-to-date 2015, respectively, primarily due to lower natural gas prices.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $16 | | 34.8 | | $16 | | 9.5 |
In the third quarter 2015, other operations and maintenance expenses were $62 million compared to $46 million for the corresponding period in 2014. The increase was primarily due to an increase in expenses associated with business development and support services, new plants placed in service in 2014 and 2015, and generation maintenance.
For year-to-date 2015, other operations and maintenance expenses were $184 million compared to $168 million for the corresponding period in 2014. The increase was primarily due to a $31 million increase in expenses associated with business development and support services, new plants placed in service in 2014 and 2015, transmission costs, and generation maintenance, partially offset by a $15 million decrease in outage expense.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Purchased power expense increased $11 million due to a $19 million increase associated with the volume of KWHs purchased, partially offset by a $4 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 $417 million compared to $431 million for the corresponding period in 2015. The decrease was primarily due to the following:
Fuel expense decreased $20 million primarily due to a $42 million decrease associated with the average cost of natural gas per KWH generated, partially offset by a $22 million increase associated with the volume of KWHs generated.
Purchased power expense increased $6 million due to a $48 million increase associated with the volume of KWHs purchased, largely offset by a $30 million decrease in the average cost of purchased power and a $12 million decrease associated with a PPA expiration.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $19 | | 30.6 | | $62 | | 33.7 |
In the third quarter 2016, other operations and maintenance expenses were $81 million compared to $62 million for the corresponding period in 2015. The increase was primarily due to a $9 million increase in expenses associated with new solar and wind facilities placed in service in 2015 and 2016, a $5 million increase associated with scheduled outage and maintenance expenses, and a $3 million increase in general business expenses associated with Southern Power's overall growth strategy.
For year-to-date 2016, other operations and maintenance expenses were $246 million compared to $184 million for the corresponding period in 2015. The increase was primarily due to a $24 million increase associated with scheduled outage and maintenance expenses, a $22 million increase in expenses associated with new solar and wind facilities placed in service in 2015 and 2016, and a $14 million increase in general business expenses associated with Southern Power's overall growth strategy.
Depreciation and Amortization
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $4 | | 6.7 | | $20 | | 12.3 |
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $29 | | 45.3 | | $64 | | 35.0 |
In the third quarter 2015,2016, depreciation and amortization was $64$93 million compared to $60$64 million for the corresponding period in 2014.2015. For year-to-date 2016, depreciation and amortization was $247 million compared to $183 million for the corresponding period in 2015. The increase wasincreases were primarily due to additional depreciation related to new solar and wind facilities placed in service in 20142015 and 2015, partially offset by rate changes related to component depreciation.2016.
For year-to-date 2015, depreciation and amortizationInterest Expense, net of Amounts Capitalized
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $17 | | 94.4 | | $16 | | 25.8 |
In the third quarter 2016, interest expense, net of amounts capitalized was $183$35 million compared to $163$18 million for the corresponding period in 2014.2015. The increase was primarily due to additional depreciationan increase of $25 million in interest expense related to solar facilities placed in service in 2014 and 2015.
Income Taxes
|
| | | | | | |
| Third Quarter 2015 vs. Third Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $(21) | | (95.5) | | $(8) | | (36.4) |
Inadditional debt issued since the third quarter of 2015 income taxes were $1primarily to fund Southern Power's growth strategy and continuous construction program, partially offset by an $8 million increase in capitalized interest associated
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
with the construction of solar facilities.
For year-to-date 2016, interest expense, net of amounts capitalized was $78 million compared to $22$62 million for the corresponding period in 2014.2015. The decreaseincrease was primarily due to increased federalan increase of $43 million in interest expense related to additional debt issued since the third quarter of 2015 primarily to fund Southern Power's growth strategy and continuous construction program, largely offset by a $27 million increase in capitalized interest associated with the construction of solar facilities.
Income Taxes (Benefit)
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(103) | | N/M | | $(181) | | N/M |
N/M - Not meaningful
In the third quarter 2016, income tax benefits related to ITCs in 2015, partially offset by higher pre-tax earnings in 2015.
For year-to-date 2015, income taxes were $14benefit was $(102) million compared to $22an expense of $1 million for the corresponding period in 2014.2015. The decreasechange was primarily due to increaseda $96 million increase in federal income tax benefits from solar ITCs and wind PTCs in 2016 and a $10 million decrease in tax expense related to ITCslower pre-tax earnings in 2015,2016, partially offset by highera $3 million increase in tax expense related to beneficial state apportionment rate changes in 2015.
For year-to-date 2016, income tax benefit was $(167) million compared to an expense of $14 million for the corresponding period in 2015. The change was primarily due to a $171 million increase in federal income tax benefits from solar ITCs and wind PTCs in 2016 and a $17 million decrease in tax expense related to lower pre-tax earnings in 2015 and2016, partially offset by a $7 million increase in tax expense related to beneficial state income taxapportionment rate changes in 2014.2015.
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, includingfacilities; and 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,factors, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Power in Item 7 of the Form 10-K.
Power Sales Agreements
See BUSINESS – "The Southern Company System – Southern Power" in Item 1 of the Form 10-K for additional information regarding Southern Power's PPAs. Generally, under the solar and wind generation PPAs, the purchasing party retains the right to keep or resell the renewable energy credits.
At 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% through 2020 and 70% through 2025, with an average remaining contract duration of approximately 10 years.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Power believes an investment coverage ratio best identifies the value 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 September 30, 2016, the average investment coverage ratio was 92% through 2020 and 91% through 2025, with an average remaining contract duration of approximately 17 years. At December 31, 2015, the average investment coverage ratio would have been 91% through 2020 and 90% through 2025, with an average remaining contract duration of approximately 18 years.
Environmental Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Power in Item 7 of the Form 10-K for information on the development by federal and state environmental regulatory agencies of additional control strategies for emissions of air pollution from industrial sources, including electric generating facilities. Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, water quality, or other environmental and health concerns could also significantly affect Southern Power. While Southern Power's PPAs generally contain provisions that
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 regulatorylegislative or legislativeregulatory changes 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 – Air Quality" of Southern 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) and the Cross State Air Pollution Rule (CSAPR).
On June 12, 2015,October 26, 2016, the EPA published a final rule requiring affected states (includingthat updates the CSAPR ozone season nitrogen oxide program, including revising ozone-season emissions budgets in Alabama and Texas and removing Florida Georgia,and 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.from the CSAPR program. The ultimate impact of the finalthis rule will depend on the outcome of any legal challenges and implementation at the development and approval of SIPs by the affected states and 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 rulemakingstate level and cannot be determined at this time.
Water QualityAcquisitions
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" ofDuring 2016, in accordance with its overall growth strategy, Southern Power in Item 7or one of its wholly-owned subsidiaries, Southern Renewable Partnerships, LLC and Southern Renewable Energy, Inc., acquired or contracted to acquire the Form 10-Kprojects 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 regarding the EPA's revisions to effluent guidelines.information.
On November 3, 2015, the EPA published final revisions to technology-based limits for certain wastestreams from steam electric power plants. These revisions impose stringent steam effluent guidelines and technology requirements for wastewater discharges at affected units. Compliance with these revisions could result in significant additional capital expenditures and could affect future unit retirement and replacement decisions. The ultimate impact of these revisions will depend on any legal challenges and implementation of the final revisions and cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Southern Power in Item 7 of the Form 10-K for additional information regarding the EPA's proposed regulation of CO2 from fossil-fuel-fired electric generating units.
On October 23, 2015, two final actions by the EPA that would limit CO2 emissions from fossil fuel-fired electric generating units were published in the Federal Register. One of the final actions contains specific emission standards governing CO2 emissions from new, modified, and reconstructed units. The other final action 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, a proposed federal plan and proposed model rule were published 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 results 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 Power cannot be determined at this time and will depend on numerous factors including the Southern Company system's
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
Acquisitions
During 2015, Southern Power Company acquired or contracted to acquire through its wholly-owned subsidiaries, Southern Renewable Partnerships, LLC or Southern Renewable Energy, Inc. (SRE), the following projects in accordance with its overall growth strategy, which are included in its capital program estimates for 2015. Acquisition-related costs were expensed as incurred and were not material. The acquisitions do not include any contingent consideration unless specifically noted.
|
| | | | | | | | | | | | | |
| Project Entity | Seller; Acquisition Date | Approx. Nameplate Capacity | Location | Southern Power Percentage Ownership | | Expected/Actual Commercial Operation Date | PPA
Counterparties for Entire Plant Output | PPA Contract Period | Approx. Purchase Price | |
| | | (MW) | | | | | | | (in millions) | |
| WIND |
| Kay Wind, LLC | Apex Clean Energy Holdings, LLC
| 299 | Kay County, Oklahoma | 100 | % | | Fourth quarter 2015 | Westar Energy, Inc. and Grant River Dam Authority | 20 years | $ | 492 |
| (a) |
| | | | | | | | | | | |
| Grant Wind, LLC | Apex Clean Energy Holdings, LLC
| 151 | Grant County, Oklahoma | 100 | % | | First quarter 2016 | Western Farmers, East Texas, and Northeast Texas Electric Cooperative | 20 years | $ | 264 |
| (a) |
| SOLAR |
| Lost Hills Blackwell Holdings, LLC (Lost Hills Blackwell) | First Solar, Inc. (First Solar)
April 15, 2015 | 35 | Kern County, California | 51 | % | (b) | April 17, 2015 | City of Roseville, California/Pacific Gas and Electric Company | 29 years | $ | 74 |
| (c) |
| | | | | | | | | | | |
| NS Solar Holdings, LLC (North Star) | First Solar
April 30, 2015 | 61 | Fresno County, California | 51 | % | (b) | June 20, 2015 | Pacific Gas and Electric Company | 20 years | $ | 211 |
| (d) |
| | | | | | | | | | | |
| Tranquillity | Recurrent Energy, LLC
August 28, 2015 | 204 | Fresno County, California | 51 | % | (b) | Fourth quarter 2016 | Shell Energy North America (US), LP/Southern California Edison Company | 18 years | $ | 100 |
| (e) |
| | | | | | | | | | | |
| Desert Stateline Holdings, LLC (Desert Stateline) | First Solar
August 31, 2015 | 300 | San Bernardino County, California | 51 | % | (b) | 8 Phases from December 2015 to Third quarter 2016 | Southern California Edison Company | 20 years | $ | 439 |
| (f) |
| | | | | | | | | | | |
| GASNA 31P, LLC (Morelos) | Solar Frontier Americas Holding, LLC
October 22, 2015 | 15 | Kern County, California | 90 | % | | Fourth quarter 2015 | Pacific Gas and Electric Company | 20 years | $ | 45 |
| (g) |
|
| | | | | | | | |
| Project Facility | Resource | Approximate Nameplate Capacity (MW) | Location | Percentage Ownership | Actual/Expected COD | PPA Contract Period |
| Acquisitions During the Nine Months Ended September 30, 2016 |
| Calipatria | Solar | 20 | Imperial County, CA | 90 | % | | February 2016 | 20 years |
| East Pecos | Solar | 120 | Pecos County, TX | 100 | % | | December 2016 | 15 years |
| Grant Plains | Wind | 147 | Grant County, OK | 100 | % | | December 2016 | Up to 20 years |
| Grant Wind | Wind | 151 | Grant County, OK | 100 | % | | April 2016 | 20 years |
| Henrietta | Solar | 102 | Kings County, CA | 51 | % | (a) | July 2016 | 20 years |
| Lamesa | Solar | 102 | Dawson County, TX | 100 | % | | First quarter 2017 | 15 years |
| Passadumkeag | Wind | 42 | Penobscot County, ME | 100 | % | | July 2016 | 15 years |
| Rutherford | Solar | 74 | Rutherford County, NC | 90 | % | | December 2016 | 15 years |
| Acquisitions Subsequent to September 30, 2016 |
| Mankato | Natural Gas | 375 | Mankato, MN | 100 | % | | N/A(b) | 10 years |
| Wake Wind | Wind | 257 | Floyd and Crosby Counties, TX | 90.1 | % | | October 2016 | 12 years |
| |
| (a) | Southern Power owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. Southern Power and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the project. In addition, Southern Power is entitled to substantially all of the federal tax benefits with respect to the transaction. |
| |
| (b) | The Mankato facility is a fully operational 375-MW natural gas-fired combined-cycle facility with an additional 345-MW expansion under development. |
Acquisitions During the Nine Months Ended September 30, 2016
(a) On February 24, 2015Southern Power's aggregate purchase price for the project facilities acquired during the nine months ended September 30, 2016 was approximately $830 million. Total aggregate construction costs, excluding the acquisition costs, are expected to be $708 million to $775 million for East Pecos, Grant Plains, Lamesa, and Rutherford, which are currently under construction. The ultimate outcome of these matters cannot be determined at this time.
Acquisitions Subsequent to September 4, 2015,30, 2016
Southern Power's aggregate purchase price for acquisitions subsequent to September 30, 2016 was approximately $873 million. As part of Southern Power's acquisition of Mankato, which has a fully operational 375-MW natural gas-fired combined-cycle facility, Southern Power entered into agreementshas commenced construction of an additional 345-MW expansion which is covered with a 20-year PPA. Total aggregate construction costs, excluding the acquisition costs allocated to acquire Kay Wind, LLC and Grant Wind, LLC, respectively. The completion of each acquisition is subject to the seller achieving certain construction and project milestones, as well as various other customary conditions to closing. Each acquisition isCWIP, are expected to closebe $170 million to $190 million. The ultimate outcome of this matter cannot be determined at or near the expected commercial operation date. Inthis time.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
addition,Acquisition Agreements Executed but Not Yet Closed
During the finalnine months ended September 30, 2016 and subsequent to that date, Southern Power entered into agreements to acquire the following projects for an aggregate purchase price may be adjusted based on performance testing as specifiedof approximately $1.2 billion:
51% ownership interest (through 100% ownership of the class A membership interests entitling Southern Power to 51% of all cash distributions and most of the federal tax benefits) in a 100-MW solar facility in Nevada covered with a 20-year PPA, which is expected to close in November 2016;
100% ownership interests in two wind facilities in Texas totaling 299 MWs, the applicable purchase agreement. The Grant Wind, LLC purchase price includes contingent consideration. majority of which is contracted under PPAs for the first 12 to 14 years of operation and are expected to close before the end of 2016; and
100% ownership interest in a 275-MW wind facility in Texas, the majority of which is contracted under a 12-year PPA and is expected to close in January 2017.
The ultimate outcome of this matterthese matters cannot be determined at this time.
(b)The aggregate amount of revenue recognized by Southern Power owns 100%related to the project facilities acquired during the nine months ended September 30, 2016 included in the condensed consolidated statements of income for year-to-date 2016 is $14 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 nine months ended September 30, 2016 included in the condensed consolidated statements 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 class A membership interestsbeginning of 2016, and a wholly-owned subsidiary offor the seller owns 100% of the class B membership interests. Southern Powercomparable 2015 period, is not meaningful and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the respective project. In addition, Southern Power is entitled to substantially all of the federal tax benefits with respect to the respective transaction.
(c) Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests for approximately $33 million. The fair values of the assets acquired through the business combination 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.omitted.
(d) Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests for approximately $100 million. The fair values of the assets acquired through the business combination 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.
(e) Concurrently, a wholly-owned subsidiary of Recurrent Energy, LLC converted all its membership interests to 100% of the class B membership interests of Tranquillity after contributing approximately $157 million of assets and receiving an initial distribution of $100 million. The fair values of the assets acquired were recorded as follows: $170 million as CWIP, $24 million as other receivables, and $37 million as payables; however, the allocation of the purchase price to individual assets has not been finalized. Subsequent to the acquisition, Southern Power and Recurrent Energy, LLC are expected to make additional construction payments of approximately $215 million and $106 million, respectively. The ultimate outcome of this matter cannot be determined at this time.
(f) Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests for approximately $223 million. As of September 30, 2015, the fair values of the assets acquired, which includes Southern Power's and First Solar's initial payments due under the related construction agreement, were recorded as follows: $413 million as CWIP and $249 million as an intangible asset; however, the allocation of the purchase price to individual assets has not been finalized. The intangible asset consists of an acquired PPA that will be amortized over its 20-year term. The estimated amortization for future periods is approximately $6.2 million in 2016, $12.5 million per year for 2017 through 2020, and $192.8 million thereafter. Southern Power's and First Solar's remaining combined future payments, including construction payments, are estimated to be between $827 million to $844 million. The ultimate outcome of this matter cannot be determined at this time.
(g) On October 22, 2015, SRE and Turner Renewable Energy, LLC (TRE), through Southern Turner Renewable Energy, LLC, a jointly-owned subsidiary owned 90% by SRE, acquired all of the outstanding membership interests of Morelos. The total purchase price, including TRE's 10% ownership, is approximately $50 million.
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,in Item 7 of the Form 10-K and during 2015, Southern Power Company acquired allFINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information.
During the outstanding membership interests of five separate solar project development entities. The construction projects arenine months ended September 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, or continued construction of, the projects set forth in the following table. Through September 30, 2016, total costcosts of construction incurred for thesethe following projects were $3.0 billion, of which $1.2 billion remains in CWIP. Including the total construction costs incurred through September 30, 2015 was $299 million.2016 and the acquisition prices allocated to CWIP, total aggregate construction costs for the following projects are estimated to be $3.1 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, excluding the Tranquillity and Desert Stateline construction projects discussed above, are detailed in the table below:
|
| | | | | | | | | | | | |
| Solar Project | Seller | Approx. Nameplate Capacity | County Location in Georgia | Expected Commercial Operation Date | PPA Counterparties
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 | (c) |
| Decatur County | TradeWind Energy, Inc. | 20 | Decatur | December 2015 | Georgia Power(b) | 20 years | $ | 45 |
| - | $47 | (c) |
| Butler | CERSM, LLC and Community Energy, Inc. | 103 | Taylor | December 2016 | Georgia Power(b) | 30 years | $ | 220 |
| - | $230 | (c) |
| Pawpaw | Longview Solar, LLC | 30 | Taylor | December 2015 | Georgia Power(a) | 30 years | $ | 70 |
| - | $80 | (c) |
| Butler Solar Farm | Strata Solar Development, LLC | 20 | Taylor | December 2015 | Georgia Power(b) | 20 years | $ | 42 |
| - | $48 | (c) |
|
| | | | |
| Solar Facility | Approximate Nameplate Capacity (MW) | Location | Actual/Expected COD | PPA Contract Period |
| Projects Completed During the Nine Months Ended September 30, 2016 |
| Butler Solar Farm | 22 | Taylor County, GA | February 2016 | 20 years |
Desert Stateline(a) | 299(b) | San Bernardino County, CA | Through July 2016 | 20 years |
| Garland A | 20 | Kern County, CA | August 2016 | 20 years |
| Pawpaw | 30 | Taylor County, GA | March 2016 | 30 years |
| Tranquillity | 205 | Fresno County, CA | July 2016 | 18 years |
| Projects Under Construction as of September 30, 2016 |
| Butler | 103 | Taylor County, GA | December 2016 | 30 years |
| Garland | 185 | Kern County, CA | October 2016 | 15 years |
| Roserock | 160 | Pecos County, TX | November 2016 | 20 years |
| Sandhills | 146 | Taylor County, GA | October 2016 | 25 years |
| |
| (a) | Approved byOn March 29, 2016, Southern Power acquired an additional 15% interest in Desert Stateline. As a result, Southern Power and the FERC subsequentclass B member are entitled to September 30, 2015.66% and 34%, respectively, of all cash distributions from Desert Stateline. In addition, Southern Power will continue to be entitled to substantially all of the federal tax benefits with respect to the transaction. |
| |
| (b) | Subject to FERC approval.The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and 189 MWs were placed in service during the nine months ended September 30, 2016. |
| |
(c) | Includes the acquisition price of all outstanding membership interests. |
Income Tax Matters
Bonus Depreciation
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITYFUTURE EARNINGS POTENTIAL – "Capital Requirements and Contractual Obligations" herein for additional information.
Power Sales Agreements
See BUSINESS"Income Tax Matters – "TheBonus Depreciation" of Southern Company System – Southern Power"Power in Item 17 of the Form 10-K for additional information regarding Southern Power's PPAs with investor-owned utilities, independent power purchasers, municipalities, and electric cooperatives.information.
Taking into accountThe extension of 50% bonus depreciation included in the PPAs and capacity from the acquisitions and construction projects discussed herein, together with various new PPAs relatingPATH Act is expected to Southern Power's existing fleet, the coverage ratioresult in approximately $650 million of its available capacitypositive cash flows for the next five years and the next 10 years has not changed materially as of September 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,2016 tax year, 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 mitigateall be realized in 2016 due to a projected consolidated net operating loss (NOL) for Southern Company. As a result, the potentialNOL will increase deferred tax assets for federal ITC and PTC carryforwards. See Note (G) to exert market power in certain areas served by the traditional operating companiesCondensed Financial Statements under "Current and in some adjacent areas. To retain market-based rate authority, the FERC directed the traditional operating companiesDeferred Income Taxes – Net Operating Loss" 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
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
concerns. The traditional operating companies and Southern Power filed a request" – Tax Credit Carryforwards" herein for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC.additional information. The ultimate outcome of this matter cannot be determined at this time.
Other Matters
Southern Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Power is subject to certain claims and legal actions arising in the ordinary course of business. Southern Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
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 continues to evaluate these requirements. The ultimate impact of this ASUis currently evaluating the new standard and has not yet been determined.
On April 7, 2015, the FASB issueddetermined its ultimate impact; however, adoption of 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 related2016-02 is expected to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Early adoption is permitted and Southern Power intends to adopt the ASU in the fourth quarter 2015. The ASU is required to be applied retrospectively to all periods presented beginning in the year of adoption. Southern Power currently reflects
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
unamortized debt issuance costs in other deferred charges and assets – non-affiliated on its balance sheet. Upon adoption, the reclassification will not have a materialsignificant impact on the results of operations, financial position, or cash flows of Southern Power.Power's balance sheet.
FINANCIAL CONDITION AND LIQUIDITY
Overview
Southern Power's financial condition remained stable at September 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 $269 million for the first nine months of 2016 compared to $609 million for the first nine months of 2015, compared to $371 million for the first nine months of 2014.2015. The increasedecrease in net cash provided from operating activities was primarily due to an increase in income tax benefits receivedunutilized ITCs and increased revenues from new PPAs, including solar.PTCs. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Bonus Depreciation" herein for additional information. Net cash used for investing activities totaled $1.45$3.0 billion for the first nine months of 20152016 primarily due to the Lost Hills Blackwell, North Star, Tranquillity, and Desert Stateline acquisitions and expenditures related to the construction of new solarrenewable facilities. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information. Net cash provided from financing activities totaled $931 million$3.0 billion for the first nine months of 20152016 primarily due to the issuance of additionalan increase in senior notes, in May 2015,notes payable, and a 13-month bank loan in August 2015. Fluctuations in cash flowcapital contributions 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 nine months of 20152016 include a $966$515 million increase in CWIP due to the acquisition and continued construction of new solar and wind facilities and a $238 million$2.2 billion increase in plant in service, and a $271 million increase in other intangible assets, primarily due to the acquisitionsolar and construction of new solar facilities.wind facilities being placed in service. Other significant changes include ana $261 million increase in long-term debt of $647 million primarily ascash and cash equivalents and a result of the issuance of senior notes in May 2015 and an$2.5 billion increase in noncontrolling interests of $430 millionnotes payable and long-term debt primarily due to contributions made by the class B members for their shares of the related acquisitions.additional borrowings to fund acquisitions and construction projects. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Acquisitions"Acquisitions" and "Construction Projects" 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
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
description of Southern Power's capital requirements for its construction program, scheduled maturities of long-term debt, as well as the related interest, leases, derivative obligations, purchase commitments, and unrecognized tax benefits.benefits, and other purchase commitments. Approximately $400$60 million will be required to repay long-term debt due September 28, 2016. There are no other scheduled maturities of long-term debt through September 30, 2016.2017. In addition, during the nine months ended September 30, 2016, and subsequent to that date, Southern Power entered into new long-term service agreements (LTSA), which begin between 2017 and 2020 and result in additional future commitments totaling approximately $927 million.
The capitalSouthern Power's construction program is subject to periodic review and revision. These amounts includeincludes estimates for potential plant acquisitions, and new construction, as well as ongoing capital improvements, and work to be performed under long-term service agreements.LTSAs, and is subject to periodic review and revision. Planned expenditures for plant acquisitions may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. Capital expenditures offor Southern Power are currently estimated to betotal approximately $2.3$4.5 billion for 2015, which includes approximately $2.2 billion2016, primarily for acquisitions and/or construction of new generating facilities. See Note (I)Capital expenditures for Southern Power are currently estimated to the Condensed Financial Statements hereintotal approximately $1.6 billion annually for additional information.2017 through 2021. 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,
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Power in Item 7 of the Form 10-K for additional information.
Southern Power's current liabilities sometimes exceed current assets due to the use of short-term debt as a funding source, and construction payables, as well as fluctuations in cash needs, which can fluctuate significantly due to both seasonality and the seasonalitystage of the business. In 2015,acquisitions and construction projects. Southern Power has utilized the capital markets and banks to issue additional senior notes and bank term loans, respectively, 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 and to meet short-term liquidity needs, including funding acquisition and construction costs.debt maturities.
To meet liquidity and capital resource requirements,As of September 30, 2016, Southern Power had at September 30, 2015 cash and cash equivalents of approximately $161 million. In August 2015,$1.1 billion.
Details of short-term borrowings were as follows:
|
| | | | | | | | | | |
| | Short-term Debt During the Period (*) |
| | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | (in millions) | | | | (in millions) |
| Commercial paper | $ | 10 |
| | 0.9 | % | | $ | 62 |
|
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2016. No short-term debt was outstanding at September 30, 2016. |
Company Credit Facility
At September 30, 2016, Southern Power Company amended and restated itshad a committed credit facility (Facility), which, among other things, extended the maturity date from 2018 to 2020. Southern Power Company increased its borrowing ability under this Facility to of $600 million from $500 million. Asexpiring in 2020, of September 30, 2015, $567which $68 million washas been used for letters of credit and $532 million remains unused. Southern Power's subsidiaries are not borrowers under the Facility.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The Facility, as well as Southern Power's term loan agreement, contains a covenant that limits the ratio of debt to capitalization (each as(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. For purposes of this definition, debt excludes any project debt incurred by certain subsidiaries of Southern Power Companyto the extent such debt is non-recourse to Southern Power, and capitalization excludes the capital stock or other equity attributable to such subsidiary. Southern Power is currently in compliance with all covenants in the Facility.
Proceeds from 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.
In connection with the construction by Tranquillity of a solar facility in California, RE Tranquillity LLC, an indirect subsidiary of Southern Power Company, entered into the Tranquillity Credit Agreement which is non-recourse to Southern Power Company. The Tranquillity Credit Agreement provides (a) a senior secured construction loan credit facility of up to $86 million, (b) a senior secured bridge loan facility of up to $172 million, and (c) a senior secured letter of credit facility to issue up to $77 million under one or more letters of credit. All three facilities are secured by the membership interests of the project companies held by Tranquillity and are expected to mature on the earlier of the commercial operation date or December 31, 2016. Proceeds from the Tranquillity Credit Agreement are being used to finance project costs related to Tranquillity's solar facility currently under construction. As of September 30, 2015, the entire amount of the Tranquillity Credit Agreement was unused.
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. CommercialSouthern Power's subsidiaries are not borrowers under the commercial paper was usedprogram.
Subsidiary Credit Facilities
In connection with the construction of solar facilities byRE Garland Holdings LLC, RE Roserock LLC, and RE Tranquillity LLC, indirect subsidiaries of Southern Power, each subsidiary entered into separate credit agreements (Project Credit Facilities), which are non-recourse to partially fundSouthern Power (other than the maturitysubsidiary 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 long-term debt in July 2015.
Detailscredit facility that is secured by the membership interests of short-term borrowings werethe respective project company, with proceeds directed to finance project costs related to the respective solar facilities. Each Project Credit Facility is secured by the assets of the applicable project subsidiary and membership interests of the applicable project subsidiary. The table below summarizes each Project Credit Facility as follows:of September 30, 2016.
|
| | | | | | | | | | | | | | | | | | |
| | | Commercial Paper at the End of the Period | | Commercial Paper During the Period(*) |
| | | Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) | | | | (in millions) |
| September 30, 2015: | | $ | 213 |
| | 0.5 | % | | $ | 281 |
| | 0.5 | % | | $ | 385 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Project | | Maturity Date | | Construction Loan Facility | | Bridge Loan Facility | | Total Loan Facility | | Loan Facility Undrawn | | Letter of Credit Facility | | Letter of Credit Facility Undrawn |
| | | | | (in millions) |
| Garland | | Earlier of PPA COD or November 30, 2016 | | $ | 86 |
| | $ | 308 |
| | $ | 394 |
| | $ | 21 |
| | $ | 49 |
| | $ | 23 |
|
| Roserock | | Earlier of PPA COD or November 30, 2016(*) | | 63 |
| | 180 |
| | 243 |
| | 34 |
| | 23 |
| | 16 |
|
| Tranquillity | | October 14, 2016 | | 86 |
| | 172 |
| | 258 |
| | 12 |
| | 77 |
| | 26 |
|
| Total | | | | $ | 235 |
| | $ | 660 |
| | $ | 895 |
| | $ | 67 |
| | $ | 149 |
| | $ | 65 |
|
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period endedSubsequent to September 30, 2015.2016, Roserock extended the maturity date of its Project Credit Facility to December 31, 2016. |
The Project Credit Facilities above had total amounts outstanding as of September 30, 2016 of $828 million at a weighted average interest rate of 2.05%. For the three-month period ended September 30, 2016, these credit agreements had a maximum amount outstanding of $828 million and an average amount outstanding of $805 million at a weighted average interest rate of 2.02%.
Furthermore, in connection with the acquisition of the Henrietta solar facility on July 1, 2016, a subsidiary of Southern Power assumed a $217 million construction loan, which was fully repaid prior to September 30, 2016. For the three-month period ended September 30, 2016, this credit agreement had a maximum amount outstanding of $217 million and an average amount outstanding of $137 million at a weighted average interest rate of 2.21%.
Southern Power believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility, bank term loans, and operating cash flows.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Power believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility, 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/or Baa2, or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, energy price risk management, transmission, and transmission.foreign currency risk management.
The maximum potential collateral requirements under these contracts at September 30, 20152016 were as follows:
| | | Credit Ratings | Maximum Potential
Collateral
Requirements | Maximum Potential
Collateral
Requirements |
| | (in millions) | (in millions) |
| At BBB and/or Baa2 | $ | 11 |
| $ | 30 |
|
| At BBB- and/or Baa3 | 334 |
| $ | 385 |
|
| Below BBB- and/or Baa3 | 1,077 |
| $ | 1,104 |
|
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, a credit rating downgrade could impact the ability of Southern Power to access capital markets and would be likely to impact the cost at which it does so.
In addition, Southern Power has a PPA that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power 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
In May 2015,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 are being allocated to renewable energy generation projects. Southern Power's obligations under its euro-denominated fixed-rate notes were effectively converted to fixed-rate U.S. dollars at issuance through cross-currency swaps, removing foreign currency exchange risk associated with the interest and principal payments. See Note (H) to the Condensed Financial Statements under "Foreign Currency Derivatives" herein for additional information.
In September 2016, Southern Power issued $290 million aggregate principal amount of Series 2016C 2.75% Senior Notes due September 20, 2023. The proceeds were used to repay a portion of its outstanding short-term indebtedness, for other general corporate purposes, including Southern Power's growth strategy and continuous construction program, as well as repayment of amounts outstanding under the Project Credit Facilities.
Also in September 2016, Southern Power repaid $80 million of an outstanding $400 million floating rate bank loan and for a portionextended the maturity date of the repayment at maturity of $525remaining $320 million from September 2016 to September 2018. In addition, Southern Power entered into a $60 million aggregate principal amount of Southern Power Company's 4.875% Senior Notes on July 15, 2015.
In August 2015, Southern Power Company entered into a $400 million aggregate principal amount 13-month floating rate bank loan bearing interest based on one-month LIBOR.LIBOR due September 2017. The proceeds were used to repay existing indebtedness and for working capital and other general corporate purposes, includingpurposes.
In addition, Southern Power's growth strategy and continuous construction program.Power issued $34 million in letters of credit during the nine months ended September 30, 2016.
During the nine months ended September 30, 2015,2016, Southern Power prepaid $2.6Power's subsidiaries incurred an additional $691 million of long-term debtshort-term borrowings pursuant to TRE.the Project Credit Facilities at a weighted average interest rate of 2.05%. Furthermore, in connection with the acquisition of the Henrietta solar facility, a subsidiary of Southern
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Power assumed a $217 million construction loan, which was fully repaid prior to September 30, 2016. In addition, Southern Power's subsidiaries issued $16 million in letters of credit.
Subsequent to September 30, 2015, RE Tranquillity LLC2016, Southern Power's subsidiaries borrowed approximately $37$5 million of construction loans pursuant to the TranquillityProject Credit AgreementFacilities at a floatingweighted average interest rate based on one-month LIBOR.of 2.03%. In addition, RE Tranquillity LLC issued $51on October 14, 2016, Southern Power repaid at maturity $246 million of letters of credit.Project Credit Facility debt.
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 September 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.
Southern Company's financial statements reflect its investments in its subsidiaries, including Southern Company Gas as a result of the Merger, on a consolidated basis. Southern Company Gas' results of operations and cash flows since July 1, 2016 and financial condition as of September 30, 2016 are reflected within Southern Company's consolidated amounts in these accompanying notes herein. Southern Company Gas continues to maintain reporting requirements as an SEC registrant and has filed its Quarterly Report on Form 10-Q with the SEC separately from this combined Form 10-Q. The equity method is used for entities in which Southern Company has significant influence but does not control, including Southern Company Gas' investment in Southern Natural Gas Company, L.L.C. (SNG), and for variable interest entities where Southern Company has an equity investment but is not the primary beneficiary. See Note (I) under "Southern Company– Merger with Southern Company Gas" and " – Investment in Southern Natural Gas" for additional information regarding the Merger and Southern Company Gas' investment in SNG, respectively.
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 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. The registrants2018, with early adoption
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
continue to evaluate the requirements of ASC 606.permitted. The ultimate impact ofregistrants are 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 the registrants' balance sheets.
On February 18, 2015,March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation(Topic 718): Improvements to Employee Share-Based Payment Accounting Standards Update (ASU) 2015-02, Amendments(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 Consolidation Analysis, which makes certain changes to bothexercise or vesting of stock compensation as income tax expense or benefit in the variable interest modelincome statement. Southern Company and the voting model, including changestraditional electric operating companies currently recognize any excess tax benefits and deficiencies related to the identificationexercise and vesting of variable interests, the variable interest entity characteristics for a limited partnership or similar entity, and the primary beneficiary determination. Thisstock compensation as additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2015. Southern Power continues to evaluate 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 and is effective for fiscal years beginning after December 15, 2015.2016. Early adoption is permitted and each registrant intendsSouthern Company and the traditional electric operating companies intend to adopt the ASU in the fourth quarter 2015.2016. The ASUadoption is requirednot expected to be applied retrospectively to all periods presented beginning in the year of adoption. 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 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 $108 million made by Georgia Power to PowerSecure under the two agreements since inception in 2014 are included in CWIP at September 30, 2016. PowerSecure construction service costs of approximately $0.2 million are included in accounts payable, affiliated in Georgia Power's balance sheet at September 30, 2016. On October 4, 2016, the two facilities began commercial operation.
Prior to Southern Company Gas' completion of its acquisition of a 50% equity interest in SNG, Southern Company and Southern Company Gas had entered into long-term interstate natural gas transportation agreements with SNG. The interstate transportation service provided to the traditional electric operating companies, Southern Power, and Southern Company Gas by SNG pursuant to these agreements is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. For the period subsequent to Southern Company Gas' investment in SNG, transportation costs paid to SNG by Southern Company were approximately $16 million, including $8 million for Georgia Power, $2 million for Southern Power, and $1 million for Alabama Power.
See Note (I) under "Southern Company– Acquisition of PowerSecure International, Inc." and " – Investment in Southern Natural Gas" for additional information regarding Southern Company's acquisition of PowerSecure and Southern Company Gas' investment in SNG, respectively.
Asset Retirement Obligations
See Note 1 to the financial statements of Southern Company, Alabama Power, Georgia Power, 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 Southern Company's and the traditional electric operating companies' asset retirement obligations (ARO) and 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, which became effective on October 19, 2015. Therefore, Alabama Power, Gulf Power, and Mississippi Power recorded new asset retirement obligations (ARO) for facilities that are subject See Note 1 to the CCR Rule. Georgiafinancial statements of Southern Power had previously recorded AROs as a result of state requirementsunder "Asset Retirement Obligations" in Georgia which closely align with the requirementsItem 8 of the CCR Rule.Form 10-K for additional information regarding Southern Power's AROs.
The cost estimates below are based on information as of September 30, 2015 using2016. The cost estimates for AROs related to the disposal of CCR are based on various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR RuleDisposal of Coal Combustion Residuals from Electric Utilities final rule requirements for closure in place.place or by other methods. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, the traditional electric operating companies expect to continue to periodically update these estimates.
As of September 30, 2015, details of the AROs, including those related to the CCR Rule, included in Southern Company's and the traditional operating companies' Condensed Balance Sheets herein were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power |
| | (in millions) |
| Balance at beginning of year | $ | 2,201 | | | $ | 829 | | | $ | 1,255 | | | $ | 17 | | | $ | 48 | |
| Liabilities incurred | 644 | | | 402 | | | — | | | 101 | | | 97 | |
| Liabilities settled | (19 | ) | | (1 | ) | | (18 | ) | | — | | | — | |
| Accretion | 83 | | | 38 | | | 42 | | | 1 | | | 2 | |
| Cash flow revisions | 214 | | | 20 | | | 193 | | | 3 | | | 25 | |
| Balance at end of period | $ | 3,123 | | | $ | 1,288 | | | $ | 1,472 | | | $ | 122 | | | $ | 172 | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
As of September 30, 2016, details of the AROs included in the registrants' Condensed Balance Sheets were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power | | Southern Power |
| | (in millions) |
| Balance at beginning of year | $ | 3,759 |
| | $ | 1,448 |
| | $ | 1,916 |
| | $ | 130 |
| | $ | 177 |
| | $ | 21 |
|
| Liabilities incurred | 41 |
| | 5 |
| | — |
| | — |
| | 15 |
| | 18 |
|
| Liabilities settled | (117 | ) | | (12 | ) | | (93 | ) | | — |
| | (12 | ) | | — |
|
| Accretion | 119 |
| | 55 |
| | 56 |
| | 2 |
| | 3 |
| | 1 |
|
| Cash flow revisions | 712 |
| | 31 |
| | 675 |
| | 2 |
| | 7 |
| | — |
|
| Balance at end of period | $ | 4,514 |
| | $ | 1,527 |
| | $ | 2,554 |
| | $ | 134 |
| | $ | 190 |
| | $ | 40 |
|
The traditional electric operating companies' increases in liabilities incurred and cash flow revisions for the nine months ended September 30, 20152016 primarily relate to anchanges in ash pond closure strategy. The increase for Georgia Power reflects its decision in AROsJune 2016 to cease operating and stop receiving coal ash at all of its ash ponds within the next three years and to eventually close all of its ash ponds either by removal, consolidation, and/or recycling for the beneficial use of coal ash or through closure in place using advanced engineering methods.
Goodwill and Other Intangible Assets
As of September 30, 2016, goodwill was as follows: |
| | | |
| | As of September 30, 2016 |
| | (in millions) |
| Southern Company | $ | 6,223 |
|
| Southern Power | $ | 2 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
As of September 30, 2016, other intangible assets were as follows:
|
| | | | | | | | | | |
| | | As of September 30, 2016 |
| | Estimated Useful Life | Gross Carrying Amount | Accumulated Amortization | Other Intangible Assets, Net |
| | | (in millions) |
| Southern Company | | | | |
| Other intangible assets subject to amortization: | | | | |
| Customer relationships | 11-26 years | $ | 268 |
| $ | (16 | ) | $ | 252 |
|
| Trade names | 5-28 years | 158 |
| (3 | ) | 155 |
|
| Patents | 3-10 years | 4 |
| — |
| 4 |
|
| Backlog | 5 years | 5 |
| — |
| 5 |
|
| Storage and transportation contracts | 1-5 years | 64 |
| (4 | ) | 60 |
|
| Software and other | 1-12 years | 2 |
| — |
| 2 |
|
| PPA fair value adjustments | 19-20 years | 405 |
| (16 | ) | 389 |
|
| Total other intangible assets subject to amortization | | $ | 906 |
| $ | (39 | ) | $ | 867 |
|
| Other intangible assets not subject to amortization: | | | | |
| Federal Communications Commission licenses | | $ | 75 |
| $ | — |
| $ | 75 |
|
| Total other intangible assets | | $ | 981 |
| $ | (39 | ) | $ | 942 |
|
| | | | | |
| Southern Power | | | | |
| Other intangible assets subject to amortization: | | | | |
| PPA fair value adjustments | 19-20 years | $ | 405 |
| $ | (16 | ) | $ | 389 |
|
Amortization associated with facilities impacted by the CCR Rule.other intangible assets was as follows:
|
| | | | | | |
| | Three Months Ended | Nine Months Ended |
| | September 30, 2016 |
| | (in millions) |
| Southern Company | $ | 25 |
| $ | 27 |
|
| Southern Power | $ | 2 |
| $ | 4 |
|
At December 31, 2015, other intangible assets consisted primarily of Southern Power's PPA fair value adjustments with permitting activitya net carrying amount of $317 million. The increases in the third quarter 2015 relatedgoodwill and other intangible assets primarily relate to Southern Company's acquisitions of PowerSecure on May 9, 2016 and Southern Company Gas on July 1, 2016.
See Note 12 to the coal ash pondfinancial 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. Also see Note (I) under "Southern Company– Acquisition of PowerSecure International, Inc." and " –Merger with Southern Company Gas" for additional information.
Natural Gas for Sale
Southern Company Gas' natural gas distribution utilities, with the exception of Nicor Gas, carry natural gas inventory on a weighted average cost of gas (WACOG) basis.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Nicor Gas' natural gas inventory is carried at cost on a last-in, first-out (LIFO) basis. Inventory decrements occurring during the year that are restored prior to year-end are charged to cost of natural gas at the retired Plant Scholz facility, Gulf Powerestimated annual replacement cost. Inventory decrements that are not restored prior to year-end are charged to cost of natural gas at the actual LIFO cost of the layers liquidated. The cost of natural gas, including inventory costs, is recovered from customers under a purchased gas recovery mechanism adjusted for differences between actual costs and amounts billed; therefore, LIFO liquidations have no impact on Southern Company's net income.
Southern Company Gas' other natural gas inventories are carried at the lower of weighted average cost or current market price, with cost determined on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded additional AROsto reduce the value of $30 million.natural gas inventories to market value.
| |
| (B) | CONTINGENCIES AND REGULATORY MATTERS |
See Note 3 to the financial statements of the registrants in Item 8 of the Form 10-K for information relating to various lawsuits, other contingencies, and regulatory matters.
General Litigation Matters
Nicor Gas and Nicor Energy Services Company, wholly-owned subsidiaries of Southern Company Gas, and Nicor Inc. are defendants in a putative class action initially filed in September 2011 in state court in Cook County, Illinois. The plaintiffs purport to represent a class of the customers who purchased the Gas Line Comfort Guard product from Nicor Energy Services Company and variously allege that the marketing, sale, and billing of the Gas Line Comfort Guard product violated the Illinois Consumer Fraud and Deceptive Business Practices Act, constituting common law fraud and resulting in unjust enrichment of these entities. The plaintiffs seek, on behalf of the classes they purport to represent, actual and punitive damages, interest, costs, attorney fees, and injunctive relief. On October 26, 2016, the court held a hearing on the plaintiffs' motion for class certification and the defendants' motion for summary judgment on all of the plaintiffs' claims. The ultimate outcome of this matter cannot be determined at this time.
Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In addition, business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation against each registrant and any subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of each registrant in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such registrant's financial statements.
AGL Resources Merger Litigation
AGL Resources and each member of the AGL Resources board of directors have been named as defendants in four purported shareholder class action lawsuits filed in the United States District Court for the Northern District of Georgia in September and October 2015. These actions were filed on behalf of named plaintiffs and other AGL Resources shareholders challenging the Merger and seeking, among other things, preliminary and permanent injunctive relief enjoining the Merger, and, in certain circumstances, damages. Southern Company and Merger Sub were also named as defendants in two of these lawsuits. Southern Company intends to vigorously defend these suits. Southern Company does not believe these suits will impact the completion of the Merger, and they are not expected to have a material impact on Southern Company's financial statements. However, the ultimate outcome of these matters cannot be determined at this time. See Note (I) under "Southern Company – Proposed Merger with AGL Resources" herein for additional information regarding the Merger.
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. 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. On August 24, 2015, the U.S. District Court for the Northern District of Alabama entered an order approving the joint stipulation among Alabama Power, the EPA, and the U.S. Department of Justice modifying the 2006 consent decree to resolve all remaining claims in the case against Alabama Power. Under the modified consent decree, Alabama Power will, without admitting liability, operate certain units subject to emission rates and an annual emissions cap; use only
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
natural gas at certain other 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.
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, and Southern Company Gas' natural gas distribution utilities in Illinois, New Jersey, Georgia, and Florida, have each received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These ratesregulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs.PSCs or other applicable state regulatory agencies.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Georgia Power's environmental remediation liability as of September 30, 20152016 was $29$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 (CERCLA), including a site in Brunswick, Georgia on the CERCLA National Priorities List. The PRPs at the Brunswick site have completed a removal action as ordered by the EPA. On July 29, 2016, Honeywell International, Inc. and Georgia Power entered into a consent decree with the EPA to perform additional remediation at the site. Additional response actions at thisthe site are anticipated. In September 2015, Georgia Power entered into an allocation agreement with another PRP, under which that PRP will be responsible (as between Georgia Power and that PRP) for paying and performing certain investigation, assessment, remediation, and other incidental activities at the Brunswick site.site, including costs associated with implementation of the consent decree. Assessment and potential cleanup of other sites are anticipated.
Georgia PowerThe ultimate outcome of these matters will depend upon the success of defenses asserted, the ultimate number of PRPs participating in the cleanup, and numerous other entities have been designated by the EPA as PRPsfactors and cannot be determined 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 EPAthis time; however, 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. While the EPA has not withdrawn the UAO, Georgia Power believes it is unlikely that the EPA would pursue any claims against Georgia Power for this matter given the conclusion of this private action.
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 thePower's regulatory treatment for environmental remediation expenditures.expenses, these matters are not expected to have a material impact on Southern Company's or Georgia Power's financial statements.
Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $46 million as of September 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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Power's environmental remediation liability was $0.3 million as of September 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.
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. On March 19, 2015, Georgia Power recovered approximately $18 million, based on its ownership interests, and Alabama Power recovered approximately $26 million. 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. Alabama Power expects its portion of the damage amounts collected 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 statementsSouthern Company Gas' environmental remediation liability as of September 30, 2015 for any potential recoveries2016 was $433 million based on the estimated cost of environmental investigation and remediation associated with known current and former operating sites. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the additional lawsuits.
applicable state regulatory agencies of Southern Company Gas' natural gas distribution utilities, with the exception of one site representing $5 million of the total accrued remediation costs. The finalultimate outcome of these matters cannot be determined at this time; however, nothese matters are not expected to have a material impact on Southern Company's Alabama Power's, or Georgia Power's net incomefinancial statements.
In September 2015, the EPA filed an administrative complaint and notice of opportunity for hearing against Nicor Gas. The complaint alleges violation of the regulatory requirements applicable to polychlorinated biphenyls in the Nicor Gas natural gas distribution system and the EPA seeks a total civil penalty of approximately $0.3 million. The ultimate resolution of this matter cannot be determined at this time; however, the final disposition of this matter is expected.not expected to have a material impact on Southern Company's financial statements.
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.
Under a 2014 settlement agreement, an adjustment to Mississippi Power's wholesale revenue requirement was allowed in the event the Kemper IGCC, or any substantial portion thereof, was placed in service before or after December 1, 2014. Therefore,On March 31, 2016, Mississippi Power has recorded a regulatory asset as a result of a portion of the Kemper IGCC being placed in service prior to the projected date and is amortizing this regulatory asset over the nine months ending December 31, 2015.
On May 13, 2015, the FERC acceptedreached a settlement agreement between Mississippi Power andwith its wholesale customers to forgoand filed a request with the FERC for an increase in wholesale base revenues under the Municipal and Rural Associations (MRA) cost-based electric tariff, increase by, among other things, increasing the accrualprimarily as a result of AFUDCplacing scrubbers for Plant Daniel Units 1 and lowering the portion of CWIP2 in rate base, effective April 1, 2015. Theservice
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
in November 2015. 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. 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. The additional resulting AFUDC is estimated to be approximately $13$11 million annually, of which $10 million relates tothrough the Kemper IGCC.IGCC's projected in-service date of December 31, 2016.
Fuel Cost Recovery
Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor and a wholesale MRA emissions cost recovery factor. At September 30, 2015,2016, the amount of over-recovered wholesale MRA fuel costs included in the balance sheets was $14$17 million compared to $0.2$24 million at December 31, 2014. 2015. At September 30, 2016 and December 31, 2015, the amount of over-recovered wholesale MB fuel costs included in the balance sheets was $1 million. Effective with the first billing cycle for September 2016, fuel rates decreased $11 million annually for wholesale MRA customers and $1 million annually for wholesale MB customers.
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory"FERC Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.
Market-Based Rate Authority
The traditional electric operating companies and Southern Power have authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies and Southern Power filed a triennial market power analysis 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 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 | September 30, 2015 |
| December 31, 2014 |
|
|
| (in millions) |
Rate CNP Compliance* – Under |
| Deferred under recovered regulatory clause revenues | $ | — |
|
| $ | 2 |
|
| | | Under recovered regulatory clause revenues, current | 38 |
| | 47 |
|
| Rate CNP PPA – Under |
| Deferred under recovered regulatory clause revenues | 66 |
|
| 29 |
|
| | | Under recovered regulatory clause revenues, current | 30 |
| | 27 |
|
| Retail Energy Cost Recovery – Over |
| Deferred over recovered regulatory clause revenues | 128 |
|
| 47 |
|
| Natural Disaster Reserve |
| Other regulatory liabilities, deferred | 76 |
|
| 84 |
|
| |
* | Formerly Known As Rate CNP Environmental |
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" and of Alabama Power under "Retail Regulatory Matters – Rate CNP" and " – Non-Environmental Federal Mandated Costs Accounting Order" in
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Item 8 of the Form 10-K for additional information regarding Alabama Power's development of a revised cost recovery mechanism and the 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 $50 million of non-environmental compliance costs during the first nine 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.
On August 14, 2015, the FASB issued ASU 2015-13, allowing 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. The new accounting guidance will have no impact on Southern Company's or Alabama Power's financial statements. |
| | | | | | | |
| Regulatory Clause | Balance Sheet Line Item | September 30,
2016 | December 31, 2015 |
|
| (in millions) |
| Rate CNP Compliance | Under recovered regulatory clause revenues | $ | — |
| $ | 43 |
|
| | Deferred over recovered regulatory clause revenues | 23 |
| — |
|
| Rate CNP PPA | Under recovered regulatory clause revenues | 52 |
| 99 |
|
| | Deferred under recovered regulatory clause revenues | 87 |
| — |
|
| Retail Energy Cost Recovery | Other regulatory liabilities, current | — |
| 238 |
|
| Deferred over recovered regulatory clause revenues | 134 |
| — |
|
| Natural Disaster Reserve | Other regulatory liabilities, deferred | 71 |
| 75 |
|
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. On August 24, 2015, the U.S. District Court for the Northern District of Alabama entered an order approving the NSR joint stipulation. In accordance with the joint stipulation, Alabama Power retired Plant Barry Unit 3 (225 MWs)gas in June 2016 and it is no longer available 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, and recovered through Rate CNP. As a result, these decisions will not have a significant impact on Southern Company's or Alabama Power's financial statements.July 2016, respectively.
Georgia Power
Rate PlansPerformance Evaluation Plan
On April 1, 2016, Mississippi Power submitted its annual PEP lookback filing for 2015, which reflected the need for a $5 million surcharge to be recovered from customers. The filing has been suspended for review by the Mississippi PSC.
On July 12, 2016, Mississippi Power submitted its annual projected PEP filing for 2016 which indicated no change in rates. The filing has been suspended for review by the Mississippi PSC.
The ultimate outcome of these matters cannot be determined at this time.
Environmental Compliance Overview Plan
On August 17, 2016, the Mississippi PSC approved Mississippi Power's revised ECO Plan filing for 2016, which requested the maximum 2% annual increase in revenues, approximately $18 million, primarily related to Plant Daniel Units 1 and 2 scrubbers being placed in service in November 2015. The revised rates became effective with the first billing cycle for September 2016. Approximately $22 million of related revenue requirements in excess of the 2% maximum was deferred for inclusion in the 2017 filing.
Fuel Cost Recovery
At September 30, 2016, the amount of over-recovered retail fuel costs included on the balance sheet was $58 million compared to $71 million at December 31, 2015.
The Mississippi PSC conditionally approved a decrease of $120 million annually in fuel cost recovery rates on January 5, 2016, effective with the first billing cycle for February 2016. On August 17, 2016, the Mississippi PSC approved an additional decrease of $51 million annually in fuel cost recovery rates effective with the first billing cycle for September 2016.
Integrated Coal Gasification Combined Cycle
See Note 3 to the financial statements of Southern Company and GeorgiaMississippi Power under "Retail "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding Mississippi Power's construction of the Kemper IGCC.
Kemper IGCC Overview
The Kemper IGCC will utilize 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.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Kemper IGCC Schedule and Cost Estimate
In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of Initial DOE Grants and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014 and continues to progress towards completing the remainder of the Kemper IGCC, including the gasifiers and the gas clean-up facilities. The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." On October 11, 2016, the Kemper IGCC began testing using clean syngas from gasifier "A" and the related gas clean-up systems to produce electricity. Late on October 31, 2016, gasifier "A" experienced challenges associated with the ash removal systems, and on November 2, 2016, Mississippi Power determined a maintenance outage on gasifier "A" is needed to make improvements to the ash removal systems. Therefore, Mississippi Power has re-sequenced activities, and gasifier "B" is now expected to progress through testing and begin producing electricity during the gasifier "A" outage. In light of these changes, Mississippi Power has determined that integrated operation of both gasifiers will not occur by mid-November and has revised the expected in-service date for the remainder of the Kemper IGCC to December 31, 2016. The remaining schedule reflects the time expected to achieve production of electricity using gasifier "B," complete gasifier "A" outage activities, and resume electricity production using gasifier "A," as well as to complete the integration of all systems necessary for both combustion turbines to simultaneously generate electricity with syngas.
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's decision discussed herein under "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order"), and actual costs incurred as of September 30, 2016 are as follows:
|
| | | | | | | | | | | |
| Cost Category | 2010 Project Estimate(a) | | Current Cost Estimate(b) | | Actual Costs |
| | (in billions) |
Plant Subject to Cost Cap(c)(e) | $ | 2.40 |
| | $ | 5.52 |
| | $ | 5.30 |
|
| Lignite Mine and Equipment | 0.21 |
| | 0.23 |
| | 0.23 |
|
CO2 Pipeline Facilities | 0.14 |
| | 0.11 |
| | 0.11 |
|
AFUDC(d) | 0.17 |
| | 0.75 |
| | 0.71 |
|
Combined Cycle and Related Assets Placed in
Service – Incremental(e) | — |
| | 0.04 |
| | 0.03 |
|
| General Exceptions | 0.05 |
| | 0.10 |
| | 0.09 |
|
Deferred Costs(e) | — |
| | 0.21 |
| | 0.20 |
|
| Additional DOE Grants | — |
| | (0.14 | ) | | (0.14 | ) |
| Total Kemper IGCC | $ | 2.97 |
| | $ | 6.82 |
| | $ | 6.53 |
|
| |
| (a) | The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities approved in 2011 by the Mississippi PSC, as well as the lignite mine and equipment, AFUDC, and general exceptions. |
| |
| (b) | Amounts in the Current Cost Estimate include certain estimated post-in-service costs which are expected to be subject to the cost cap. |
| |
| (c) | The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. The Current Cost Estimate and the Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap and exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" herein for additional information. The Current Cost Estimate and the Actual Costs reflect 100% of the costs of the Kemper IGCC. See note (e) for additional information. |
| |
| (d) | Mississippi Power's 2010 Project Estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC as described in "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order." The Current Cost Estimate also reflects the impact of a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. See "FERC Matters" herein for additional information. |
| |
| (e) | Non-capital Kemper IGCC-related costs incurred during construction were initially deferred as regulatory assets. Some of these costs are now included in rates and are being recognized through income; however, such costs continue to be included in the Current Cost Estimate and the Actual Costs at September 30, 2016. The wholesale portion of debt carrying costs, whether deferred or recognized through income, is not included in the Current Cost Estimate and the Actual Costs at September 30, 2016. See "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities" herein for additional information. |
Of the total costs, including post-in-service costs for the lignite mine, incurred as of September 30, 2016, $3.70 billion was included in property, plant, and equipment (which is net of the Initial DOE Grants, the Additional DOE Grants, and estimated probable losses of $2.63 billion), $6 million in other property and investments, $81 million in fossil fuel stock, $46 million in materials and supplies, $33 million in other regulatory assets, current, $177 million in other regulatory assets, deferred, $4 million in other current assets, and $9 million in other deferred charges and assets in the balance sheet.
Mississippi Power does not intend to seek rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate of $88 million ($54 million after tax) in the third quarter 2016 and a total of $222 million ($137 million after tax) for the nine months ended September 30, 2016. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.63 billion ($1.63 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through September 30, 2016. The increase to the cost estimate in the third quarter of 2016 primarily reflects $53 million for the extension of the Kemper IGCC's projected in-service date from October 31, 2016 to December 31, 2016 and
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
increased efforts related to operational readiness and challenges in start-up and commissioning activities, including the cost of repairs and modifications to gasifier "B" and mechanical improvements to coal feed and ash management systems, as well as certain post-in-service costs expected to be subject to the cost cap. The year-to-date increase to the cost estimate also includes $78 million for the extension of the Kemper IGCC's projected in-service date from August 31, 2016 to October 31, 2016. In addition, during the start-up and commissioning process, Mississippi Power is identifying potential improvement projects that ultimately may be completed subsequent to placing the remainder of the Kemper IGCC in service. If completed, such improvement projects would be expected to enhance plant performance, safety, and/or operations. The related potential costs have yet to be fully evaluated, have not been included in the current cost estimate, and may be subject to the $2.88 billion cost cap.
Any extension of the in-service date beyond December 31, 2016 is currently estimated to result in additional base costs of approximately $25 million to $35 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any extension of the in-service date with respect to the Kemper IGCC beyond December 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 $15 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees of approximately $3 million per month. For additional information, see "2015 Rate Case" herein.
Mississippi Power's analysis of the time needed to complete the start-up and commissioning activities for the Kemper IGCC will continue until the remaining Kemper IGCC assets are placed in service. The next steps for the facility include the testing and production of electricity using clean syngas from gasifier "B," as well as the generation of electricity using clean syngas from gasifier "A," which are scheduled to occur by the end of November. If integrated operation of both gasifiers does not occur by mid-December, the expected in-service date and related cost estimate for the Kemper IGCC likely would require further revision. Further cost increases and/or extensions of the expected in-service date may result from factors including, but not limited to, difficulties integrating the systems required for sustained operations, sustaining nitrogen supply, major equipment failure, unforeseen engineering or design problems including any repairs and/or modifications to systems, and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). Any further changes in the estimated costs of the Kemper IGCC subject to the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Mississippi Power's statements of income and these changes could be material.
Rate Recovery of Kemper IGCC Costs
See "FERC Matters" herein for additional information regarding Mississippi Power's MRA cost based tariff relating to 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
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
based upon assumptions in Mississippi Power's petition for the CPCN. Mississippi Power expects the Mississippi PSC to apply operational parameters in connection with future proceedings related to the operation of the Kemper IGCC. To the extent the Mississippi PSC determines the Kemper IGCC does not meet the operational parameters ultimately adopted by the Mississippi PSC or Mississippi Power incurs additional costs to satisfy such parameters, there could be a material adverse impact on Mississippi Power's financial statements. See "Prudence" herein for additional information.
2013 MPSC Rate Order
In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that was intended to establish the process for resolving matters regarding cost recovery related to the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. In March 2013, the Mississippi PSC issued a rate order approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designed to collect $156 million annually beginning in 2014 (2013 MPSC Rate Order) to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service, based on a mirror CWIP methodology (Mirror CWIP rate).
Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continues to record AFUDC on the Kemper IGCC. Through September 30, 2016, AFUDC recorded since the original May 2014 estimated in-service date for the Kemper IGCC has totaled $352 million. Mississippi Power has not recorded any AFUDC on Kemper IGCC costs in excess of the $2.88 billion cost cap, except for Cost Cap Exception amounts.
On February 12, 2015, the Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015 and required the fourth quarter 2015 refund of the $342 million collected under the 2013 MPSC Rate Order, along with associated carrying costs of $29 million. The Court's decision did not impact the 2012 MPSC CPCN Order or the February 2013 legislation described below.
2015 Rate Case
On August 13, 2015, the Mississippi PSC approved Mississippi Power's request for interim rates, which presented an alternative rate proposal (In-Service Asset Proposal) designed to recover Mississippi Power's costs associated with the Kemper IGCC assets that are commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The interim rates were designed to collect approximately $159 million annually and became effective with the first billing cycle for September 2015, subject to refund and certain other conditions.
On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order adopting in full the 2015 Stipulation entered into between Mississippi Power and the MPUS regarding the In-Service Asset Proposal. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The In-Service Asset Rate Order also included a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets. The stipulated revenue requirement excluded the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by SMEPA. Mississippi Power continues to evaluate its alternatives with respect to its investment and related costs associated with the 15% undivided interest.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
With implementation of the new rates on December 17, 2015, the interim rates were terminated and, in March 2016, Mississippi Power completed customer refunds of approximately $11 million for the difference between the interim rates collected and the permanent rates.
On July 27, 2016, the Court dismissed Greenleaf's motion for reconsideration of its previous decision to dismiss Greenleaf's appeal of the In-Service Asset Rate Order.
In addition to current estimated costs at September 30, 2016 of $6.82 billion, Mississippi Power anticipates that it will incur additional expenses in excess of current rates associated with operating the Kemper IGCC after it is placed in service until the Kemper IGCC cost recovery approach is finalized, which are expected to be material. These costs include, but are not limited to, regulatory costs, operational costs in excess of current rates, taxes, and additional carrying costs. Mississippi Power expects to request authority from the Mississippi PSC and the FERC to defer all Kemper IGCC costs incurred after the in-service date that cannot be capitalized, are not included in current rates, and are not required to be charged against earnings as a result of the $2.88 billion cost cap until such time as the Mississippi PSC completes its review and includes the resulting allowable costs in rates. Mississippi Power is required to file its next rate request with the Mississippi PSC related to cost recovery for the Kemper IGCC by June 3, 2017. See "Regulatory Assets and Liabilities" below for additional information. As part of that filing, Mississippi Power expects to request recovery of certain costs that the Mississippi PSC had excluded from the revenue requirement calculation for the in-service assets.
Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law in 2013. Mississippi Power expects to securitize prudently-incurred qualifying facility costs in excess of the certificated cost estimate of $2.4 billion. Qualifying facility costs include, but are not limited to, pre-construction costs, construction costs, regulatory costs, and accrued AFUDC. The Court's decision regarding the 2013 MPSC Rate Order did not impact Mississippi Power's ability to utilize alternate financing through securitization or the February 2013 legislation.
Prudence
On August 17, 2016, the Mississippi PSC issued an order establishing a discovery docket to manage all filings related to the prudence of the Kemper IGCC. On October 3, 2016, Mississippi Power made a required compliance filing, which included a review and explanation of differences between the Kemper IGCC project estimate set forth in the 2010 CPCN proceeding and the most recent Kemper IGCC project estimate, as well as comparisons of current cost estimates and current expected plant operational parameters to the estimates presented in the 2010 CPCN proceedings for the first five years following the start of commercial operations. Certain costs, including operations and maintenance, are materially higher than the amounts presented in the CPCN proceedings. Additionally, while the current estimated operational availability estimates reflect ultimate results similar to those presented in the 2010 CPCN proceedings, the ramp up period for the current estimates reflects a lower starting point and a slower escalation rate. Mississippi Power expects the Mississippi PSC to address these issues in connection with its next rate request.
Regulatory Matters – GeorgiaAssets and Liabilities
Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC issued an accounting order in 2011 granting Mississippi Power –the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date, subject to review of such costs by the Mississippi PSC. Such costs include, but are not limited to, carrying costs on Kemper IGCC assets currently placed in service, costs associated with Mississippi PSC and MPUS consultants, prudence costs, legal fees, and operating expenses associated with assets placed in service.
In August 2014, Mississippi Power requested confirmation by the Mississippi PSC of Mississippi Power's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
recovery mechanism proceedings. Beginning in the third quarter 2015 and the second quarter 2016, in connection with the implementation of retail and wholesale rates, respectively, Mississippi Power began expensing certain ongoing project costs and certain retail debt carrying costs (associated with assets placed in service and other non-CWIP accounts) that previously were deferred as regulatory assets and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees. The amortization periods for these regulatory assets vary from two years to 10 years as set forth in the In-Service Asset Rate Plans"Order and "Retail Regulatory Matters –the settlement agreement with wholesale customers. As of September 30, 2016, the balance associated with these regulatory assets was $105 million, of which $33 million is included in current assets. Other regulatory assets associated with the remainder of the Kemper IGCC totaled $105 million as of September 30, 2016. The amortization period for these assets is expected to be determined by the Mississippi PSC in future rate proceedings following completion of construction and start-up of the Kemper IGCC and related prudence reviews. See "FERC Matters" herein for information related to the 2016 settlement agreement with wholesale customers.
The In-Service Asset Rate Plans,Order requires Mississippi Power to submit an annual true-up calculation of its actual cost of capital, compared to the stipulated total cost of capital, with the first occurring as of May 31, 2016. At September 30, 2016, Mississippi Power's related regulatory liability included in its balance sheet totaled approximately $7 million. See "2015 Rate Case" respectively,herein for additional information.
See Note 1 to the financial statements of Mississippi Power under "Regulatory Assets and Liabilities" in Item 8 of the Form 10-K for additional information.
Lignite Mine and CO2 Pipeline Facilities
In accordanceconjunction 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 entered into agreements with Denbury Onshore (Denbury) and Treetop Midstream Services, LLC (Treetop), pursuant to which Denbury would purchase 70% of the CO2 captured from the Kemper IGCC and Treetop would purchase 30% of the CO2 captured from the Kemper IGCC. On June 3, 2016, Mississippi Power cancelled its contract with Treetop and amended its contract with Denbury to reflect, among other things, Denbury's agreement to purchase 100% of the CO2 captured from the Kemper IGCC, an initial contract term of 16 years, and termination rights if Mississippi Power has not satisfied its contractual obligation to deliver captured CO2 by July 1, 2017, in addition to Denbury's existing termination rights in the event of a change in law, force majeure, or an event of default by Mississippi Power. Any termination or material modification of the agreement with Denbury could impact the operations of the Kemper IGCC and result in a material reduction in Mississippi Power's revenues to the extent Mississippi Power is not able to enter into other similar contractual arrangements or otherwise sequester the CO2 produced. Additionally, sustained oil price reductions could result in significantly lower revenues than Mississippi Power 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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Litigation
On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. On August 12, 2016, Southern Company and Mississippi Power removed the case to the U.S. District Court for the Southern District of Mississippi, where the case is currently pending. However, the plaintiffs have filed a request to remand the case back to state court. 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. Southern Company, Mississippi Power, and SCS have moved to compel arbitration pursuant to the terms of the CO2 contract.
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.
Income Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Mississippi Power in Item 7 of the Form 10-K and Note (G) to the Condensed Financial Statements under "Section 174 Research and Experimental Deduction" herein for additional information.
Bonus Depreciation
The extension of 50% bonus depreciation included in the PATH Act is expected to result in approximately $400 million of positive cash flows for the 2016 tax year, which may not all be realized in 2016 due to a projected consolidated net operating loss for Southern Company. Approximately $370 million of the benefit is dependent upon placing the remainder of the Kemper IGCC in service by December 31, 2016, of which $250 million has been received as of September 30, 2016 through quarterly income tax refunds. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and Note (G) to the Condensed Financial Statements under "Current and Deferred Income Taxes – Net Operating Loss" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.
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
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation against Mississippi Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein or in Note 3 to the financial statements of Mississippi Power in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Mississippi Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
The SEC is conducting a formal investigation of Southern Company and Mississippi Power concerning the estimated costs and expected in-service date of the Kemper IGCC. Southern Company and Mississippi Power believe the investigation is focused primarily on periods subsequent to 2010 and on accounting matters, disclosure controls and procedures, and internal controls over financial reporting associated with the Kemper IGCC. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" herein for additional information on the Kemper IGCC estimated construction costs and expected in-service date. The ultimate outcome of this matter cannot be determined at this time; however, it is not expected to have a material impact on the financial statements of Mississippi Power.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Mississippi Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Mississippi Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Mississippi Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Mississippi Power in Item 7 of the Form 10-K for a complete discussion of Mississippi Power's critical accounting policies and estimates related to Electric Utility Regulation, Asset Retirement Obligations, Contingent Obligations, Unbilled Revenues, Pension and Other Postretirement Benefits, and AFUDC.
Kemper IGCC Estimated Construction Costs, Project Completion Date, and Rate Recovery
During 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, Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $88 million ($54 million after tax) in the third quarter 2016, $81 million ($50 million after tax) in the second quarter 2016, $53 million ($33 million after tax) in the first quarter 2016, $183 million ($113 million after tax) in the fourth quarter 2015, $150 million ($93 million after tax) in the third quarter 2015, $23 million ($14 million after tax) in the second quarter 2015, $9 million ($6 million after tax) in the first quarter 2015, $70 million ($43 million after tax) in the fourth quarter 2014, $418 million ($258 million after tax) in the third quarter 2014, $380 million ($235 million after tax) in the first quarter 2014, $40 million ($25 million after tax) in the fourth quarter 2013, ARP,$150 million ($93 million after tax) in the third quarter 2013, $450 million ($278 million after tax) in the second quarter 2013, $462 million ($285 million after tax) in the first quarter 2013, and $78 million ($48 million after tax) in the fourth quarter 2012. In the aggregate, Mississippi Power has
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
incurred charges of $2.63 billion ($1.63 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through September 30, 2016.
Mississippi Power's revised cost estimate reflects an expected in-service date of December 31, 2016 and includes certain post-in-service costs which are expected to be subject to the cost cap. Mississippi Power has experienced, and may continue to experience, material changes in the cost estimate for the Kemper IGCC. Further cost increases and/or extensions of the expected in-service date may result from factors including, but not limited to, difficulties integrating the systems required for sustained operations, sustaining nitrogen supply, major equipment failure, unforeseen engineering or design problems including any repairs and/or modifications to systems, and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). In addition, during the start-up and commissioning process, Mississippi Power is also identifying potential improvement projects that ultimately may be completed subsequent to placing the remainder of the Kemper IGCC in service. If completed, such improvement projects would be expected to enhance plant performance, safety, and/or operations. The related potential costs have yet to be fully evaluated, have not been included in the current cost estimates, and may be subject to the $2.88 billion cost cap. In subsequent periods, any further changes in the estimated costs of the Kemper IGCC subject to the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Mississippi Power's statements of income and these changes could be material.
Any extension of the in-service date beyond December 31, 2016 is currently estimated to result in additional base costs of approximately $25 million to $35 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any extension of the in-service date with respect to the Kemper IGCC beyond December 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 $15 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees of approximately $3 million per month.
Given the significant judgment involved in estimating the future costs to complete construction and start-up, the project completion date, the ultimate rate recovery for the Kemper IGCC, and the potential impact on Mississippi Power's results of operations, Mississippi Power considers these items to be critical accounting estimates. See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Recently Issued Accounting Standards
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 accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. Mississippi Power is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on Mississippi Power's balance sheet.
On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation(Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions. Most significantly, entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. Mississippi Power currently recognizes any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15,
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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2016. Early adoption is permitted and Mississippi Power intends to adopt the ASU 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 Coal Gasification Combined Cycle" herein for additional information. Earnings for the nine months ended September 30, 2016 were negatively affected by revisions to the cost estimate for the Kemper IGCC.
Through September 30, 2016, Mississippi Power has incurred non-recoverable cash expenditures of $2.42 billion and is expected to incur approximately $0.21 billion in additional non-recoverable cash expenditures through completion of the construction and start-up of the Kemper IGCC, which includes certain post-in-service costs expected to be subject to the cost cap.
Mississippi Power's capital expenditures and debt maturities are expected to materially exceed operating cash flows through 2021. In addition to the Kemper IGCC, projected capital expenditures in that period include investments to maintain existing generation facilities, to add environmental modifications to existing generating units, to add or change fuel sources for certain existing units, and to expand and improve transmission and distribution facilities.
On January 28, 2016, Mississippi Power issued a promissory note for up to $275 million to Southern Company, which matures in December 2017, bearing interest based on one-month LIBOR. During the first nine months of 2016, Mississippi Power borrowed $100 million under this promissory note and an additional $100 million under a separate promissory note issued to Southern Company in November 2015. On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicate of financial institutions for an aggregate amount of $1.2 billion. Mississippi Power borrowed $900 million on March 8, 2016 under the term loan agreement and the remaining $300 million on October 2, 2015, Georgia7, 2016. Mississippi Power filedused the following tariff adjustmentsinitial proceeds to repay $900 million in maturing bank loans on March 8, 2016 and the remaining $300 million to repay at maturity Mississippi Power's Series 2011A 2.35% Senior Notes due October 15, 2016. On June 27, 2016, Mississippi Power received a capital contribution from Southern Company for $225 million, the proceeds of which were used to repay to Southern Company a portion of the existing promissory note issued in November 2015. As of September 30, 2016, the amount of outstanding promissory notes to Southern Company totaled $551 million.
As of September 30, 2016, Mississippi Power's current liabilities exceeded current assets by approximately $411 million primarily due to the $300 million in senior notes which matured on October 15, 2016, as well as $65 million in short-term debt.
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 the remainder of its short-term capital needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $372 million for the first nine months of 2016, an increase of $23 million as compared to the corresponding period in 2015. The increase in cash provided from operating activities is primarily due to income taxes receivable associated with research and experimental (R&E) deductions and accrued taxes, partially offset by lower R&E tax deductions, the cessation of Mirror CWIP collections and subsequent refund payments, and higher recovery of regulatory fuel clause revenues. See Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" and "Unrecognized Tax Benefits – Section 174 Research and Experimental Deduction" herein for additional information. Net cash used for investing activities totaled $509 million for the first nine months of 2016 primarily due to gross property additions related to the Kemper IGCC, partially offset by receipt of $137 million in Additional DOE Grants. Net cash provided from financing activities totaled $198 million for the first nine months
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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of 2016 primarily due to long-term debt issuances and capital contributions from Southern Company, partially offset by redemptions of long-term debt and a decrease in short-term borrowings. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first nine months of 2016 include an increase in long-term debt of $826 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 and a $475 million decrease in notes payable. Additionally, CWIP increased $271 million primarily due to the Kemper IGCC and the customer liability associated with Kemper IGCC refunds decreased $72 million. Other significant changes include a $110 million increase in accrued income taxes due to bonus depreciation, a $61 million increase in accumulated deferred income taxes (ADIT) due to transmission and distribution property-related ADITs and additional Section 174 R&E deduction, partially offset by ADITs associated with the Georgia PSC to become effective January 1, 2016 pending its approval:
estimated losses on the Kemper IGCC construction, and a $39 million increase in traditional base tariffsprepaid income taxes. Total common stockholder's equity increased $269 million primarily due to the receipt of capital contributions from Southern Company and net income for the 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 $300 million will be required through September 30, 2017 to fund maturities of long-term debt, and $25 million will be required to fund maturities of short-term debt. See "Sources of Capital" herein for additional information. Subsequent to September 30, 2016, Mississippi Power repaid at maturity $300 million aggregate principal amount of its Series 2011A 2.35% Senior Notes due October 15, 2016. If the Kemper IGCC does not go into service by December 31, 2016, Mississippi Power also would have to repay approximately $49 million;$250 million of tax benefits received as a result of quarterly income tax estimates through September 30, 2016. See "Income Tax Matters" herein for additional information.
The construction program of Mississippi Power is currently estimated to be $0.8 billion for 2016, net of the Additional DOE Grants, $0.3 billion for 2017, $0.2 billion for 2018, $0.2 billion for 2019, $0.3 billion for 2020, and $0.3 billion for 2021, which includes revised estimates for the Kemper IGCC, including post-in-service costs. The expenditures related to the construction and start-up of the Kemper IGCC are currently estimated to be $0.7 billion for 2016, net of the Additional DOE Grants, and $0.1 billion for 2017. These estimated expenditures do not include potential compliance costs that may arise from the EPA's final rules and guidelines or subsequently approved state plans that would limit CO2 emissions from existing, new, modified, or reconstructed fossil-fuel-fired electric generating units.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing 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 Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein for additional information and further risks related to the estimated schedule and costs and rate recovery for the Kemper IGCC.
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Sources of Capital
In December 2015, the Mississippi PSC approved the In-Service Asset Rate Order, which among other things, provided for retail rate recovery of an annual revenue requirement of approximately $126 million effective December 17, 2015. The amount, type, and timing of future financings will depend upon regulatory approval, prevailing market conditions, and other factors, which includes resolution of Kemper IGCC cost recovery. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" and – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" and " – 2015 Rate Case" of Mississippi Power in Item 7 of the Form 10-K for additional information. Also see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Bonus Depreciation" of Mississippi Power in Item 7 of the Form 10-K for additional information.
Mississippi Power received $245 million of Initial DOE Grants in prior years that were used for the construction of the Kemper IGCC. An additional $25 million of grants from the DOE is expected to be received for commercial operation of the Kemper IGCC. 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.
On January 28, 2016, Mississippi Power issued a promissory note for up to $275 million to Southern Company, which matures in December 2017, bearing interest based on one-month LIBOR. During the first nine months of 2016, Mississippi Power borrowed $100 million pursuant to the $275 million promissory note and an additional $100 million under a separate promissory note issued to Southern Company in November 2015. On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicate of financial institutions for an aggregate amount of $1.2 billion. Mississippi Power borrowed $900 million on March 8, 2016 under the term loan agreement and the remaining $300 million on October 7, 2016. Mississippi Power used the initial proceeds to repay $900 million in maturing bank loans on March 8, 2016 and the remaining $300 million to repay at maturity Mississippi Power's Series 2011A 2.35% Senior Notes due October 15, 2016. The term loan pursuant to this agreement matures on April 1, 2018 and bears interest based on one-month LIBOR. On June 27, 2016, Mississippi Power received a capital contribution from Southern Company for $225 million, the proceeds of which were used to repay to Southern Company a portion of the existing promissory note issued in November 2015. As of September 30, 2016, the amount of outstanding promissory notes to Southern Company totaled $551 million.
Mississippi Power intends to utilize operating cash flows and lines of credit (to the extent available) as well as loans and, under certain circumstances, equity contributions from Southern Company to fund Mississippi Power's short-term capital needs.
At September 30, 2016, Mississippi Power had approximately $159 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2016 were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Expires | | | | Executable Term Loans | | Due Within One Year |
| 2016 | | 2017 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out |
| (in millions) | | (in millions) | | (in millions) | | (in millions) |
| $ | 100 |
| | $ | 75 |
| | $ | 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 Credit Arrangements" herein for additional information.
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
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(including guarantee obligations) of Mississippi Power. Such cross default provisions to other indebtedness would trigger an event of default if Mississippi Power defaulted on indebtedness or guarantee obligations over a specific threshold. Such cross acceleration provisions to other indebtedness would trigger an event of default if Mississippi Power defaulted on indebtedness, the payment of which was then accelerated. Mississippi Power is in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowing.
Subject to applicable market conditions, Mississippi Power expects to seek to renew or replace its credit arrangements as needed, prior to expiration. In connection therewith, Mississippi Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the $150 million unused credit arrangements with banks is allocated to provide liquidity support to Mississippi 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 September 30, 2016 was approximately $40 million.
Details of short-term borrowings were as follows:
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| | | | | | | | | | | | | | | | |
| | | Short-term Debt at September 30, 2016 | | Short-term Debt During the Period(*) |
| | | Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) | | | | (in millions) |
| Short-term bank debt | | $ | 25 |
| | 2.2% | | $ | 25 |
| | 2.1% | | $ | 25 |
|
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 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 and/or Baa2 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, energy price risk management, and transmission. At September 30, 2016, the maximum potential collateral requirements under these contracts at a rating of BBB and/or Baa2 or BBB- and/or Baa3 was not material. The maximum potential collateral requirements at a rating below BBB- and/or Baa3 equaled approximately $259 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, a credit rating downgrade could impact the ability of Mississippi Power to access capital markets, and would be likely to impact the cost at which it does so.
On May 12, 2016, Fitch downgraded the senior unsecured long-term debt rating of Mississippi Power to BBB+ from A- and revised the ratings outlook from negative to stable.
Financing Activities
On January 28, 2016, Mississippi Power issued a promissory note for up to $275 million to Southern Company, which matures in December 2017, bearing interest based on one-month LIBOR. During the first nine months of 2016, Mississippi Power borrowed $100 million under this promissory note and an additional $100 million under a separate promissory note issued to Southern Company in November 2015. On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicate of financial institutions for an aggregate amount of
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
$1.2 billion. Mississippi Power borrowed $900 million on March 8, 2016 under the term loan agreement and the remaining $300 million on October 7, 2016. Mississippi Power used the initial proceeds to repay $900 million in maturing bank loans on March 8, 2016 and the remaining $300 million to repay at maturity Mississippi Power's Series 2011A 2.35% Senior Notes due October 15, 2016. The term loan pursuant to this agreement matures on April 1, 2018 and bears interest based on one-month LIBOR. On June 27, 2016, Mississippi Power received a capital contribution from Southern Company of $225 million, the proceeds of which were used to repay to Southern Company a portion of the promissory note issued in November 2015. As of September 30, 2016, the amount of outstanding promissory notes to Southern Company totaled $551 million.
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.
In September 2016, Mississippi Power entered into interest rate swaps to fix the variable interest rate on $900 million of the term loan entered into in March 2016.
SOUTHERN POWER COMPANY
AND SUBSIDIARY COMPANIES
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2016 | | 2015 | | 2016 | | 2015 |
| | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | |
| Wholesale revenues, non-affiliates | $ | 387 |
| | $ | 295 |
| | $ | 866 |
| | $ | 776 |
|
| Wholesale revenues, affiliates | 110 |
| | 104 |
| | 313 |
| | 303 |
|
| Other revenues | 3 |
| | 2 |
| | 10 |
| | 7 |
|
| Total operating revenues | 500 |
| | 401 |
| | 1,189 |
| | 1,086 |
|
| Operating Expenses: | | | | | | | |
| Fuel | 154 |
| | 118 |
| | 341 |
| | 361 |
|
| Purchased power, non-affiliates | 25 |
| | 17 |
| | 60 |
| | 52 |
|
| Purchased power, affiliates | 8 |
| | 5 |
| | 16 |
| | 18 |
|
| Other operations and maintenance | 81 |
| | 62 |
| | 246 |
| | 184 |
|
| Depreciation and amortization | 93 |
| | 64 |
| | 247 |
| | 183 |
|
| Taxes other than income taxes | 5 |
| | 6 |
| | 17 |
| | 17 |
|
| Total operating expenses | 366 |
|
| 272 |
| | 927 |
| | 815 |
|
| Operating Income | 134 |
| | 129 |
| | 262 |
| | 271 |
|
| Other Income and (Expense): | | | | | | | |
| Interest expense, net of amounts capitalized | (35 | ) | | (18 | ) | | (78 | ) | | (62 | ) |
| Other income (expense), net | 2 |
| | 1 |
| | 3 |
| | 1 |
|
| Total other income and (expense) | (33 | ) | | (17 | ) | | (75 | ) | | (61 | ) |
| Earnings Before Income Taxes | 101 |
| | 112 |
| | 187 |
| | 210 |
|
| Income taxes (benefit) | (102 | ) | | 1 |
| | (167 | ) | | 14 |
|
| Net Income | 203 |
| | 111 |
| | 354 |
| | 196 |
|
| Less: Net income attributable to noncontrolling interests | 27 |
| | 9 |
| | 39 |
| | 15 |
|
| Net Income Attributable to Southern Power | $ | 176 |
| | $ | 102 |
| | $ | 315 |
| | $ | 181 |
|
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2016 | | 2015 | | 2016 | | 2015 |
| | (in millions) | | (in millions) |
| Net Income | $ | 203 |
| | $ | 111 |
| | $ | 354 |
| | $ | 196 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
| Changes in fair value, net of tax of $14, $-, $(1), and $-, respectively | 23 |
| | — |
| | (1 | ) | | — |
|
Reclassification adjustment for amounts included in net
income, net of tax of $(1), $-, $7, and $-, respectively | (1 | ) | | — |
| | 13 |
| | — |
|
| Total other comprehensive income (loss) | 22 |
| | — |
| | 12 |
| | — |
|
| Less: Comprehensive income attributable to noncontrolling interests | 27 |
| | 9 |
| | 39 |
| | 15 |
|
| Comprehensive Income Attributable to Southern Power | $ | 198 |
| | $ | 102 |
| | $ | 327 |
| | $ | 181 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
|
| | | | | | | |
| | For the Nine Months Ended September 30, |
| | 2016 | | 2015 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 354 |
| | $ | 196 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 262 |
| | 187 |
|
| Deferred income taxes | (668 | ) | | 222 |
|
| Investment tax credits | — |
| | 294 |
|
| Amortization of investment tax credits | (25 | ) | | (14 | ) |
| Deferred revenues | 9 |
| | 15 |
|
| Collateral deposits | (80 | ) | | — |
|
| Accrued income taxes, non-current | — |
| | 100 |
|
| Other, net | 10 |
| | 10 |
|
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (82 | ) | | (28 | ) |
| -Prepaid income taxes | (16 | ) | | (116 | ) |
| -Other current assets | 1 |
| | 1 |
|
| -Accounts payable | 7 |
| | 1 |
|
| -Accrued taxes | 483 |
| | (247 | ) |
| -Other current liabilities | 14 |
| | (12 | ) |
| Net cash provided from operating activities | 269 |
| | 609 |
|
| Investing Activities: | | | |
| Business acquisitions | (1,134 | ) | | (1,128 | ) |
| Property additions | (1,702 | ) | | (348 | ) |
| Change in construction payables | (69 | ) | | 88 |
|
| Payments pursuant to long-term service agreements | (58 | ) | | (65 | ) |
| Investment in restricted cash | (750 | ) | | — |
|
| Distribution of restricted cash | 746 |
| | — |
|
| Other investing activities | (41 | ) | | (1 | ) |
| Net cash used for investing activities | (3,008 | ) | | (1,454 | ) |
| Financing Activities: | | | |
| Increase in notes payable, net | 692 |
| | 18 |
|
| Proceeds — | | | |
| Senior notes | 1,531 |
| | 650 |
|
| Capital contributions | 800 |
| | 226 |
|
| Other long-term debt | 63 |
| | 400 |
|
| Redemptions — | | | |
| Senior notes | — |
| | (525 | ) |
| Other long-term debt | (84 | ) | | (3 | ) |
| Distributions to noncontrolling interests | (22 | ) | | (6 | ) |
| Capital contributions from noncontrolling interests | 367 |
| | 274 |
|
| Purchase of membership interests from noncontrolling interests | (129 | ) | | — |
|
| Payment of common stock dividends | (204 | ) | | (98 | ) |
| Other financing activities | (14 | ) | | (5 | ) |
| Net cash provided from financing activities | 3,000 |
| | 931 |
|
| Net Change in Cash and Cash Equivalents | 261 |
| | 86 |
|
| Cash and Cash Equivalents at Beginning of Period | 830 |
| | 75 |
|
| Cash and Cash Equivalents at End of Period | $ | 1,091 |
| | $ | 161 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
| Interest (net of $32 and $4 capitalized for 2016 and 2015, respectively) | $ | 49 |
| | $ | 69 |
|
| Income taxes, net | 71 |
| | (215 | ) |
| Noncash transactions — Accrued property additions at end of period | 210 |
| | 120 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At September 30, 2016 | | At December 31, 2015 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 1,091 |
| | $ | 830 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 121 |
| | 75 |
|
| Other accounts receivable | | 25 |
| | 19 |
|
| Affiliated | | 67 |
| | 30 |
|
| Fossil fuel stock | | 14 |
| | 16 |
|
| Materials and supplies | | 163 |
| | 63 |
|
| Prepaid income taxes | | 61 |
| | 45 |
|
| Other current assets | | 32 |
| | 30 |
|
| Total current assets | | 1,574 |
| | 1,108 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 9,491 |
| | 7,275 |
|
| Less accumulated provision for depreciation | | 1,465 |
| | 1,248 |
|
| Plant in service, net of depreciation | | 8,026 |
| | 6,027 |
|
| Construction work in progress | | 1,652 |
| | 1,137 |
|
| Total property, plant, and equipment | | 9,678 |
| | 7,164 |
|
| Other Property and Investments: | | | | |
| Goodwill | | 2 |
| | 2 |
|
Other intangible assets, net of amortization of $16 and $12
at September 30, 2016 and December 31, 2015, respectively | | 389 |
| | 317 |
|
| Total other property and investments | | 391 |
| | 319 |
|
| Deferred Charges and Other Assets: | | | | |
| Prepaid long-term service agreements | | 151 |
| | 166 |
|
| Accumulated deferred income taxes | | 199 |
| | — |
|
| Other deferred charges and assets — affiliated | | 3 |
| | 9 |
|
| Other deferred charges and assets — non-affiliated | | 355 |
| | 139 |
|
| Total deferred charges and other assets | | 708 |
| | 314 |
|
| Total Assets | | $ | 12,351 |
| | $ | 8,905 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholders' Equity | | At September 30, 2016 | | At December 31, 2015 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 60 |
| | $ | 403 |
|
| Notes payable | | 828 |
| | 137 |
|
| Accounts payable — | | | | |
| Affiliated | | 91 |
| | 66 |
|
| Other | | 218 |
| | 327 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 147 |
| | 198 |
|
| Other accrued taxes | | 16 |
| | 5 |
|
| Accrued interest | | 30 |
| | 23 |
|
| Contingent consideration | | 30 |
| | 36 |
|
| Other current liabilities | | 97 |
| | 44 |
|
| Total current liabilities | | 1,517 |
| | 1,239 |
|
| Long-term Debt | | 4,548 |
| | 2,719 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 140 |
| | 601 |
|
| Accumulated deferred investment tax credits | | 1,385 |
| | 889 |
|
| Accrued income taxes, non-current | | 109 |
| | 109 |
|
| Asset retirement obligations | | 40 |
| | 21 |
|
| Deferred capacity revenues — affiliated | | 19 |
| | 17 |
|
| Other deferred credits and liabilities | | 115 |
| | 3 |
|
| Total deferred credits and other liabilities | | 1,808 |
| | 1,640 |
|
| Total Liabilities | | 7,873 |
| | 5,598 |
|
| Redeemable Noncontrolling Interests | | 49 |
| | 43 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, par value $.01 per share — | | | | |
| Authorized — 1,000,000 shares | | | | |
| Outstanding — 1,000 shares | | — |
| | — |
|
| Paid-in capital | | 2,620 |
| | 1,822 |
|
| Retained earnings | | 769 |
| | 657 |
|
| Accumulated other comprehensive income (loss) | | 16 |
| | 4 |
|
| Total common stockholder's equity | | 3,405 |
| | 2,483 |
|
| Noncontrolling interests | | 1,024 |
| | 781 |
|
| Total stockholders' equity | | 4,429 |
| | 3,264 |
|
| Total Liabilities and Stockholders' Equity | | $ | 12,351 |
| | $ | 8,905 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRD QUARTER 2016 vs. THIRD QUARTER 2015
AND
YEAR-TO-DATE 2016 vs. YEAR-TO-DATE 2015
OVERVIEW
Southern Power constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Power continually seeks opportunities to execute its strategy to create value through various transactions including acquisitions and sales of assets, construction of new generating facilities, and entry into PPAs primarily with investor-owned utilities, independent power producers, municipalities, electric cooperatives, and other load-serving entities. In general, Southern Power has constructed or acquired new generating capacity only after entering into or assuming long-term PPAs for the new facilities.
During the nine months ended September 30, 2016, Southern Power acquired or commenced construction of approximately 758 MWs of additional solar and wind facilities and, subsequent to September 30, 2016, acquired or commenced construction of approximately 977 MWs of wind and natural gas facilities. In addition, Southern Power has committed to acquire approximately 674 MWs of solar and wind facilities over the next several months. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information.
At September 30, 2016, Southern Power had an average investment coverage ratio of 92% through 2020 and 91% 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
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $74 | | 72.5 | | $134 | | 74.0 |
Net income attributable to Southern Power for the third quarter 2016 was $176 million compared to $102 million for the corresponding period in 2015. Net income attributable to Southern Power for year-to-date 2016 was $315 million compared to $181 million for the corresponding period in 2015. The increases were primarily due to increased federal income tax benefits from solar ITCs and wind PTCs and increased renewable energy sales, partially offset by increases in depreciation, operations and maintenance expenses, and interest expense from debt issuances, all related to new solar and wind facilities.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Operating Revenues
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $99 | | 24.7 | | $103 | | 9.5 |
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.
Capacity revenues are an integral component of Southern Power's natural gas and biomass PPAs. Energy under these PPAs is generally sold at variable cost or is indexed to published gas indices. Energy revenues also include fees for support services, fuel storage, and unit start charges.
Southern Power's electricity sales from solar and wind generating facilities are also through long-term PPAs; however, these solar and wind PPAs do not have a capacity charge and customers purchase the energy output of a dedicated renewable facility through an energy charge. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, and other factors.
|
| | | | | | | | | | | |
| | Third Quarter 2016
vs.
Third Quarter 2015 | | Year-to-Date 2016
vs.
Year-to-Date 2015 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| PPA capacity revenues | $ | (19 | ) | | (11.8) | | $ | (25 | ) | | (5.8) |
| PPA energy revenues | 62 |
| | 33.3 | | 79 |
| | 17.5 |
| Total PPA revenues | 43 |
| | 11.8 | | 54 |
| | 6.1 |
| Revenues not covered by PPAs | 55 |
| | 121.9 | | 46 |
| | 23.4 |
| Other revenues | 1 |
| | 50.0 | | 3 |
| | 42.9 |
| Total operating revenues | $ | 99 |
| | 24.7% | | $ | 103 |
| | 9.5% |
In the third quarter 2016, operating revenues were $500 million compared to $401 million for the corresponding period in 2015. The $99 million increase in operating revenues was primarily due to the environmental compliance cost recovery tariff by approximately $75 million;following:
PPA capacity revenues decreased $19 million primarily due to the remarketing of generation capacity into the short-term markets as a result of PPA expirations.
PPA energy revenuesincreased $62 million primarily due to an increase in the demand-side management tariffsrenewable energy sales from new solar and wind facilities.
Revenues not covered by approximately $7 million; and
PPAs increased $55 million primarily due to an increase in short-term sales to non-affiliates as a result of the municipal franchise fee tariffremarketing of generation capacity from expired PPAs.
For year-to-date 2016, operating revenues were $1.2 billion compared to $1.1 billion for the corresponding period in 2015. The $103 million increase in operating revenues was primarily due to the following:
PPA capacity revenues decreased $25 million as a result of a $44 million decrease in non-affiliate capacity revenues primarily due to the remarketing of generation capacity into the short-term markets as a result of PPA expirations, partially offset by a $19 million increase in affiliate capacity revenues due to new PPAs.
PPA energy revenuesincreased $79 million primarily due to a $122 million increase in renewable energy sales arising from new solar and wind facilities, partially offset by a decrease of $43 million in fuel revenues related to natural gas facility PPAs.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Revenues not covered by PPAs increased $46 million due to a $70 million increase in short-term sales to non-affiliates as a result of the remarketing of generation capacity from expired PPAs, partially offset by a $24 million decrease in power pool revenue primarily associated with a reduction in available uncovered capacity.
Wholesale revenues will vary depending on the energy demand of Southern Power's customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Power's energy. Increases and decreases in revenues under PPAs that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.
Fuel and Purchased Power Expenses
Fuel costs constitute the single largest expense for Southern Power. In addition, Southern Power purchases a portion of its electricity needs from the wholesale market and the power pool. Details of Southern Power's generation and purchased power were as follows:
|
| | | | | |
| | Third Quarter 2016 | Third Quarter 2015 | | Year-to-Date 2016 | Year-to-Date 2015 |
| | (in billions of KWHs) |
| Generation | 11.1 | 9.4 | | 27.9 | 24.8 |
| Purchased power | 0.9 | 0.5 | | 2.5 | 1.5 |
| Total generation and purchased power | 12.0 | 9.9 | | 30.4 | 26.3 |
Total generation and purchased power excluding solar, wind, and tolling agreements | 6.7 | 5.2 | | 17.7 | 15.9 |
Southern Power's PPAs for natural gas and biomass generation generally provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing Southern Power for substantially all of the cost of fuel relating to the energy delivered under such PPAs. Consequently, changes in such fuel costs are generally accompanied by a corresponding change in related fuel revenues and do not have a significant impact on net income. Southern Power is responsible for the cost of fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the wholesale market or into the power pool, for capacity owned directly by Southern Power (excluding its subsidiaries).
Purchased power expenses will vary depending on demand, availability, and the cost of generating resources throughout the Southern Company system and other contract resources. Load requirements are submitted to the power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power, an affiliate company, or external parties.
|
| | | | | | | | | | | | |
| | | Third Quarter 2016
vs.
Third Quarter 2015 | | Year-to-Date 2016
vs.
Year-to-Date 2015 |
| | | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | | $ | 36 |
| | 30.5 | | $ | (20 | ) | | (5.5) |
| Purchased power | | 11 |
| | 50.0 | | 6 |
| | 8.6 |
| Total fuel and purchased power expenses | | $ | 47 |
| | | | $ | (14 | ) | | |
In the third quarter 2016, total fuel and purchased power expenses were $187 million compared to $140 million for the corresponding period in 2015. The increase was primarily due to the following:
Fuel expense increased $36 million primarily due to a $27 million increase associated with the volume of KWHs generated and a $9 million increase associated with average cost of natural gas per KWH generated.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Purchased power expense increased $11 million due to a $19 million increase associated with the volume of KWHs purchased, partially offset by a $4 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 $417 million compared to $431 million for the corresponding period in 2015. The decrease was primarily due to the following:
Fuel expense decreased $20 million primarily due to a $42 million decrease associated with the average cost of natural gas per KWH generated, partially offset by a $22 million increase associated with the volume of KWHs generated.
Purchased power expense increased $6 million due to a $48 million increase associated with the volume of KWHs purchased, largely offset by a $30 million decrease in the average cost of purchased power and a $12 million decrease associated with a PPA expiration.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $19 | | 30.6 | | $62 | | 33.7 |
In the third quarter 2016, other operations and maintenance expenses were $81 million compared to $62 million for the corresponding period in 2015. The increase was primarily due to a $9 million increase in expenses associated with new solar and wind facilities placed in service in 2015 and 2016, a $5 million increase associated with scheduled outage and maintenance expenses, and a $3 million increase in general business expenses associated with Southern Power's overall growth strategy.
For year-to-date 2016, other operations and maintenance expenses were $246 million compared to $184 million for the corresponding period in 2015. The increase was primarily due to a $24 million increase associated with scheduled outage and maintenance expenses, a $22 million increase in expenses associated with new solar and wind facilities placed in service in 2015 and 2016, and a $14 million increase in general business expenses associated with Southern Power's overall growth strategy.
Depreciation and Amortization
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $29 | | 45.3 | | $64 | | 35.0 |
In the third quarter 2016, depreciation and amortization was $93 million compared to $64 million for the corresponding period in 2015. For year-to-date 2016, depreciation and amortization was $247 million compared to $183 million for the corresponding period in 2015. The increases were primarily due to additional depreciation related to new solar and wind facilities placed in service in 2015 and 2016.
Interest Expense, net of Amounts Capitalized
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $17 | | 94.4 | | $16 | | 25.8 |
In the third quarter 2016, interest expense, net of amounts capitalized was $35 million compared to $18 million for the corresponding period in 2015. The increase was primarily due to an increase of $25 million in interest expense related to additional debt issued since the third quarter of 2015 primarily to fund Southern Power's growth strategy and continuous construction program, partially offset by an $8 million increase in capitalized interest associated
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
with the construction of solar facilities.
For year-to-date 2016, interest expense, net of amounts capitalized was $78 million compared to $62 million for the corresponding period in 2015. The increase was primarily due to an increase of $43 million in interest expense related to additional debt issued since the third quarter of 2015 primarily to fund Southern Power's growth strategy and continuous construction program, largely offset by a $27 million increase in capitalized interest associated with the construction of solar facilities.
Income Taxes (Benefit)
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(103) | | N/M | | $(181) | | N/M |
N/M - Not meaningful
In the third quarter 2016, income tax benefit was $(102) million compared to an expense of $1 million for the corresponding period in 2015. The change was primarily due to a $96 million increase in federal income tax benefits from solar ITCs and wind PTCs in 2016 and a $10 million decrease in tax expense related to lower pre-tax earnings in 2016, partially offset by a $3 million increase in tax expense related to beneficial state apportionment rate changes in 2015.
For year-to-date 2016, income tax benefit was $(167) million compared to an expense of $14 million for the corresponding period in 2015. The change was primarily due to a $171 million increase in federal income tax benefits from solar ITCs and wind PTCs in 2016 and a $17 million decrease in tax expense related to lower pre-tax earnings in 2016, partially offset by a $7 million increase in tax expense related to beneficial state apportionment rate changes in 2015.
See Note (G) to the Condensed Financial Statements herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern Power's future earnings potential. The level of Southern Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Power's competitive wholesale business. These factors include: Southern Power's ability to achieve sales growth while containing costs; regulatory matters; creditworthiness of customers; total generating capacity available in Southern Power's market areas; the successful remarketing of capacity as current contracts expire; Southern Power's ability to execute its growth strategy, including successful additional investments in renewable and other energy projects, and to construct generating facilities; and the impact of federal 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 generation from units within the power pool, and operational limitations. For additional information relating to these factors, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Power in Item 7 of the Form 10-K.
Power Sales Agreements
See BUSINESS – "The Southern Company System – Southern Power" in Item 1 of the Form 10-K for additional information regarding Southern Power's PPAs. Generally, under the solar and wind generation PPAs, the purchasing party retains the right to keep or resell the renewable energy credits.
At 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% through 2020 and 70% through 2025, with an average remaining contract duration of approximately $1310 years.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Power believes an investment coverage ratio best identifies the value 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 September 30, 2016, the average investment coverage ratio was 92% through 2020 and 91% through 2025, with an average remaining contract duration of approximately 17 years. At December 31, 2015, the average investment coverage ratio would have been 91% through 2020 and 90% through 2025, with an average remaining contract duration of approximately 18 years.
Environmental Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Power in Item 7 of the Form 10-K for information on the development by federal and state environmental regulatory agencies of additional control strategies for emissions of air pollution from industrial sources, including electric generating facilities. Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, water quality, or other environmental and health concerns could also significantly affect Southern Power. While Southern Power's PPAs generally contain provisions that permit charging the counterparty with some of the new costs incurred as a result of changes in environmental laws and regulations, the full impact of any such legislative or regulatory changes cannot be determined at this time.
Environmental Statutes and Regulations
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 of the Form 10-K for additional information regarding the EPA's Cross State Air Pollution Rule (CSAPR).
On October 26, 2016, the EPA published a final rule that updates the CSAPR ozone season nitrogen oxide program, including revising ozone-season emissions budgets in Alabama and Texas and removing Florida and North Carolina from the CSAPR program. The ultimate impact of this rule will depend on the outcome of any legal challenges and implementation at the state level and cannot be determined at this time.
Acquisitions
During 2016, in accordance with its overall growth strategy, Southern Power or one of its wholly-owned subsidiaries, Southern Renewable Partnerships, LLC and Southern Renewable Energy, Inc., acquired or contracted to acquire 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
|
| | | | | | | | |
| Project Facility | Resource | Approximate Nameplate Capacity (MW) | Location | Percentage Ownership | Actual/Expected COD | PPA Contract Period |
| Acquisitions During the Nine Months Ended September 30, 2016 |
| Calipatria | Solar | 20 | Imperial County, CA | 90 | % | | February 2016 | 20 years |
| East Pecos | Solar | 120 | Pecos County, TX | 100 | % | | December 2016 | 15 years |
| Grant Plains | Wind | 147 | Grant County, OK | 100 | % | | December 2016 | Up to 20 years |
| Grant Wind | Wind | 151 | Grant County, OK | 100 | % | | April 2016 | 20 years |
| Henrietta | Solar | 102 | Kings County, CA | 51 | % | (a) | July 2016 | 20 years |
| Lamesa | Solar | 102 | Dawson County, TX | 100 | % | | First quarter 2017 | 15 years |
| Passadumkeag | Wind | 42 | Penobscot County, ME | 100 | % | | July 2016 | 15 years |
| Rutherford | Solar | 74 | Rutherford County, NC | 90 | % | | December 2016 | 15 years |
| Acquisitions Subsequent to September 30, 2016 |
| Mankato | Natural Gas | 375 | Mankato, MN | 100 | % | | N/A(b) | 10 years |
| Wake Wind | Wind | 257 | Floyd and Crosby Counties, TX | 90.1 | % | | October 2016 | 12 years |
| |
| (a) | Southern Power owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. Southern Power and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the project. In addition, Southern Power is entitled to substantially all of the federal tax benefits with respect to the transaction. |
| |
| (b) | The Mankato facility is a fully operational 375-MW natural gas-fired combined-cycle facility with an additional 345-MW expansion under development. |
Acquisitions During the Nine Months Ended September 30, 2016
Southern Power's aggregate purchase price for the project facilities acquired during the nine months ended September 30, 2016 was approximately $830 million. Total aggregate construction costs, excluding the acquisition costs, are expected to be $708 million to $775 million for East Pecos, Grant Plains, Lamesa, and Rutherford, which are currently under construction. The ultimate outcome of these matters cannot be determined at this time.
Acquisitions Subsequent to September 30, 2016
Southern Power's aggregate purchase price for acquisitions subsequent to September 30, 2016 was approximately $873 million. As part of Southern Power's acquisition of Mankato, which has a fully operational 375-MW natural gas-fired combined-cycle facility, Southern Power has commenced construction of an additional 345-MW expansion which is covered with a 20-year PPA. Total aggregate construction costs, excluding the acquisition costs allocated to CWIP, are expected to be $170 million to $190 million. The ultimate outcome of this matter cannot be determined at this time.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Acquisition Agreements Executed but Not Yet Closed
During the nine months ended September 30, 2016 and subsequent to that date, Southern Power entered into agreements to acquire the following projects for an aggregate purchase price of approximately $1.2 billion:
51% ownership interest (through 100% ownership of the class A membership interests entitling Southern Power to 51% of all cash distributions and most of the federal tax benefits) in a 100-MW solar facility in Nevada covered with a 20-year PPA, which is expected to close in November 2016;
100% ownership interests in two wind facilities in Texas totaling 299 MWs, the majority of which is contracted under PPAs for the first 12 to 14 years of operation and are expected to close before the end of 2016; and
100% ownership interest in a 275-MW wind facility in Texas, the majority of which is contracted under a 12-year PPA and is expected to close in January 2017.
The ultimate outcome of these matters cannot be determined at this time.
The aggregate amount of revenue recognized by Southern Power related to the project facilities acquired during the nine months ended September 30, 2016 included in the condensed consolidated statements of income for year-to-date 2016 is $14 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 nine months ended September 30, 2016 included in the condensed consolidated statements 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
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" of Southern Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information.
During the nine months ended September 30, 2016, in accordance with its overall growth strategy, Southern Power completed construction of and placed in service, or continued construction of, the projects set forth in the following table. Through September 30, 2016, total costs of construction incurred for the following projects were $3.0 billion, of which $1.2 billion remains in CWIP. Including the total construction costs incurred through September 30, 2016 and the acquisition prices allocated to CWIP, total aggregate construction costs for the following projects are estimated to be $3.1 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
|
| | | | |
| Solar Facility | Approximate Nameplate Capacity (MW) | Location | Actual/Expected COD | PPA Contract Period |
| Projects Completed During the Nine Months Ended September 30, 2016 |
| Butler Solar Farm | 22 | Taylor County, GA | February 2016 | 20 years |
Desert Stateline(a) | 299(b) | San Bernardino County, CA | Through July 2016 | 20 years |
| Garland A | 20 | Kern County, CA | August 2016 | 20 years |
| Pawpaw | 30 | Taylor County, GA | March 2016 | 30 years |
| Tranquillity | 205 | Fresno County, CA | July 2016 | 18 years |
| Projects Under Construction as of September 30, 2016 |
| Butler | 103 | Taylor County, GA | December 2016 | 30 years |
| Garland | 185 | Kern County, CA | October 2016 | 15 years |
| Roserock | 160 | Pecos County, TX | November 2016 | 20 years |
| Sandhills | 146 | Taylor County, GA | October 2016 | 25 years |
| |
| (a) | On March 29, 2016, Southern Power acquired an additional 15% interest in Desert Stateline. As a result, Southern Power and the class B member are entitled to 66% and 34%, respectively, of all cash distributions from Desert Stateline. In addition, Southern Power will continue to be entitled to substantially all of the federal tax benefits with respect to the transaction. |
| |
| (b) | The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and 189 MWs were placed in service during the nine months ended September 30, 2016. |
Income Tax Matters
Bonus Depreciation
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Bonus Depreciation" of Southern Power in Item 7 of the Form 10-K for additional information.
The extension of 50% bonus depreciation included in the PATH Act is expected to result in approximately $650 million of positive cash flows for the 2016 tax year, which may not all be realized in 2016 due to a projected consolidated net operating loss (NOL) for Southern Company. As a result, the NOL will increase deferred tax assets for federal ITC and PTC carryforwards. See Note (G) to the Condensed Financial Statements under "Current and Deferred Income Taxes – Net Operating Loss" and " – Tax Credit Carryforwards" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.
Other Matters
Southern Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Power is subject to certain claims and legal actions arising in the ordinary course of business. Southern Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
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-Lived Assets and Intangibles, Acquisition Accounting, Depreciation, and ITCs.
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 accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. Southern 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 Southern Power's balance sheet.
FINANCIAL CONDITION AND LIQUIDITY
Overview
Southern Power's financial condition remained stable at September 30, 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 of Capital" herein for additional information on lines of credit.
Net cash provided from operating activities totaled $269 million for the first nine months of 2016 compared to $609 million for the first nine months of 2015. The decrease in net cash provided from operating activities was primarily due to an increase in unutilized ITCs and PTCs. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Bonus Depreciation" herein for additional information. Net cash used for investing activities totaled $3.0 billion for the first nine months of 2016 primarily due to acquisitions and the construction of renewable facilities. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information. Net cash provided from financing activities totaled $3.0 billion for the first nine months of 2016 primarily due to an increase in senior notes, notes payable, and capital contributions 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 nine months of 2016 include a $515 million increase in CWIP due to the acquisition and continued construction of new solar and wind facilities and a $2.2 billion increase in plant in service, primarily due to solar and wind facilities being placed in service. Other significant changes include a $261 million increase in cash and cash equivalents and a $2.5 billion increase in notes payable and long-term debt primarily due to additional borrowings to fund acquisitions and construction projects. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" 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
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
description of Southern Power's capital requirements for its construction program, scheduled maturities of long-term debt, as well as the related interest, leases, derivative obligations, unrecognized tax benefits, and other purchase commitments. Approximately $60 million will be required to repay maturities of long-term debt through September 30, 2017. In addition, during the nine months ended September 30, 2016, and subsequent to that date, Southern Power entered into new long-term service agreements (LTSA), which begin between 2017 and 2020 and result in additional future commitments totaling approximately $927 million.
Southern Power's construction program includes estimates for potential plant acquisitions, new construction, capital improvements, and work to be performed under LTSAs, and is subject to periodic review and revision. Planned expenditures for plant acquisitions may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. Capital expenditures for Southern Power are currently estimated to total approximately $4.5 billion for 2016, primarily for acquisitions and/or construction of new generating facilities. Capital expenditures for Southern Power are currently estimated to total approximately $1.6 billion annually for 2017 through 2021. Actual capital costs may vary from these estimates because of numerous factors such as: changes in business conditions; changes in the expected environmental compliance program; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in FERC rules and regulations; changes in load projections; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. See Note (I) to the Condensed Financial Statements herein for additional information.
Sources of Capital
Southern Power plans to obtain the funds required for acquisitions, construction, and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, securities issuances, term loans, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Power in Item 7 of the Form 10-K for additional information.
Southern Power's current liabilities sometimes exceed current assets due to the use of short-term debt as a funding source, and construction payables, as well as fluctuations in cash needs, due to both seasonality and the stage of acquisitions and construction projects. Southern Power expects to utilize the capital markets, bank term loans, and commercial paper markets as the source of funds for the majority of its debt maturities.
As of September 30, 2016, Southern Power had cash and cash equivalents of approximately $1.1 billion.
Details of short-term borrowings were as follows:
|
| | | | | | | | | | |
| | Short-term Debt During the Period (*) |
| | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | (in millions) | | | | (in millions) |
| Commercial paper | $ | 10 |
| | 0.9 | % | | $ | 62 |
|
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2016. No short-term debt was outstanding at September 30, 2016. |
Company Credit Facility
At September 30, 2016, Southern Power had a committed credit facility (Facility) of $600 million expiring in 2020, of which $68 million has been used for letters of credit and $532 million remains unused. Southern Power's subsidiaries are not borrowers under the Facility.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 capitalization excludes the capital stock or other equity attributable to such subsidiary. Southern Power is currently in compliance with all covenants in the Facility.
Proceeds from the Facility may be used for working capital and general corporate purposes as well as liquidity support for Southern Power's commercial paper program. Subject to applicable market conditions, Southern Power expects to renew or replace the Facility, as needed, prior to expiration. In connection therewith, Southern Power may extend the maturity date and/or increase or decrease the lending commitment thereunder. See Note 6 to the financial statements of Southern Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
Southern Power's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes, including maturing debt. Southern Power's subsidiaries are not borrowers under the commercial paper program.
Subsidiary Credit Facilities
In connection with the construction of solar facilities byRE Garland Holdings LLC, RE Roserock LLC, and RE Tranquillity LLC, indirect subsidiaries of Southern Power, each subsidiary entered into separate credit agreements (Project Credit Facilities), which are non-recourse to Southern Power (other than the subsidiary party to the agreement). Each Project Credit Facility provides (a) a senior secured construction loan credit facility, (b) a senior secured bridge loan facility, and (c) a senior secured letter of credit facility that is secured by the membership interests of the respective project company, with proceeds directed to finance project costs related to the respective solar facilities. Each Project Credit Facility is secured by the assets of the applicable project subsidiary and membership interests of the applicable project subsidiary. The table below summarizes each Project Credit Facility as of September 30, 2016.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Project | | Maturity Date | | Construction Loan Facility | | Bridge Loan Facility | | Total Loan Facility | | Loan Facility Undrawn | | Letter of Credit Facility | | Letter of Credit Facility Undrawn |
| | | | | (in millions) |
| Garland | | Earlier of PPA COD or November 30, 2016 | | $ | 86 |
| | $ | 308 |
| | $ | 394 |
| | $ | 21 |
| | $ | 49 |
| | $ | 23 |
|
| Roserock | | Earlier of PPA COD or November 30, 2016(*) | | 63 |
| | 180 |
| | 243 |
| | 34 |
| | 23 |
| | 16 |
|
| Tranquillity | | October 14, 2016 | | 86 |
| | 172 |
| | 258 |
| | 12 |
| | 77 |
| | 26 |
|
| Total | | | | $ | 235 |
| | $ | 660 |
| | $ | 895 |
| | $ | 67 |
| | $ | 149 |
| | $ | 65 |
|
| |
| (*) | Subsequent to September 30, 2016, Roserock extended the maturity date of its Project Credit Facility to December 31, 2016. |
The Project Credit Facilities above had total amounts outstanding as of September 30, 2016 of $828 million at a weighted average interest rate of 2.05%. For the three-month period ended September 30, 2016, these credit agreements had a maximum amount outstanding of $828 million and an average amount outstanding of $805 million at a weighted average interest rate of 2.02%.
Furthermore, in connection with the acquisition of the Henrietta solar facility on July 1, 2016, a subsidiary of Southern Power assumed a $217 million construction loan, which was fully repaid prior to September 30, 2016. For the three-month period ended September 30, 2016, this credit agreement had a maximum amount outstanding of $217 million and an average amount outstanding of $137 million at a weighted average interest rate of 2.21%.
Southern Power believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility, bank term loans, and operating cash flows.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Credit Rating Risk
Southern Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2, or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, energy price risk management, transmission, and foreign currency risk management.
The maximum potential collateral requirements under these contracts at September 30, 2016 were as follows:
|
| | | |
| Credit Ratings | Maximum Potential
Collateral
Requirements |
| | (in millions) |
| At BBB and/or Baa2 | $ | 30 |
|
| At BBB- and/or Baa3 | $ | 385 |
|
| Below BBB- and/or Baa3 | $ | 1,104 |
|
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, a credit rating downgrade could impact the ability of Southern Power to access capital markets and would be likely to impact the cost at which it does so.
In addition, Southern Power has a PPA that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power's credit. The PPA requires credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses resulting from a credit downgrade.
Financing Activities
In June 2016, Southern Power issued €600 million aggregate principal amount of Series 2016A 1.00% Senior Notes due June 20, 2022 and €500 million aggregate principal amount of Series 2016B 1.85% Senior Notes due June 20, 2026. The proceeds are being allocated to renewable energy generation projects. Southern Power's obligations under its euro-denominated fixed-rate notes were effectively converted to fixed-rate U.S. dollars at issuance through cross-currency swaps, removing foreign currency exchange risk associated with the interest and principal payments. See Note (H) to the Condensed Financial Statements under "Foreign Currency Derivatives" herein for additional information.
In September 2016, Southern Power issued $290 million aggregate principal amount of Series 2016C 2.75% Senior Notes due September 20, 2023. The proceeds were used for general corporate purposes, including Southern Power's growth strategy and continuous construction program, as well as repayment of amounts outstanding under the Project Credit Facilities.
Also in September 2016, Southern Power repaid $80 million of an outstanding $400 million floating rate bank loan and extended the maturity date of the remaining $320 million from September 2016 to September 2018. In addition, Southern Power entered into a $60 million aggregate principal amount floating rate bank loan bearing interest based on one-month LIBOR due September 2017. The proceeds were used to repay existing indebtedness and for other general corporate purposes.
In addition, Southern Power issued $34 million in letters of credit during the nine months ended September 30, 2016.
During the nine months ended September 30, 2016, Southern Power's subsidiaries incurred an additional $691 million of short-term borrowings pursuant to the Project Credit Facilities at a weighted average interest rate of 2.05%. Furthermore, in connection with the acquisition of the Henrietta solar facility, a subsidiary of Southern
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Power assumed a $217 million construction loan, which was fully repaid prior to September 30, 2016. In addition, Southern Power's subsidiaries issued $16 million in letters of credit.
Subsequent to September 30, 2016, Southern Power's subsidiaries borrowed $5 million pursuant to the Project Credit Facilities at a weighted average interest rate of 2.03%. In addition, on October 14, 2016, Southern Power repaid at maturity $246 million of Project Credit Facility debt.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
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, 2015 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended September 30, 2016 and 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.
Southern Company's financial statements reflect its investments in its subsidiaries, including Southern Company Gas as a result of the Merger, on a consolidated basis. Southern Company Gas' results of operations and cash flows since July 1, 2016 and financial condition as of September 30, 2016 are reflected within Southern Company's consolidated amounts in these accompanying notes herein. Southern Company Gas continues to maintain reporting requirements as an SEC registrant and has filed its Quarterly Report on Form 10-Q with the SEC separately from this combined Form 10-Q. The equity method is used for entities in which Southern Company has significant influence but does not control, including Southern Company Gas' investment in Southern Natural Gas Company, L.L.C. (SNG), and for variable interest entities where Southern Company has an equity investment but is not the primary beneficiary. See Note (I) under "Southern Company– Merger with Southern Company Gas" and " – Investment in Southern Natural Gas" for additional information regarding the Merger and Southern Company Gas' investment in SNG, respectively.
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.
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 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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Integrated Resource Planpermitted. The registrants are currently evaluating the new standard and have not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on the registrants' balance sheets.
On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation(Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions. Most significantly, entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or 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 as additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016. Early adoption is permitted and Southern Company and the traditional electric operating companies intend to adopt the ASU 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 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 $108 million made by Georgia Power to PowerSecure under the two agreements since inception in 2014 are included in CWIP at September 30, 2016. PowerSecure construction service costs of approximately $0.2 million are included in accounts payable, affiliated in Georgia Power's balance sheet at September 30, 2016. On October 4, 2016, the two facilities began commercial operation.
Prior to Southern Company Gas' completion of its acquisition of a 50% equity interest in SNG, Southern Company and Southern Company Gas had entered into long-term interstate natural gas transportation agreements with SNG. The interstate transportation service provided to the traditional electric operating companies, Southern Power, and Southern Company Gas by SNG pursuant to these agreements is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. For the period subsequent to Southern Company Gas' investment in SNG, transportation costs paid to SNG by Southern Company were approximately $16 million, including $8 million for Georgia Power, $2 million for Southern Power, and $1 million for Alabama Power.
See Note (I) under "Southern Company– Acquisition of PowerSecure International, Inc." and " – Investment in Southern Natural Gas" for additional information regarding Southern Company's acquisition of PowerSecure and Southern Company Gas' investment in SNG, respectively.
Asset Retirement Obligations
See Note 31 to the financial statements of Southern Company, andAlabama Power, Georgia Power, under "Retail Regulatory Matters – GeorgiaGulf Power, – Integrated Resource Plans" and "Retail Regulatory Matters – Integrated Resource Plans," respectively, in Item 8 of the Form 10-K for additional information.
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. On October 13, 2015, Plant Kraft Units 1 through 4 (316 MWs) were retired.
Fuel Cost Recovery
See Note 3 to the financial statements of Southern Company and GeorgiaMississippi Power under "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery""Asset Retirement Obligations and "Retail Regulatory Matters – Fuel Cost Recovery," respectively, in Item 8Other Costs of the Form 10-K for additional information.
As of September 30, 2015 and December 31, 2014, Georgia Power's under recovered fuel balance totaled $41 million and $199 million, respectively. For September 30, 2015 and December 31, 2014, the balance is included in current assets and current assets and other deferred charges and assets, respectively, on Southern Company's and Georgia Power's Condensed Balance Sheets herein. On September 18, 2015, Georgia Power filed a rate request with the Georgia PSC to lower total annual billings by approximately $268 million effective January 1, 2016. The Georgia PSC is scheduled to vote on this matter on December 15, 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 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,Removal" in Item 8 of the Form 10-K for additional information regarding GeorgiaSouthern Company's and the traditional electric operating companies' asset retirement obligations (ARO) and the EPA's regulation of CCR. See Note 1 to the financial statements of Southern Power under "Asset Retirement Obligations" in Item 8 of the Form 10-K for additional information regarding Southern Power's constructionAROs.
The cost estimates below are based on information as of Plant Vogtle Units 3September 30, 2016. The cost estimates for AROs related to the disposal of CCR are based on various assumptions related to closure and 4, Vogtle Construction Monitoring (VCM) reports,post-closure costs, timing of future cash outlays, inflation and pending litigation.
In 2008, Georgia Power, actingdiscount rates, and the potential methods for itself and as agent for the Vogtle Owners, entered into an agreement (Vogtle 3 and 4 Agreement)complying with the Contractor, pursuant to whichDisposal 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 Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4. Current anticipated in-service dates for Plant Vogtle Units 3 and 4 areexpected method of compliance, refinement of assumptions underlying the second quarter 2019cost estimates, such as the quantities of CCR at each site, and the second quarter 2020, respectively.
Underdetermination of timing, including 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 adjustmentspotential 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, 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 owedclosing ash ponds prior to the Contractor underend of their currently anticipated useful life, the Vogtle 3 and 4 Agreement. Georgia Power's proportionate share is 45.7%.traditional electric operating companies expect to continue to periodically update these estimates.
Certain payment obligations of Westinghouse and CB&I Stone & Webster, Inc. (S&W) (formerly known as Stone & Webster, Inc.) under the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation (Toshiba) and The Shaw
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Group Inc. (Shaw Group) (a subsidiaryAs of Chicago Bridge & Iron Company, N.V. (CB&I)), respectively. 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. 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 breachesSeptember 30, 2016, details of the Vogtle 3 and 4 Agreement byAROs included in the Vogtle Owners, Vogtle Owner insolvency, and certain other events.registrants' Condensed Balance Sheets were as follows:
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. |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power | | Southern Power |
| | (in millions) |
| Balance at beginning of year | $ | 3,759 |
| | $ | 1,448 |
| | $ | 1,916 |
| | $ | 130 |
| | $ | 177 |
| | $ | 21 |
|
| Liabilities incurred | 41 |
| | 5 |
| | — |
| | — |
| | 15 |
| | 18 |
|
| Liabilities settled | (117 | ) | | (12 | ) | | (93 | ) | | — |
| | (12 | ) | | — |
|
| Accretion | 119 |
| | 55 |
| | 56 |
| | 2 |
| | 3 |
| | 1 |
|
| Cash flow revisions | 712 |
| | 31 |
| | 675 |
| | 2 |
| | 7 |
| | — |
|
| Balance at end of period | $ | 4,514 |
| | $ | 1,527 |
| | $ | 2,554 |
| | $ | 134 |
| | $ | 190 |
| | $ | 40 |
|
The NRC certified the Westinghouse Design Control Document, as amended (DCD),traditional electric operating companies' increases in cash flow revisions for the AP1000 nuclear reactor design,nine months ended September 30, 2016 primarily relate to changes 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 may arise 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 responsibleash pond closure strategy. The increase for these costs under the terms of the Vogtle 3 and 4 Agreement. Also in 2012, Georgia Power reflects its decision in June 2016 to cease operating and stop receiving coal ash at all of its ash ponds within the other Vogtle Owners filed suit against the Contractor in the U.S. District Courtnext three years and to eventually close all of its ash ponds either by removal, consolidation, and/or recycling for the Southern Districtbeneficial use 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 Powercoal ash or through closure in place using advanced engineering methods.
Goodwill and the other Vogtle Owners in the U.S. District Court for the DistrictOther Intangible Assets
As of Columbia alleging the Vogtle Owners are responsible for these costs. The Contractor also asserted it is entitled to extensions of the guaranteed substantial completion dates of AprilSeptember 30, 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. On March 10, 2015, the U.S. Court of Appeals for the District of Columbia Circuit affirmed the decision of the U.S. District Court for the District of Columbia, which had dismissed the Contractor's suit, ruling that the proper venue is the U.S. District Court for the Southern District of Georgia. The case is pending in the U.S. District Court for the Southern District of Georgia (Vogtle Construction Litigation). 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).goodwill was as follows: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). On October 27, 2015, Westinghouse and CB&I announced an agreement under which Westinghouse or one of its affiliates will acquire S&W from CB&I, subject to satisfaction of certain conditions to closing. In addition, on October 27, 2015, Westinghouse and the Vogtle Owners entered into a term sheet (Term Sheet) setting forth the terms of a settlement agreement to resolve disputes between the Vogtle Owners and the Contractor under the Vogtle 3 and 4 Agreement, including the Vogtle Construction Litigation. |
| | | |
| | As of September 30, 2016 |
| | (in millions) |
| Southern Company | $ | 6,223 |
|
| Southern Power | $ | 2 |
|
In accordance with the Term Sheet: (i) the Vogtle Owners and the Contractor will enter into mutual releases of all open claims which have been asserted, including any potential extension of such open claims, as well as future claims based on events occurring prior to the effective date of the release that potentially could have been asserted under the original terms of the Vogtle 3 and 4 Agreement, including the Vogtle Construction Litigation, which will be dismissed with prejudice; (ii) the Vogtle 3 and 4 Agreement will be amended to restrict the Contractor's ability to seek further increases in the contract price by clarifying and limiting the circumstances that constitute nuclear
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
regulatory changes in law; (iii) enhanced dispute resolution procedures will be implemented; (iv) the guaranteed substantial completion dates under the Vogtle 3 and 4 Agreement will be revised to match the current estimated in-service datesAs of JuneSeptember 30, 2019 for Unit 3 and June 30, 2020 for Unit 4 (as discussed below); (v) delay liquidated damages will now commence from the current estimated nuclear fuel loading date for each unit, which is2016, other intangible assets were as follows:
|
| | | | | | | | | | |
| | | As of September 30, 2016 |
| | Estimated Useful Life | Gross Carrying Amount | Accumulated Amortization | Other Intangible Assets, Net |
| | | (in millions) |
| Southern Company | | | | |
| Other intangible assets subject to amortization: | | | | |
| Customer relationships | 11-26 years | $ | 268 |
| $ | (16 | ) | $ | 252 |
|
| Trade names | 5-28 years | 158 |
| (3 | ) | 155 |
|
| Patents | 3-10 years | 4 |
| — |
| 4 |
|
| Backlog | 5 years | 5 |
| — |
| 5 |
|
| Storage and transportation contracts | 1-5 years | 64 |
| (4 | ) | 60 |
|
| Software and other | 1-12 years | 2 |
| — |
| 2 |
|
| PPA fair value adjustments | 19-20 years | 405 |
| (16 | ) | 389 |
|
| Total other intangible assets subject to amortization | | $ | 906 |
| $ | (39 | ) | $ | 867 |
|
| Other intangible assets not subject to amortization: | | | | |
| Federal Communications Commission licenses | | $ | 75 |
| $ | — |
| $ | 75 |
|
| Total other intangible assets | | $ | 981 |
| $ | (39 | ) | $ | 942 |
|
| | | | | |
| Southern Power | | | | |
| Other intangible assets subject to amortization: | | | | |
| PPA fair value adjustments | 19-20 years | $ | 405 |
| $ | (16 | ) | $ | 389 |
|
Amortization associated with other intangible assets was as follows:
|
| | | | | | |
| | Three Months Ended | Nine Months Ended |
| | September 30, 2016 |
| | (in millions) |
| Southern Company | $ | 25 |
| $ | 27 |
|
| Southern Power | $ | 2 |
| $ | 4 |
|
At December 31, 2018 for Unit 32015, other intangible assets consisted primarily of Southern Power's PPA fair value adjustments with a net carrying amount of $317 million. The increases in goodwill and December 31, 2019 for Unit 4, rather than the original guaranteed substantial completion dates under the Vogtle 3other intangible assets primarily relate to Southern Company's acquisitions of PowerSecure on May 9, 2016 and 4 Agreement; and (vi) Georgia Power, basedSouthern Company Gas on its ownership interest, will payJuly 1, 2016.
See Note 12 to the Contractorfinancial statements of Southern Company under "Southern Power" and capitalizeNote 2 to the project cost approximately $350 million,financial statements of which approximately $120 million has been paid previously under the dispute resolution proceduresSouthern Power in Item 8 of the Vogtle 3Form 10-K for additional information regarding Southern Power's PPA fair value adjustments. Also see Note (I) under "Southern Company– Acquisition of PowerSecure International, Inc." and 4 Agreement. In addition, the Vogtle Owners and the Contractor resolved other open existing items relating to the scope of the project under the Vogtle 3 and 4 Agreement, including cyber security," –Merger with Southern Company Gas" for which costs were reflected in Georgia Power's previously disclosed in-service cost estimate. Further, as part of the proposed settlement and in connection with Westinghouse's proposed acquisition of S&W: (i) the Vogtle Owners will terminate the parent guarantee of Shaw Group with respect to certain obligations of S&W, subject to obtaining the consent of the DOE under loan guarantee agreements relating to Plant Vogtle Units 3 and 4, while the parent guarantee of Toshiba with respect to certain obligations of Westinghouse will remain in place; (ii) Westinghouse will make provisions to engage Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor; and (iii) the Vogtle Owners, CB&I, and Shaw Group also will enter into mutual releases of any and all claims against each other arising out of the construction of Plant Vogtle Units 3 and 4.additional information.
The settlement of the pending disputes between the Vogtle Owners and the Contractor, including the Vogtle Construction Litigation, is subject to consummation of Westinghouse's proposed acquisition of S&W. If this proposed acquisition is not completed, the Vogtle Construction Litigation will continue and the Contractor may from time to time continue to assert that it is entitled to additional payments with respect to its allegations, any of which could be substantial.Natural Gas for Sale
Georgia Power will submit the ultimate settlement agreement terms and the related amendments to the Vogtle 3 and 4 Agreement to the Georgia PSC for its review.
Georgia Power is required to file semi-annual VCM reportsSouthern Company Gas' natural gas distribution utilities, 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% 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 2013, the Georgia PSC approvedexception of Nicor Gas, carry natural gas inventory on a stipulation (2013 Stipulation) entered into by Georgia Power and the Georgia PSC staff to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate, until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.
On April 15, 2015, the Georgia PSC issued a procedural order in connection with the twelfth VCM report, which included a requested amendment (Requested Amendment) to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 (second quarter of 2019 and second quarter of 2020, respectively) as well as additional estimated owner-related costs, which include approximately $10 million per month, including property taxes, oversight costs, compliance costs, and other operational readiness costs to include the estimated owner's costs associated with the proposed 18-month Contractor delay and to increase the estimated total in-service capitalweighted average cost of Plant Vogtle Units 3 and 4 to $5.0 billion. 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, while financing costs on any construction-related costs in excess of the $4.4 billion certified amount are expected to be recovered through AFUDC.gas (WACOG) basis.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
The Georgia PSC has approved twelve VCM reports covering the periods through December 31, 2014, including construction capital costs incurred, which through that date totaled $3.0 billion. On August 28, 2015, Georgia Power filed its thirteenth VCM report with the Georgia PSC covering the period from January 1 through June 30, 2015, which requested approval for an additional $148 million of construction capital costs incurred during that period and reflected estimated financing costsNicor Gas' natural gas inventory is carried at cost on a last-in, first-out (LIFO) basis. Inventory decrements occurring during the construction period to total approximately $2.4 billion. Georgia Power will continue to incur financing costs of approximately $30 million per month until Plant Vogtle Units 3 and 4 are placed in service.
On October 30, 2015, Georgia Power filed to increase the NCCR tariff by approximately $19 million, effective January 1, 2016, pending Georgia PSC approval.
Processes are in placeyear that are designedrestored prior to assure compliance withyear-end are charged to cost of natural gas at the requirements specified in the DCD and the COLs, including inspections by Southern Nuclear and the NRCestimated annual replacement cost. Inventory decrements 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 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 inrestored prior to year-end are charged to cost of natural gas at 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 its fabrication, assembly, delivery, and installationactual LIFO cost of the shield buildinglayers liquidated. The cost of natural gas, including inventory costs, is recovered from customers under a purchased gas recovery mechanism adjusted for differences between actual costs and structural modules, delaysamounts billed; therefore, LIFO liquidations have no impact on Southern Company's net income.
Southern Company Gas' other natural gas inventories are carried at the lower of weighted average cost or current market price, with cost determined on a WACOG basis. For any declines in market prices below the 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 unitWACOG considered to be placed in service before 2021.other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value.
Future claims by the Contractor or Georgia Power (on behalf of the Vogtle Owners) could arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement, but also may be resolved through litigation.The ultimate outcome of these matters cannot be determined at this time.
Gulf Power
Retail Base Rate Case
| |
| (B) | CONTINGENCIES AND REGULATORY MATTERS |
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Case"the registrants in Item 8 of the Form 10-K for additional information.information relating to various lawsuits, other contingencies, and regulatory matters.
General Litigation Matters
Nicor Gas and Nicor Energy Services Company, wholly-owned subsidiaries of Southern Company Gas, and Nicor Inc. are defendants in a putative class action initially filed in September 2011 in state court in Cook County, Illinois. The plaintiffs purport to represent a class of the customers who purchased the Gas Line Comfort Guard product from Nicor Energy Services Company and variously allege that the marketing, sale, and billing of the Gas Line Comfort Guard product violated the Illinois Consumer Fraud and Deceptive Business Practices Act, constituting common law fraud and resulting in unjust enrichment of these entities. The plaintiffs seek, on behalf of the classes they purport to represent, actual and punitive damages, interest, costs, attorney fees, and injunctive relief. On October 26, 2016, the court held a hearing on the plaintiffs' motion for class certification and the defendants' motion for summary judgment on all of the plaintiffs' claims. The ultimate outcome of this matter cannot be determined at this time.
Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In December 2013,addition, business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the Florida PSC approved a settlement agreement that provides Gulf Power may reduce depreciation expenseenvironment, such as regulation of air emissions and record a regulatory asset upwater 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 $62.5 million between January 2014have been caused by CO2 and June 2017. Inother 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 given month, such depreciation expense reduction maysubsidiaries cannot be predicted at this time; however, for current proceedings not exceed the amount necessary for the retail ROE, asspecifically reported herein or in Note 3 to the Florida PSC monthly, to reach the midpointfinancial statements of each registrant in Item 8 of the authorized retail ROE range thenForm 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 Remediation
The Southern Company system must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companies, and Southern Company Gas' natural gas distribution utilities in effect. For 2014Illinois, New Jersey, Georgia, and Florida, have each received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the first nine months of 2015, Gulf Power recognized reductions in depreciation expense of $8.4 million and $20.5 million, respectively.state PSCs or other applicable state regulatory agencies.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Cost Recovery Clauses
Georgia Power's environmental remediation liability as of September 30, 2016 was $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 (CERCLA), including a site in Brunswick, Georgia on the CERCLA National Priorities List. The PRPs at the Brunswick site have completed a removal action as ordered by the EPA. On July 29, 2016, Honeywell International, Inc. and Georgia Power entered into a consent decree with the EPA to perform additional remediation at the site. Additional response actions at the site are anticipated. In September 2015, Georgia Power entered into an allocation agreement with another PRP, under which that PRP will be responsible (as between Georgia Power and that PRP) for paying and performing certain investigation, assessment, remediation, and other incidental activities at the Brunswick site, including costs associated with implementation of the consent decree. Assessment and potential cleanup of other sites are anticipated.
The ultimate outcome of these matters will depend upon the success of defenses asserted, the ultimate number of PRPs participating in the cleanup, and numerous other factors and cannot be determined at this time; however, as a result of Georgia Power's regulatory treatment for environmental remediation expenses, these matters are not expected to have a material impact on Southern Company's or Georgia Power's financial statements.
Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $46 million as of September 30, 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.
The final outcome of these matters cannot be determined at this time. However, based on the currently known conditions at these sites and the nature and extent of activities relating to these sites, management of Southern Company and Gulf Power does not believe that additional liabilities, if any, at these sites would be material to their respective financial statements.
Southern Company Gas' environmental remediation liability as of September 30, 2016 was $433 million based on the estimated cost of environmental investigation and remediation associated with known current and former operating sites. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies of Southern Company Gas' natural gas distribution utilities, with the exception of one site representing $5 million of the total accrued remediation costs. The ultimate outcome of these matters cannot be determined at this time; however, these matters are not expected to have a material impact on Southern Company's financial statements.
In September 2015, the EPA filed an administrative complaint and notice of opportunity for hearing against Nicor Gas. The complaint alleges violation of the regulatory requirements applicable to polychlorinated biphenyls in the Nicor Gas natural gas distribution system and the EPA seeks a total civil penalty of approximately $0.3 million. The ultimate resolution of this matter cannot be determined at this time; however, the final disposition of this matter is not expected to have a material impact on Southern Company's financial statements.
FERC Matters
Municipal and Rural Associations Tariff
See Note 3 to the financial statements of GulfMississippi Power under "Retail Regulatory Matters – Cost Recovery Clauses""FERC Matters" in Item 8 of the Form 10-K for additional information regarding Gulfa settlement agreement entered into by Mississippi Power regarding the establishment of a regulatory asset for Kemper IGCC-related costs. See "Integrated Coal Gasification Combined Cycle" herein for information regarding Mississippi Power's construction of the Kemper IGCC.
On March 31, 2016, Mississippi Power reached a settlement agreement with its wholesale customers and filed a request with the FERC for an increase in wholesale base revenues under the Municipal and Rural Associations (MRA) cost-based electric tariff, primarily as a result of placing scrubbers for Plant Daniel Units 1 and 2 in service
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
in November 2015. The settlement agreement, accepted by the FERC, 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. 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. The additional resulting AFUDC is estimated to be approximately $11 million through the Kemper IGCC's projected in-service date of December 31, 2016.
Fuel Cost Recovery
Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At September 30, 2016, the amount of over-recovered wholesale MRA fuel costs included in the balance sheets was $17 million compared to $24 million at December 31, 2015. At September 30, 2016 and December 31, 2015, the amount of over-recovered wholesale MB fuel costs included in the balance sheets was $1 million. Effective with the first billing cycle for September 2016, fuel rates decreased $11 million annually for wholesale MRA customers and $1 million annually for wholesale MB customers.
See Note 3 to the financial statements of Mississippi Power under "FERC Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.
Market-Based Rate Authority
The traditional electric operating companies and Southern Power have authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies and Southern Power filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In April 2015, the FERC issued an order finding that the traditional electric operating companies' and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and Southern Power filed a request for rehearing in May 2015 and in June 2015 filed their response with the FERC. 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. 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 |
| September 30, 2015 |
| December 31, 2014 |
|
|
|
| (in millions) |
| Fuel Cost Recovery – Under |
| Under recovered regulatory clause revenues |
| $ | 2 |
|
| $ | 40 |
|
| Purchased Power Capacity Recovery – Over |
| Other regulatory liabilities, current |
| 3 |
|
| — |
|
| Environmental Cost Recovery - Over | | Other regulatory liabilities, current | | 5 |
| | — |
|
| Environmental Cost Recovery – Under |
| Under recovered regulatory clause revenues |
| — |
|
| 10 |
|
| Energy Conservation Cost Recovery – Over | | Other regulatory liabilities, current | | 3 |
| | — |
|
| Energy Conservation Cost Recovery – Under |
| Under recovered regulatory clause revenues |
| — |
|
| 3 |
|
|
| | | | | | | |
| Regulatory Clause | Balance Sheet Line Item | September 30,
2016 | December 31, 2015 |
|
| (in millions) |
| Rate CNP Compliance | Under recovered regulatory clause revenues | $ | — |
| $ | 43 |
|
| | Deferred over recovered regulatory clause revenues | 23 |
| — |
|
| Rate CNP PPA | Under recovered regulatory clause revenues | 52 |
| 99 |
|
| | Deferred under recovered regulatory clause revenues | 87 |
| — |
|
| Retail Energy Cost Recovery | Other regulatory liabilities, current | — |
| 238 |
|
| Deferred over recovered regulatory clause revenues | 134 |
| — |
|
| Natural Disaster Reserve | Other regulatory liabilities, deferred | 71 |
| 75 |
|
On NovemberEnvironmental 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 2015, the Florida PSC approved Gulf(300 MWs representing Alabama Power's annual rate clause request for its fuel, purchased power capacity, environmental,ownership interest) and energy conservation cost recovery factors for 2016. The net effect of the approved changes is a $49 million decreasebegan operating Units 1 and 2 solely on natural gas in annual revenue for 2016. The decreased revenues will not have a significant impact on net income since most of the revenues will be offset by lower expenses.
Mississippi Power
2015 Rate Case
On May 15, 2015June 2016 and July 10, 2015, Mississippi2016, respectively.
Georgia Power filed alternative rate proposals related to recovery of Kemper IGCC-related costs with the Mississippi PSC. On August 13, 2015, the Mississippi PSC approved the implementation of interim rates designed to collect approximately $159 million annually. See "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Rate Case" herein for additional information.
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,change in rates. The filing has been suspended for review by the Mississippi PSC suspended the filing to allow it more time for review. PSC.
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.Environmental Compliance Overview Plan
On October 6, 2015,August 17, 2016, the Mississippi PSC approved Mississippi Power's requestrevised ECO Plan filing for 2016, which requested the maximum 2% annual increase in revenues, approximately $18 million, primarily related to continue a zero System Restoration Rider (SRR) rate for 2015 and to accrue approximately $3 million to the property damage reserve in 2015.
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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 bescrubbers being placed in service in November 2015. The revised rates became effective with the fourth quarter 2015. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total costfirst billing cycle for September 2016. Approximately $22 million of related revenue requirements in excess of the project is approximately $660 million, with Mississippi Power's portion being $330 million, excluding AFUDC. Mississippi Power's portion of2% maximum was deferred for inclusion in the cost is expected to be recovered through the ECO Plan following the scheduled completion of the project. As of September 30, 2015, total project expenditures were $626 million, of which Mississippi Power's portion was $320 million, excluding AFUDC of $32 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.2017 filing.
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 September 30, 2015,2016, the amount of over recoveredover-recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheet hereinthe balance sheet was $44$58 million compared to under recovered retail fuel costs of $2$71 million at December 31, 2014.2015.
Ad Valorem Tax Adjustment
See Note 3 toThe Mississippi PSC conditionally approved a decrease of $120 million annually in fuel cost recovery rates on January 5, 2016, effective with the financial statements of Mississippi Power under "Retail Regulatory Matters – Ad Valorem Tax Adjustment" in Item 8 of the Form 10-Kfirst billing cycle for additional information.
February 2016. On September 1, 2015,August 17, 2016, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment factor filing effective September 18, 2015, which requested an annual rateadditional decrease of 0.35%, or $2$51 million annually in annual retail revenues, primarily due to a decrease in average millage rates.fuel cost recovery rates effective with the first billing cycle for September 2016.
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.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 theInitial DOE under the Clean Coal Power Initiative Round 2 (DOE Grants)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 initial production of syngas began on July 14, 2016 for whichgasifier "B" and on September 13, 2016 for gasifier "A." On October 11, 2016, the Kemper IGCC began testing using clean syngas from gasifier "A" and the related gas clean-up systems to produce electricity. Late on October 31, 2016, gasifier "A" experienced challenges associated with the ash removal systems, and on November 2, 2016, Mississippi Power determined a maintenance outage on gasifier "A" is needed to make improvements to the ash removal systems. Therefore, Mississippi Power has re-sequenced activities, and gasifier "B" is now expected to progress through testing and begin producing electricity during the gasifier "A" outage. In light of these changes, Mississippi Power has determined that integrated operation of both gasifiers will not occur by mid-November and has revised the expected in-service date is currently expected to occur infor the first half of 2016. Recoveryremainder of the Kemper IGCC to December 31, 2016. The remaining schedule reflects the time expected to achieve production of electricity using gasifier "B," complete gasifier "A" outage activities, and resume electricity production using gasifier "A," as well as to complete the integration of all systems necessary for both combustion turbines to simultaneously generate electricity with syngas.
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 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) (CostCost Cap Exceptions)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 September 30, 2015, as adjusted for the Court's decision,2016 are as follows:
| | | Cost Category | 2010 Project Estimate(f) | | Current Estimate(a) | | Actual Costs | 2010 Project Estimate(a) | | Current Cost Estimate(b) | | Actual Costs |
| | (in billions) | (in billions) |
Plant Subject to Cost Cap(g)(e) | $ | 2.40 |
| | $ | 5.11 |
| | $ | 4.66 |
| $ | 2.40 |
| | $ | 5.52 |
| | $ | 5.30 |
|
| 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 |
| | 0.11 |
|
AFUDC(c)(d) | 0.17 | | 0.66 | | 0.55 | 0.17 |
| | 0.75 |
| | 0.71 |
|
Combined Cycle and Related Assets Placed in
Service – Incremental(g)(e) | — |
| | 0.02 |
| | — |
| — |
| | 0.04 |
| | 0.03 |
|
| General Exceptions | 0.05 | | 0.10 | | 0.08 | 0.05 |
| | 0.10 |
| | 0.09 |
|
Deferred Costs(g)(e) | — |
| | 0.20 | | 0.17 | — |
| | 0.21 |
| | 0.20 |
|
| Additional DOE Grants | | — |
| | (0.14 | ) | | (0.14 | ) |
| Total Kemper IGCC | $ | 2.97 |
| | $ | 6.43 |
| | $ | 5.80 |
| $ | 2.97 |
| | $ | 6.82 |
| | $ | 6.53 |
|
| |
| (a) | AmountsThe 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities approved in 2011 by the Current Estimate reflect estimated costs through June 30, 2016.Mississippi PSC, as well as the lignite mine and equipment, AFUDC, and general exceptions. |
| |
| (b) | Amounts in the Current Cost Estimate include certain estimated post-in-service costs which are expected to be subject to the cost cap. |
| |
| (c) | The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. The Current Cost Estimate and the Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap and exclude post-in-service costs for the lignite mine. See "Rate"Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order"Order" herein for additional information. The Current Cost Estimate and the Actual Costs reflect 100% of the costs of the Kemper IGCC. See note (g)(e) for additional information. |
| |
(c)(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 estimateCurrent 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. |
| |
(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 as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities." |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| |
(f) | The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificatedestimate for the CO2 pipeline facilities which was approved in 2011 by the Mississippi PSC.
|
| |
(g) | Beginning in the third quarter 2015, certain costs, including debt carrying costs (associated with placed in service and other non-construction work in progress accounts), that previously were initially deferred as regulatory assetsassets. 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 estimateCurrent Cost Estimate and actual coststhe Actual Costs at September 30, 2015.2016. The wholesale portion of debt carrying costs, whether deferred or recognized through income, is not included in the Current Cost Estimate and the Actual Costs at September 30, 2016. See "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities" herein for additional information. |
Of the total costs, including post-in-service costs for the lignite mine, incurred as of September 30, 2015, $3.452016, $3.70 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 $2.23$2.63 billion), $2$6 million in other property and investments, $62$81 million in fossil fuel stock, $43$46 million in materials and supplies, $50$33 million in other regulatory assets, current, $158$177 million in other regulatory assets, deferred, $4 million in other current assets, and $15$9 million in other deferred charges and assets in the balance sheet.
Mississippi Power does not intend to seek rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate above the cost cap of $150$88 million ($9354 million after tax) in the third quarter 20152016 and a total of $182$222 million ($112137 million after tax) for the nine months ended September 30, 2015. These amounts are2016. Since 2012, in addition tothe aggregate, Mississippi Power has incurred charges totaling $868 million ($536 million after tax), $1.10of $2.63 billion ($681 million after tax), and $78 million ($48 million1.63 billion 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 September 30, 2016. The increasesincrease to the cost estimate in 2015the third quarter of 2016 primarily reflect costsreflects $53 million for the extension of the Kemper IGCC's projected in-service date from October 31, 2016 to December 31, 2016 and
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
increased efforts related to equipment rework, scope modifications,operational readiness and the related additional labor costschallenges in support of start-up and operational readinesscommissioning activities, including the cost of repairs and modifications to gasifier "B" and mechanical improvements to coal feed and ash management systems, as well as additional schedulecertain post-in-service costs through June 30,expected to be subject to the cost cap. The year-to-date increase to the cost estimate also includes $78 million for the extension of the Kemper IGCC's projected in-service date from August 31, 2016 to October 31, 2016. In addition, during the start-up and commissioning process, Mississippi Power is identifying potential improvement projects that ultimately may be completed subsequent to placing the remainder of the Kemper IGCC in service. If completed, such improvement projects would be expected to enhance plant performance, safety, and/or operations. The related potential costs have yet to be fully evaluated, have not been included in the current cost estimate, includes costs through June 30, 2016. and may be subject to the $2.88 billion cost cap.
Any extension of the in-service date beyond June 30,December 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 extension of the in-service date with respect to the Kemper IGCC beyond June 30,December 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 $12$15 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees. Beginning in the third quarter 2015, in connection with the implementationfees of interim rate recovery, certain of these ongoing project costs are being expensed, with the remainder being deferred as regulatory assets and are estimated to total approximately $6$3 million per month. For additional information, see "2015"2015 Rate Case"Case" herein.
Mississippi Power’sPower's analysis of the time needed to complete the start-up and commissioning activities for the Kemper IGCC will continue until the remaining Kemper IGCC assets are placed in service. The next steps for the facility include the testing and production of electricity using clean syngas from gasifier "B," as well as the generation of electricity using clean syngas from gasifier "A," which are scheduled to occur by the end of November. If integrated operation of both gasifiers does not occur by mid-December, the expected in-service date and related cost estimate for the Kemper IGCC likely would require further revision. Further cost increases and/or extensions of the expected in-service date 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, sustaining nitrogen supply, 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) 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 Southern Company's and Mississippi Power's results of operations, financial condition, and liquidity.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 (as defined below) 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 Southern Company's or Mississippi Power's financial statements. See "Prudence" herein for additional information.
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 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 throughIGCC. Through September 30, 2016, AFUDC recorded since the original May 2014 estimated in-service date. Mississippi Power will not record AFUDC on any additional costs ofdate for the Kemper IGCC that exceedhas totaled $352 million. Mississippi Power has not recorded any AFUDC on Kemper IGCC costs in excess of the $2.88 billion cost cap, except for Cost Cap Exception amounts. 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. In addition, Mississippi Power 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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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. 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. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015. Through July 2015 billings, Mississippi Power had collectedand required the fourth quarter 2015 refund of the $342 million through ratescollected under the 2013 MPSC Rate Order, and had accrued $27 million inalong with associated carrying costs through September 30, 2015. Refunds will begin in early November 2015.of $29 million. The Court's decision did not impact the 2012 MPSC CPCN Order or the 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 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). In light of thePSC approved Mississippi PSC's July 7, 2015 order, RMP 2019 is no longer viable as originally proposed by Mississippi Power.
Furthermore, on July 10, 2015, Mississippi Power filed a supplemental filing including aPower's request for interim rates, (Supplemental Notice) with the Mississippi PSC in response to the July 7, 2015 order of the Mississippi PSC. The Supplemental Noticewhich 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 requested thatannually and became effective with the first billing cycle for September 2015, subject to refund and certain other conditions.
On December 3, 2015, the Mississippi PSC issued the In-Service Asset 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 MPUS regarding the In-Service Asset Proposal and requested that the Mississippi PSC establish a scheduling order for consideration of permanent rates under theProposal. The In-Service Asset Proposal.
Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The 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.
On August 13, 2015, the Mississippi PSC approved the implementation of interim rates that became effectiveevaluate its alternatives with respect to its investment and related costs associated with the first billing cycle in September (on August 19), subject to refund and certain other conditions. In addition, the Mississippi PSC reserved the right to modify or terminate the interim rates based upon a material change in circumstances. Through September 30, 2015, Mississippi Power had recognized $28 million under the interim rates. The Mississippi PSC is scheduled to issue a final order on or before December 8, 2015 related to permanent rates for the In-Service Asset Proposal.15% undivided interest.
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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
With implementation of the new rates on December 17, 2015, the interim rates were terminated and, in March 2016, Mississippi Power expectscompleted 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 seek additional rate relief to address recoverydismiss Greenleaf's appeal of the remaining Kemper IGCC assets. In-Service Asset Rate Order.
In addition to current estimated costs at September 30, 20152016 of $6.43$6.82 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, taxes, and additional carrying costs which could be material. Recovery of these costs would be subjectcosts. Mississippi Power expects 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 byrequest authority from the Mississippi PSC and the Mississippi Public Utilities Staff (MPUS). TheFERC to defer all Kemper IGCC costs incurred after the in-service date that cannot be capitalized, are not included in current rates, and are not required to be charged against earnings as a result of the $2.88 billion cost cap until such time as the Mississippi PSC has encouragedcompletes its review and includes the parties to workresulting allowable costs in good faith to settle contested issues andrates. Mississippi Power is workingrequired to reach a mutually acceptable resolution.file its next rate request with the Mississippi PSC related to cost recovery for the Kemper IGCC by June 3, 2017. See "2015 Mississippi Supreme Court Decision""Regulatory Assets and "2015 Rate Case" hereinLiabilities" below for additional information. As part of that filing, Mississippi Power expects to request recovery of certain costs that the Mississippi PSC had excluded from the revenue requirement calculation for the in-service assets.
Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law in 2013. Mississippi Power expects to securitize prudently-incurred qualifying facility costs in excess of the certificated cost estimate of $2.4 billion. Qualifying facility costs include, but are not limited to, pre-construction costs, construction costs, regulatory costs, and accrued AFUDC. The Court's decision regarding the 2013 MPSC Rate Order did not impact Mississippi Power's ability to utilize alternate financing through securitization or the February 2013 legislation.
Prudence
On August 17, 2016, the Mississippi PSC issued an order establishing a discovery docket to manage all filings related to the prudence of the Kemper IGCC. On October 3, 2016, Mississippi Power made a required compliance filing, which included a review and explanation of differences between the Kemper IGCC project estimate set forth in the 2010 CPCN proceeding and the most recent Kemper IGCC project estimate, as well as comparisons of current cost estimates and current expected plant operational parameters to the estimates presented in the 2010 CPCN proceedings for the first five years following the start of commercial operations. Certain costs, including operations and maintenance, are materially higher than the amounts presented in the CPCN proceedings. Additionally, while the current estimated operational availability estimates reflect ultimate results similar to those presented in the 2010 CPCN proceedings, the ramp up period for the current estimates reflects a lower starting point and a slower escalation rate. Mississippi Power expects the Mississippi PSC to address these issues in connection with its next rate request.
Regulatory Assets and Liabilities
Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC issued an accounting order in 2011 granting Mississippi Power the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date, subject to review of such costs by the Mississippi PSC. Such costs include, but are not limited to, carrying costs on Kemper IGCC assets currently placed in service, costs associated with Mississippi PSC and MPUS consultants, prudence costs, legal fees, and operating expenses associated with assets placed in service.
In August 2014, Mississippi Power requested confirmation by the Mississippi PSC of Mississippi Power's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost
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recovery mechanism proceedings. Beginning in the third quarter 2015 and the second quarter 2016, in connection with the implementation of interimretail 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-construction work in progressnon-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 over a 24-month period.fees. The amortization periods for these regulatory assets vary from two years to 10 years as set forth in the In-Service Asset Rate Order and the settlement agreement with wholesale customers. As of September 30, 2015,2016, the balance associated with these regulatory assets was $117 million. The amortization period for these regulatory assets$105 million, of which $33 million is subject to the Mississippi PSC’s final orderincluded in the 2015 Rate Case.current assets. Other regulatory assets associated with the remainder of the Kemper IGCC totaled $91$105 million as of September 30, 2015.2016. The amortization period for these assets is expected to be determined by the Mississippi PSC in future rate proceedings following completion of construction and start-up of the Kemper IGCC and related prudence reviews.
Also see "2015 Mississippi Supreme Court Decision" See "FERC Matters" herein for information related to the 2016 settlement agreement with wholesale customers.
The In-Service Asset Rate Order requires Mississippi Power to submit an annual true-up calculation of its actual cost of capital, compared to the stipulated total cost of capital, with the first occurring as of May 31, 2016. At September 30, 2016, Mississippi Power's related regulatory liability included in its balance sheet totaled approximately $7 million. See "2015 Rate Case" herein for additional information.
See Note 1 to the financial statements of Mississippi Power under "Regulatory Assets and Liabilities" in Item 8 of the Form 10-K for additional information.
Lignite Mine and CO2 Pipeline Facilities
In conjunction with the Kemper IGCC, Mississippi Power will 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 entered into agreements with Denbury Onshore (Denbury) and Treetop Midstream Services, LLC (Treetop), pursuant to which Denbury would purchase 70% of the CO2 captured from the Kemper IGCC and Treetop would purchase 30% of the CO2 captured from the Kemper IGCC. On June 3, 2016, Mississippi Power cancelled its contract with Treetop and amended its contract with Denbury to reflect, among other things, Denbury's agreement to purchase 100% of the CO2 captured from the Kemper IGCC, an initial contract term of 16 years, and termination rights if Mississippi Power has not satisfied its contractual obligation to deliver captured CO2 by July 1, 2017, in addition to Denbury's existing termination rights in the event of a change in law, force majeure, or an event of default by Mississippi Power. Any termination or material modification of the agreement with Denbury could impact the operations of the Kemper IGCC and result in a material reduction in Mississippi Power's revenues to the extent Mississippi Power is not able to enter into other similar contractual arrangements or otherwise sequester the CO2 produced. Additionally, sustained oil price reductions could result in significantly lower revenues than Mississippi Power 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.
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Litigation
On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. On August 12, 2016, Southern Company and Mississippi Power removed the case to the U.S. District Court for the Southern District of Mississippi, where the case is currently pending. However, the plaintiffs have filed a request to remand the case back to state court. 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. Southern Company, Mississippi Power, and SCS have moved to compel arbitration pursuant to the terms of the CO2 contract.
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.
Income Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Mississippi Power in Item 7 of the Form 10-K and Note (G) to the Condensed Financial Statements under "Section 174 Research and Experimental Deduction" herein for additional information.
Bonus Depreciation
The extension of 50% bonus depreciation included in the PATH Act is expected to result in approximately $400 million of positive cash flows for the 2016 tax year, which may not all be realized in 2016 due to a projected consolidated net operating loss for Southern Company. Approximately $370 million of the benefit is dependent upon placing the remainder of the Kemper IGCC in service by December 31, 2016, of which $250 million has been received as of September 30, 2016 through quarterly income tax refunds. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and Note (G) to the Condensed Financial Statements under "Current and Deferred Income Taxes – Net Operating Loss" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.
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
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nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation against Mississippi Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein or in Note 3 to the financial statements of Mississippi Power in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Mississippi Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
The SEC is conducting a formal investigation of Southern Company and Mississippi Power concerning the estimated costs and expected in-service date of the Kemper IGCC. Southern Company and Mississippi Power believe the investigation is focused primarily on periods subsequent to 2010 and on accounting matters, disclosure controls and procedures, and internal controls over financial reporting associated with the Kemper IGCC. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" herein for additional information on the Kemper IGCC estimated construction costs and expected in-service date. The ultimate outcome of this matter cannot be determined at this time; however, it is not expected to have a material impact on the financial statements of Mississippi Power.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Mississippi Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Mississippi Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Mississippi Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Mississippi Power in Item 7 of the Form 10-K for a complete discussion of Mississippi Power's critical accounting policies and estimates related to Electric Utility Regulation, Asset Retirement Obligations, Contingent Obligations, Unbilled Revenues, Pension and Other Postretirement Benefits, and AFUDC.
Kemper IGCC Estimated Construction Costs, Project Completion Date, and Rate Recovery
During 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, Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $88 million ($54 million after tax) in the third quarter 2016, $81 million ($50 million after tax) in the second quarter 2016, $53 million ($33 million after tax) in the first quarter 2016, $183 million ($113 million after tax) in the fourth quarter 2015, $150 million ($93 million after tax) in the third quarter 2015, $23 million ($14 million after tax) in the second quarter 2015, $9 million ($6 million after tax) in the first quarter 2015, $70 million ($43 million after tax) in the fourth quarter 2014, $418 million ($258 million after tax) in the third quarter 2014, $380 million ($235 million after tax) in the first quarter 2014, $40 million ($25 million after tax) in the fourth quarter 2013, $150 million ($93 million after tax) in the third quarter 2013, $450 million ($278 million after tax) in the second quarter 2013, $462 million ($285 million after tax) in the first quarter 2013, and $78 million ($48 million after tax) in the fourth quarter 2012. In the aggregate, Mississippi Power has
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incurred charges of $2.63 billion ($1.63 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through September 30, 2016.
Mississippi Power's revised cost estimate reflects an expected in-service date of December 31, 2016 and includes certain post-in-service costs which are expected to be subject to the cost cap. Mississippi Power has experienced, and may continue to experience, material changes in the cost estimate for the Kemper IGCC. Further cost increases and/or extensions of the expected in-service date may result from factors including, but not limited to, difficulties integrating the systems required for sustained operations, sustaining nitrogen supply, major equipment failure, unforeseen engineering or design problems including any repairs and/or modifications to systems, and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). In addition, during the start-up and commissioning process, Mississippi Power is also identifying potential improvement projects that ultimately may be completed subsequent to placing the remainder of the Kemper IGCC in service. If completed, such improvement projects would be expected to enhance plant performance, safety, and/or operations. The related potential costs have yet to be fully evaluated, have not been included in the current cost estimates, and may be subject to the $2.88 billion cost cap. In subsequent periods, any further changes in the estimated costs of the Kemper IGCC subject to the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Mississippi Power's statements of income and these changes could be material.
Any extension of the in-service date beyond December 31, 2016 is currently estimated to result in additional base costs of approximately $25 million to $35 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any extension of the in-service date with respect to the Kemper IGCC beyond December 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 $15 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees of approximately $3 million per month.
Given the significant judgment involved in estimating the future costs to complete construction and start-up, the project completion date, the ultimate rate recovery for the Kemper IGCC, and the potential impact on Mississippi Power's results of operations, Mississippi Power considers these items to be critical accounting estimates. See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Recently Issued Accounting Standards
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 accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. Mississippi Power is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on Mississippi Power's balance sheet.
On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation(Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions. Most significantly, entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. Mississippi Power currently recognizes any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15,
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2016. Early adoption is permitted and Mississippi Power intends to adopt the ASU 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 Coal Gasification Combined Cycle" herein for additional information. Earnings for the nine months ended September 30, 2016 were negatively affected by revisions to the cost estimate for the Kemper IGCC.
Through September 30, 2016, Mississippi Power has incurred non-recoverable cash expenditures of $2.42 billion and is expected to incur approximately $0.21 billion in additional non-recoverable cash expenditures through completion of the construction and start-up of the Kemper IGCC, which includes certain post-in-service costs expected to be subject to the cost cap.
Mississippi Power's capital expenditures and debt maturities are expected to materially exceed operating cash flows through 2021. In addition to the Kemper IGCC, projected capital expenditures in that period include investments to maintain existing generation facilities, to add environmental modifications to existing generating units, to add or change fuel sources for certain existing units, and to expand and improve transmission and distribution facilities.
On January 28, 2016, Mississippi Power issued a promissory note for up to $275 million to Southern Company, which matures in December 2017, bearing interest based on one-month LIBOR. During the first nine months of 2016, Mississippi Power borrowed $100 million under this promissory note and an additional $100 million under a separate promissory note issued to Southern Company in November 2015. On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicate of financial institutions for an aggregate amount of $1.2 billion. Mississippi Power borrowed $900 million on March 8, 2016 under the term loan agreement and the remaining $300 million on October 7, 2016. Mississippi Power used the initial proceeds to repay $900 million in maturing bank loans on March 8, 2016 and the remaining $300 million to repay at maturity Mississippi Power's Series 2011A 2.35% Senior Notes due October 15, 2016. On June 27, 2016, Mississippi Power received a capital contribution from Southern Company for $225 million, the proceeds of which were used to repay to Southern Company a portion of the existing promissory note issued in November 2015. As of September 30, 2016, the amount of outstanding promissory notes to Southern Company totaled $551 million.
As of September 30, 2016, Mississippi Power's current liabilities exceeded current assets by approximately $411 million primarily due to the $300 million in senior notes which matured on October 15, 2016, as well as $65 million in short-term debt.
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 the remainder of its short-term capital needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $372 million for the first nine months of 2016, an increase of $23 million as compared to the corresponding period in 2015. The increase in cash provided from operating activities is primarily due to income taxes receivable associated with research and experimental (R&E) deductions and accrued taxes, partially offset by lower R&E tax deductions, the cessation of Mirror CWIP collections and subsequent refund payments, and higher recovery of regulatory fuel clause revenues. See Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" and "Unrecognized Tax Benefits – Section 174 Research and Experimental Deduction" herein for additional information. Net cash used for investing activities totaled $509 million for the first nine months of 2016 primarily due to gross property additions related to the Kemper IGCC, partially offset by receipt of $137 million in Additional DOE Grants. Net cash provided from financing activities totaled $198 million for the first nine months
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of 2016 primarily due to long-term debt issuances and capital contributions from Southern Company, partially offset by redemptions of long-term debt and a decrease in short-term borrowings. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first nine months of 2016 include an increase in long-term debt of $826 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 and a $475 million decrease in notes payable. Additionally, CWIP increased $271 million primarily due to the Kemper IGCC and the customer liability associated with Kemper IGCC refunds decreased $72 million. Other significant changes include a $110 million increase in accrued income taxes due to bonus depreciation, a $61 million increase in accumulated deferred income taxes (ADIT) due to transmission and distribution property-related ADITs and additional Section 174 R&E deduction, partially offset by ADITs associated with the estimated losses on the Kemper IGCC construction, and a $39 million increase in prepaid income taxes. Total common stockholder's equity increased $269 million primarily due to the receipt of capital contributions from Southern Company and net income for the 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 $300 million will be required through September 30, 2017 to fund maturities of long-term debt, and $25 million will be required to fund maturities of short-term debt. See "Sources of Capital" herein for additional information. Subsequent to September 30, 2016, Mississippi Power repaid at maturity $300 million aggregate principal amount of its Series 2011A 2.35% Senior Notes due October 15, 2016. If the Kemper IGCC does not go into service by December 31, 2016, Mississippi Power also would have to repay approximately $250 million of tax benefits received as a result of quarterly income tax estimates through September 30, 2016. See "Income Tax Matters" herein for additional information.
The construction program of Mississippi Power is currently estimated to be $0.8 billion for 2016, net of the Additional DOE Grants, $0.3 billion for 2017, $0.2 billion for 2018, $0.2 billion for 2019, $0.3 billion for 2020, and $0.3 billion for 2021, which includes revised estimates for the Kemper IGCC, including post-in-service costs. The expenditures related to the construction and start-up of the Kemper IGCC are currently estimated to be $0.7 billion for 2016, net of the Additional DOE Grants, and $0.1 billion for 2017. These estimated expenditures do not include potential compliance costs that may arise from the EPA's final rules and guidelines or subsequently approved state plans that would limit CO2 emissions from existing, new, modified, or reconstructed fossil-fuel-fired electric generating units.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing 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 Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein for additional information and further risks related to the estimated schedule and costs and rate recovery for the Kemper IGCC.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Sources of Capital
In December 2015, the Mississippi PSC approved the In-Service Asset Rate Order, which among other things, provided for retail rate recovery of an annual revenue requirement of approximately $126 million effective December 17, 2015. The amount, type, and timing of future financings will depend upon regulatory approval, prevailing market conditions, and other factors, which includes resolution of Kemper IGCC cost recovery. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" and – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" and " – 2015 Rate Case" of Mississippi Power in Item 7 of the Form 10-K for additional information. Also see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Bonus Depreciation" of Mississippi Power in Item 7 of the Form 10-K for additional information.
Mississippi Power received $245 million of Initial DOE Grants in prior years that were used for the construction of the Kemper IGCC. An additional $25 million of grants from the DOE is expected to be received for commercial operation of the Kemper IGCC. 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.
On January 28, 2016, Mississippi Power issued a promissory note for up to $275 million to Southern Company, which matures in December 2017, bearing interest based on one-month LIBOR. During the first nine months of 2016, Mississippi Power borrowed $100 million pursuant to the $275 million promissory note and an additional $100 million under a separate promissory note issued to Southern Company in November 2015. On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicate of financial institutions for an aggregate amount of $1.2 billion. Mississippi Power borrowed $900 million on March 8, 2016 under the term loan agreement and the remaining $300 million on October 7, 2016. Mississippi Power used the initial proceeds to repay $900 million in maturing bank loans on March 8, 2016 and the remaining $300 million to repay at maturity Mississippi Power's Series 2011A 2.35% Senior Notes due October 15, 2016. The term loan pursuant to this agreement matures on April 1, 2018 and bears interest based on one-month LIBOR. On June 27, 2016, Mississippi Power received a capital contribution from Southern Company for $225 million, the proceeds of which were used to repay to Southern Company a portion of the existing promissory note issued in November 2015. As of September 30, 2016, the amount of outstanding promissory notes to Southern Company totaled $551 million.
Mississippi Power intends to utilize operating cash flows and lines of credit (to the extent available) as well as loans and, under certain circumstances, equity contributions from Southern Company to fund Mississippi Power's short-term capital needs.
At September 30, 2016, Mississippi Power had approximately $159 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2016 were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Expires | | | | Executable Term Loans | | Due Within One Year |
| 2016 | | 2017 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out |
| (in millions) | | (in millions) | | (in millions) | | (in millions) |
| $ | 100 |
| | $ | 75 |
| | $ | 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 Credit Arrangements" herein for additional information.
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
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(including guarantee obligations) of Mississippi Power. Such cross default provisions to other indebtedness would trigger an event of default if Mississippi Power defaulted on indebtedness or guarantee obligations over a specific threshold. Such cross acceleration provisions to other indebtedness would trigger an event of default if Mississippi Power defaulted on indebtedness, the payment of which was then accelerated. Mississippi Power is in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowing.
Subject to applicable market conditions, Mississippi Power expects to seek to renew or replace its credit arrangements as needed, prior to expiration. In connection therewith, Mississippi Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the $150 million unused credit arrangements with banks is allocated to provide liquidity support to Mississippi 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 September 30, 2016 was approximately $40 million.
Details of short-term borrowings were as follows:
|
| | | | | | | | | | | | | | | | |
| | | Short-term Debt at September 30, 2016 | | Short-term Debt During the Period(*) |
| | | Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) | | | | (in millions) |
| Short-term bank debt | | $ | 25 |
| | 2.2% | | $ | 25 |
| | 2.1% | | $ | 25 |
|
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 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 and/or Baa2 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, energy price risk management, and transmission. At September 30, 2016, the maximum potential collateral requirements under these contracts at a rating of BBB and/or Baa2 or BBB- and/or Baa3 was not material. The maximum potential collateral requirements at a rating below BBB- and/or Baa3 equaled approximately $259 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, a credit rating downgrade could impact the ability of Mississippi Power to access capital markets, and would be likely to impact the cost at which it does so.
On May 12, 2016, Fitch downgraded the senior unsecured long-term debt rating of Mississippi Power to BBB+ from A- and revised the ratings outlook from negative to stable.
Financing Activities
On January 28, 2016, Mississippi Power issued a promissory note for up to $275 million to Southern Company, which matures in December 2017, bearing interest based on one-month LIBOR. During the first nine months of 2016, Mississippi Power borrowed $100 million under this promissory note and an additional $100 million under a separate promissory note issued to Southern Company in November 2015. On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicate of financial institutions for an aggregate amount of
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
$1.2 billion. Mississippi Power borrowed $900 million on March 8, 2016 under the term loan agreement and the remaining $300 million on October 7, 2016. Mississippi Power used the initial proceeds to repay $900 million in maturing bank loans on March 8, 2016 and the remaining $300 million to repay at maturity Mississippi Power's Series 2011A 2.35% Senior Notes due October 15, 2016. The term loan pursuant to this agreement matures on April 1, 2018 and bears interest based on one-month LIBOR. On June 27, 2016, Mississippi Power received a capital contribution from Southern Company of $225 million, the proceeds of which were used to repay to Southern Company a portion of the promissory note issued in November 2015. As of September 30, 2016, the amount of outstanding promissory notes to Southern Company totaled $551 million.
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.
In September 2016, Mississippi Power entered into interest rate swaps to fix the variable interest rate on $900 million of the term loan entered into in March 2016.
SOUTHERN POWER COMPANY
AND SUBSIDIARY COMPANIES
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2016 | | 2015 | | 2016 | | 2015 |
| | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | |
| Wholesale revenues, non-affiliates | $ | 387 |
| | $ | 295 |
| | $ | 866 |
| | $ | 776 |
|
| Wholesale revenues, affiliates | 110 |
| | 104 |
| | 313 |
| | 303 |
|
| Other revenues | 3 |
| | 2 |
| | 10 |
| | 7 |
|
| Total operating revenues | 500 |
| | 401 |
| | 1,189 |
| | 1,086 |
|
| Operating Expenses: | | | | | | | |
| Fuel | 154 |
| | 118 |
| | 341 |
| | 361 |
|
| Purchased power, non-affiliates | 25 |
| | 17 |
| | 60 |
| | 52 |
|
| Purchased power, affiliates | 8 |
| | 5 |
| | 16 |
| | 18 |
|
| Other operations and maintenance | 81 |
| | 62 |
| | 246 |
| | 184 |
|
| Depreciation and amortization | 93 |
| | 64 |
| | 247 |
| | 183 |
|
| Taxes other than income taxes | 5 |
| | 6 |
| | 17 |
| | 17 |
|
| Total operating expenses | 366 |
|
| 272 |
| | 927 |
| | 815 |
|
| Operating Income | 134 |
| | 129 |
| | 262 |
| | 271 |
|
| Other Income and (Expense): | | | | | | | |
| Interest expense, net of amounts capitalized | (35 | ) | | (18 | ) | | (78 | ) | | (62 | ) |
| Other income (expense), net | 2 |
| | 1 |
| | 3 |
| | 1 |
|
| Total other income and (expense) | (33 | ) | | (17 | ) | | (75 | ) | | (61 | ) |
| Earnings Before Income Taxes | 101 |
| | 112 |
| | 187 |
| | 210 |
|
| Income taxes (benefit) | (102 | ) | | 1 |
| | (167 | ) | | 14 |
|
| Net Income | 203 |
| | 111 |
| | 354 |
| | 196 |
|
| Less: Net income attributable to noncontrolling interests | 27 |
| | 9 |
| | 39 |
| | 15 |
|
| Net Income Attributable to Southern Power | $ | 176 |
| | $ | 102 |
| | $ | 315 |
| | $ | 181 |
|
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2016 | | 2015 | | 2016 | | 2015 |
| | (in millions) | | (in millions) |
| Net Income | $ | 203 |
| | $ | 111 |
| | $ | 354 |
| | $ | 196 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
| Changes in fair value, net of tax of $14, $-, $(1), and $-, respectively | 23 |
| | — |
| | (1 | ) | | — |
|
Reclassification adjustment for amounts included in net
income, net of tax of $(1), $-, $7, and $-, respectively | (1 | ) | | — |
| | 13 |
| | — |
|
| Total other comprehensive income (loss) | 22 |
| | — |
| | 12 |
| | — |
|
| Less: Comprehensive income attributable to noncontrolling interests | 27 |
| | 9 |
| | 39 |
| | 15 |
|
| Comprehensive Income Attributable to Southern Power | $ | 198 |
| | $ | 102 |
| | $ | 327 |
| | $ | 181 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
|
| | | | | | | |
| | For the Nine Months Ended September 30, |
| | 2016 | | 2015 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 354 |
| | $ | 196 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 262 |
| | 187 |
|
| Deferred income taxes | (668 | ) | | 222 |
|
| Investment tax credits | — |
| | 294 |
|
| Amortization of investment tax credits | (25 | ) | | (14 | ) |
| Deferred revenues | 9 |
| | 15 |
|
| Collateral deposits | (80 | ) | | — |
|
| Accrued income taxes, non-current | — |
| | 100 |
|
| Other, net | 10 |
| | 10 |
|
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (82 | ) | | (28 | ) |
| -Prepaid income taxes | (16 | ) | | (116 | ) |
| -Other current assets | 1 |
| | 1 |
|
| -Accounts payable | 7 |
| | 1 |
|
| -Accrued taxes | 483 |
| | (247 | ) |
| -Other current liabilities | 14 |
| | (12 | ) |
| Net cash provided from operating activities | 269 |
| | 609 |
|
| Investing Activities: | | | |
| Business acquisitions | (1,134 | ) | | (1,128 | ) |
| Property additions | (1,702 | ) | | (348 | ) |
| Change in construction payables | (69 | ) | | 88 |
|
| Payments pursuant to long-term service agreements | (58 | ) | | (65 | ) |
| Investment in restricted cash | (750 | ) | | — |
|
| Distribution of restricted cash | 746 |
| | — |
|
| Other investing activities | (41 | ) | | (1 | ) |
| Net cash used for investing activities | (3,008 | ) | | (1,454 | ) |
| Financing Activities: | | | |
| Increase in notes payable, net | 692 |
| | 18 |
|
| Proceeds — | | | |
| Senior notes | 1,531 |
| | 650 |
|
| Capital contributions | 800 |
| | 226 |
|
| Other long-term debt | 63 |
| | 400 |
|
| Redemptions — | | | |
| Senior notes | — |
| | (525 | ) |
| Other long-term debt | (84 | ) | | (3 | ) |
| Distributions to noncontrolling interests | (22 | ) | | (6 | ) |
| Capital contributions from noncontrolling interests | 367 |
| | 274 |
|
| Purchase of membership interests from noncontrolling interests | (129 | ) | | — |
|
| Payment of common stock dividends | (204 | ) | | (98 | ) |
| Other financing activities | (14 | ) | | (5 | ) |
| Net cash provided from financing activities | 3,000 |
| | 931 |
|
| Net Change in Cash and Cash Equivalents | 261 |
| | 86 |
|
| Cash and Cash Equivalents at Beginning of Period | 830 |
| | 75 |
|
| Cash and Cash Equivalents at End of Period | $ | 1,091 |
| | $ | 161 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
| Interest (net of $32 and $4 capitalized for 2016 and 2015, respectively) | $ | 49 |
| | $ | 69 |
|
| Income taxes, net | 71 |
| | (215 | ) |
| Noncash transactions — Accrued property additions at end of period | 210 |
| | 120 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At September 30, 2016 | | At December 31, 2015 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 1,091 |
| | $ | 830 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 121 |
| | 75 |
|
| Other accounts receivable | | 25 |
| | 19 |
|
| Affiliated | | 67 |
| | 30 |
|
| Fossil fuel stock | | 14 |
| | 16 |
|
| Materials and supplies | | 163 |
| | 63 |
|
| Prepaid income taxes | | 61 |
| | 45 |
|
| Other current assets | | 32 |
| | 30 |
|
| Total current assets | | 1,574 |
| | 1,108 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 9,491 |
| | 7,275 |
|
| Less accumulated provision for depreciation | | 1,465 |
| | 1,248 |
|
| Plant in service, net of depreciation | | 8,026 |
| | 6,027 |
|
| Construction work in progress | | 1,652 |
| | 1,137 |
|
| Total property, plant, and equipment | | 9,678 |
| | 7,164 |
|
| Other Property and Investments: | | | | |
| Goodwill | | 2 |
| | 2 |
|
Other intangible assets, net of amortization of $16 and $12
at September 30, 2016 and December 31, 2015, respectively | | 389 |
| | 317 |
|
| Total other property and investments | | 391 |
| | 319 |
|
| Deferred Charges and Other Assets: | | | | |
| Prepaid long-term service agreements | | 151 |
| | 166 |
|
| Accumulated deferred income taxes | | 199 |
| | — |
|
| Other deferred charges and assets — affiliated | | 3 |
| | 9 |
|
| Other deferred charges and assets — non-affiliated | | 355 |
| | 139 |
|
| Total deferred charges and other assets | | 708 |
| | 314 |
|
| Total Assets | | $ | 12,351 |
| | $ | 8,905 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholders' Equity | | At September 30, 2016 | | At December 31, 2015 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 60 |
| | $ | 403 |
|
| Notes payable | | 828 |
| | 137 |
|
| Accounts payable — | | | | |
| Affiliated | | 91 |
| | 66 |
|
| Other | | 218 |
| | 327 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 147 |
| | 198 |
|
| Other accrued taxes | | 16 |
| | 5 |
|
| Accrued interest | | 30 |
| | 23 |
|
| Contingent consideration | | 30 |
| | 36 |
|
| Other current liabilities | | 97 |
| | 44 |
|
| Total current liabilities | | 1,517 |
| | 1,239 |
|
| Long-term Debt | | 4,548 |
| | 2,719 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 140 |
| | 601 |
|
| Accumulated deferred investment tax credits | | 1,385 |
| | 889 |
|
| Accrued income taxes, non-current | | 109 |
| | 109 |
|
| Asset retirement obligations | | 40 |
| | 21 |
|
| Deferred capacity revenues — affiliated | | 19 |
| | 17 |
|
| Other deferred credits and liabilities | | 115 |
| | 3 |
|
| Total deferred credits and other liabilities | | 1,808 |
| | 1,640 |
|
| Total Liabilities | | 7,873 |
| | 5,598 |
|
| Redeemable Noncontrolling Interests | | 49 |
| | 43 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, par value $.01 per share — | | | | |
| Authorized — 1,000,000 shares | | | | |
| Outstanding — 1,000 shares | | — |
| | — |
|
| Paid-in capital | | 2,620 |
| | 1,822 |
|
| Retained earnings | | 769 |
| | 657 |
|
| Accumulated other comprehensive income (loss) | | 16 |
| | 4 |
|
| Total common stockholder's equity | | 3,405 |
| | 2,483 |
|
| Noncontrolling interests | | 1,024 |
| | 781 |
|
| Total stockholders' equity | | 4,429 |
| | 3,264 |
|
| Total Liabilities and Stockholders' Equity | | $ | 12,351 |
| | $ | 8,905 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRD QUARTER 2016 vs. THIRD QUARTER 2015
AND
YEAR-TO-DATE 2016 vs. YEAR-TO-DATE 2015
OVERVIEW
Southern Power constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Power continually seeks opportunities to execute its strategy to create value through various transactions including acquisitions and sales of assets, construction of new generating facilities, and entry into PPAs primarily with investor-owned utilities, independent power producers, municipalities, electric cooperatives, and other load-serving entities. In general, Southern Power has constructed or acquired new generating capacity only after entering into or assuming long-term PPAs for the new facilities.
During the nine months ended September 30, 2016, Southern Power acquired or commenced construction of approximately 758 MWs of additional solar and wind facilities and, subsequent to September 30, 2016, acquired or commenced construction of approximately 977 MWs of wind and natural gas facilities. In addition, Southern Power has committed to acquire approximately 674 MWs of solar and wind facilities over the next several months. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information.
At September 30, 2016, Southern Power had an average investment coverage ratio of 92% through 2020 and 91% 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
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $74 | | 72.5 | | $134 | | 74.0 |
Net income attributable to Southern Power for the third quarter 2016 was $176 million compared to $102 million for the corresponding period in 2015. Net income attributable to Southern Power for year-to-date 2016 was $315 million compared to $181 million for the corresponding period in 2015. The increases were primarily due to increased federal income tax benefits from solar ITCs and wind PTCs and increased renewable energy sales, partially offset by increases in depreciation, operations and maintenance expenses, and interest expense from debt issuances, all related to new solar and wind facilities.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Operating Revenues
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $99 | | 24.7 | | $103 | | 9.5 |
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.
Capacity revenues are an integral component of Southern Power's natural gas and biomass PPAs. Energy under these PPAs is generally sold at variable cost or is indexed to published gas indices. Energy revenues also include fees for support services, fuel storage, and unit start charges.
Southern Power's electricity sales from solar and wind generating facilities are also through long-term PPAs; however, these solar and wind PPAs do not have a capacity charge and customers purchase the energy output of a dedicated renewable facility through an energy charge. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, and other factors.
|
| | | | | | | | | | | |
| | Third Quarter 2016
vs.
Third Quarter 2015 | | Year-to-Date 2016
vs.
Year-to-Date 2015 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| PPA capacity revenues | $ | (19 | ) | | (11.8) | | $ | (25 | ) | | (5.8) |
| PPA energy revenues | 62 |
| | 33.3 | | 79 |
| | 17.5 |
| Total PPA revenues | 43 |
| | 11.8 | | 54 |
| | 6.1 |
| Revenues not covered by PPAs | 55 |
| | 121.9 | | 46 |
| | 23.4 |
| Other revenues | 1 |
| | 50.0 | | 3 |
| | 42.9 |
| Total operating revenues | $ | 99 |
| | 24.7% | | $ | 103 |
| | 9.5% |
In the third quarter 2016, operating revenues were $500 million compared to $401 million for the corresponding period in 2015. The $99 million increase in operating revenues was primarily due to the following:
PPA capacity revenues decreased $19 million primarily due to the remarketing of generation capacity into the short-term markets as a result of PPA expirations.
PPA energy revenuesincreased $62 million primarily due to an increase in renewable energy sales from new solar and wind facilities.
Revenues not covered by PPAs increased $55 million primarily due to an increase in short-term sales to non-affiliates as a result of the remarketing of generation capacity from expired PPAs.
For year-to-date 2016, operating revenues were $1.2 billion compared to $1.1 billion for the corresponding period in 2015. The $103 million increase in operating revenues was primarily due to the following:
PPA capacity revenues decreased $25 million as a result of a $44 million decrease in non-affiliate capacity revenues primarily due to the remarketing of generation capacity into the short-term markets as a result of PPA expirations, partially offset by a $19 million increase in affiliate capacity revenues due to new PPAs.
PPA energy revenuesincreased $79 million primarily due to a $122 million increase in renewable energy sales arising from new solar and wind facilities, partially offset by a decrease of $43 million in fuel revenues related to natural gas facility PPAs.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Revenues not covered by PPAs increased $46 million due to a $70 million increase in short-term sales to non-affiliates as a result of the remarketing of generation capacity from expired PPAs, partially offset by a $24 million decrease in power pool revenue primarily associated with a reduction in available uncovered capacity.
Wholesale revenues will vary depending on the energy demand of Southern Power's customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Power's energy. Increases and decreases in revenues under PPAs that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.
Fuel and Purchased Power Expenses
Fuel costs constitute the single largest expense for Southern Power. In addition, Southern Power purchases a portion of its electricity needs from the wholesale market and the power pool. Details of Southern Power's generation and purchased power were as follows:
|
| | | | | |
| | Third Quarter 2016 | Third Quarter 2015 | | Year-to-Date 2016 | Year-to-Date 2015 |
| | (in billions of KWHs) |
| Generation | 11.1 | 9.4 | | 27.9 | 24.8 |
| Purchased power | 0.9 | 0.5 | | 2.5 | 1.5 |
| Total generation and purchased power | 12.0 | 9.9 | | 30.4 | 26.3 |
Total generation and purchased power excluding solar, wind, and tolling agreements | 6.7 | 5.2 | | 17.7 | 15.9 |
Southern Power's PPAs for natural gas and biomass generation generally provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing Southern Power for substantially all of the cost of fuel relating to the energy delivered under such PPAs. Consequently, changes in such fuel costs are generally accompanied by a corresponding change in related fuel revenues and do not have a significant impact on net income. Southern Power is responsible for the cost of fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the wholesale market or into the power pool, for capacity owned directly by Southern Power (excluding its subsidiaries).
Purchased power expenses will vary depending on demand, availability, and the cost of generating resources throughout the Southern Company system and other contract resources. Load requirements are submitted to the power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power, an affiliate company, or external parties.
|
| | | | | | | | | | | | |
| | | Third Quarter 2016
vs.
Third Quarter 2015 | | Year-to-Date 2016
vs.
Year-to-Date 2015 |
| | | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | | $ | 36 |
| | 30.5 | | $ | (20 | ) | | (5.5) |
| Purchased power | | 11 |
| | 50.0 | | 6 |
| | 8.6 |
| Total fuel and purchased power expenses | | $ | 47 |
| | | | $ | (14 | ) | | |
In the third quarter 2016, total fuel and purchased power expenses were $187 million compared to $140 million for the corresponding period in 2015. The increase was primarily due to the following:
Fuel expense increased $36 million primarily due to a $27 million increase associated with the volume of KWHs generated and a $9 million increase associated with average cost of natural gas per KWH generated.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Purchased power expense increased $11 million due to a $19 million increase associated with the volume of KWHs purchased, partially offset by a $4 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 $417 million compared to $431 million for the corresponding period in 2015. The decrease was primarily due to the following:
Fuel expense decreased $20 million primarily due to a $42 million decrease associated with the average cost of natural gas per KWH generated, partially offset by a $22 million increase associated with the volume of KWHs generated.
Purchased power expense increased $6 million due to a $48 million increase associated with the volume of KWHs purchased, largely offset by a $30 million decrease in the average cost of purchased power and a $12 million decrease associated with a PPA expiration.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $19 | | 30.6 | | $62 | | 33.7 |
In the third quarter 2016, other operations and maintenance expenses were $81 million compared to $62 million for the corresponding period in 2015. The increase was primarily due to a $9 million increase in expenses associated with new solar and wind facilities placed in service in 2015 and 2016, a $5 million increase associated with scheduled outage and maintenance expenses, and a $3 million increase in general business expenses associated with Southern Power's overall growth strategy.
For year-to-date 2016, other operations and maintenance expenses were $246 million compared to $184 million for the corresponding period in 2015. The increase was primarily due to a $24 million increase associated with scheduled outage and maintenance expenses, a $22 million increase in expenses associated with new solar and wind facilities placed in service in 2015 and 2016, and a $14 million increase in general business expenses associated with Southern Power's overall growth strategy.
Depreciation and Amortization
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $29 | | 45.3 | | $64 | | 35.0 |
In the third quarter 2016, depreciation and amortization was $93 million compared to $64 million for the corresponding period in 2015. For year-to-date 2016, depreciation and amortization was $247 million compared to $183 million for the corresponding period in 2015. The increases were primarily due to additional depreciation related to new solar and wind facilities placed in service in 2015 and 2016.
Interest Expense, net of Amounts Capitalized
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $17 | | 94.4 | | $16 | | 25.8 |
In the third quarter 2016, interest expense, net of amounts capitalized was $35 million compared to $18 million for the corresponding period in 2015. The increase was primarily due to an increase of $25 million in interest expense related to additional debt issued since the third quarter of 2015 primarily to fund Southern Power's growth strategy and continuous construction program, partially offset by an $8 million increase in capitalized interest associated
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
with the construction of solar facilities.
For year-to-date 2016, interest expense, net of amounts capitalized was $78 million compared to $62 million for the corresponding period in 2015. The increase was primarily due to an increase of $43 million in interest expense related to additional debt issued since the third quarter of 2015 primarily to fund Southern Power's growth strategy and continuous construction program, largely offset by a $27 million increase in capitalized interest associated with the construction of solar facilities.
Income Taxes (Benefit)
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(103) | | N/M | | $(181) | | N/M |
N/M - Not meaningful
In the third quarter 2016, income tax benefit was $(102) million compared to an expense of $1 million for the corresponding period in 2015. The change was primarily due to a $96 million increase in federal income tax benefits from solar ITCs and wind PTCs in 2016 and a $10 million decrease in tax expense related to lower pre-tax earnings in 2016, partially offset by a $3 million increase in tax expense related to beneficial state apportionment rate changes in 2015.
For year-to-date 2016, income tax benefit was $(167) million compared to an expense of $14 million for the corresponding period in 2015. The change was primarily due to a $171 million increase in federal income tax benefits from solar ITCs and wind PTCs in 2016 and a $17 million decrease in tax expense related to lower pre-tax earnings in 2016, partially offset by a $7 million increase in tax expense related to beneficial state apportionment rate changes in 2015.
See Note (G) to the Condensed Financial Statements herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern Power's future earnings potential. The level of Southern Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Power's competitive wholesale business. These factors include: Southern Power's ability to achieve sales growth while containing costs; regulatory matters; creditworthiness of customers; total generating capacity available in Southern Power's market areas; the successful remarketing of capacity as current contracts expire; Southern Power's ability to execute its growth strategy, including successful additional investments in renewable and other energy projects, and to construct generating facilities; and the impact of federal 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 generation from units within the power pool, and operational limitations. For additional information relating to these factors, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Power in Item 7 of the Form 10-K.
Power Sales Agreements
See BUSINESS – "The Southern Company System – Southern Power" in Item 1 of the Form 10-K for additional information regarding Southern Power's PPAs. Generally, under the solar and wind generation PPAs, the purchasing party retains the right to keep or resell the renewable energy credits.
At 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% through 2020 and 70% through 2025, with an average remaining contract duration of approximately 10 years.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Power believes an investment coverage ratio best identifies the value 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 September 30, 2016, the average investment coverage ratio was 92% through 2020 and 91% through 2025, with an average remaining contract duration of approximately 17 years. At December 31, 2015, the average investment coverage ratio would have been 91% through 2020 and 90% through 2025, with an average remaining contract duration of approximately 18 years.
Environmental Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Power in Item 7 of the Form 10-K for information on the development by federal and state environmental regulatory agencies of additional control strategies for emissions of air pollution from industrial sources, including electric generating facilities. Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, water quality, or other environmental and health concerns could also significantly affect Southern Power. While Southern Power's PPAs generally contain provisions that permit charging the counterparty with some of the new costs incurred as a result of changes in environmental laws and regulations, the full impact of any such legislative or regulatory changes cannot be determined at this time.
Environmental Statutes and Regulations
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 of the Form 10-K for additional information regarding the EPA's Cross State Air Pollution Rule (CSAPR).
On October 26, 2016, the EPA published a final rule that updates the CSAPR ozone season nitrogen oxide program, including revising ozone-season emissions budgets in Alabama and Texas and removing Florida and North Carolina from the CSAPR program. The ultimate impact of this rule will depend on the outcome of any legal challenges and implementation at the state level and cannot be determined at this time.
Acquisitions
During 2016, in accordance with its overall growth strategy, Southern Power or one of its wholly-owned subsidiaries, Southern Renewable Partnerships, LLC and Southern Renewable Energy, Inc., acquired or contracted to acquire 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
|
| | | | | | | | |
| Project Facility | Resource | Approximate Nameplate Capacity (MW) | Location | Percentage Ownership | Actual/Expected COD | PPA Contract Period |
| Acquisitions During the Nine Months Ended September 30, 2016 |
| Calipatria | Solar | 20 | Imperial County, CA | 90 | % | | February 2016 | 20 years |
| East Pecos | Solar | 120 | Pecos County, TX | 100 | % | | December 2016 | 15 years |
| Grant Plains | Wind | 147 | Grant County, OK | 100 | % | | December 2016 | Up to 20 years |
| Grant Wind | Wind | 151 | Grant County, OK | 100 | % | | April 2016 | 20 years |
| Henrietta | Solar | 102 | Kings County, CA | 51 | % | (a) | July 2016 | 20 years |
| Lamesa | Solar | 102 | Dawson County, TX | 100 | % | | First quarter 2017 | 15 years |
| Passadumkeag | Wind | 42 | Penobscot County, ME | 100 | % | | July 2016 | 15 years |
| Rutherford | Solar | 74 | Rutherford County, NC | 90 | % | | December 2016 | 15 years |
| Acquisitions Subsequent to September 30, 2016 |
| Mankato | Natural Gas | 375 | Mankato, MN | 100 | % | | N/A(b) | 10 years |
| Wake Wind | Wind | 257 | Floyd and Crosby Counties, TX | 90.1 | % | | October 2016 | 12 years |
| |
| (a) | Southern Power owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. Southern Power and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the project. In addition, Southern Power is entitled to substantially all of the federal tax benefits with respect to the transaction. |
| |
| (b) | The Mankato facility is a fully operational 375-MW natural gas-fired combined-cycle facility with an additional 345-MW expansion under development. |
Acquisitions During the Nine Months Ended September 30, 2016
Southern Power's aggregate purchase price for the project facilities acquired during the nine months ended September 30, 2016 was approximately $830 million. Total aggregate construction costs, excluding the acquisition costs, are expected to be $708 million to $775 million for East Pecos, Grant Plains, Lamesa, and Rutherford, which are currently under construction. The ultimate outcome of these matters cannot be determined at this time.
Acquisitions Subsequent to September 30, 2016
Southern Power's aggregate purchase price for acquisitions subsequent to September 30, 2016 was approximately $873 million. As part of Southern Power's acquisition of Mankato, which has a fully operational 375-MW natural gas-fired combined-cycle facility, Southern Power has commenced construction of an additional 345-MW expansion which is covered with a 20-year PPA. Total aggregate construction costs, excluding the acquisition costs allocated to CWIP, are expected to be $170 million to $190 million. The ultimate outcome of this matter cannot be determined at this time.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Acquisition Agreements Executed but Not Yet Closed
During the nine months ended September 30, 2016 and subsequent to that date, Southern Power entered into agreements to acquire the following projects for an aggregate purchase price of approximately $1.2 billion:
51% ownership interest (through 100% ownership of the class A membership interests entitling Southern Power to 51% of all cash distributions and most of the federal tax benefits) in a 100-MW solar facility in Nevada covered with a 20-year PPA, which is expected to close in November 2016;
100% ownership interests in two wind facilities in Texas totaling 299 MWs, the majority of which is contracted under PPAs for the first 12 to 14 years of operation and are expected to close before the end of 2016; and
100% ownership interest in a 275-MW wind facility in Texas, the majority of which is contracted under a 12-year PPA and is expected to close in January 2017.
The ultimate outcome of these matters cannot be determined at this time.
The aggregate amount of revenue recognized by Southern Power related to the project facilities acquired during the nine months ended September 30, 2016 included in the condensed consolidated statements of income for year-to-date 2016 is $14 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 nine months ended September 30, 2016 included in the condensed consolidated statements 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
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" of Southern Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information.
During the nine months ended September 30, 2016, in accordance with its overall growth strategy, Southern Power completed construction of and placed in service, or continued construction of, the projects set forth in the following table. Through September 30, 2016, total costs of construction incurred for the following projects were $3.0 billion, of which $1.2 billion remains in CWIP. Including the total construction costs incurred through September 30, 2016 and the acquisition prices allocated to CWIP, total aggregate construction costs for the following projects are estimated to be $3.1 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
|
| | | | |
| Solar Facility | Approximate Nameplate Capacity (MW) | Location | Actual/Expected COD | PPA Contract Period |
| Projects Completed During the Nine Months Ended September 30, 2016 |
| Butler Solar Farm | 22 | Taylor County, GA | February 2016 | 20 years |
Desert Stateline(a) | 299(b) | San Bernardino County, CA | Through July 2016 | 20 years |
| Garland A | 20 | Kern County, CA | August 2016 | 20 years |
| Pawpaw | 30 | Taylor County, GA | March 2016 | 30 years |
| Tranquillity | 205 | Fresno County, CA | July 2016 | 18 years |
| Projects Under Construction as of September 30, 2016 |
| Butler | 103 | Taylor County, GA | December 2016 | 30 years |
| Garland | 185 | Kern County, CA | October 2016 | 15 years |
| Roserock | 160 | Pecos County, TX | November 2016 | 20 years |
| Sandhills | 146 | Taylor County, GA | October 2016 | 25 years |
| |
| (a) | On March 29, 2016, Southern Power acquired an additional 15% interest in Desert Stateline. As a result, Southern Power and the class B member are entitled to 66% and 34%, respectively, of all cash distributions from Desert Stateline. In addition, Southern Power will continue to be entitled to substantially all of the federal tax benefits with respect to the transaction. |
| |
| (b) | The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and 189 MWs were placed in service during the nine months ended September 30, 2016. |
Income Tax Matters
Bonus Depreciation
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Bonus Depreciation" of Southern Power in Item 7 of the Form 10-K for additional information.
The extension of 50% bonus depreciation included in the PATH Act is expected to result in approximately $650 million of positive cash flows for the 2016 tax year, which may not all be realized in 2016 due to a projected consolidated net operating loss (NOL) for Southern Company. As a result, the NOL will increase deferred tax assets for federal ITC and PTC carryforwards. See Note (G) to the Condensed Financial Statements under "Current and Deferred Income Taxes – Net Operating Loss" and " – Tax Credit Carryforwards" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.
Other Matters
Southern Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Power is subject to certain claims and legal actions arising in the ordinary course of business. Southern Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
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-Lived Assets and Intangibles, Acquisition Accounting, Depreciation, and ITCs.
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 accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. Southern 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 Southern Power's balance sheet.
FINANCIAL CONDITION AND LIQUIDITY
Overview
Southern Power's financial condition remained stable at September 30, 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 of Capital" herein for additional information on lines of credit.
Net cash provided from operating activities totaled $269 million for the first nine months of 2016 compared to $609 million for the first nine months of 2015. The decrease in net cash provided from operating activities was primarily due to an increase in unutilized ITCs and PTCs. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Bonus Depreciation" herein for additional information. Net cash used for investing activities totaled $3.0 billion for the first nine months of 2016 primarily due to acquisitions and the construction of renewable facilities. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information. Net cash provided from financing activities totaled $3.0 billion for the first nine months of 2016 primarily due to an increase in senior notes, notes payable, and capital contributions 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 nine months of 2016 include a $515 million increase in CWIP due to the acquisition and continued construction of new solar and wind facilities and a $2.2 billion increase in plant in service, primarily due to solar and wind facilities being placed in service. Other significant changes include a $261 million increase in cash and cash equivalents and a $2.5 billion increase in notes payable and long-term debt primarily due to additional borrowings to fund acquisitions and construction projects. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" 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
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
description of Southern Power's capital requirements for its construction program, scheduled maturities of long-term debt, as well as the related interest, leases, derivative obligations, unrecognized tax benefits, and other purchase commitments. Approximately $60 million will be required to repay maturities of long-term debt through September 30, 2017. In addition, during the nine months ended September 30, 2016, and subsequent to that date, Southern Power entered into new long-term service agreements (LTSA), which begin between 2017 and 2020 and result in additional future commitments totaling approximately $927 million.
Southern Power's construction program includes estimates for potential plant acquisitions, new construction, capital improvements, and work to be performed under LTSAs, and is subject to periodic review and revision. Planned expenditures for plant acquisitions may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. Capital expenditures for Southern Power are currently estimated to total approximately $4.5 billion for 2016, primarily for acquisitions and/or construction of new generating facilities. Capital expenditures for Southern Power are currently estimated to total approximately $1.6 billion annually for 2017 through 2021. Actual capital costs may vary from these estimates because of numerous factors such as: changes in business conditions; changes in the expected environmental compliance program; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in FERC rules and regulations; changes in load projections; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. See Note (I) to the Condensed Financial Statements herein for additional information.
Sources of Capital
Southern Power plans to obtain the funds required for acquisitions, construction, and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, securities issuances, term loans, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Power in Item 7 of the Form 10-K for additional information.
Southern Power's current liabilities sometimes exceed current assets due to the use of short-term debt as a funding source, and construction payables, as well as fluctuations in cash needs, due to both seasonality and the stage of acquisitions and construction projects. Southern Power expects to utilize the capital markets, bank term loans, and commercial paper markets as the source of funds for the majority of its debt maturities.
As of September 30, 2016, Southern Power had cash and cash equivalents of approximately $1.1 billion.
Details of short-term borrowings were as follows:
|
| | | | | | | | | | |
| | Short-term Debt During the Period (*) |
| | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | (in millions) | | | | (in millions) |
| Commercial paper | $ | 10 |
| | 0.9 | % | | $ | 62 |
|
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2016. No short-term debt was outstanding at September 30, 2016. |
Company Credit Facility
At September 30, 2016, Southern Power had a committed credit facility (Facility) of $600 million expiring in 2020, of which $68 million has been used for letters of credit and $532 million remains unused. Southern Power's subsidiaries are not borrowers under the Facility.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 capitalization excludes the capital stock or other equity attributable to such subsidiary. Southern Power is currently in compliance with all covenants in the Facility.
Proceeds from the Facility may be used for working capital and general corporate purposes as well as liquidity support for Southern Power's commercial paper program. Subject to applicable market conditions, Southern Power expects to renew or replace the Facility, as needed, prior to expiration. In connection therewith, Southern Power may extend the maturity date and/or increase or decrease the lending commitment thereunder. See Note 6 to the financial statements of Southern Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
Southern Power's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes, including maturing debt. Southern Power's subsidiaries are not borrowers under the commercial paper program.
Subsidiary Credit Facilities
In connection with the construction of solar facilities byRE Garland Holdings LLC, RE Roserock LLC, and RE Tranquillity LLC, indirect subsidiaries of Southern Power, each subsidiary entered into separate credit agreements (Project Credit Facilities), which are non-recourse to Southern Power (other than the subsidiary party to the agreement). Each Project Credit Facility provides (a) a senior secured construction loan credit facility, (b) a senior secured bridge loan facility, and (c) a senior secured letter of credit facility that is secured by the membership interests of the respective project company, with proceeds directed to finance project costs related to the respective solar facilities. Each Project Credit Facility is secured by the assets of the applicable project subsidiary and membership interests of the applicable project subsidiary. The table below summarizes each Project Credit Facility as of September 30, 2016.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Project | | Maturity Date | | Construction Loan Facility | | Bridge Loan Facility | | Total Loan Facility | | Loan Facility Undrawn | | Letter of Credit Facility | | Letter of Credit Facility Undrawn |
| | | | | (in millions) |
| Garland | | Earlier of PPA COD or November 30, 2016 | | $ | 86 |
| | $ | 308 |
| | $ | 394 |
| | $ | 21 |
| | $ | 49 |
| | $ | 23 |
|
| Roserock | | Earlier of PPA COD or November 30, 2016(*) | | 63 |
| | 180 |
| | 243 |
| | 34 |
| | 23 |
| | 16 |
|
| Tranquillity | | October 14, 2016 | | 86 |
| | 172 |
| | 258 |
| | 12 |
| | 77 |
| | 26 |
|
| Total | | | | $ | 235 |
| | $ | 660 |
| | $ | 895 |
| | $ | 67 |
| | $ | 149 |
| | $ | 65 |
|
| |
| (*) | Subsequent to September 30, 2016, Roserock extended the maturity date of its Project Credit Facility to December 31, 2016. |
The Project Credit Facilities above had total amounts outstanding as of September 30, 2016 of $828 million at a weighted average interest rate of 2.05%. For the three-month period ended September 30, 2016, these credit agreements had a maximum amount outstanding of $828 million and an average amount outstanding of $805 million at a weighted average interest rate of 2.02%.
Furthermore, in connection with the acquisition of the Henrietta solar facility on July 1, 2016, a subsidiary of Southern Power assumed a $217 million construction loan, which was fully repaid prior to September 30, 2016. For the three-month period ended September 30, 2016, this credit agreement had a maximum amount outstanding of $217 million and an average amount outstanding of $137 million at a weighted average interest rate of 2.21%.
Southern Power believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility, bank term loans, and operating cash flows.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Credit Rating Risk
Southern Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2, or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, energy price risk management, transmission, and foreign currency risk management.
The maximum potential collateral requirements under these contracts at September 30, 2016 were as follows:
|
| | | |
| Credit Ratings | Maximum Potential
Collateral
Requirements |
| | (in millions) |
| At BBB and/or Baa2 | $ | 30 |
|
| At BBB- and/or Baa3 | $ | 385 |
|
| Below BBB- and/or Baa3 | $ | 1,104 |
|
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, a credit rating downgrade could impact the ability of Southern Power to access capital markets and would be likely to impact the cost at which it does so.
In addition, Southern Power has a PPA that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power's credit. The PPA requires credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses resulting from a credit downgrade.
Financing Activities
In June 2016, Southern Power issued €600 million aggregate principal amount of Series 2016A 1.00% Senior Notes due June 20, 2022 and €500 million aggregate principal amount of Series 2016B 1.85% Senior Notes due June 20, 2026. The proceeds are being allocated to renewable energy generation projects. Southern Power's obligations under its euro-denominated fixed-rate notes were effectively converted to fixed-rate U.S. dollars at issuance through cross-currency swaps, removing foreign currency exchange risk associated with the interest and principal payments. See Note (H) to the Condensed Financial Statements under "Foreign Currency Derivatives" herein for additional information.
In September 2016, Southern Power issued $290 million aggregate principal amount of Series 2016C 2.75% Senior Notes due September 20, 2023. The proceeds were used for general corporate purposes, including Southern Power's growth strategy and continuous construction program, as well as repayment of amounts outstanding under the Project Credit Facilities.
Also in September 2016, Southern Power repaid $80 million of an outstanding $400 million floating rate bank loan and extended the maturity date of the remaining $320 million from September 2016 to September 2018. In addition, Southern Power entered into a $60 million aggregate principal amount floating rate bank loan bearing interest based on one-month LIBOR due September 2017. The proceeds were used to repay existing indebtedness and for other general corporate purposes.
In addition, Southern Power issued $34 million in letters of credit during the nine months ended September 30, 2016.
During the nine months ended September 30, 2016, Southern Power's subsidiaries incurred an additional $691 million of short-term borrowings pursuant to the Project Credit Facilities at a weighted average interest rate of 2.05%. Furthermore, in connection with the acquisition of the Henrietta solar facility, a subsidiary of Southern
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Power assumed a $217 million construction loan, which was fully repaid prior to September 30, 2016. In addition, Southern Power's subsidiaries issued $16 million in letters of credit.
Subsequent to September 30, 2016, Southern Power's subsidiaries borrowed $5 million pursuant to the Project Credit Facilities at a weighted average interest rate of 2.03%. In addition, on October 14, 2016, Southern Power repaid at maturity $246 million of Project Credit Facility debt.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
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, 2015 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended September 30, 2016 and 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.
Southern Company's financial statements reflect its investments in its subsidiaries, including Southern Company Gas as a result of the Merger, on a consolidated basis. Southern Company Gas' results of operations and cash flows since July 1, 2016 and financial condition as of September 30, 2016 are reflected within Southern Company's consolidated amounts in these accompanying notes herein. Southern Company Gas continues to maintain reporting requirements as an SEC registrant and has filed its Quarterly Report on Form 10-Q with the SEC separately from this combined Form 10-Q. The equity method is used for entities in which Southern Company has significant influence but does not control, including Southern Company Gas' investment in Southern Natural Gas Company, L.L.C. (SNG), and for variable interest entities where Southern Company has an equity investment but is not the primary beneficiary. See Note (I) under "Southern Company– Merger with Southern Company Gas" and " – Investment in Southern Natural Gas" for additional information regarding the Merger and Southern Company Gas' investment in SNG, respectively.
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.
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 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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
permitted. The registrants are currently evaluating the new standard and have not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on the registrants' balance sheets.
On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation(Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions. Most significantly, entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or 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 as additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016. Early adoption is permitted and Southern Company and the traditional electric operating companies intend to adopt the ASU 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 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 $108 million made by Georgia Power to PowerSecure under the two agreements since inception in 2014 are included in CWIP at September 30, 2016. PowerSecure construction service costs of approximately $0.2 million are included in accounts payable, affiliated in Georgia Power's balance sheet at September 30, 2016. On October 4, 2016, the two facilities began commercial operation.
Prior to Southern Company Gas' completion of its acquisition of a 50% equity interest in SNG, Southern Company and Southern Company Gas had entered into long-term interstate natural gas transportation agreements with SNG. The interstate transportation service provided to the traditional electric operating companies, Southern Power, and Southern Company Gas by SNG pursuant to these agreements is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. For the period subsequent to Southern Company Gas' investment in SNG, transportation costs paid to SNG by Southern Company were approximately $16 million, including $8 million for Georgia Power, $2 million for Southern Power, and $1 million for Alabama Power.
See Note (I) under "Southern Company– Acquisition of PowerSecure International, Inc." and " – Investment in Southern Natural Gas" for additional information regarding Southern Company's acquisition of PowerSecure and Southern Company Gas' investment in SNG, respectively.
Asset Retirement Obligations
See Note 1 to the financial statements of Southern Company, Alabama Power, Georgia Power, 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 Southern Company's and the traditional electric operating companies' asset retirement obligations (ARO) and the EPA's regulation of CCR. See Note 1 to the financial statements of Southern Power under "Asset Retirement Obligations" in Item 8 of the Form 10-K for additional information regarding Southern Power's AROs.
The cost estimates below are based on information as of September 30, 2016. The cost estimates for AROs related to the disposal of CCR are based on various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the Disposal of Coal Combustion Residuals from Electric Utilities final rule requirements for closure in place or by other methods. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, the traditional electric operating companies expect to continue to periodically update these estimates.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
As of September 30, 2016, details of the AROs included in the registrants' Condensed Balance Sheets were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power | | Southern Power |
| | (in millions) |
| Balance at beginning of year | $ | 3,759 |
| | $ | 1,448 |
| | $ | 1,916 |
| | $ | 130 |
| | $ | 177 |
| | $ | 21 |
|
| Liabilities incurred | 41 |
| | 5 |
| | — |
| | — |
| | 15 |
| | 18 |
|
| Liabilities settled | (117 | ) | | (12 | ) | | (93 | ) | | — |
| | (12 | ) | | — |
|
| Accretion | 119 |
| | 55 |
| | 56 |
| | 2 |
| | 3 |
| | 1 |
|
| Cash flow revisions | 712 |
| | 31 |
| | 675 |
| | 2 |
| | 7 |
| | — |
|
| Balance at end of period | $ | 4,514 |
| | $ | 1,527 |
| | $ | 2,554 |
| | $ | 134 |
| | $ | 190 |
| | $ | 40 |
|
The traditional electric operating companies' increases in cash flow revisions for the nine months ended September 30, 2016 primarily relate to changes in ash pond closure strategy. The increase for Georgia Power reflects its decision in June 2016 to cease operating and stop receiving coal ash at all of its ash ponds within the next three years and to eventually close all of its ash ponds either by removal, consolidation, and/or recycling for the beneficial use of coal ash or through closure in place using advanced engineering methods.
Goodwill and Other Intangible Assets
As of September 30, 2016, goodwill was as follows: |
| | | |
| | As of September 30, 2016 |
| | (in millions) |
| Southern Company | $ | 6,223 |
|
| Southern Power | $ | 2 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
As of September 30, 2016, other intangible assets were as follows:
|
| | | | | | | | | | |
| | | As of September 30, 2016 |
| | Estimated Useful Life | Gross Carrying Amount | Accumulated Amortization | Other Intangible Assets, Net |
| | | (in millions) |
| Southern Company | | | | |
| Other intangible assets subject to amortization: | | | | |
| Customer relationships | 11-26 years | $ | 268 |
| $ | (16 | ) | $ | 252 |
|
| Trade names | 5-28 years | 158 |
| (3 | ) | 155 |
|
| Patents | 3-10 years | 4 |
| — |
| 4 |
|
| Backlog | 5 years | 5 |
| — |
| 5 |
|
| Storage and transportation contracts | 1-5 years | 64 |
| (4 | ) | 60 |
|
| Software and other | 1-12 years | 2 |
| — |
| 2 |
|
| PPA fair value adjustments | 19-20 years | 405 |
| (16 | ) | 389 |
|
| Total other intangible assets subject to amortization | | $ | 906 |
| $ | (39 | ) | $ | 867 |
|
| Other intangible assets not subject to amortization: | | | | |
| Federal Communications Commission licenses | | $ | 75 |
| $ | — |
| $ | 75 |
|
| Total other intangible assets | | $ | 981 |
| $ | (39 | ) | $ | 942 |
|
| | | | | |
| Southern Power | | | | |
| Other intangible assets subject to amortization: | | | | |
| PPA fair value adjustments | 19-20 years | $ | 405 |
| $ | (16 | ) | $ | 389 |
|
Amortization associated with other intangible assets was as follows:
|
| | | | | | |
| | Three Months Ended | Nine Months Ended |
| | September 30, 2016 |
| | (in millions) |
| Southern Company | $ | 25 |
| $ | 27 |
|
| Southern Power | $ | 2 |
| $ | 4 |
|
At December 31, 2015, other intangible assets consisted primarily of Southern Power's PPA fair value adjustments with a net carrying amount of $317 million. The increases in goodwill and other intangible assets primarily relate to Southern Company's acquisitions of PowerSecure on May 9, 2016 and Southern Company Gas on July 1, 2016.
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. Also see Note (I) under "Southern Company– Acquisition of PowerSecure International, Inc." and " –Merger with Southern Company Gas" for additional information.
Natural Gas for Sale
Southern Company Gas' natural gas distribution utilities, with the exception of Nicor Gas, carry natural gas inventory on a weighted average cost of gas (WACOG) basis.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Nicor Gas' natural gas inventory is carried at cost on a last-in, first-out (LIFO) basis. Inventory decrements occurring during the year that are restored prior to year-end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year-end are charged to cost of natural gas at the actual LIFO cost of the layers liquidated. The cost of natural gas, including inventory costs, is recovered from customers under a purchased gas recovery mechanism adjusted for differences between actual costs and amounts billed; therefore, LIFO liquidations have no impact on Southern Company's net income.
Southern Company Gas' other natural gas inventories are carried at the lower of weighted average cost or current market price, with cost determined on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value.
| |
| (B) | CONTINGENCIES AND REGULATORY MATTERS |
See Note 3 to the financial statements of the registrants in Item 8 of the Form 10-K for information relating to various lawsuits, other contingencies, and regulatory matters.
General Litigation Matters
Nicor Gas and Nicor Energy Services Company, wholly-owned subsidiaries of Southern Company Gas, and Nicor Inc. are defendants in a putative class action initially filed in September 2011 in state court in Cook County, Illinois. The plaintiffs purport to represent a class of the customers who purchased the Gas Line Comfort Guard product from Nicor Energy Services Company and variously allege that the marketing, sale, and billing of the Gas Line Comfort Guard product violated the Illinois Consumer Fraud and Deceptive Business Practices Act, constituting common law fraud and resulting in unjust enrichment of these entities. The plaintiffs seek, on behalf of the classes they purport to represent, actual and punitive damages, interest, costs, attorney fees, and injunctive relief. On October 26, 2016, the court held a hearing on the plaintiffs' motion for class certification and the defendants' motion for summary judgment on all of the plaintiffs' claims. The ultimate outcome of this matter cannot be determined at this time.
Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In addition, business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation against each registrant and any subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of each registrant in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such registrant's financial statements.
Environmental Remediation
The Southern Company system must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companies, and Southern Company Gas' natural gas distribution utilities in Illinois, New Jersey, Georgia, and Florida, have each received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Georgia Power's environmental remediation liability as of September 30, 2016 was $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 (CERCLA), including a site in Brunswick, Georgia on the CERCLA National Priorities List. The PRPs at the Brunswick site have completed a removal action as ordered by the EPA. On July 29, 2016, Honeywell International, Inc. and Georgia Power entered into a consent decree with the EPA to perform additional remediation at the site. Additional response actions at the site are anticipated. In September 2015, Georgia Power entered into an allocation agreement with another PRP, under which that PRP will be responsible (as between Georgia Power and that PRP) for paying and performing certain investigation, assessment, remediation, and other incidental activities at the Brunswick site, including costs associated with implementation of the consent decree. Assessment and potential cleanup of other sites are anticipated.
The ultimate outcome of these matters will depend upon the success of defenses asserted, the ultimate number of PRPs participating in the cleanup, and numerous other factors and cannot be determined at this time; however, as a result of Georgia Power's regulatory treatment for environmental remediation expenses, these matters are not expected to have a material impact on Southern Company's or Georgia Power's financial statements.
Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $46 million as of September 30, 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.
The final outcome of these matters cannot be determined at this time. However, based on the currently known conditions at these sites and the nature and extent of activities relating to these sites, management of Southern Company and Gulf Power does not believe that additional liabilities, if any, at these sites would be material to their respective financial statements.
Southern Company Gas' environmental remediation liability as of September 30, 2016 was $433 million based on the estimated cost of environmental investigation and remediation associated with known current and former operating sites. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies of Southern Company Gas' natural gas distribution utilities, with the exception of one site representing $5 million of the total accrued remediation costs. The ultimate outcome of these matters cannot be determined at this time; however, these matters are not expected to have a material impact on Southern Company's financial statements.
In September 2015, the EPA filed an administrative complaint and notice of opportunity for hearing against Nicor Gas. The complaint alleges violation of the regulatory requirements applicable to polychlorinated biphenyls in the Nicor Gas natural gas distribution system and the EPA seeks a total civil penalty of approximately $0.3 million. The ultimate resolution of this matter cannot be determined at this time; however, the final disposition of this matter is not expected to have a material impact on Southern Company's financial statements.
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 "Integrated Coal Gasification Combined Cycle" herein for information regarding Mississippi Power's construction of the Kemper IGCC.
On March 31, 2016, Mississippi Power reached a settlement agreement with its wholesale customers and filed a request with the FERC for an increase in wholesale base revenues under the Municipal and Rural Associations (MRA) cost-based electric tariff, primarily as a result of placing scrubbers for Plant Daniel Units 1 and 2 in service
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
in November 2015. The settlement agreement, accepted by the FERC, 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. 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 terminatingauthorizing 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. The additional resulting AFUDC is estimated to be approximately $11 million through the Kemper IGCC's projected in-service date of December 31, 2016.
Fuel Cost Recovery
Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At September 30, 2016, the amount of over-recovered wholesale MRA fuel costs included in the balance sheets was $17 million compared to $24 million at December 31, 2015. At September 30, 2016 and December 31, 2015, the amount of over-recovered wholesale MB fuel costs included in the balance sheets was $1 million. Effective with the first billing cycle for September 2016, fuel rates decreased $11 million annually for wholesale MRA customers and $1 million annually for wholesale MB customers.
See Note 3 to the financial statements of Mississippi Power under "FERC Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.
Market-Based Rate Authority
The traditional electric operating companies and Southern Power have authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies and Southern Power filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In April 2015, the FERC issued an order finding that the traditional electric operating companies' and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and Southern Power filed a request for rehearing in May 2015 and in June 2015 filed their response with the FERC. 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 balance of each regulatory clause recovery on the balance sheet follows:
|
| | | | | | | |
| Regulatory Clause | Balance Sheet Line Item | September 30,
2016 | December 31, 2015 |
|
| (in millions) |
| Rate CNP Compliance | Under recovered regulatory clause revenues | $ | — |
| $ | 43 |
|
| | Deferred over recovered regulatory clause revenues | 23 |
| — |
|
| Rate CNP PPA | Under recovered regulatory clause revenues | 52 |
| 99 |
|
| | Deferred under recovered regulatory clause revenues | 87 |
| — |
|
| Retail Energy Cost Recovery | Other regulatory liabilities, current | — |
| 238 |
|
| Deferred over recovered regulatory clause revenues | 134 |
| — |
|
| Natural Disaster Reserve | Other regulatory liabilities, deferred | 71 |
| 75 |
|
Environmental Accounting Order
In April 2016, as part of its environmental compliance strategy, Alabama Power ceased using coal at Plant Greene County Units 1 and 2 (300 MWs representing Alabama Power's ownership interest) and began operating Units 1 and 2 solely on natural gas in June 2016 and July 2016, respectively.
Georgia Power
Rate Plans
See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Rate Plans" and "Retail Regulatory Matters – Rate Plans," respectively, in Item 8 of the Form 10-K for additional information.
Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, Environmental Compliance Cost Recovery tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to the construction of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through separate fuel cost recovery tariffs. See "Nuclear Construction" 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 – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the NCCR tariff. Also see "Fuel Cost Recovery" herein and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Fuel Cost Recovery" and Southern Company under "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding fuel cost recovery.
Pursuant to the terms and conditions of a settlement agreement related to Southern Company's acquisition of Southern Company Gas approved by the Georgia PSC on April 14, 2016, Georgia Power's 2013 ARP will continue in effect until December 31, 2019, and Georgia Power will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, Georgia Power and Atlanta Gas Light Company (collectively, Utilities) each will retain their respective merger savings, net of transition costs, as defined in the settlement agreement;
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through December 31, 2022, such net merger savings applicable to each utility will be shared on a 60/40 basis between their respective customers and the Utilities; thereafter, all merger savings will be retained by customers. See Note (I) under "Southern Company – Merger with Southern Company Gas" for additional information regarding the Merger.
Integrated Resource Plan
See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Integrated Resource Plan" and "Retail Regulatory Matters – Integrated Resource Plan," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's triennial Integrated Resource Plan (2016 IRP).
On July 28, 2016, the Georgia PSC voted to approve the 2016 IRP including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 combustion turbine (17 MWs), as well as the decertification of the Intercession City unit (143 MWs total capacity). On August 2, 2016, the Plant Mitchell and Plant Kraft units were retired. On August 31, 2016, Georgia Power sold its 33% ownership interest in the Intercession City unit to Duke Energy Florida, Inc.
Additionally, the Georgia PSC approved Georgia Power's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures taken to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4.
The Georgia PSC approved the reclassification of the remaining net book value of Plant Mitchell Unit 3 and costs associated with materials and supplies remaining at the unit retirement date to a regulatory asset. Recovery of the unit's net book value will continue through December 31, 2019, as provided in the 2013 ARP. The timing of the recovery of the remaining balance of the unit's net book value as of December 31, 2019 and costs associated with materials and supplies remaining at the unit retirement date will be deferred for consideration in Georgia Power's base rate case required to be filed by July 1, 2019.
The Georgia PSC also approved the Renewable Energy Development Initiative to procure an additional 1,200 MWs of renewable resources primarily utilizing market-based prices established through a competitive bidding process with expected in-service dates between 2018 and 2021. Additionally, 200 MWs of self-build capacity for use by Georgia Power was approved, as well as consideration for no more than 200 MWs of capacity as part of a renewable commercial and industrial program.
The Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve the nuclear 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.
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 September 30, 2016 and December 31, 2015, Georgia Power's over recovered fuel balance totaled $125 million and $116 million, respectively. For September 30, 2016, the balance is included in over recovered regulatory clause revenues, current on Georgia Power's Condensed Balance Sheets and in other current liabilities on Southern Company's Condensed Balance Sheets. For December 31, 2015, the balance is included in over recovered regulatory clause revenues, current and other deferred credits and liabilities on Georgia Power's Condensed Balance Sheets and in other current liabilities and other deferred credits and liabilities on Southern Company's Condensed Balance Sheets. On May 17, 2016, the Georgia PSC approved Georgia Power's request to decrease fuel rates by 15% effective June 1, 2016, which will reduce annual billings by approximately $313 million. Georgia Power is currently scheduled to file its next fuel case by February 28, 2017.
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Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's or Georgia Power's revenues or net income, but will affect cash flow.
Storm Damage Recovery
As of September 30, 2016, the balance in Georgia Power's regulatory asset related to storm damage was $94 million. During October 2016, Hurricane Matthew caused significant damage to Georgia Power's transmission and distribution facilities. The total amount of restoration costs related to this hurricane is estimated to be between $130 million and $155 million, which will be charged to capital accounts or to the storm damage reserve. Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, to the storm damage reserve to cover the operating and maintenance costs of damages from major storms to its transmission and distribution facilities, which is recoverable through base rates. The rate of recovery of storm damage costs after December 31, 2019 is expected to be adjusted in Georgia Power's base rate case required to be filed by July 1, 2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's or Georgia Power's financial statements. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Storm Damage Recovery" and Note 1 to the financial statements of Georgia Power under "Storm Damage Recovery" in Item 8 of the Form 10-K for additional information regarding Georgia Power's storm damage reserve.
Nuclear Construction
See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Retail Regulatory Matters – Nuclear Construction," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's construction of Plant Vogtle Units 3 and 4, Vogtle Construction Monitoring (VCM) reports, the NCCR tariff, the Vogtle Construction Litigation (as defined below), and the Contractor Settlement Agreement (as defined below).
In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an agreement with the Contractor, pursuant to which the Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4 (Vogtle 3 and 4 Agreement).
Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. The Vogtle 3 and 4 Agreement also provides for liquidated damages upon the Contractor's failure to fulfill the schedule and performance guarantees, 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 obligations of Westinghouse and WECTEC under the Vogtle 3 and 4 Agreement were originally guaranteed by Toshiba Corporation (Westinghouse's parent company) and The Shaw Group Inc. (which is now a subsidiary of CB&I), respectively. On March 9, 2016, in connection with Westinghouse's acquisition of WECTEC and pursuant to the settlement agreement described below, the guarantee of The Shaw Group Inc. was terminated. The guarantee of Toshiba Corporation remains in place. In the event of 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.
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The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay certain termination costs. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain Vogtle Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.
In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4. Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 each year. If the projected construction capital costs to be borne by Georgia Power increase by 5% above the certified cost or the projected in-service dates are significantly extended, Georgia Power is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. In February 2013, Georgia Power requested an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to $4.8 billion and to extend the estimated in-service dates to the fourth quarter 2017 (from April 2016) and the fourth quarter 2018 (from April 2017) for Plant Vogtle Units 3 and 4, respectively. In October 2013, the Georgia PSC approved a stipulation (2013 Stipulation) between Georgia Power and the Georgia PSC Staff to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate until the completion of Plant Vogtle Unit 3 or earlier if deemed appropriate by the Georgia PSC and Georgia Power.
On April 15, 2015, the Georgia PSC issued a procedural order in connection with the twelfth VCM report, which included a requested amendment (Requested Amendment) to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 (second quarter of 2019 and second quarter of 2020, respectively) and to increase the estimated total in-service capital cost of Plant Vogtle Units 3 and 4 to $5.0 billion. Pursuant to the Georgia PSC's procedural order, the Georgia PSC deemed the Requested Amendment unnecessary and withdrawn until the completion of construction of Plant Vogtle Unit 3 consistent with the 2013 Stipulation. The Georgia PSC recognized that the certified cost and the 2013 Stipulation do not constitute a cost recovery cap. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by Georgia Power in excess of the certified amount will be included in rate base, provided Georgia Power shows the costs to be reasonable and prudent.
On December 31, 2015, Westinghouse and the Vogtle Owners entered into a definitive settlement agreement (Contractor Settlement Agreement) to resolve disputes between the Vogtle Owners and the Contractor under the Vogtle 3 and 4 Agreement, including litigation that was pending in the U.S. District Court for the Southern District of Georgia (Vogtle Construction Litigation). Effective December 31, 2015, Georgia Power, acting for itself and as agent 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 $256 million had been paid as of September 30, 2016. In addition, the Contractor Settlement Agreement provides for the resolution of other open existing items relating to the scope of the project under the Vogtle 3 and 4 Agreement, including cyber security, for which costs were reflected in Georgia Power's previously disclosed in-service cost estimate. Further, as part of the settlement and Westinghouse's acquisition of WECTEC: (i) Westinghouse engaged Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor; and (ii) the Vogtle Owners, CB&I, and The Shaw Group Inc. entered into mutual releases of any and all claims arising out of events or circumstances in connection with the construction of Plant Vogtle Units 3 and 4 that occurred on or before the date of the Contractor Settlement Agreement. On January 5, 2016, the Vogtle Construction Litigation was dismissed with prejudice.
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The Georgia PSC has approved fourteen VCM reports covering the periods through December 31, 2015, including construction capital costs incurred, which through that date totaled $3.3 billion. On January 21, 2016, Georgia Power submitted the Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement 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.
On October 20, 2016, Georgia Power and the Georgia PSC Staff entered into a settlement agreement (Vogtle Cost Settlement Agreement) resolving the following prudence matters: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report will be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement is reasonable and prudent and none of the amounts paid or to be paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) financing costs on verified and approved capital costs will be deemed prudent provided they are incurred prior to December 31, 2019 and December 31, 2020 for Plant Vogtle Units 3 and 4, respectively; and (iv) (a) the in-service capital cost forecast will be adjusted to $5.680 billion (Revised Forecast), which includes a contingency of $240 million above Georgia Power's current forecast of $5.440 billion, (b) capital costs incurred up to the Revised Forecast will be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, and (c) Georgia Power would have the burden to show that any capital costs above the Revised Forecast are reasonable and prudent. Under the terms of the Vogtle Cost Settlement Agreement, the certified in-service capital cost for purposes of calculating the NCCR tariff will remain at $4.418 billion. Construction capital costs above $4.418 billion will accrue AFUDC through commercial operation. The ROE used to calculate the NCCR tariff will be reduced from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016. For purposes of the AFUDC calculation, the ROE on costs between $4.418 billion and $5.440 billion will also be 10.00% and the ROE on any amounts above $5.440 billion would be Georgia Power's average cost of long-term debt. If the Georgia PSC adjusts Georgia Power's ROE rate setting point in a rate case prior to Plant Vogtle Units 3 and 4 being placed into retail rate base, then the ROE for purposes of calculating both the NCCR tariff and AFUDC will likewise be 95 basis points lower than the revised ROE rate setting point. If Plant Vogtle Units 3 and 4 are not commercially operational by December 31, 2020, then (i) the ROE for purposes of calculating the NCCR tariff will be reduced an additional 300 basis points, and may, at the Georgia PSC's discretion, be accrued to be used for the benefit of customers, until such time as the units reach commercial operation and (ii) the ROE used to calculate AFUDC will be Georgia Power's average cost of long-term debt.
Under the terms of the Vogtle Cost Settlement Agreement, Plant Vogtle Units 3 and 4 will be placed into retail rate base on December 31, 2020 or upon reaching commercial operation, whichever is later. The Georgia PSC will determine for retail ratemaking purposes the process of transitioning Plant Vogtle Units 3 and 4 from a construction project to an operating plant no later than Georgia Power's base rate case required to be filed by July 1, 2019.
The Vogtle Cost Settlement Agreement is subject to approval by the Georgia PSC, which is scheduled to vote on this matter on December 20, 2016. Accordingly, the terms of the Vogtle Cost Settlement Agreement are subject to change and the terms of any final agreement approved by the Georgia PSC may differ materially from the terms of the Vogtle Cost Settlement Agreement. If approved, the Vogtle Cost Settlement Agreement is expected to reduce Georgia Power's revenues for the years 2016 through 2020 by a total of approximately $325 million ($115 million reduction in net income).
On August 31, 2016, Georgia Power filed the fifteenth VCM report with the Georgia PSC covering the period from January 1 through June 30, 2016 requesting approval of $141 million of construction capital costs incurred during that period. Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was $3.8 billion as of September 30, 2016. Estimated financing costs during the construction period total approximately $2.4 billion, of which $1.2 billion had been incurred through September 30, 2016.
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On November 1, 2016, Georgia Power submitted its 2017 NCCR tariff filing requesting that the current NCCR tariff rate remain effective for 2017 if the Georgia PSC approves the Vogtle Cost Settlement Agreement. As required under the current order, Georgia Power concurrently submitted a 2017 NCCR tariff rate calculated using the current authorized 10.95% ROE, which would result in an increase of approximately $70 million.
There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, at the federal and state level, and additional challenges may arise as construction proceeds. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Vogtle Owners or the Contractor or to both.
As construction continues, the risk remains that challenges with Contractor performance including labor productivity, fabrication, delivery, assembly, and installation of plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost. Contractor performance and progress in recent months, primarily associated with Unit 3, has resulted in additional current schedule pressure of approximately three to four months and has increased the likelihood of further schedule impacts to that unit. Georgia Power expects the Contractor to employ mitigation efforts to maintain the current project schedule and believes the Contractor is responsible for any related costs under the Vogtle 3 and 4 Agreement. Should Unit 3 be placed in service after June 2019, Georgia Power estimates its financing costs to be approximately $22 million per month. Additionally, Georgia Power estimates its owner's costs to be approximately $2 million per month, net of delay liquidated damages and certain incentive payments that would no longer be required to be paid per the Contractor Settlement Agreement. The Contractor's progress on Unit 4 indicates that the current estimated in-service date of June 2020 remains achievable. In addition, the IRS has allocated production tax credits to each of Plant Vogtle Units 3 and 4, which require the applicable unit to be placed in service before 2021.
Future claims by the Contractor or Georgia Power (on behalf of the Vogtle Owners) could arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement and, under the enhanced dispute resolution procedures, may be resolved through litigation after the completion of nuclear fuel load for both units.
The ultimate outcome of these matters cannot be determined at this time.
Gulf Power
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information regarding Gulf Power's rates and charges for service to retail customers.
On May 5, 2016, Gulf Power delivered a letter to the Florida PSC requesting recognition of Gulf Power's ownership in Plant Scherer Unit 3 as being in service to retail customers when and as its existing wholesale contracts expire. As a result, on September 13, 2016, the Florida PSC instructed Gulf Power to file its monthly earnings surveillance reports both including and excluding its share of investment and expenses related to Plant Scherer Unit 3 that is not covered by contracts. See "Retail Base Rate Cases" and "Cost Recovery Clauses" herein for additional information.
Retail Base Rate Cases
See Note 3 to the financial statements of Southern Company and Gulf Power under "Retail Regulatory Matters – Gulf Power – Retail Base Rate Case" and "Retail Regulatory Matters – Retail Base Rate Case," respectively, in Item 8 of the Form 10-K for additional information.
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In 2013, the Florida PSC approved a settlement agreement (2013 Rate Case Settlement Agreement) that authorized Gulf Power to reduce depreciation and record a regulatory asset up to $62.5 million from January 2014 through June 2017. In any given month, such depreciation reduction may not exceed the amount necessary for the retail ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. For 2014 and 2015, Gulf Power recognized reductions in depreciation of $8.4 million and $20.1 million, respectively. In the third quarter 2016 and in accordance with the 2013 Rate Case Settlement Agreement, Gulf Power reversed reductions previously recorded to depreciation. As a result, for the first nine months of 2016, the net reduction in depreciation was zero.
On October 12, 2016, Gulf Power filed a petition (2016 Rate Case) with the Florida PSC requesting an increase in retail rates and charges of $106.8 million based on the projected test year of January 1, 2017 through December 31, 2017 and a retail ROE of 11% compared to the current retail ROE of 10.25%. The recoverability of the costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 will be decided in this matter. The Florida PSC is expected to make a decision on the 2016 Rate Case in the second quarter 2017. Gulf Power has requested that the increase in base rates, if approved by the Florida PSC, become effective in July 2017. The ultimate outcome of this matter cannot be determined at this time.
Cost Recovery Clauses
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K for additional information regarding Gulf Power's recovery of retail costs through various regulatory clauses and accounting orders. Gulf Power has four regulatory clauses which are approved by the Florida PSC. The balance of each regulatory clause recovery on the balance sheet follows:
|
| | | | | | | |
| Regulatory Clause | Balance Sheet Line Item | September 30,
2016 | December 31, 2015 |
|
| (in millions) |
| Fuel Cost Recovery | Other regulatory liabilities, current | $ | 20 |
| $ | 18 |
|
| Purchased Power Capacity Recovery | Other regulatory liabilities, current | 3 |
| — |
|
| Purchased Power Capacity Recovery | Under recovered regulatory clause revenues | — |
| 1 |
|
| Environmental Cost Recovery | Other regulatory liabilities, current | 5 |
| — |
|
| Environmental Cost Recovery | Under recovered regulatory clause revenues | — |
| 19 |
|
| Energy Conservation Cost Recovery | Other regulatory liabilities, current | — |
| 4 |
|
| Energy Conservation Cost Recovery | Under recovered regulatory clause revenues | 2 |
| — |
|
On November 2, 2016, the Florida PSC approved Gulf Power's annual rate clause request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2017. The net effect of the approved changes is a $41 million decrease in annual revenues for 2017. In general, the decreased revenues will not have a significant impact on net income since most of the revenues will be offset by lower expenses. However, certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 were included in the environmental clause rate, which will have an impact of approximately $11 million and $14 million of additional revenue in 2016 and 2017, respectively. The final disposition of these costs and the related impact on rates is expected to be decided by the Florida PSC in the 2016 Rate Case as discussed previously. The ultimate outcome of this matter cannot be determined at this time.
Other Matters
As a result of the cost to comply with environmental regulations imposed by the EPA, Gulf Power retired its coal-fired generation at Plant Smith Units 1 and 2 (357 MWs) on March 31, 2016. Gulf Power filed a petition with the
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Florida PSC requesting permission to recover the remaining net book value of Plant Smith Units 1 and 2 and the remaining materials and supplies associated with these units as of the retirement date. In connection with this request, Gulf Power reclassified approximately $63 million to a regulatory asset, including the remaining net book value of the units and the associated materials and supplies. On August 29, 2016, the Florida PSC approved Gulf Power's request to create a regulatory asset and defer the recovery over a period to be decided in the 2016 Rate Case.
Mississippi Power
Energy Efficiency
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Energy Efficiency" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's energy efficiency programs.
On May 3, 2016, the Mississippi PSC issued an order approving the annual Energy Efficiency Cost Rider Compliance filing, which included an anticipated reduction of $2 million in retail revenues for the year ending December 31, 2016.
Performance Evaluation Plan
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Performance Evaluation Plan" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's base rates.
On April 1, 2016, Mississippi Power submitted its annual PEP lookback filing for 2015, which reflected the need for a $5 million surcharge to be recovered from customers. The filing has been suspended for review by the Mississippi PSC.
On July 12, 2016, Mississippi Power submitted its annual projected PEP filing for 2016 which indicated no change in rates. The filing has been suspended for review by the Mississippi PSC.
The ultimate outcome of these matters 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" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's ECO Plan.
On August 17, 2016, the Mississippi PSC approved Mississippi Power's revised ECO Plan filing for 2016, which requested the maximum 2% annual increase in revenues, approximately $18 million, primarily related to Plant Daniel Units 1 and 2 scrubbers being placed in service in November 2015. The revised rates became effective with the first billing cycle for September 2016. Approximately $22 million of related revenue requirements in excess of the 2% maximum was deferred for inclusion in the 2017 filing.
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 September 30, 2016, the amount of over-recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheet was $58 million compared to $71 million at December 31, 2015.
The Mississippi PSC conditionally approved a decrease of $120 million annually in fuel cost recovery rates on January 5, 2016, effective with the first billing cycle for February 2016. On August 17, 2016, the Mississippi PSC approved an additional decrease of $51 million annually in fuel cost recovery rates effective with the first billing cycle for September 2016.
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Southern Company Gas
Natural Gas Cost Recovery
Southern Company Gas has established natural gas cost recovery rates approved by the relevant state regulatory agencies in the states in which it serves. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow.
Regulatory Infrastructure Programs
Southern Company Gas' natural gas distribution utilities are involved in ongoing capital projects associated with infrastructure improvement programs that have been previously approved by their applicable state regulatory agencies and provide an appropriate return on invested capital. These infrastructure improvement programs update or expand the natural gas distribution systems of the utilities to improve safety and reliability and meet operational flexibility and growth. Southern Company Gas currently has approved infrastructure improvement programs in six different states with initial program lengths ranging from four to 10 years, with the longest set to expire in 2025. The average annual spend under these programs ranges from $10 million to $250 million.
Southern Company Gas currently has proposed infrastructure improvement programs pending approval by the applicable state regulatory agencies in Georgia and New Jersey requesting average annual spending of $44 million through 2020 and $110 million through 2027, respectively. The ultimate outcome of these matters 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
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 (Initial DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014 and continues to progress towards completing the remainder of the Kemper IGCC, including the gasifiers and the gas clean-up facilities. The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." On October 11, 2016, the Kemper IGCC began testing using clean syngas from gasifier "A" and the related gas clean-up systems to produce electricity. Late on October 31, 2016, gasifier "A" experienced challenges associated with the ash removal systems, and on November 2, 2016, Mississippi Power determined a maintenance outage on gasifier "A" is needed to make improvements to the ash removal systems.
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(UNAUDITED)
Therefore, Mississippi Power has re-sequenced activities, and gasifier "B" is now expected to progress through testing and begin producing electricity during the gasifier "A" outage. In light of these changes, Mississippi Power has determined that integrated operation of both gasifiers will not occur by mid-November and has revised the expected in-service date for the remainder of the Kemper IGCC to December 31, 2016. The remaining schedule reflects the time expected to achieve production of electricity using gasifier "B," complete gasifier "A" outage activities, and resume electricity production using gasifier "A," as well as to complete the integration of all systems necessary for both combustion turbines to simultaneously generate electricity with syngas.
Recovery of the costs subject to the cost cap and the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions) remains subject to review and approval by the Mississippi PSC. Mississippi Power's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Mississippi Supreme Court's (Court) decision discussed herein under "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order"), and actual costs incurred as of September 30, 2016 are as follows:
|
| | | | | | | | | | | |
| Cost Category | 2010 Project Estimate(a) | | Current Cost Estimate(b) | | Actual Costs |
| | (in billions) |
Plant Subject to Cost Cap(c)(e) | $ | 2.40 |
| | $ | 5.52 |
| | $ | 5.30 |
|
| Lignite Mine and Equipment | 0.21 |
| | 0.23 |
| | 0.23 |
|
CO2 Pipeline Facilities | 0.14 |
| | 0.11 |
| | 0.11 |
|
AFUDC(d) | 0.17 |
| | 0.75 |
| | 0.71 |
|
Combined Cycle and Related Assets Placed in
Service – Incremental(e) | — |
| | 0.04 |
| | 0.03 |
|
| General Exceptions | 0.05 |
| | 0.10 |
| | 0.09 |
|
Deferred Costs(e) | — |
| | 0.21 |
| | 0.20 |
|
Additional DOE Grants(f) | — |
| | (0.14 | ) | | (0.14 | ) |
| Total Kemper IGCC | $ | 2.97 |
| | $ | 6.82 |
| | $ | 6.53 |
|
| |
| (a) | The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities approved in 2011 by the Mississippi PSC, as well as the lignite mine and equipment, AFUDC, and general exceptions. |
| |
| (b) | Amounts in the Current Cost Estimate include certain estimated post-in-service costs which are expected to be subject to the cost cap. |
| |
| (c) | The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. The Current Cost Estimate and the Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap and exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" herein for additional information. The Current Cost Estimate and the Actual Costs reflect 100% of the costs of the Kemper IGCC. See note (e) for additional information. |
| |
| (d) | Mississippi Power's 2010 Project Estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC as described in "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order." The Current Cost Estimate also reflects the impact of a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. See "FERC Matters" herein for additional information. |
| |
| (e) | Non-capital Kemper IGCC-related costs incurred during construction were initially deferred as regulatory assets. Some of these costs are now included in rates and are being recognized through income; however, such costs continue to be included in the Current Cost Estimate and the Actual Costs at September 30, 2016. The wholesale portion of debt carrying costs, whether deferred or recognized through income, is not included in the Current Cost Estimate and the Actual Costs at September 30, 2016. See "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities" herein for additional information. |
| |
| (f) | On April 8, 2016, Mississippi Power received approximately $137 million in additional grants from the DOE for the Kemper IGCC (Additional DOE Grants), which are expected to be used to reduce future rate impacts for customers. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Of the total costs, including post-in-service costs for the lignite mine, incurred as of September 30, 2016, $3.70 billion was included in property, plant, and equipment (which is net of the Initial DOE Grants, the Additional DOE Grants, and estimated probable losses of $2.63 billion), $6 million in other property and investments, $81 million in fossil fuel stock, $46 million in materials and supplies, $33 million in other regulatory assets, current, $177 million in other regulatory assets, deferred, $4 million in other current assets, and $9 million in other deferred charges and assets in the balance sheet.
Mississippi Power does not intend to seek rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate of $88 million ($54 million after tax) in the third quarter 2016 and a total of $222 million ($137 million after tax) for the nine months ended September 30, 2016. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.63 billion ($1.63 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through September 30, 2016. The increase to the cost estimate in the third quarter of 2016 primarily reflects $53 million for the extension of the Kemper IGCC's projected in-service date from October 31, 2016 to December 31, 2016 and increased efforts related to operational readiness and challenges in start-up and commissioning activities, including the cost of repairs and modifications to gasifier "B" and mechanical improvements to coal feed and ash management systems, as well as certain post-in-service costs expected to be subject to the cost cap. The year-to-date increase to the cost estimate also includes $78 million for the extension of the Kemper IGCC's projected in-service date from August 31, 2016 to October 31, 2016. In addition, during the start-up and commissioning process, Mississippi Power is identifying potential improvement projects that ultimately may be completed subsequent to placing the remainder of the Kemper IGCC in service. If completed, such improvement projects would be expected to enhance plant performance, safety, and/or operations. The related potential costs have yet to be fully evaluated, have not been included in the current cost estimate, and may be subject to the $2.88 billion cost cap.
Any extension of the in-service date beyond December 31, 2016 is currently estimated to result in additional base costs of approximately $25 million to $35 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any extension of the in-service date with respect to the Kemper IGCC beyond December 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 $15 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees of approximately $3 million per month. For additional information, see "2015 Rate Case" herein.
Mississippi Power's analysis of the time needed to complete the start-up and commissioning activities for the Kemper IGCC will continue until the remaining Kemper IGCC assets are placed in service. The next steps for the facility include the testing and production of electricity using clean syngas from gasifier "B," as well as the generation of electricity using clean syngas from gasifier "A," which are scheduled to occur by the end of November. If integrated operation of both gasifiers does not occur by mid-December, the expected in-service date and related cost estimate for the Kemper IGCC likely would require further revision. Further cost increases and/or extensions of the expected in-service date may result from factors including, but not limited to, difficulties integrating the systems required for sustained operations, sustaining nitrogen supply, major equipment failure, unforeseen engineering or design problems including any repairs and/or modifications to systems, and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). Any further changes in the estimated costs of the Kemper IGCC subject to the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company's and Mississippi Power's statements of income and these changes could be material.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Rate Recovery of Kemper IGCC Costs
See "FERC Matters" herein for additional information regarding Mississippi Power's MRA cost based tariff relating to 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 future proceedings related to the operation of the Kemper IGCC. To the extent the Mississippi PSC determines the Kemper IGCC does not meet the operational parameters ultimately adopted by the Mississippi PSC or Mississippi Power incurs additional costs to satisfy such parameters, there could be a material adverse impact on Southern Company's or Mississippi Power's financial statements. See "Prudence" herein for additional information.
2013 MPSC Rate Order
In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that was intended to establish the process for resolving matters regarding cost recovery related to the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. In March 2013, the Mississippi PSC issued a rate order approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designed to collect $156 million annually beginning in 2014 (2013 MPSC Rate Order) to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service, based on a mirror CWIP methodology (Mirror CWIP rate).
Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continues to record AFUDC on the Kemper IGCC. Through September 30, 2016, AFUDC recorded since the original May 2014 estimated in-service date for the Kemper IGCC has totaled $352 million. Mississippi Power has not recorded any AFUDC on Kemper IGCC costs in excess of the $2.88 billion cost cap, except for Cost Cap Exception amounts.
On February 12, 2015, the Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and requiring(2) the Mississippi PSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015 and required the fourth quarter 2015 refund of collectionsthe $342 million collected under Mirror CWIP.the 2013 MPSC Rate Order, along with associated carrying costs of $29 million. The Court's decision did not impact the 2012 MPSC CPCN Order or the February 2013 legislation described below.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
2015 Rate Case
On August 13, 2015, the Mississippi PSC approved Mississippi Power's request for interim rates, which presented an alternative rate proposal (In-Service Asset Proposal) designed to recover Mississippi Power's costs associated with the Kemper IGCC assets that are commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The interim rates were designed to collect approximately $159 million annually and became effective with the first billing cycle for September 2015, subject to refund and certain other conditions.
On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order adopting in full a stipulation entered into between Mississippi Power and the Mississippi Public Utilities Staff (MPUS) regarding the In-Service Asset Proposal. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The In-Service Asset Rate Order also included a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets. The stipulated revenue requirement excluded the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by SMEPA. Mississippi Power continues to evaluate its alternatives with respect to its investment and related costs associated with the 15% undivided interest.
With implementation of the new rates on December 17, 2015, the interim rates were terminated and, in March 2016, Mississippi Power completed customer refunds of approximately $11 million for the difference between the interim rates collected and the permanent rates.
On July 27, 2016, the Court dismissed Greenleaf CO2 Solutions, LLC (Greenleaf) motion for reconsideration of its previous decision to dismiss Greenleaf's appeal of the In-Service Asset Rate Order.
In addition to current estimated costs at September 30, 2016 of $6.82 billion, Mississippi Power anticipates that it will incur additional expenses in excess of current rates associated with operating the Kemper IGCC after it is placed in service until the Kemper IGCC cost recovery approach is finalized, which are expected to be material. These costs include, but are not limited to, regulatory costs, operational costs in excess of current rates, taxes, and additional carrying costs. Mississippi Power expects to request authority from the Mississippi PSC and the FERC to defer all Kemper IGCC costs incurred after the in-service date that cannot be capitalized, are not included in current rates, and are not required to be charged against earnings as a result of the $2.88 billion cost cap until such time as the Mississippi PSC completes its review and includes the resulting allowable costs in rates. Mississippi Power is required to file its next rate request with the Mississippi PSC related to cost recovery for the Kemper IGCC by June 3, 2017. See "Regulatory Assets and Liabilities" below for additional information. As part of that filing, Mississippi Power expects to request recovery of certain costs that the Mississippi PSC had excluded from the revenue requirement calculation for the in-service assets.
Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law in 2013. Mississippi Power expects to securitize prudently-incurred qualifying facility costs in excess of the certificated cost estimate of $2.4 billion. Qualifying facility costs include, but are not limited to, pre-construction costs, construction costs, regulatory costs, and accrued AFUDC. The Court's decision regarding the 2013 MPSC Rate Order did not impact Mississippi Power's ability to utilize alternate financing through securitization or the February 2013 legislation.
Prudence
On August 17, 2016, the Mississippi PSC issued an order establishing a discovery docket to manage all filings related to the prudence of the Kemper IGCC. On October 3, 2016, Mississippi Power made a required compliance filing, which included a review and explanation of differences between the Kemper IGCC project estimate set forth in the 2010 CPCN proceeding and the most recent Kemper IGCC project estimate, as well as comparisons of current cost estimates and current expected plant operational parameters to the estimates presented in the 2010 CPCN proceedings for the first five years following the start of commercial operations. Certain costs, including
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
operations and maintenance, are materially higher than the amounts presented in the CPCN proceedings. Additionally, while the current estimated operational availability estimates reflect ultimate results similar to those presented in the 2010 CPCN proceedings, the ramp up period for the current estimates reflects a lower starting point and a slower escalation rate. Mississippi Power expects the Mississippi PSC to address these issues in connection with its next rate request.
Regulatory Assets and Liabilities
Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC issued an accounting order in 2011 granting Mississippi Power the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date, subject to review of such costs by the Mississippi PSC. Such costs include, but are not limited to, carrying costs on Kemper IGCC assets currently placed in service, costs associated with Mississippi PSC and MPUS consultants, prudence costs, legal fees, and operating expenses associated with assets placed in service.
In August 2014, Mississippi Power requested confirmation by the Mississippi PSC of Mississippi Power's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. Beginning in the third quarter 2015 and the second quarter 2016, in connection with the implementation of retail and wholesale rates, respectively, Mississippi Power began expensing certain ongoing project costs and certain retail debt carrying costs (associated with assets placed in service and other non-CWIP accounts) that previously were deferred as regulatory assets and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees. The amortization periods for these regulatory assets vary from two years to 10 years as set forth in the In-Service Asset Rate Order and the settlement agreement with wholesale customers. As of September 30, 2016, the balance associated with these regulatory assets was $105 million, of which $33 million is included in current assets. Other regulatory assets associated with the remainder of the Kemper IGCC totaled $105 million as of September 30, 2016. The amortization period for these assets is expected to be determined by the Mississippi PSC in future rate proceedings following completion of construction and start-up of the Kemper IGCC and related prudence reviews. See "FERC Matters" herein for information related to the 2016 settlement agreement with wholesale customers.
The In-Service Asset Rate Order requires Mississippi Power to submit an annual true-up calculation of its actual cost of capital, compared to the stipulated total cost of capital, with the first occurring as of May 31, 2016. At September 30, 2016, Mississippi Power's related regulatory liability included in its balance sheet totaled approximately $7 million. See "2015 Rate Case" herein for additional information.
See Note 1 to the financial statements of Southern Company and Mississippi Power under "Regulatory Assets and Liabilities" in Item 8 of the Form 10-K for additional information.
Lignite Mine and CO2 Pipeline Facilities
In conjunction with the Kemper IGCC, Mississippi Power will 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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. In addition to the obligation to fund the reclamation activities, Mississippi Power currently provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. See
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Note 1 to the financial statements of Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" and "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.
In addition, Mississippi Power has constructed and will operate the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery. Mississippi Power 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 has been engaged in ongoing discussions with its off-takers regarding the status of the CO2 delivery schedule as well as other issues related to the 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.Power. Any termination or material modification of these agreementsthe agreement with Denbury could impact the operations of the Kemper IGCC and result in a material reduction in future chemical product salesMississippi Power's revenues and could have a material financial impact on Mississippi Power to the extent Mississippi Power is not able to enter into other similar contractual arrangements.arrangements or otherwise sequester the CO2 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.
TerminationLitigation
On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. On August 12, 2016, Southern Company and Mississippi Power removed the case to the U.S. District Court for the Southern District of Proposed Sale of Undivided InterestMississippi, where the case is currently pending. However, the plaintiffs have filed a request to SMEPA
In 2010 and as amended in 2012,remand the case back to state court. The individual plaintiff, John Carlton Dean, alleges that Mississippi Power and SMEPA entered into an asset purchase agreement (APA) whereby SMEPA agreed to purchase a 15% undivided interest inSouthern Company violated the Kemper IGCC. On May 20, 2015, SMEPA notified Mississippi Power of its termination of the APA betweenUnfair Trade Practices Act. All plaintiffs have alleged that Mississippi Power and SMEPA.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 previously receivedand Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a total of $275 million of depositsreceiver 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 SMEPA that were requiredbeing charged to be returned to SMEPA with interest in connection with the termination of the APA. customers through electric rates.
On June 3, 2015,9, 2016, Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint relates to the cancelled CO2 contract with Treetop and alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and seeks compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS have moved to compel arbitration pursuant to 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. These tax credits 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%terms of the CO2 produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. Through September 30, 2015, contract.
Southern Company and Mississippi Power had recorded tax benefits totaling $276 million for the Phase II credits,believe these legal challenges have no merit; however, an adverse outcome in these proceedings could impact Southern Company's results of which approximately $235 million had been utilized. While the in-service date for the remainderoperations, financial condition, and liquidity and could have a material impact on Mississippi Power's results of the Kemper IGCC is currently expected to occur in the first half of 2016, Mississippi Power now anticipates the in-service date to occur subsequent to April 19, 2016, but has not made a final determination to that effect. Due to this uncertainty,operations, financial condition, and liquidity. Southern Company and Mississippi Power have reflectedwill vigorously defend themselves in these tax credits as unrecognized tax benefitsmatters, and reclassified the Phase II credits to a current liability on their September 30, 2015 balance sheets, with no impact to net income. Repayment to the IRS would occur with the quarterly estimated tax payment following a final determination that the in-service date would occur subsequent to April 19, 2016. Any cash funding requirements necessary for Mississippi Power to make this repayment are expected to be provided by Southern Company. See Note (G) herein under "Unrecognized Tax Benefits – Investment Tax Credits" for additional information. The ultimate outcome of this tax matterthese matters cannot be determined at this time.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| |
| (C) | FAIR VALUE MEASUREMENTS |
As of September 30, 2016, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
|
| | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using | | |
| As of September 30, 2016: | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Net Asset Value as a Practical Expedient (NAV) | | Total |
| | (in millions) |
| Southern Company | | | | | | | | | |
| Assets: | | | | | | | | | |
Energy-related derivatives(a) | $ | 203 |
| | $ | 190 |
| | $ | — |
| | $ | — |
| | $ | 393 |
|
| Interest rate derivatives | — |
| | 19 |
| | — |
| | — |
| | 19 |
|
| Foreign currency derivatives | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
Nuclear decommissioning trusts(b) | 660 |
| | 938 |
| | — |
| | 18 |
| | 1,616 |
|
| Cash equivalents | 1,680 |
| | — |
| | — |
| | — |
| | 1,680 |
|
| Other investments | 9 |
| | — |
| | 1 |
| | — |
| | 10 |
|
| Total | $ | 2,552 |
| | $ | 1,170 |
| | $ | 1 |
| | $ | 18 |
| | $ | 3,741 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | 267 |
| | $ | 274 |
| | $ | — |
| | $ | — |
| | $ | 541 |
|
| Interest rate derivatives | — |
| | 7 |
| | — |
| | — |
| | 7 |
|
| Foreign currency derivatives | — |
| | 24 |
| | — |
| | — |
| | 24 |
|
| Contingent consideration | — |
| | — |
| | 18 |
| | — |
| | 18 |
|
| Total | $ | 267 |
| | $ | 305 |
| | $ | 18 |
| | $ | — |
| | $ | 590 |
|
| | | | | | | | | | |
| Alabama Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | 8 |
|
Nuclear decommissioning trusts(c) | | | | | | | | |
|
|
| Domestic equity | 373 |
| | 72 |
| | — |
| | — |
| | 445 |
|
| Foreign equity | 49 |
| | 49 |
| | — |
| | — |
| | 98 |
|
| U.S. Treasury and government agency securities | — |
| | 22 |
| | — |
| | — |
| | 22 |
|
| Corporate bonds | 22 |
| | 148 |
| | — |
| | — |
| | 170 |
|
| Mortgage and asset backed securities | — |
| | 21 |
| | — |
| | — |
| | 21 |
|
| Private Equity | — |
| | — |
| | — |
| | 18 |
| | 18 |
|
| Other | — |
| | 7 |
| | — |
| | — |
| | 7 |
|
| Cash equivalents | 410 |
| | — |
| | — |
| | — |
| | 410 |
|
| Total | $ | 854 |
| | $ | 327 |
| | $ | — |
| | $ | 18 |
| | $ | 1,199 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 21 |
| | $ | — |
| | $ | — |
| | $ | 21 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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, 2014, and 2015. In May 2015, Southern Company amended its 2008 through 2013 federal income tax returns to include deductions for Kemper IGCC-related R&E expenditures. Due to the uncertainty related to this tax position, Southern Company and Mississippi Power had unrecognized tax benefits associated with these R&E deductions totaling approximately $414 million as of September 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. |
| | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using | | |
| As of September 30, 2016: | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Net Asset Value as a Practical Expedient (NAV) | | Total |
| | (in millions) |
| Georgia Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 15 |
| | $ | — |
| | $ | — |
| | $ | 15 |
|
| Interest rate derivatives | — |
| | 10 |
| | — |
| | — |
| | 10 |
|
Nuclear decommissioning trusts(c) (d) | | | | | | | | | |
| Domestic equity | 197 |
| | 1 |
| | — |
| | — |
| | 198 |
|
| Foreign equity | — |
| | 125 |
| | — |
| |
|
| | 125 |
|
| U.S. Treasury and government agency securities | — |
| | 59 |
| | — |
| | — |
| | 59 |
|
| Municipal bonds | — |
| | 70 |
| | — |
| | — |
| | 70 |
|
| Corporate bonds | — |
| | 172 |
| | — |
| | — |
| | 172 |
|
| Mortgage and asset backed securities | — |
| | 149 |
| | — |
| | — |
| | 149 |
|
| Other | 19 |
| | 43 |
| | — |
| | — |
| | 62 |
|
| Cash equivalents | 32 |
| | — |
| | — |
| | — |
| | 32 |
|
| Total | $ | 248 |
| | $ | 644 |
| | $ | — |
| | $ | — |
| | $ | 892 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 16 |
| | $ | — |
| | $ | — |
| | $ | 16 |
|
| | | | | | | | | | |
| Gulf Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
| Cash equivalents | 20 |
| | — |
| | — |
| | — |
| | 20 |
|
| Total | $ | 20 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 21 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 51 |
| | $ | — |
| | $ | — |
| | $ | 51 |
|
| Interest rate derivatives | — |
| | 6 |
| | — |
| | — |
| | 6 |
|
| Total | $ | — |
| | $ | 57 |
| | $ | — |
| | $ | — |
| | $ | 57 |
|
| | | | | | | | | | |
| Mississippi Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
| Cash equivalents | 137 |
| | — |
| | — |
| | — |
| | 137 |
|
| Total | $ | 137 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 138 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 21 |
| | $ | — |
| | $ | — |
| | $ | 21 |
|
| Interest rate derivatives | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
| Total | $ | — |
| | $ | 22 |
| | $ | — |
| | $ | — |
| | $ | 22 |
|
| | | | | | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| |
(C) | FAIR VALUE MEASUREMENTS |
As of September 30, 2015, assets and liabilities measured at fair value on a recurring basis during the period, together with the associated level of the fair value hierarchy, were as follows:
|
| | | | | | | | | | | | | | | | |
| | | Fair Value Measurements Using | | |
| As of September 30, 2015: | | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Total |
| | | (in millions) |
| Southern Company | | | | | | | | |
| Assets: | | | | | | | | |
| Energy-related derivatives | | $ | — |
| | $ | 4 |
| | $ | — |
| | $ | 4 |
|
| Interest rate derivatives | | — |
| | 20 |
| | — |
| | 20 |
|
Nuclear decommissioning trusts(a) | | 587 |
| | 869 |
| | 16 |
| | 1,472 |
|
| Cash equivalents | | 747 |
| | — |
| | — |
| | 747 |
|
| Other investments | | 9 |
| | — |
| | 1 |
| | 10 |
|
| Total | | $ | 1,343 |
| | $ | 893 |
| | $ | 17 |
| | $ | 2,253 |
|
| Liabilities: | | | | | | | | |
| Energy-related derivatives | | $ | — |
| | $ | 211 |
| | $ | — |
| | $ | 211 |
|
| Interest rate derivatives | | — |
| | 36 |
| | — |
| | 36 |
|
| Total | | $ | — |
| | $ | 247 |
| | $ | — |
| | $ | 247 |
|
| | | | | | | | | |
| Alabama Power | | | | | | | | |
| Assets: | | | | | | | | |
| Energy-related derivatives | | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | 2 |
|
Nuclear decommissioning trusts(b) | | | | | | | | |
| Domestic equity | | 346 |
| | 72 |
| | — |
| | 418 |
|
| Foreign equity | | 46 |
| | 45 |
| | — |
| | 91 |
|
| U.S. Treasury and government agency securities | | — |
| | 28 |
| | — |
| | 28 |
|
| Corporate bonds | | 10 |
| | 126 |
| | — |
| | 136 |
|
| Mortgage and asset backed securities | | — |
| | 18 |
| | — |
| | 18 |
|
| Other | | — |
| | 4 |
| | 16 |
| | 20 |
|
| Cash equivalents | | 484 |
| | — |
| | — |
| | 484 |
|
| Total | | $ | 886 |
| | $ | 295 |
| | $ | 16 |
| | $ | 1,197 |
|
| Liabilities: | | | | | | | | |
| Energy-related derivatives | | $ | — |
| | $ | 54 |
| | $ | — |
| | $ | 54 |
|
| Interest rate derivatives | | — |
| | 17 |
| | — |
| | 17 |
|
| Total | | $ | — |
| | $ | 71 |
| | $ | — |
| | $ | 71 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| | | | | Fair Value Measurements Using | | | Fair Value Measurements Using | | |
| As of September 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 September 30, 2016: | | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Net Asset Value as a Practical Expedient (NAV) | | Total |
| | | (in millions) | (in millions) |
| Georgia Power | | | | | | | | | |
| Southern Power | | | | | | | | | | |
| Assets: | | | | | | | | | | | | | | | | | |
| Energy-related derivatives | | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | 2 |
| $ | — |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 3 |
|
| Interest rate derivatives | | — |
| | 9 |
| | — |
| | 9 |
| |
Nuclear decommissioning trusts(b) (c) | | | | | | | | | |
| Domestic equity | | 169 |
| | 1 |
| | — |
| | 170 |
| |
| Foreign equity | | — |
| | 109 |
| | — |
| | 109 |
| |
| U.S. Treasury and government agency securities | | — |
| | 112 |
| | — |
| | 112 |
| |
| Municipal bonds | | — |
| | 74 |
| | — |
| | 74 |
| |
| Corporate bonds | | — |
| | 166 |
| | — |
| | 166 |
| |
| Mortgage and asset backed securities | | — |
| | 109 |
| | — |
| | 109 |
| |
| Other | | 16 |
| | 5 |
| | — |
| | 21 |
| |
| Foreign currency derivatives | | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
| Cash equivalents | | 37 |
| | — |
| | — |
| | 37 |
| 647 |
| | — |
| | — |
| | — |
| | 647 |
|
| Total | | $ | 222 |
| | $ | 587 |
| | $ | — |
| | $ | 809 |
| $ | 647 |
| | $ | 26 |
| | $ | — |
| | $ | — |
| | $ | 673 |
|
| Liabilities: | | | | | | | | | | | | | | | | | |
| Energy-related derivatives | | $ | — |
| | $ | 16 |
| | $ | — |
| | $ | 16 |
| $ | — |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 3 |
|
| Interest rate derivatives | | — |
| | 19 |
| | — |
| | 19 |
| |
| Foreign currency derivatives | | — |
| | 24 |
| | — |
| | — |
| | 24 |
|
| Contingent consideration | | — |
| | — |
| | 18 |
| | — |
| | 18 |
|
| Total | | $ | — |
| | $ | 35 |
| | $ | — |
| | $ | 35 |
| $ | — |
|
| $ | 27 |
|
| $ | 18 |
|
| $ | — |
|
| $ | 45 |
|
| | | | | | | | | | |
| Gulf Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Cash equivalents | | $ | 18 |
| | $ | — |
| | $ | — |
| | $ | 18 |
| |
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | | — |
| | 94 |
| | — |
| | 94 |
| |
| | | | | | | | | | |
| Mississippi Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Cash equivalents | | $ | 64 |
| | $ | — |
| | $ | — |
| | $ | 64 |
| |
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | | — |
| | 47 |
| | — |
| | 47 |
| |
| | | | | | | | | | |
| Southern Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Interest rate derivatives | | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
| |
| Cash equivalents | | 103 |
| | — |
| | — |
| | 103 |
| |
| Total | | $ | 103 |
| | $ | 1 |
| | $ | — |
| | $ | 104 |
| |
| |
| (a) | Excludes $7 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value. |
| |
| (b) | For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table. |
| |
(b)(c) | Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| |
(c)(d) | Includes the investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of September 30, 2015,2016, approximately $69$42 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan to creditors under the funds' managers' securities lending program. |
Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. The fair value of the funds at Southern Company, including reinvested interest and dividends and excluding the funds' expenses, increased by $49 million and $116 million, respectively, for the three and nine months ended September 30, 2016, and decreased by $65 million and $33 million, respectively, for the three and nine months ended September 30, 2015. Alabama Power recorded an increase in fair value of $26 million and $66 million, respectively, for the three and nine months ended September 30, 2016 and a decrease in fair value of $39 million and $19 million, respectively, for the three and nine months ended September 30, 2015 as a change in regulatory liabilities related to its AROs. Georgia Power recorded an increase in fair value of $23 million and $50 million, respectively, for the three and nine months ended September 30, 2016 and a decrease in fair value of $26 million and $14 million, respectively, for the three and nine months ended September 30, 2015 as a change in its regulatory asset related to its AROs.
Valuation Methodologies
The energy-related derivatives primarily consist of exchange-traded and over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter 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 reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include 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 reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputs to the net present
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
value calculation may include the contract terms, counterparty credit risk, and discount rates. The interest rate derivatives and cross-currency swaps are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note (H) 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, which are reflected as "Other" in the table above, 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.Form 10-K for additional information.
Southern Power has contingent payment obligations related to certain acquisitions whereby Southern Power is obligated to pay generation-based payments to the seller over a 10-year period beginning at the commercial operation date. The obligation is measured at fair value using significant inputs such as forecasted facility generation in MW-hours, a fixed dollar amount per MW-hour, and a discount rate, and is evaluated periodically. The fair value of partnerships is determined by aggregatingcontingent consideration reflects the net present value of the underlying assets.expected payments and any change arising from forecasted generation is expected to be immaterial.
"Other investments" include investments that are not traded in the open market. The fair value of these investments have been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan executions.
As of September 30, 2016, the fair value measurements of private equity investments held in the nuclear decommissioning trust that are calculated at net asset value per share (or its equivalent) as a practical expedient, as well as the nature and risks of those investments, were as follows:
|
| | | | | | | | | | | |
| As of September 30, 2016: | Fair Value | | Unfunded Commitments | | Redemption Frequency | | Redemption Notice Period |
| | (in millions) | | | | |
| Southern Company | $ | 18 |
| | $ | 27 |
| | Not Applicable | | Not Applicable |
| Alabama Power | $ | 18 |
| | $ | 27 |
| | Not Applicable | | Not Applicable |
Private equity funds include a fund-of-funds that invests in high-quality private equity funds across several market sectors, a fund that invests in real estate assets, and a fund that acquires companies to create resale value. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated. Liquidations are expected to occur at various times over the next ten years.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
As of September 30, 2015, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows:
|
| | | | | | | | | | |
| As of September 30, 2015: | | Fair Value | | Unfunded Commitments | | Redemption Frequency | | Redemption Notice Period |
| | | (in millions) | | | | | | |
| Southern Company | | | | | | |
| Nuclear decommissioning trusts: | | | | | | | | |
| Foreign equity funds | | $ | 109 |
| | None | | Monthly | | 5 days |
| Equity - commingled funds | | 45 |
| | None | | Daily | | Daily |
| Debt - commingled funds | | 16 |
| | None | | Daily | | 5 days |
| Other - commingled funds | | 5 |
| | None | | Daily | | Not applicable |
| Other - money market funds | | 16 |
| | None | | Daily | | Not applicable |
| Trust-owned life insurance | | 112 |
| | None | | Daily | | 15 days |
| Cash equivalents: | | | | | | | | |
| Money market funds | | 747 |
| | None | | Daily | | Not applicable |
| Alabama Power | | | | | | | | |
| Nuclear decommissioning trusts: | | | | | | | | |
| Equity - commingled funds | | $ | 45 |
| | None | | Daily | | Daily |
| Debt - commingled funds | | 16 |
| | None | | Daily | | 5 days |
| Trust-owned life insurance | | 112 |
| | None | | Daily | | 15 days |
| Cash equivalents: | | | | | | | | |
| Money market funds | | 484 |
| | None | | Daily | | Not applicable |
| Georgia Power | | | | | | | | |
| Nuclear decommissioning trusts: | | | | | | | | |
| Foreign equity funds | | $ | 109 |
| | None | | Monthly | | 5 days |
| Other - commingled funds | | 5 |
| | None | | Daily | | Not applicable |
| Other - money market funds | | 16 |
| | None | | Daily | | Not applicable |
| Cash equivalents: | | | | | | | | |
| Money market funds | | 37 |
| | None | | Daily | | Not applicable |
| Gulf Power | | | | | | | | |
| Cash equivalents: | | | | | | | | |
| Money market funds | | $ | 18 |
| | None | | Daily | | Not applicable |
| Mississippi Power | | | | | | | | |
| Cash equivalents: | | | | | | | | |
| Money market funds | | $ | 64 |
| | None | | Daily | | Not applicable |
| Southern Power | | | | | | | | |
| Cash equivalents: | | | | | | | | |
| Money market funds | | $ | 103 |
| | None | | Daily | | Not applicable |
The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. Alabama Power and Georgia Power have external trust funds (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 primarily invests in a diversified portfolio of equity securities of foreign companies, including those 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, and global depositary receipts), and rights and warrants 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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 foreign equity fund, then the foreign equity fund's board may refuse to 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 own 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 nine months ended September 30, 2015, the change in fair value of the funds, including reinvested interest and dividends and excluding the funds' expenses, decreased by $65 million and $33 million, respectively, at Southern Company. For the three and nine months ended September 30, 2015, Alabama Power recorded a decrease in fair value of $39 million and $19 million, respectively, as a decrease in regulatory liabilities. For the three and nine months ended September 30, 2015, Georgia Power recorded a decrease in fair value of $26 million and $14 million, respectively, as a reduction of its regulatory asset related to its ARO.
The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by 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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
As of September 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 | | $ | 25,489 |
| | $ | 26,099 |
| $ | 43,668 |
| | $ | 47,227 |
|
| Alabama Power | | $ | 7,295 |
| | $ | 7,558 |
| $ | 7,091 |
| | $ | 7,961 |
|
| Georgia Power | | $ | 9,887 |
| | $ | 10,231 |
| $ | 10,398 |
| | $ | 11,582 |
|
| Gulf Power | | $ | 1,310 |
| | $ | 1,338 |
| $ | 1,184 |
| | $ | 1,267 |
|
| Mississippi Power | | $ | 2,273 |
| | $ | 2,228 |
| $ | 2,981 |
| | $ | 2,967 |
|
| Southern Power | | $ | 2,142 |
| | $ | 2,149 |
| $ | 4,608 |
| | $ | 4,821 |
|
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.
Earnings per Share
For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under the stock option and performance share plans. See Note 8 to the financial statements of Southern Company in Item 8 of the Form 10-K for information on the stock option and performance share plans. The effect of both stock options and performance share award units was determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:
| | | | | Three Months Ended September 30, 2015 |
| Three Months Ended September 30, 2014 | | Nine Months Ended September 30, 2015 | | Nine Months Ended September 30, 2014 | Three Months Ended September 30, 2016 |
| Three Months Ended September 30, 2015 | | Nine Months Ended September 30, 2016 | | Nine Months Ended September 30, 2015 |
| | | (in millions) | (in millions) |
| As reported shares | | 910 |
| | 898 |
| | 910 |
| | 894 |
| 968 |
| | 910 |
| | 940 |
| | 910 |
|
| Effect of options and performance share award units | | 2 |
| | 4 |
| | 3 |
| | 4 |
| 7 |
| | 2 |
| | 5 |
| | 3 |
|
| Diluted shares | | 912 |
| | 902 |
| | 913 |
| | 898 |
| 975 |
| | 912 |
| | 945 |
| | 913 |
|
Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were immaterial for the three andnine months ended September 30, 2016 and were 15 million and 1 million for the three and nine months ended September 30, 2015, respectively, and were 16 million and 17 million for the three and nine months ended September 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 | | — |
| — |
| | 2,226 |
| — |
| — |
| | 2,226 |
|
| Other comprehensive income (loss) | | — |
| — |
| | (95 | ) | — |
| — |
| | (95 | ) |
| Stock issued | | 65,725 |
| 2,599 |
| | 3,265 |
| — |
| — |
| | 3,265 |
|
| Stock-based compensation | | — |
| — |
| | 119 |
| — |
| — |
| | 119 |
|
| Cash dividends on common stock | | — |
| — |
| | (1,553 | ) | — |
| — |
| | (1,553 | ) |
| Contributions from noncontrolling interests | | — |
| — |
| | — |
| — |
| 357 |
| | 357 |
|
| Distributions to noncontrolling interests | | — |
| — |
| | — |
| — |
| (21 | ) | | (21 | ) |
| Purchase of membership interests from noncontrolling interests | | — |
| — |
| | — |
| — |
| (129 | ) | | (129 | ) |
| Net income attributable to noncontrolling interests | | — |
| — |
| | — |
| — |
| 36 |
| | 36 |
|
| Other | | — |
| (46 | ) | | (7 | ) | — |
| — |
| | (7 | ) |
| Balance at September 30, 2016 | | 980,798 |
| (799 | ) | | $ | 24,547 |
| $ | 609 |
| $ | 1,024 |
| | $ | 26,180 |
|
| | | | | | | |
| Balance at December 31, 2014 | 908,502 |
| | (725 | ) | | $ | 19,949 |
| | $ | 756 |
| | $ | 221 |
| | $ | 20,926 |
| 908,502 |
| (725 | ) | | $ | 19,949 |
| $ | 756 |
| $ | 221 |
| | $ | 20,926 |
|
| Net income after dividends on preferred and preference stock | — |
| | — |
| | 2,096 |
| | — |
| | — |
| | 2,096 |
| |
| Consolidated net income attributable to Southern Company | | — |
| — |
| | 2,096 |
| — |
| — |
| | 2,096 |
|
| Other comprehensive income (loss) | — |
| | — |
| | (7 | ) | | — |
| | — |
| | (7 | ) | — |
| — |
| | (7 | ) | — |
| — |
| | (7 | ) |
| Stock issued | 3,769 |
| | — |
| | 136 |
| | — |
| | — |
| | 136 |
| 3,769 |
| — |
| | 136 |
| — |
| — |
| | 136 |
|
| Stock-based compensation | — |
| | — |
| | 78 |
| | — |
| | — |
| | 78 |
| — |
| — |
| | 78 |
| — |
| — |
| | 78 |
|
| Stock repurchased, at cost | — |
| | (2,599 | ) | | (115 | ) | | — |
| | — |
| | (115 | ) | — |
| (2,599 | ) | | (115 | ) | — |
| — |
| | (115 | ) |
| Cash dividends on common stock | — |
| | — |
| | (1,465 | ) | | — |
| | — |
| | (1,465 | ) | — |
| — |
| | (1,465 | ) | — |
| — |
| | (1,465 | ) |
| Preference stock redemption | — |
| | — |
| | — |
| | (150 | ) | | — |
| | (150 | ) | — |
| — |
| | — |
| (150 | ) | — |
| | (150 | ) |
| Contributions from noncontrolling interest | — |
| | — |
| | — |
| | — |
| | 429 |
| | 429 |
| |
| Distributions to noncontrolling interest | — |
| | — |
| | — |
| | — |
| | (13 | ) | | (13 | ) | |
| Net income attributable to noncontrolling interest | — |
| | — |
| | — |
| | — |
| | 13 |
| | 13 |
| |
| Contributions from noncontrolling interests | | — |
| — |
| | — |
| — |
| 429 |
| | 429 |
|
| Distributions to noncontrolling interests | | — |
| — |
| | — |
| — |
| (13 | ) | | (13 | ) |
| Net income attributable to noncontrolling interests | | — |
| — |
| | — |
| — |
| 13 |
| | 13 |
|
| Other | — |
| | (8 | ) | | (8 | ) | | 3 |
| | — |
| | (5 | ) | — |
| (8 | ) | | (8 | ) | 3 |
| — |
| | (5 | ) |
| Balance at September 30, 2015 | 912,271 |
| | (3,332 | ) | | $ | 20,664 |
| | $ | 609 |
| | $ | 650 |
| | $ | 21,923 |
| 912,271 |
| (3,332 | ) | | $ | 20,664 |
| $ | 609 |
| $ | 650 |
| | $ | 21,923 |
|
| | | | | | | | | | | | | |
| Balance at December 31, 2013 | 892,733 |
| | (5,647 | ) | | $ | 19,008 |
| | $ | 756 |
| | $ | — |
| | $ | 19,764 |
| |
| Net income after dividends on preferred and preference stock | — |
| | — |
| | 1,680 |
| | — |
| | — |
| | 1,680 |
| |
| Other comprehensive income (loss) | — |
| | — |
| | 6 |
| | — |
| | — |
| | 6 |
| |
| Treasury stock re-issued | — |
| | 4,996 |
| | 225 |
| | — |
| �� | — |
| | 225 |
| |
| Stock issued | 7,781 |
| | — |
| | 332 |
| | — |
| | — |
| | 332 |
| |
| Stock repurchased, at cost | — |
| | — |
| | (5 | ) | | — |
| | — |
| | (5 | ) | |
| Cash dividends on common stock | — |
| | — |
| | (1,390 | ) | | — |
| | — |
| | (1,390 | ) | |
| Other | — |
| | (51 | ) | | 1 |
| | — |
| | — |
| | 1 |
| |
| Balance at September 30, 2014 | 900,514 |
| | (702 | ) | | $ | 19,857 |
| | $ | 756 |
| | $ | — |
| | $ | 20,613 |
| |
| |
| (*) | Primarily related to Southern Power Company.Company and excludes redeemable noncontrolling interests. See Note 10 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information. |
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 were repurchased through September 30, 2015 at a total cost of approximately
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
$115 million. There were no repurchases during the three months ended September 30, 2015 and no further repurchases under this program are anticipated.
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 September 30, 20152016 was approximately $1.8$1.9 billion (comprised of approximately $810$890 million at Alabama Power, $872$868 million at Georgia Power, $82 million at Gulf Power, and $40 million at Mississippi Power). In addition, at September 30, 2015,2016, the traditional electric operating companies had approximately $354$358 million (comprised of approximately $200$87 million at Alabama Power, $121$250 million at Georgia Power, and $33$21 million at Gulf Power) of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months, of which $120 million were remarketed by Alabama Power subsequent to September 30, 2015.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 September 30, 2015:2016:
| | | | | Expires | | | | Executable Term Loans | | Due Within One Year | Expires | | | | Executable Term Loans | | Due Within One Year |
| Company | | 2015 |
| | 2016 |
| | 2017 | | 2018 | | 2020 | | 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 (a) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1,000 |
| | $1,250 | | $ | 2,250 |
| | $ | 2,250 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | — |
| $ | — |
| $ | 1,000 |
| $ | 1,250 |
| | $ | 2,250 |
| | $ | 2,250 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Alabama Power | | — |
| | 40 |
| | — |
| | 500 |
| | 800 |
| | 1,340 |
| | 1,339 |
| | — |
| | — |
| | — |
| | 40 |
| — |
| 35 |
| 500 |
| 800 |
| | 1,335 |
| | 1,335 |
| | — |
| | — |
| | — |
| | 35 |
|
| Georgia Power | | — |
| | — |
| | — |
| | — |
| | 1,750 |
| | 1,750 |
| | 1,732 |
| | — |
| | — |
| | — |
| | — |
| — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,732 |
| | — |
| | — |
| | — |
| | — |
|
| Gulf Power | | 20 |
| | 225 |
| | 30 |
| | — |
| | — |
| | 275 |
| | 275 |
| | 50 |
| | — |
| | 50 |
| | 195 |
| 50 |
| 65 |
| 165 |
| — |
| | 280 |
| | 280 |
| | 45 |
| | — |
| | 45 |
| | 70 |
|
Mississippi Power (b) | | 15 |
| | 220 |
| | — |
| | — |
| | — |
| | 235 |
| | 210 |
| | 30 |
| | 30 |
| | 60 |
| | 175 |
| 100 |
| 75 |
| — |
| — |
| | 175 |
| | 150 |
| | — |
| | 15 |
| | 15 |
| | 160 |
|
Southern Power (c) | | — |
| | — |
| | — |
| | — |
| | 600 |
| | 600 |
| | 567 |
| | — |
| | — |
| | — |
| | — |
| |
Southern Power Company(b) | | — |
| — |
| — |
| 600 |
| | 600 |
| | 532 |
| | — |
| | — |
| | — |
| | — |
|
Southern Company Gas(c) | | — |
| 75 |
| 1,925 |
| — |
| | 2,000 |
| | 1,947 |
| | — |
| | — |
| | — |
| | — |
|
| Other | | — |
| | 70 |
| | — |
| | — |
| | — |
| | 70 |
| | 70 |
| | — |
| | — |
| | — |
| | 70 |
| — |
| 55 |
| — |
| — |
| | 55 |
| | 55 |
| | 20 |
| | — |
| | 20 |
| | 35 |
|
| Total | | $ | 35 |
| | $ | 555 |
| | $ | 30 |
| | $ | 1,500 |
| | $4,400 | | $ | 6,520 |
| | $ | 6,443 |
| | $ | 80 |
| | $ | 30 |
| | $ | 110 |
| | $ | 480 |
| |
| Southern Company Consolidated | | $ | 150 |
| $ | 305 |
| $ | 3,590 |
| $ | 4,400 |
| | $ | 8,445 |
| | $ | 8,281 |
| | $ | 65 |
| | $ | 15 |
| | $ | 80 |
| | $ | 300 |
|
| |
| (a) | ExcludesRepresents the $8.1 billion Bridge Agreement entered into in September 2015 that will be funded only to the extent necessary to provide financing for the Merger as discussed herein.Southern Company parent entity. |
| |
| (b) | Subsequent to September 30, 2015, a $15 million bank credit arrangement expired pursuant toExcluding its terms.subsidiaries. See "Southern Power Project Credit Facilities" below and Note (I) under "Southern Power" for additional information. |
| |
| (c) | ExcludesSouthern Company Gas guarantees the Tranquillity Credit Agreement assumed with the acquisitionobligations of Tranquillity on August 28, 2015,Southern Company Gas Capital, which is non-recourse tothe borrower of $1.3 billion of these arrangements. Southern Power Company the proceedsGas' committed credit arrangements also include $700 million restricted for working capital needs of which are being used to finance project costs related to Tranquillity's solar facility currently under construction in California. See Note (I) to the Condensed Financial Statements herein for additional information regarding Tranquillity.Nicor Gas. |
As reflected inOn May 24, 2016, Southern Company's $8.1 billion Bridge Agreement to provide Merger financing, to the table above, in August 2015, Southern Company, Alabama Power, Georgia Power, and Southern Power Company each amended and restated their multi-year credit arrangements, which, among other things, extended the maturity dates from 2018 to 2020. Southern Company and Southern Power Company increased their borrowing ability under these arrangements to $1.25 billion from $1.0 billion and to $600 million from $500 million, respectively. Georgia Power increased its borrowing ability by $150 million under its facility maturing in 2020, and terminated its aggregate $150 million facilities maturing in 2016. In September 2015, Southern Company entered into an additional multi-year credit arrangement for $1.0 billion with a maturity date of 2018, which contains a covenant that limits debt levels to 70% of total capitalization, as defined in the agreement. Additionally, Southern Company amended its existing multi-year credit arrangement to increase the limit on debt levels to 70% from 65% of total capitalization, as defined in the agreement. Alabama Power entered into a new $500 million three-year credit arrangement which replaced a majority of Alabama Power's bi-lateral credit arrangements.extent necessary, was terminated.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
Southern Company intendsPower Project Credit Facilities
In connection with the construction of solar facilities by RE Garland Holdings LLC, RE Roserock LLC, and RE Tranquillity LLC, indirect subsidiaries of Southern Power, each subsidiary entered into separate credit agreements (Project Credit Facilities), which are non-recourse to initially fundSouthern Power (other than the cash consideration forsubsidiary party to the Merger using approximately $7.0 billionagreement). 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 debt and $1.0 billion of equity. Southern Company expects to issue approximately $2.0 billion of additional equity through 2019 to offset a portioncredit facility that is secured by the membership interests of the debt issuedrespective project company, with proceeds directed to fundfinance project costs related to the cash consideration forrespective
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
solar facilities. Each Project Credit Facility is secured by the Merger. In addition, Southern Company entered intoassets of the $8.1 billion Bridge Agreement on applicable project subsidiary and membership interests of the applicable project subsidiary. The table below summarizes each Project Credit Facility as of September 30, 2015 to provide financing for2016.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Project | | Maturity Date | | Construction Loan Facility | | Bridge Loan Facility | | Total Loan Facility | | Loan Facility Undrawn | | Letter of Credit Facility | | Letter of Credit Facility Undrawn |
| | | | | (in millions) |
| Garland | | Earlier of PPA COD or November 30, 2016 | | $ | 86 |
| | $ | 308 |
| | $ | 394 |
| | $ | 21 |
| | $ | 49 |
| | $ | 23 |
|
| Roserock | | Earlier of PPA COD or November 30, 2016(*) | | 63 |
| | 180 |
| | 243 |
| | 34 |
| | 23 |
| | 16 |
|
| Tranquillity | | October 14, 2016 | | 86 |
| | 172 |
| | 258 |
| | 12 |
| | 77 |
| | 26 |
|
| Total | | | | $ | 235 |
| | $ | 660 |
| | $ | 895 |
| | $ | 67 |
| | $ | 149 |
| | $ | 65 |
|
| |
| (*) | Subsequent to September 30, 2016, Roserock extended the maturity date of its Project Credit Facility to December 31, 2016. |
The Project Credit Facilities above had total amounts outstanding as of September 30, 2016 of $828 million at a weighted average interest rate of 2.05%. For the Merger in the event long-term financing is not available.three-month period ended September 30, 2016, these credit agreements had a maximum amount outstanding of $828 million and an average amount outstanding of $805 million at a weighted average interest rate of 2.02%.
The Bridge Agreement provides for total loan commitments in an aggregate amount of $8.1 billion to fund the payment of the cash consideration payable under the Merger Agreement and other cash payments requiredFurthermore, in connection with the consummationacquisition of the Merger, the Bridge Agreement and the borrowings thereunder, the other financing transactions relatedHenrietta solar facility on July 1, 2016, a subsidiary of Southern Power assumed a $217 million construction loan, which was fully repaid prior to the Merger, and the payment of fees and expenses incurred in connection with the foregoing. If funded, the loan under the Bridge Agreement will mature and be payable in full on the date that is 364 days after the funding of the commitments under the Bridge Agreement (Closing Date). As of September 30, 2015, Southern Company2016. For the three-month period ended September 30, 2016, this credit agreement had noa maximum amount outstanding loans under the Bridge Agreement. See Note (I) under "Southern Company – Proposed Merger with AGL Resources" herein for additional information regarding the Merger.of $217 million and an average amount outstanding of $137 million at a weighted average interest rate of 2.21%.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Financing Activities
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first nine months of 2015:2016:
| | | Company | Senior Note Issuances | | Senior Note Redemptions | | Revenue Bond Issuances and Reofferings of Purchased Bonds(a) | | Revenue
Bond
Maturities and
Repurchases | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(b) | Senior Note Issuances | | Senior Note Maturities and Redemptions | | Revenue
Bond
Maturities Redemptions and
Repurchases | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(a) |
| | (in millions) | (in millions) |
Southern Company | $ | 600 |
| | $ | 400 |
| | $ | — |
| | $ | — |
| | $ | 400 |
| | $ | — |
| $ | 8,500 |
| | $ | 500 |
| | $ | — |
| | $ | 800 |
| | $ | — |
|
| Alabama Power | 975 |
| | 250 |
| | 80 |
| | 134 |
| | — |
| | — |
| 400 |
| | 200 |
| | — |
| | 45 |
| | — |
|
| Georgia Power | — |
| | 525 |
| | 274 |
| | 268 |
| | 600 |
| | 20 |
| 650 |
| | 700 |
| | 4 |
| | 300 |
| | 5 |
|
| Gulf Power | — |
| | 60 |
| | 13 |
| | 13 |
| | — |
| | — |
| — |
| | 125 |
| | — |
| | 2 |
| | — |
|
| Mississippi Power | — |
| | — |
| | — |
| | — |
| | — |
| | 352 |
| — |
| | — |
| | — |
| | 1,100 |
| | 652 |
|
| Southern Power | 650 |
| | 525 |
| | — |
| | — |
| | 400 |
| | 3 |
| 1,531 |
| | — |
| | — |
| | 63 |
| | 84 |
|
Southern Company Gas(c) | | 900 |
| | 300 |
| | — |
| | — |
| | — |
|
| Other | — |
| | — |
| | — |
| | — |
| | — |
| | 13 |
| — |
| | — |
| | — |
| | — |
| | 60 |
|
| Total | $ | 2,225 |
| | $ | 1,760 |
| | $ | 367 |
| | $ | 415 |
| | $ | 1,400 |
| | $ | 388 |
| |
Elimination(d) | | — |
| | — |
| | — |
| | (200 | ) | | (225 | ) |
| Southern Company Consolidated | | $ | 11,981 |
| | $ | 1,825 |
| | $ | 4 |
| | $ | 2,110 |
| | $ | 576 |
|
| |
| (a) | Includes a reoffering by Alabama Power of $80 million aggregate principal amount of revenue bonds purchased and held since April 2015; reofferings by Georgia Power of $104.6 million and $65 million aggregate principal amount of revenue bonds purchased and held since 2013 and April 2015, respectively; and a reoffering by Gulf Power of $13 million aggregate principal amount of revenue bonds purchased and held in July 2015. Also includes repurchases and reofferings by Georgia Power of $94.6 million and $10 million aggregate principal amount of revenue bonds in August 2015 in connection with optional tenders. |
| |
(b) | Includes reductions in capital lease obligations resulting from cash payments under capital leases. |
| |
| (b) | Represents the Southern Company parent entity. |
| |
| (c) | Reflects only long-term debt financing activities occurring subsequent to completion of the Merger. The senior notes were issued by Southern Company Gas Capital and guaranteed by Southern Company Gas. |
| |
| (d) | Intercompany loans from Southern Company to Mississippi Power eliminated in Southern Company's Consolidated Financial Statements. |
Southern Company
In June 2015,May 2016, Southern Company issued $600the 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 consideration for the Merger and related transaction costs and for other general corporate purposes.
In September 2016, Southern Company issued $800 million aggregate principal amount of Series 2015A 2.750% Senior2016A 5.25% Junior Subordinated Notes due June 15, 2020.October 1, 2076. The proceeds were used to pay a portionrepay short-term indebtedness that was incurred to repay at maturity $500 million aggregate principal amount of Southern Company's outstanding short-term indebtednessSeries 2011A 1.95% Senior Notes due September 1, 2016 and for other general corporate purposes.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
In September 2015, Southern Company entered into a $400 million aggregate principal amount 18-month floating rate bank loan bearing interest based on one-month LIBOR. The proceeds were used for working capital and other general corporate purposes.
Subsequent to September 30, 2015, Southern Company issued $1.0 billion aggregate principal amount of Series 2015A 6.25% Junior Subordinated Notes due October 15, 2075. The proceeds were used to pay a portion of Southern Company's outstanding short-term indebtedness and for other general corporate purposes.
Alabama Power
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.program.
In April 2015,March 2016, Alabama Power purchasedentered into three bank term loan agreements with maturity dates of March 2021, in an aggregate principal amount of $45 million, one of which bears interest at 2.38% per annum and held $80two of which bear interest based on three-month LIBOR.
Georgia Power
In March 2016, Georgia Power issued $325 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 in2016A 3.25% Senior Notes due April 2015, Alabama Power issued $1751, 2026 and $325 million additional aggregate principal amount of its Series 2015A 3.750%2016B 2.40% Senior Notes due MarchApril 1, 2045 (Additional2021. An amount equal to the proceeds from the Series 2015A2016A 3.25% Senior Notes) andNotes due April 1, 2026 will be allocated to eligible green expenditures, including financing of or investments in solar generating facilities or electric vehicle charging infrastructure, or payments under PPAs served by solar or wind generating facilities. 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 itsGeorgia Power's Series 2015B 2.800%2013B Floating Rate Senior Notes due April 1, 2025 (Series 2015B Senior Notes). AMarch 15, 2016, to repay a portion of the proceeds of the Additional Series 2015A Senior NotesGeorgia Power's short-term indebtedness, and the Series 2015B Senior Notes were used in May 2015 to redeem 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 AlabamaGeorgia Power's continuous construction program.
Georgia Power
In April 2015, Georgia Power purchased and held $65 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 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 since 2013.
In June 2015,2016, Georgia Power made additional borrowings under the FFB Credit Facility in an aggregate principal amount of $600 million. The$300 million at a 2.571% interest rate applicable to the $600 million principal amount is 3.283% for an interest period that extends tothrough 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
Gulf 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.
In August 2015, in connection with optional tenders, GeorgiaMay 2016, Gulf Power repurchased and reoffered to the public $94.6redeemed $125 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgiaits Series 2011A 5.75% Senior Notes due June 1, 2051.
Also in May 2016, Gulf Power Company Plant Bowen Project), First Series 2009 and $10entered into an 11-month floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was for $100 million aggregate principal amount and the proceeds were used to repay existing indebtedness and for working capital and other general corporate purposes.
Mississippi Power
On January 28, 2016, Mississippi Power issued a promissory note for up to $275 million to Southern Company, which matures in December 2017, bearing interest based on one-month LIBOR. During the first nine months of Development Authority2016, Mississippi Power borrowed $100 million under this promissory note and an additional $100 million under a separate promissory note issued to Southern Company in November 2015. On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicate of Burke County (Georgia) Pollution Control Revenue Bonds (Georgiafinancial institutions for an aggregate amount of $1.2 billion. Mississippi Power borrowed $900 million on March 8, 2016 under the term loan agreement and the remaining $300 million on October 7, 2016. Mississippi Power used the initial proceeds to repay $900 million in maturing bank loans on March 8, 2016 and the remaining $300 million to repay at maturity Mississippi Power's Series 2011A 2.35% Senior Notes due October 15, 2016. The term loan pursuant to this agreement matures on April 1, 2018 and bears interest based on one-month LIBOR. On June 27, 2016, Mississippi Power received a capital contribution from Southern Company Plant Vogtle Project), First Series 2013.of $225 million, the proceeds of which were used to repay to Southern Company a portion of the promissory note issued in November 2015. As of September 30, 2016, the amount of outstanding promissory notes to Southern Company totaled $551 million.
In June 2016, Mississippi Power renewed a $10 million short-term note, which matures on June 30, 2017, bearing interest based on three-month LIBOR.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Mississippi Power
In April 2015, Mississippi Power entered into two short-term floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. 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 deposits 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.
Southern Power
In May 2015,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 are being allocated to renewable energy generation projects. Southern Power's obligations under its euro-denominated fixed-rate notes were effectively converted to fixed-rate U.S. dollars at issuance through cross-currency swaps, removing foreign currency exchange risk associated with the interest and principal payments. See Note (H) under "Foreign Currency Derivatives" for additional information.
In September 2016, Southern Power issued $290 million aggregate principal amount of Series 2016C 2.75% Senior Notes due September 20, 2023. The proceeds were used to repay a portion of its outstanding short-term indebtedness, for other general corporate purposes, including Southern Power's growth strategy and continuous construction program, as well as repayment of amounts outstanding under the Project Credit Facilities.
Also in September 2016, Southern Power repaid $80 million of an outstanding $400 million floating rate bank loan and for a portionextended the maturity date of the repayment at maturity of $525remaining $320 million from September 2016 to September 2018. In addition, Southern Power entered into a $60 million aggregate principal amount of Southern Power Company's 4.875% Senior Notes on July 15, 2015.
In August 2015, Southern Power Company entered into a $400 million aggregate principal amount 13-month floating rate bank loan bearing interest based on one-month LIBOR.LIBOR due September 2017. The proceeds were used to repay existing indebtedness and for working capital and other general corporate purposes, includingpurposes.
In addition, Southern Power's growth strategy and continuous construction program.Power issued $34 million in letters of credit during the nine months ended September 30, 2016.
During the nine months ended September 30, 2015,2016, Southern Power's subsidiaries incurred an additional $691 million of short-term borrowings pursuant to the Project Credit Facilities at a weighted average interest rate of 2.05%. Furthermore, in connection with the acquisition of the Henrietta solar facility, a subsidiary of Southern Power prepaid $2.6assumed a $217 million construction loan, which was fully repaid prior to September 30, 2016. In addition, Southern Power's subsidiaries issued $16 million in letters of long-term debtcredit.
Southern Company Gas
In September 2016, Southern Company Gas Capital issued $350 million aggregate principal amount of 2.45% Senior Notes due October 1, 2023 and $550 million aggregate principal amount of 3.95% Senior Notes due October 1, 2046, both of which are guaranteed by Southern Company Gas. The proceeds were used to Turner Renewablerepay a $360 million promissory note issued to Southern Company for the purpose of funding a portion of the purchase price for Southern Company Gas' 50% equity interest in SNG, to fund Southern Company Gas' purchase of Piedmont Natural Gas Company, Inc.'s (Piedmont) interest in SouthStar Energy LLC.Services, LLC (SouthStar), to make a voluntary pension contribution, to repay at maturity $120 million aggregate principal amount of Series A Floating Rate Senior Notes due October 27, 2016, and for general corporate purposes. See Note (I) under "Southern Company– Investment in Southern Natural Gas" and " – Acquisition of Remaining Interest in SouthStar" for additional information regarding Southern Company Gas' investment in SNG and purchase of Piedmont's interest in SouthStar, respectively.
Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. 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)
Southern Company Gas has a defined benefit, trusteed, pension plan covering eligible employees. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended. Southern Company Gas made a $125 million voluntary contribution to the qualified pension plan in September 2016. Southern Company Gas also provides certain defined benefit and defined contribution plans for a selected group of management and highly compensated employees. Benefits under these non-qualified plans are largely unfunded and benefits are primarily paid using corporate assets. In addition, Southern Company Gas provides certain medical care and life insurance benefits for eligible retired employees through a postretirement benefit plan. Southern Company Gas also has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses.
Components of the net periodic benefit costs for the three and nine months ended September 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 September 30, 2016 | | | | | | | | | | |
| Service cost | | $ | 68 |
| | $ | 14 |
| | $ | 17 |
| | $ | 3 |
| | $ | 3 |
|
| Interest cost | | 110 |
| | 23 |
| | 34 |
| | 5 |
| | 4 |
|
| Expected return on plan assets | | (203 | ) | | (46 | ) | | (64 | ) | | (9 | ) | | (9 | ) |
| Amortization: | | | | | | | | | | |
| Prior service costs | | 3 |
| | 1 |
| | 1 |
| | — |
| | 1 |
|
| Net (gain)/loss | | 45 |
| | 10 |
| | 14 |
| | 2 |
| | 2 |
|
| Net periodic pension cost | | $ | 23 |
| | $ | 2 |
| | $ | 2 |
| | $ | 1 |
| | $ | 1 |
|
| Nine Months Ended September 30, 2016 | | | | | | | | | | |
| Service cost | | $ | 192 |
| | $ | 43 |
| | $ | 52 |
| | $ | 9 |
| | $ | 9 |
|
| Interest cost | | 311 |
| | 71 |
| | 102 |
| | 14 |
| | 14 |
|
| Expected return on plan assets | | (577 | ) | | (138 | ) | | (193 | ) | | (26 | ) | | (26 | ) |
| Amortization: | | | | | | | | | | |
| Prior service costs | | 10 |
| | 2 |
| | 4 |
| | 1 |
| | 1 |
|
| Net (gain)/loss | | 120 |
| | 30 |
| | 41 |
| | 5 |
| | 5 |
|
| Net periodic pension cost | | $ | 56 |
| | $ | 8 |
| | $ | 6 |
| | $ | 3 |
| | $ | 3 |
|
| Three Months Ended September 30, 2015 | | | | | | | | | | | | | | | | | | | |
| Service cost | | $ | 65 |
| | $ | 14 |
| | $ | 18 |
| | $ | 3 |
| | $ | 3 |
| $ | 65 |
| | $ | 14 |
| | $ | 18 |
| | $ | 3 |
| | $ | 3 |
|
| Interest cost | | 111 |
| | 26 |
| | 38 |
| | 5 |
| | 5 |
| 111 |
| | 26 |
| | 38 |
| | 5 |
| | 5 |
|
| Expected return on plan assets | | (181 | ) | | (44 | ) | | (62 | ) | | (8 | ) | | (8 | ) | (181 | ) | | (44 | ) | | (62 | ) | | (8 | ) | | (8 | ) |
| Amortization: | | | | | | | | | | | | | | | | | | | |
| Prior service costs | | 6 |
| | 2 |
| | 2 |
| | 1 |
| | — |
| 6 |
| | 2 |
| | 2 |
| | 1 |
| | — |
|
| Net (gain)/loss | | 53 |
| | 14 |
| | 19 |
| | 2 |
| | 3 |
| 53 |
| | 14 |
| | 19 |
| | 2 |
| | 3 |
|
| Net cost | | $ | 54 |
| | $ | 12 |
| | $ | 15 |
| | $ | 3 |
| | $ | 3 |
| |
| Net periodic pension cost | | $ | 54 |
| | $ | 12 |
| | $ | 15 |
| | $ | 3 |
| | $ | 3 |
|
| Nine Months Ended September 30, 2015 | | | | | | | | | | | | | | | | | | | |
| Service cost | | $ | 193 |
| | $ | 44 |
| | $ | 54 |
| | $ | 9 |
| | $ | 9 |
| $ | 193 |
| | $ | 44 |
| | $ | 54 |
| | $ | 9 |
| | $ | 9 |
|
| Interest cost | | 333 |
| | 79 |
| | 115 |
| | 15 |
| | 16 |
| 333 |
| | 79 |
| | 115 |
| | 15 |
| | 16 |
|
| Expected return on plan assets | | (543 | ) | | (133 | ) | | (188 | ) | | (24 | ) | | (25 | ) | (543 | ) | | (133 | ) | | (188 | ) | | (24 | ) | | (25 | ) |
| Amortization: | | | | | | | | | | | | | | | | | | | |
| Prior service costs | | 19 |
| | 5 |
| | 7 |
| | 1 |
| | 1 |
| 19 |
| | 5 |
| | 7 |
| | 1 |
| | 1 |
|
| Net (gain)/loss | | 161 |
| | 41 |
| | 57 |
| | 7 |
| | 8 |
| 161 |
| | 41 |
| | 57 |
| | 7 |
| | 8 |
|
| Net cost | | $ | 163 |
| | $ | 36 |
| | $ | 45 |
| | $ | 8 |
| | $ | 9 |
| |
| Three Months Ended September 30, 2014 | | | | | | | | | | | |
| Service cost | | $ | 53 |
| | $ | 12 |
| | $ | 16 |
| | $ | 4 |
| | $ | 3 |
| |
| Interest cost | | 109 |
| | 26 |
| | 39 |
| | 4 |
| | 5 |
| |
| Expected return on plan assets | | (161 | ) | | (42 | ) | | (57 | ) | | (7 | ) | | (8 | ) | |
| Amortization: | | | | | | | | | | | |
| Prior service costs | | 6 |
| | 2 |
| | 2 |
| | — |
| | — |
| |
| Net (gain)/loss | | 28 |
| | 7 |
| | 10 |
| | 1 |
| | 2 |
| |
| Net cost | | $ | 35 |
| | $ | 5 |
| | $ | 10 |
| | $ | 2 |
| | $ | 2 |
| |
| Nine Months Ended September 30, 2014 | | | | | | | | | | | |
| Service cost | | $ | 160 |
| | $ | 36 |
| | $ | 47 |
| | $ | 8 |
| | $ | 8 |
| |
| Interest cost | | 326 |
| | 78 |
| | 115 |
| | 14 |
| | 15 |
| |
| Expected return on plan assets | | (484 | ) | | (126 | ) | | (170 | ) | | (21 | ) | | (22 | ) | |
| Amortization: | | | | | | | | | | | |
| Prior service costs | | 19 |
| | 5 |
| | 7 |
| | 1 |
| | 1 |
| |
| Net (gain)/loss | | 83 |
| | 23 |
| | 30 |
| | 3 |
| | 4 |
| |
| Net cost | | $ | 104 |
| | $ | 16 |
| | $ | 29 |
| | $ | 5 |
| | $ | 6 |
| |
| Net periodic pension cost | | $ | 163 |
| | $ | 36 |
| | $ | 45 |
| | $ | 8 |
| | $ | 9 |
|
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 September 30, 2016 | | | | | | | | | | |
| Service cost | | $ | 6 |
| | $ | 1 |
| | $ | 2 |
| | $ | — |
| | $ | — |
|
| Interest cost | | 20 |
| | 5 |
| | 7 |
| | 1 |
| | — |
|
| Expected return on plan assets | | (16 | ) | | (6 | ) | | (6 | ) | | — |
| | — |
|
| Amortization: | | | | | | | | | | |
| Prior service costs | | 1 |
| | 1 |
| | — |
| | — |
| | — |
|
| Net (gain)/loss | | 5 |
| | — |
| | 3 |
| | — |
| | 1 |
|
| Net periodic postretirement benefit cost | | $ | 16 |
| | $ | 1 |
| | $ | 6 |
| | $ | 1 |
| | $ | 1 |
|
| Nine Months Ended September 30, 2016 | | | | | | | | | | |
| Service cost | | $ | 17 |
| | $ | 4 |
| | $ | 5 |
| | $ | 1 |
| | $ | 1 |
|
| Interest cost | | 55 |
| | 14 |
| | 22 |
| | 2 |
| | 2 |
|
| Expected return on plan assets | | (44 | ) | | (19 | ) | | (17 | ) | | (1 | ) | | (1 | ) |
| Amortization: | | | | | | | | | | |
| Prior service costs | | 4 |
| | 3 |
| | 1 |
| | — |
| | — |
|
| Net (gain)/loss | | 12 |
| | 1 |
| | 7 |
| | — |
| | 1 |
|
| Net periodic postretirement benefit cost | | $ | 44 |
| | $ | 3 |
| | $ | 18 |
| | $ | 2 |
| | $ | 3 |
|
| Three Months Ended September 30, 2015 | | | | | | | | | | | | | | | | | | | |
| Service cost | | $ | 6 |
| | $ | 1 |
| | $ | 2 |
| | $ | 1 |
| | $ | — |
| $ | 6 |
| | $ | 1 |
| | $ | 2 |
| | $ | 1 |
| | $ | — |
|
| Interest cost | | 20 |
| | 5 |
| | 9 |
| | — |
| | 1 |
| 20 |
| | 5 |
| | 9 |
| | — |
| | 1 |
|
| Expected return on plan assets | | (15 | ) | | (6 | ) | | (6 | ) | | — |
| | — |
| (15 | ) | | (6 | ) | | (6 | ) | | — |
| | — |
|
| Amortization: | | | | | | | | | | | | | | | | | | | |
| Prior service costs | | 1 |
| | 2 |
| | — |
| | — |
| | — |
| 1 |
| | 2 |
| | — |
| | — |
| | — |
|
| Net (gain)/loss | | 4 |
| | — |
| | 2 |
| | — |
| | — |
| 4 |
| | — |
| | 2 |
| | — |
| | — |
|
| Net cost | | $ | 16 |
| | $ | 2 |
| | $ | 7 |
| | $ | 1 |
| | $ | 1 |
| |
| Net periodic postretirement benefit cost | | $ | 16 |
| | $ | 2 |
| | $ | 7 |
| | $ | 1 |
| | $ | 1 |
|
| Nine Months Ended September 30, 2015 | | | | | | | | | | | | | | | | | | | |
| Service cost | | $ | 17 |
| | $ | 4 |
| | $ | 5 |
| | $ | 1 |
| | $ | 1 |
| $ | 17 |
| | $ | 4 |
| | $ | 5 |
| | $ | 1 |
| | $ | 1 |
|
| Interest cost | | 59 |
| | 15 |
| | 26 |
| | 2 |
| | 3 |
| 59 |
| | 15 |
| | 26 |
| | 2 |
| | 3 |
|
| Expected return on plan assets | | (44 | ) | | (19 | ) | | (18 | ) | | (1 | ) | | (1 | ) | (44 | ) | | (19 | ) | | (18 | ) | | (1 | ) | | (1 | ) |
| Amortization: | | | | | | | | | | | | | | | | | | | |
| Prior service costs | | 3 |
| | 3 |
| | — |
| | — |
| | — |
| 3 |
| | 3 |
| | — |
| | — |
| | — |
|
| Net (gain)/loss | | 13 |
| | 1 |
| | 8 |
| | — |
| | — |
| 13 |
| | 1 |
| | 8 |
| | — |
| | — |
|
| Net cost | | $ | 48 |
| | $ | 4 |
| | $ | 21 |
| | $ | 2 |
| | $ | 3 |
| |
| Three Months Ended September 30, 2014 | | | | | | | | | | | |
| Service cost | | $ | 5 |
| | $ | 1 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| |
| Interest cost | | 19 |
| | 5 |
| | 9 |
| | — |
| | — |
| |
| Expected return on plan assets | | (14 | ) | | (6 | ) | | (6 | ) | | — |
| | — |
| |
| Amortization: | | | | | | | | | | | |
| Prior service costs | | 1 |
| | 1 |
| | — |
| | — |
| | — |
| |
| Net (gain)/loss | | 1 |
| | — |
| | — |
| | — |
| | — |
| |
| Net cost | | $ | 12 |
| | $ | 1 |
| | $ | 5 |
| | $ | — |
| | $ | — |
| |
| Nine Months Ended September 30, 2014 | | | | | | | | | | | |
| Service cost | | $ | 16 |
| | $ | 4 |
| | $ | 5 |
| | $ | 1 |
| | $ | 1 |
| |
| Interest cost | | 59 |
| | 15 |
| | 26 |
| | 2 |
| | 2 |
| |
| Expected return on plan assets | | (44 | ) | | (19 | ) | | (19 | ) | | (1 | ) | | (1 | ) | |
| Amortization: | | | | | | | | | | | |
| Prior service costs | | 3 |
| | 3 |
| | — |
| | — |
| | — |
| |
| Net (gain)/loss | | 2 |
| | — |
| | 1 |
| | — |
| | — |
| |
| Net cost | | $ | 36 |
| | $ | 3 |
| | $ | 13 |
| | $ | 2 |
| | $ | 2 |
| |
| Net periodic postretirement benefit cost | | $ | 48 |
| | $ | 4 |
| | $ | 21 |
| | $ | 2 |
| | $ | 3 |
|
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. 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.
Current and Deferred Income Taxes
Net Operating Loss
Southern Power ITCCompany expects to be in a consolidated net operating loss (NOL) position for income tax purposes for the 2016 tax year. The NOL will limit the amount of positive cash flows resulting from bonus depreciation, ITCs, and PTCs for the tax year and will significantly increase deferred tax assets for the NOL and tax credit carryforwards. Portions of the NOL are expected to be carried back to prior tax years and forward to the 2017 tax year, which could further increase existing tax credit carryforwards. The ultimate outcome of this matter cannot be determined at this time.
Tax Credit Carryforwards
Southern PowerCompany had federal ITC and PTC carryforwards which are expected(primarily related to result in $212Southern Power) totaling $1.2 billion and $26 million, of federal income tax benefitsrespectively, as of September 30, 2015,2016 and $554 million and $1 million, respectively, as of December 31, 2015. Additionally, Southern Company had $165 million of state ITC carryforwards for the state of Georgia as of September 30, 2016 compared to $305$188 million as of December 31, 2014. 2015. See "Unrecognized Tax Benefits" herein for further information.
The federal ITC carryforwards as of September 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 September 30, 2016 begin expiring in 2035 but are expected to be utilized by the end of 2021. The state ITC carryforwards for the state of Georgia as of September 30, 2016 expire between 2020 and 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 29.1% for the financial statementsnine months ended September 30, 2016 compared to 33.5% 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, partially offset by the impact of each registrantadditional state income tax benefits recognized in Item 8 of the Form 10-K for additional tax information.2015.
Mississippi Power
Mississippi Power's effective tax (benefit) rate was (20.9)(276.2)% for the nine months ended September 30, 20152016 compared to (45.5)(20.9)% for the corresponding period in 2014.2015. The increaseeffective tax rate decrease was primarily due to a reductionan increase in tax benefits related to the estimated probable losses on construction of the Kemper IGCC and a decreasean increase in non-taxable AFUDC equity related to placing the Kemper IGCC combined cycle in service in August 2014.equity.
Southern Power
Southern Power's effective tax (benefit) rate was 6.9%(88.9)% for the nine months ended September 30, 20152016 compared to 14.4%6.9% for the corresponding period in 2014.2015. The effective tax rate decrease was primarily due to increased federal income tax benefits from ITCs related to ITCssolar projects expected to be placed in 2015, partially offset by higher pre-tax earningsservice in 20152016 and beneficial state income tax changesadditional PTCs related to wind projects in 2014.2016 compared to 2015.
Unrecognized Tax Benefits
See Note 5 to the financial statements of each registrant under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K for additional information.
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 | 24 |
| | 7 |
| | 31 |
|
| Tax positions from prior periods | 459 |
| | (6 | ) | | 456 |
|
| Reductions due to settlements | — |
| | — |
| | — |
|
| Balance as of September 30, 2015 | $ | 648 |
| | $ | 6 |
| | $ | 657 |
|
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 and deferred federal investment tax credits that no longer meet the more-likely-than-not recognition threshold. See "Section 174 Research and Experimental Deduction" and "Investment Tax Credits" herein for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
The impact on the effectiveChanges during 2016 for unrecognized tax rate, if recognized, wasbenefits were as follows:
|
| | | | | | | | | | | | | | | |
| | As of September 30, 2015 | | As of December 31, 2014 |
| | Mississippi Power | | Southern Power | | Southern Company | | Southern Company |
| | (in millions) |
| Tax positions impacting the effective tax rate | $ | (2 | ) | | $ | 6 |
| | $ | 7 |
| | $ | 10 |
|
| Tax positions not impacting the effective tax rate | 650 |
| | — |
| | 650 |
| | 160 |
|
| Balance of unrecognized tax benefits | $ | 648 |
| | $ | 6 |
| | $ | 657 |
| | $ | 170 |
|
|
| | | | | | | | | | | |
| | Mississippi Power | | Southern Power | | Southern Company |
| | (in millions) |
| Unrecognized tax benefits as of December 31, 2015 | $ | 421 |
| | $ | 8 |
| | $ | 433 |
|
| Tax positions from current periods | — |
| | 12 |
| | 12 |
|
| Tax positions from prior periods | 18 |
| | (1 | ) | | 13 |
|
| Balance as of September 30, 2016 | $ | 439 |
| | $ | 19 |
| | $ | 458 |
|
The tax positions impacting the effective tax ratefrom current periods primarily relate to federal income tax benefits related to ITCs.from deferred ITCs and ITCs impacting the estimated annual effective tax rate for interim reporting purposes. The tax positions not impacting the effectivefrom prior periods primarily relate to federal income tax rate relate tobenefits from ITCs, and from deductions for Kemper IGCC-related R&E expendituresresearch and deferred federal investment tax credits that no longer meet the more-likely-than-not recognition threshold.experimental (R&E) expenditures. See "Section"Section 174 Research and Experimental Deduction" and "Investment Tax Credits" hereinDeduction" below for additional information. These amounts are presented on a gross basis without considering the related federal or state income tax impact.
The impact on the effective tax rate, if recognized, is as follows:
|
| | | | | | | | | | | | | | | |
| | As of September 30, 2016 | | As of December 31, 2015 |
| | Mississippi Power | | Southern Power | | Southern Company | | Southern Company |
| | (in millions) |
| Tax positions impacting the effective tax rate | $ | 1 |
| | $ | 19 |
| | $ | 20 |
| | $ | 10 |
|
| Tax positions not impacting the effective tax rate | 438 |
| | — |
| | 438 |
| | 423 |
|
| Balance of unrecognized tax benefits | $ | 439 |
| | $ | 19 |
| | $ | 458 |
| | $ | 433 |
|
The tax positions impacting the effective tax rate primarily relate to federal income tax benefits from ITCs and Southern Company's estimate of the uncertainty related to the amount of those benefits. The impact on the effective tax rate is determined based on the amount of ITCs, which is uncertain. If these tax positions are not able to be recognized due to a federal audit adjustment equal to the estimated amount, the amount of tax credit carryforwards discussed above would be reduced by approximately $94 million.
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, 2014, and 2015 federal income tax returns and has received partial acceptance letters from the IRS; however, the IRS has not finalized its audits. Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits for the Southern Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2011.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Section 174 Research and Experimental Deduction
Southern Company reduced tax payments for 2015, and included in its 2013 and 2014 consolidated federal income tax returnshas reflected deductions for R&E expenditures related to the Kemper IGCC. In May 2015, Southern 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 believe that a significant portion of the plant costs qualify as deductible R&E expenditures under Internal Revenue Code Section 174. TheSubsequent to September 30, 2016, Southern Company and Mississippi Power responded to a notice of proposed assessment from the IRS, which is currently reviewingcontinuing to review the underlying support for the deduction, but has not completed its audit of these expenditures.deduction. Due to the uncertainty related to this tax position, Southern Company and Mississippi Power had related unrecognized tax benefits associated with these R&E deductions of approximately $414$438 million and associated interest of $7$24 million as of September 30, 2015. The2016. It is reasonably possible that this matter will be resolved in the next 12 months; however, the ultimate outcome of this matter cannot be determined at this time.
Investment Tax Credits
The IRS allocated $279 million (Phase II) of Internal Revenue Code Section 48A tax credits to Mississippi Power in connection with the Kemper IGCC. These tax credits 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. Through September 30, 2015, Southern Company and Mississippi Power had recorded tax benefits totaling $276 million for the Phase II credits, of which approximately $235 million had been utilized. While the in-service date for the remainder of the Kemper IGCC is currently expected to occur in the first half of 2016, Mississippi Power now anticipates the in-service date to occur subsequent to April 19, 2016, but has not made a final determination to that effect. As of September 30, 2015, the more-likely-than-not threshold had no longer been met for recognition of these benefits; therefore, Southern Company and Mississippi Power have reflected these tax credits as unrecognized tax benefits and reclassified the Phase II credits to a current liability on their September 30, 2015 balance sheets, with no impact to net income. Repayment to the IRS would occur with the quarterly estimated tax payment following a final determination that the in-service date would occur subsequent to April 19, 2016. The ultimate outcome of this matter cannot be determined at this time.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Southern Company, the traditional electric operating companies, Southern Power, and Southern PowerCompany Gas are exposed to market risks, primarilyincluding commodity price risk, and interest rate risk, weather 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 grossnet 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
TheSouthern Company, the traditional electric operating companies, Southern Power, and Southern PowerCompany Gas enter into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies and the natural gas distribution utilities of Southern Company Gas have limited exposure to market volatility in energy-related commodity fuel prices and prices of electricity.prices. Each of the traditional electric operating companies managesand certain natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs, implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. The traditional electric operating companies (with respect to wholesale generating capacity), Southern Power, and Southern PowerCompany Gas have limited exposure to market volatility in energy-related commodity fuel prices and prices of electricity because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies, Southern Power, and Southern PowerCompany Gas may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted wholesale generating capacity is used to sell electricity.electricity and natural gas.
To mitigate residual risks relativeSouthern Company Gas uses storage and transportation capacity contracts to movements in electricity prices, the traditional operating companies andmanage market price risks. 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 forCompany Gas purchases natural gas purchases; however,for storage when the current market price paid to buy and transport natural gas plus the cost to store and finance the natural gas is less than the market price Southern Company Gas will receive in the future, resulting in a significant portionpositive net operating margin. Southern Company Gas uses New York Mercantile Exchange (NYMEX) futures and over-the-counter (OTC) contracts to sell natural gas at that future price to substantially protect the operating margin ultimately realized when the stored natural gas is sold. Southern Company Gas also enters into transactions to secure transportation capacity between delivery points in order to
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
serve its customers and various markets. Southern Company Gas uses NYMEX futures and OTC contracts to capture the price differential between the locations served by the capacity in order to substantially protect the operating margin ultimately realized when natural gas is physically flowed between the delivery points. These contracts generally meet the definition of derivatives, but are not designated as hedges for accounting purposes.
Southern Company Gas also enters into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are priced at market.reflected in the statements of income.
Energy-related derivative contracts are accounted for under one of three methods:
Regulatory Hedges — Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the traditional electric operating companies' and Southern Company Gas' 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.and natural gas industries. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.
At September 30, 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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 | | 221 | | 2020 | | 2017 | |
Southern Company(*) | | 540 | | 2020 | | 2022 |
| Alabama Power | | 50 | | 2018 | |
| 75 | | 2020 | | — |
| Georgia Power | | 50 | | 2017 | |
| 148 | | 2020 | | — |
| Gulf Power | | 83 | | 2020 | |
| 57 | | 2020 | | — |
| Mississippi Power | | 37 | | 2018 | |
| 37 | | 2020 | | — |
| Southern Power | | 1 | | 2016 | | 2017 | 9 | | 2017 | | 2016 |
| |
| (*) | Southern Company Gas' derivative instruments are comprised of both long and short natural gas positions. A long position is a contract to purchase natural gas and a short position is a contract to sell natural gas. Southern Company Gas' volume represents the net of long natural gas positions of 3.2 billion mmBtu and short natural gas positions of 2.9 billion mmBtu as of September 30, 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 5 million mmBtu for Southern Company 4 million mmBtu forand Georgia Power, and 1 million mmBtu for Southern Power.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
For cash flow hedges, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending September 30, 20162017 are immaterial for all registrants.
Interest Rate Derivatives
Southern Company and certain subsidiaries may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings, providing an offset, with any difference representing ineffectiveness. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
At September 30, 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 September 30, 2015 | Notional Amount | | Interest Rate Received | Weighted Average Interest Rate Paid | Hedge Maturity Date | | Fair Value
Gain (Loss) at September 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 | | $ | (17 | ) | |
| Gulf Power | | $ | 80 |
| | 3-month
LIBOR | 2.32% | December 2026 | | $ | (6 | ) |
| Cash Flow Hedges of Existing Debt | | Cash Flow Hedges of Existing Debt | | |
| Mississippi Power | | 900 |
| | 1-month
LIBOR | 0.79% | March 2018 | | (1 | ) |
| Fair Value Hedges of Existing Debt | | Fair Value Hedges of Existing Debt | | |
Southern Company(a) | | 250 |
| | 1.30% | 3-month
LIBOR + 0.17% | August 2017 | | 1 |
|
Southern Company(a) | | 300 |
| | 2.75% | 3-month
LIBOR + 0.92% | June 2020 | | 9 |
|
| Georgia Power | | 350 |
| | 3-month
LIBOR | | 2.57% | | November 2025 | | (18 | ) | 250 |
| | 5.40% | 3-month
LIBOR + 4.02% | June 2018 | | 2 |
|
| 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 | | | |
| Southern Company | | 250 |
| | 1.30% | | 3-month
LIBOR + 0.17% | | August 2017 | | 2 |
| |
| Southern Company | | 300 |
| | 2.75% | | 3-month
LIBOR + 0.92% | | June 2020 | | 8 |
| |
| Georgia Power | | 250 |
| | 5.40% | | 3-month
LIBOR + 4.02% | | June 2018 | | 3 |
| 200 |
| | 4.25% | 3-month
LIBOR + 2.46% | December 2019 | | 5 |
|
| Georgia Power | | 200 |
| | 4.25% | | 3-month
LIBOR + 2.46% | | December 2019 | | 5 |
| 500 |
| | 1.95% | 3-month
LIBOR + 0.76% | December 2018 | | 2 |
|
| Derivatives not Designated as Hedges | Derivatives not Designated as Hedges | | | Derivatives not Designated as Hedges | | |
| Southern Power | | 65 |
| (b)(e) | 3-month
LIBOR | 2.50% | October 2016 | (f) | — |
|
Southern Power(a) | | 65 |
| (b) | 3-month
LIBOR | | 2.50% | | October 2016 | (c) | 1 |
| 47 |
| (c)(e) | 3-month
LIBOR | 2.21% | October 2016 | (f) | — |
|
| Total | | $ | 2,065 |
| | $ | (16 | ) | |
| Southern Power | | 65 |
| (d)(e) | 3-month
LIBOR | 2.21% | November 2016 | (g) | — |
|
| Southern Company Consolidated | | $ | 2,657 |
| | $ | 12 |
|
| |
| (a) | Swaption at RE Tranquillity LLC, a subsidiary of Tranquillity. See Note (I) toRepresents the Condensed Financial Statements herein for additional information regarding Tranquillity.Southern Company parent entity. |
| |
| (b) | Swaption at RE Tranquillity LLC. See Note 12 to the financial statements of Southern Company and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information. |
| |
| (c) | Swaption at RE Roserock LLC. See Note 12 to the financial statements of Southern Company and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information. Subsequent to September 30, 2016, Roserock extended the maturity date of its swaption to December 31, 2016. |
| |
| (d) | Swaption at RE Garland Holdings LLC. See Note 12 to the financial statements of Southern Company and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information. |
| |
| (e) | Amortizing notional amount. |
| |
(c)(f) | Represents the mandatory settlement date. Settlement will be based on a 15-year amortizing swap. |
| |
| (g) | Represents the mandatory settlement date. Settlement will be based on a 12-year amortizing swap. |
The estimated pre-tax gains (losses) that willexpected to be reclassified from accumulated OCI to interest expense for the next 12-month period ending September 30, 20162017 are $(21) million for Southern Company and immaterial for all other registrants. Southern Company and certain subsidiaries have deferred gains and losses that are expected to be amortized into earnings through 2037.2046.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 September 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 September 30, 2016 |
| (in millions) | | (in millions) | | | (in millions) |
| Cash Flow Hedges of Existing Debt | | | | | |
| Southern Power | $ | 677 |
| 2.95% | € | 600 |
| 1.00% | June 2022 | $ | (2 | ) |
| Southern Power | 564 |
| 3.78% | 500 |
| 1.85% | June 2026 | 1 |
|
| Total | $ | 1,241 |
| | € | 1,100 |
| | | $ | (1 | ) |
The estimated pre-tax gains (losses) that will be reclassified from accumulated OCI to earnings for the next 12-month period ending September 30, 2017 are $(12) million for Southern Company and Southern Power.
Derivative Financial Statement Presentation and Amounts
Derivative contracts of Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are presented on a net basis in the financial statements to the extent that the contracts are subject to netting arrangements. Some of these energy-related and interest 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.
At September 30, 2016, the fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:
|
| | | | | | |
| | As of September 30, 2016 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities |
| | (in millions) |
| Southern Company | | |
| Derivatives designated as hedging instruments for regulatory purposes | | |
| Energy-related derivatives: | | |
| Other current assets/Liabilities from risk management activities, net of collateral | $ | 20 |
| $ | (62 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | 13 |
| (53 | ) |
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 33 |
| $ | (115 | ) |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | |
| Energy-related derivatives: | | |
| Other current assets/Liabilities from risk management activities, net of collateral | $ | 4 |
| $ | (6 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| (1 | ) |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | |
| | As of September 30, 2016 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities |
| | (in millions) |
| Interest rate derivatives: |
|
|
| Other current assets/Liabilities from risk management activities, net of collateral | $ | 8 |
| $ | (7 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | 11 |
| — |
|
| Foreign currency derivatives: | | |
| Other current assets/Liabilities from risk management activities, net of collateral | $ | — |
| $ | (24 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | 23 |
| — |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 46 |
| $ | (38 | ) |
| Derivatives not designated as hedging instruments | | |
| Energy-related derivatives: | | |
| Other current assets/Liabilities from risk management activities, net of collateral | $ | 305 |
| $ | (345 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | 58 |
| (74 | ) |
| Total derivatives not designated as hedging instruments | $ | 363 |
| $ | (419 | ) |
| Gross amounts of recognized assets and liabilities | $ | 442 |
| $ | (572 | ) |
Gross amounts offset in the Balance Sheet(*) | $ | (283 | ) | $ | 394 |
|
| Net amounts of assets and liabilities presented in the Balance Sheet | $ | 159 |
| $ | (178 | ) |
| | | |
| Alabama Power | | |
| Derivatives designated as hedging instruments for regulatory purposes | | |
| Energy-related derivatives: | | |
| Other current assets/Liabilities from risk management activities | $ | 4 |
| $ | (14 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | 4 |
| (7 | ) |
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 8 |
| $ | (21 | ) |
| Gross amounts of recognized assets and liabilities | $ | 8 |
| $ | (21 | ) |
Gross amounts offset in the Balance Sheet(*) | $ | (7 | ) | $ | 7 |
|
| Net amounts of assets and liabilities presented in the Balance Sheet | $ | 1 |
| $ | (14 | ) |
| | | |
| Georgia Power | | |
| Derivatives designated as hedging instruments for regulatory purposes | | |
| Energy-related derivatives: | | |
| Other current assets/Other current liabilities | $ | 7 |
| $ | (5 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | 8 |
| (11 | ) |
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 15 |
| $ | (16 | ) |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | |
| Interest rate derivatives: | | |
| Other current assets/Other current liabilities | $ | 5 |
| $ | — |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 5 |
| — |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 10 |
| $ | — |
|
| Gross amounts of recognized assets and liabilities | $ | 25 |
| $ | (16 | ) |
Gross amounts offset in the Balance Sheet(*) | $ | (11 | ) | $ | 11 |
|
| Net amounts of assets and liabilities presented in the Balance Sheet | $ | 14 |
| $ | (5 | ) |
| | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | |
| | As of September 30, 2016 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities |
| | (in millions) |
| Gulf Power | | |
| Derivatives designated as hedging instruments for regulatory purposes | | |
| Energy-related derivatives: | | |
| Other current assets/Liabilities from risk management activities | $ | 1 |
| $ | (24 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| (27 | ) |
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 1 |
| $ | (51 | ) |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | |
| Interest rate derivatives: | | |
| Other current assets/Liabilities from risk management activities | $ | — |
| $ | (6 | ) |
| Gross amounts of recognized assets and liabilities | $ | 1 |
| $ | (57 | ) |
Gross amounts offset in the Balance Sheet(*) | $ | (1 | ) | $ | 1 |
|
| Net amounts of assets and liabilities presented in the Balance Sheet | $ | — |
| $ | (56 | ) |
| | | |
| Mississippi Power | | |
| Derivatives designated as hedging instruments for regulatory purposes | | |
| Energy-related derivatives: | | |
| Other current assets/Other current liabilities | $ | — |
| $ | (13 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | 1 |
| (8 | ) |
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 1 |
| $ | (21 | ) |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | |
| Interest rate derivatives: | | |
| Other current assets/Other current liabilities | $ | — |
| $ | (1 | ) |
| Gross amounts of recognized assets and liabilities | $ | 1 |
| $ | (22 | ) |
Gross amounts offset in the Balance Sheet(*) | $ | (1 | ) | $ | 1 |
|
| Net amounts of assets and liabilities presented in the Balance Sheet | $ | — |
| $ | (21 | ) |
| | | |
| Southern Power | | |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | |
| Energy-related derivatives: | | |
| Other current assets/Other current liabilities | $ | 2 |
| $ | (3 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| — |
|
| Foreign currency derivatives: | | |
| Other current assets/Other current liabilities | $ | — |
| $ | (24 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | 23 |
| — |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 25 |
| $ | (27 | ) |
| Derivatives not designated as hedging instruments | | |
| Energy-related derivatives: | | |
| Other current assets/Other current liabilities | $ | 1 |
| $ | — |
|
| Gross amounts of recognized assets and liabilities | $ | 26 |
| $ | (27 | ) |
Gross amounts offset in the Balance Sheet(*) | $ | (1 | ) | $ | 1 |
|
| Net amounts of assets and liabilities presented in the Balance Sheet | $ | 25 |
| $ | (26 | ) |
| |
| (*) | Includes any cash/financial collateral pledged or received. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
At December 31, 2015, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:
| | | Asset Derivatives at September 30, 2015 | |
| 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 | Southern Power |
| | | (in millions) | (in millions) |
| Derivatives designated as hedging instruments for regulatory purposes | | | | | | | | | | | | | |
| Energy-related derivatives: | | | | | | | | | | | | | |
| Other current assets | | $ | 3 |
| | $ | 1 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | | $ | 3 |
| $ | 1 |
| $ | 2 |
| $ | — |
| $ | — |
|
| Other deferred charges and assets | | 1 |
| | 1 |
| | — |
| | — |
| | — |
| | | |
| Total derivatives designated as hedging instruments for regulatory purposes | | $ | 4 |
| | $ | 2 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | 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 | | $ | 11 |
| | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | — |
| 19 |
| — |
| 5 |
| 1 |
| — |
|
| Other deferred charges and assets | | 8 |
| | — |
| | 4 |
| | — |
| | — |
| | — |
| |
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | | $ | 19 |
| | $ | — |
| | $ | 9 |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | 22 |
| $ | — |
| $ | 5 |
| $ | 1 |
| $ | 3 |
|
| Derivatives not designated as hedging instruments | | | | | | | | | | | | | |
| Energy-related derivatives: | | |
| Other current assets | | $ | 1 |
| $ | — |
| $ | — |
| $ | — |
| $ | 1 |
|
| Interest rate derivatives: | | | | | | | | | | | | | |
| Other deferred charges and assets | | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1 |
| |
| Other current assets | | 3 |
| — |
| — |
| — |
| 3 |
|
| Total derivatives not designated as hedging instruments | | $ | 4 |
| $ | — |
| $ | — |
| $ | — |
| $ | 4 |
|
| Total asset derivatives | | $ | 24 |
| | $ | 2 |
| | $ | 11 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| $ | 29 |
| $ | 1 |
| $ | 7 |
| $ | 1 |
| $ | 7 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| Liability Derivatives at September 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(*) | | $ | 117 |
| | $ | 36 |
| | $ | 14 |
| | $ | 41 |
| | $ | 26 |
| | |
| Other deferred credits and liabilities | | 94 |
| | 18 |
| | 2 |
| | 53 |
| | 21 |
| | |
| Total derivatives designated as hedging instruments for regulatory purposes | | $ | 211 |
| | $ | 54 |
| | $ | 16 |
| | $ | 94 |
| | $ | 47 |
| | N/A |
|
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | | | | | | | | | |
| Interest rate derivatives: | | | | | | | | | | | | |
Other current liabilities(*) | | $ | 36 |
| | $ | 17 |
| | $ | 19 |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Total liability derivatives | | $ | 247 |
| | $ | 71 |
| | $ | 35 |
| | $ | 94 |
| | $ | 47 |
| | $ | — |
|
| |
(*) | 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)
At December 31, 2014, 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 | |
| Liability Derivatives at December 31, 2015 | | Liability 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 |
| | $ | — |
| | $ | — |
| | | |
| Other deferred charges and assets | | — |
| | — |
| | 1 |
| | — |
| | — |
| | | |
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 | | $ | 7 |
| | $ | 1 |
| | $ | 7 |
| | $ | — |
| | $ | — |
| | N/A |
| $ | 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: | | | | | | | | | | | | | |
| Other current assets | | $ | 7 |
| | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | — |
| |
| Other deferred charges and assets | | 1 |
| | — |
| | 1 |
| | — |
| | — |
| | — |
| |
| 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 | | $ | 8 |
| | $ | — |
| | $ | 6 |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | 32 |
| $ | 15 |
| $ | 6 |
| $ | — |
| $ | — |
| $ | 2 |
|
| Derivatives not designated as hedging instruments | | | | | | | | | | | | | |
| Energy-related derivatives: | | | | | | | | | | | | | |
| Other current assets | | $ | 6 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 5 |
| |
| Total asset derivatives | | $ | 21 |
| | $ | 1 |
| | $ | 13 |
| | $ | — |
| | $ | — |
| | $ | 5 |
| |
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. |
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." |
TheIn 2015, 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 at September 30, 2015 and December 31, 20142015 are presented in the following tables.table:
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| | | Derivative Contracts at September 30, 2015 | |
| 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) | | $ | 4 |
| | $ | 2 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | 7 |
| $ | 1 |
| $ | 2 |
| $ | — |
| $ | — |
| $ | 4 |
|
Gross amounts not offset in the Balance Sheet (b) | | (4 | ) | | (2 | ) | | (2 | ) | | — |
| | — |
| | — |
| (6 | ) | (1 | ) | (2 | ) | — |
| — |
| (1 | ) |
| Net energy-related derivative assets | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | 1 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 3 |
|
| Interest rate derivatives: | | | | | | | | | | | | | |
Interest rate derivatives presented in the Balance Sheet (a) | | $ | 20 |
| | $ | — |
| | $ | 9 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| $ | 22 |
| $ | — |
| $ | 5 |
| $ | 1 |
| $ | — |
| $ | 3 |
|
Gross amounts not offset in the Balance Sheet (b) | | (9 | ) | | — |
| | (2 | ) | | — |
| | — |
| | — |
| (9 | ) | — |
| (4 | ) | — |
| — |
| — |
|
| Net interest rate derivative assets | | $ | 11 |
| | $ | — |
| | $ | 7 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| $ | 13 |
| $ | — |
| $ | 1 |
| $ | 1 |
| $ | — |
| $ | 3 |
|
| Liabilities | | | | | | | | | | | | | |
| Energy-related derivatives: | | | | | | | | | | | | | |
Energy-related derivatives presented in the Balance Sheet (a) | | $ | 211 |
| | $ | 54 |
| | $ | 16 |
| | $ | 94 |
| | $ | 47 |
| | $ | — |
| $ | 220 |
| $ | 55 |
| $ | 15 |
| $ | 100 |
| $ | 47 |
| $ | 3 |
|
Gross amounts not offset in the Balance Sheet (b) | | (4 | ) | | (2 | ) | | (2 | ) | | — |
| | — |
| | — |
| (6 | ) | (1 | ) | (2 | ) | — |
| — |
| (1 | ) |
| Net energy-related derivative liabilities | | $ | 207 |
| | $ | 52 |
| | $ | 14 |
| | $ | 94 |
| | $ | 47 |
| | $ | — |
| $ | 214 |
| $ | 54 |
| $ | 13 |
| $ | 100 |
| $ | 47 |
| $ | 2 |
|
| Interest rate derivatives: | | | | | | | | | | | | | |
Interest rate derivatives presented in the Balance Sheet (a) | | $ | 36 |
| | $ | 17 |
| | $ | 19 |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | 30 |
| $ | 15 |
| $ | 6 |
| $ | — |
| $ | — |
| $ | — |
|
Gross amounts not offset in the Balance Sheet (b) | | (9 | ) | | — |
| | (2 | ) | | — |
| | — |
| | — |
| (9 | ) | — |
| (4 | ) | — |
| — |
| — |
|
| Net interest rate derivative liabilities | | $ | 27 |
| | $ | 17 |
| | $ | 17 |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | 21 |
| $ | 15 |
| $ | 2 |
| $ | — |
| $ | — |
| $ | — |
|
| |
| (a) | NoneAs of December 31, 2015, none of the registrants offsetsoffset fair value amounts for multiple derivative instruments executed with the same counterparty onin the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented onin the balance sheets are the same. |
| |
| (b) | Includes gross amounts subject to netting terms that are not offset onin 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 |
| | | Fair Value |
| | | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power | | Southern Power |
| | | (in millions) |
| Assets | | | | | | | | | | | | |
| Energy-related derivatives: | | | | | | | | | | | | |
Energy-related derivatives presented in the Balance Sheet (a) | | $ | 13 |
| | $ | 1 |
| | $ | 7 |
| | $ | — |
| | $ | — |
| | $ | 5 |
|
Gross amounts not offset in the Balance Sheet (b) | | (9 | ) | | — |
| | (7 | ) | | — |
| | — |
| | — |
|
| Net energy-related derivative assets | | $ | 4 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 5 |
|
| Interest rate derivatives: | | | | | | | | | | | | |
Interest rate derivatives presented in the Balance Sheet (a) | | $ | 8 |
| | $ | — |
| | $ | 6 |
| | $ | — |
| | $ | — |
| | $ | — |
|
Gross amounts not offset in the Balance Sheet (b) | | (8 | ) | | — |
| | (6 | ) | | — |
| | — |
| | — |
|
| Net interest rate derivative assets | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Liabilities | | | | | | | | | | | | |
| Energy-related derivatives: | | | | | | | | | | | | |
Energy-related derivatives presented in the Balance Sheet (a) | | $ | 201 |
| | $ | 53 |
| | $ | 27 |
| | $ | 72 |
| | $ | 45 |
| | $ | 4 |
|
Gross amounts not offset in the Balance Sheet (b) | | (9 | ) | | — |
| | (7 | ) | | — |
| | — |
| | — |
|
| Net energy-related derivative liabilities | | $ | 192 |
| | $ | 53 |
| | $ | 20 |
| | $ | 72 |
| | $ | 45 |
| | $ | 4 |
|
| Interest rate derivatives: | | | | | | | | | | | | |
Interest rate derivatives presented in the Balance Sheet (a) | | $ | 24 |
| | $ | 8 |
| | $ | 14 |
| | $ | — |
| | $ | — |
| | $ | — |
|
Gross amounts not offset in the Balance Sheet (b) | | (8 | ) | | — |
| | (6 | ) | | — |
| | — |
| | — |
|
| Net interest rate derivative liabilities | | $ | 16 |
| | $ | 8 |
| | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | — |
|
| |
(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 September 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 September 30, 2015 | |
| Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at September 30, 2016 | | Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at September 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 | | $ | (117 | ) | | $ | (36 | ) | | $ | (14 | ) | | $ | (41 | ) | | $ | (26 | ) | $ | (52 | ) | $ | (10 | ) | $ | (2 | ) | $ | (24 | ) | $ | (13 | ) |
| Other regulatory assets, deferred | | (94 | ) | | (18 | ) | | (2 | ) | | (53 | ) | | (21 | ) | (42 | ) | (4 | ) | (4 | ) | (26 | ) | (8 | ) |
Other regulatory liabilities, current (a) | | 3 |
| | 1 |
| | 2 |
| | — |
| | — |
| 8 |
| 1 |
| 4 |
| — |
| — |
|
Other regulatory liabilities, deferred (b) | | 1 |
| | 1 |
| | — |
| | — |
| | — |
| 1 |
| — |
| 1 |
| — |
| — |
|
| Total energy-related derivative gains (losses) | | $ | (207 | ) | | $ | (52 | ) | | $ | (14 | ) | | $ | (94 | ) | | $ | (47 | ) | $ | (85 | ) | $ | (13 | ) | $ | (1 | ) | $ | (50 | ) | $ | (21 | ) |
| |
| (a) | Southern Company, Alabama Power, and Georgia Power includeincludes 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 in the Balance Sheet at December 31, 2015 | | Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2015 |
Derivative Category and Balance Sheet Location | | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power | 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 | ) |
| |
(a)(*) | Southern Company, Alabama Power, and Georgia Power includeincludes 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 September 30, 2015 and 2014, the pre-tax effects of interest rate 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 |
| | | 2015 | | 2014 | | | | 2015 | | 2014 |
| | | (in millions) | | | | (in millions) |
| Southern Company | | | | | | | | | | |
| Interest rate derivatives | | $ | (28 | ) | | $ | (1 | ) | | Interest expense, net of amounts capitalized | | $ | (2 | ) | | $ | (2 | ) |
| Alabama Power | | | | | | | | | | |
| Interest rate derivatives | | $ | (10 | ) | | $ | (1 | ) | | Interest expense, net of amounts capitalized | | $ | (1 | ) | | $ | (1 | ) |
| Georgia Power | | | | | | | | | | |
| Interest rate derivatives | | $ | (18 | ) | | $ | — |
| | Interest expense, net of amounts capitalized | | $ | (1 | ) | | $ | (1 | ) |
For the nine months ended September 30, 2015 and 2014, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments were as follows:
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | |
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 | | $ | (26 | ) | | $ | (1 | ) | | Interest expense, net of amounts capitalized | | $ | (7 | ) | | $ | (6 | ) |
| Alabama Power | | | | | | | | | | |
| Interest rate derivatives | | $ | (9 | ) | | $ | (1 | ) | | Interest expense, net of amounts capitalized | | $ | (2 | ) | | $ | (2 | ) |
| Georgia Power | | | | | | | | | | |
| Interest rate derivatives | | $ | (17 | ) | | $ | — |
| | Interest expense, net of amounts capitalized | | $ | (3 | ) | | $ | (2 | ) |
| 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 | ) | | $ | (1 | ) |
For the three months ended September 30, 2016 and 2015, the pre-tax effects of energy-related derivatives, interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instruments were as follows:
|
| | | | | | | | | | | | | | | | |
Derivatives in Cash Flow Hedging Relationships | Gain (Loss) Recognized in OCI on Derivative (Effective Portion) | | Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) |
| | Statements of Income Location | Amount |
| | 2016 | | 2015 | | | 2016 | | 2015 |
| | (in millions) | | | (in millions) |
| Southern Company | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | — |
| | Amortization | $ | 1 |
| | $ | — |
|
| Interest rate derivatives | (6 | ) | | (28 | ) | | Interest expense, net of amounts capitalized | (6 | ) | | (2 | ) |
| Foreign currency derivatives | 37 |
| | — |
| | Interest expense, net of amounts capitalized | (6 | ) | | — |
|
| | | | | | Other income (expense), net(*) | 7 |
| | — |
|
| Total | $ | 31 |
| | $ | (28 | ) | | | $ | (4 | ) | | $ | (2 | ) |
| Alabama Power | | | | | | | | |
| Interest rate derivatives | $ | — |
| | $ | (10 | ) | | Interest expense, net of amounts capitalized | $ | (2 | ) | | $ | (1 | ) |
| Georgia Power | | | | | | | | |
| Interest rate derivatives | $ | — |
| | $ | (18 | ) | | Interest expense, net of amounts capitalized | $ | (1 | ) | | $ | (1 | ) |
| Southern Power | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | — |
| | Amortization | $ | 1 |
| | $ | — |
|
| Foreign currency derivatives | 37 |
| | — |
| | Interest expense, net of amounts capitalized | (6 | ) | | — |
|
| | | | | | Other income (expense), net(*) | 7 |
| | — |
|
| Total | $ | 37 |
| | $ | — |
| | | $ | 2 |
| | $ | — |
|
| |
| (*) | The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
For the nine months ended September 30, 20152016 and 2014,2015, the pre-tax effects of energy-related derivatives, 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 | | | | | | | | |
| Energy-related derivatives | $ | (1 | ) | | $ | — |
| | Amortization | $ | 1 |
| | $ | — |
|
| Interest rate derivatives | (189 | ) | | (26 | ) | | Interest expense, net of amounts capitalized | (13 | ) | | (7 | ) |
| Foreign currency derivatives | (1 | ) | | — |
| | Interest expense, net of amounts capitalized | (7 | ) | | — |
|
| | | | | | Other income (expense), net(*) | (13 | ) | | — |
|
| Total | $ | (191 | ) | | $ | (26 | ) | | | $ | (32 | ) | | $ | (7 | ) |
| Alabama Power | | | | | | | | |
| Interest rate derivatives | $ | (3 | ) | | $ | (9 | ) | | Interest expense, net of amounts capitalized | $ | (5 | ) | | $ | (2 | ) |
| Georgia Power | | | | | | | | |
| Interest rate derivatives | $ | — |
| | $ | (17 | ) | | Interest expense, net of amounts capitalized | $ | (3 | ) | | $ | (3 | ) |
| Gulf Power | | | | | | | | |
| Interest rate derivatives | $ | (7 | ) | | $ | — |
| | Interest expense, net of amounts capitalized | $ | — |
| | $ | — |
|
| Mississippi Power | | | | | | | | |
| Interest rate derivatives | $ | (1 | ) | | $ | — |
| | Interest expense, net of amounts capitalized | $ | (1 | ) | | $ | (1 | ) |
| Southern Power | | | | | | | | |
| Energy-related derivatives | $ | (1 | ) | | $ | — |
| | Amortization | $ | 1 |
| | $ | — |
|
| Interest rate derivatives | — |
| | — |
| | Interest expense, net of amounts capitalized | (1 | ) | | (1 | ) |
| Foreign currency derivatives | (1 | ) | | — |
| | Interest expense, net of amounts capitalized | (7 | ) | | — |
|
| | | | | | Other income (expense), net(*) | (13 | ) | | — |
|
| Total | $ | (2 | ) | | $ | — |
| | | $ | (20 | ) | | $ | (1 | ) |
| |
| (*) | The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes. |
For the three and nine months ended September 30, 20152016 and 2014,2015, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were as follows:
| | | Derivatives in Fair Value Hedging Relationships | | Derivatives in Fair Value Hedging Relationships |
| | | | Gain (Loss) |
| | | Gain (Loss) | | Three Months Ended September 30, | Nine Months Ended September 30, |
| Derivative Category | | Statements of Income Location | 2015 | | 2014 | Statements of Income Location | 2016 | | 2015 | 2016 | | 2015 |
| | | (in millions) | | (in millions) |
| Southern Company | | | | | | | | | | |
| Interest rate derivatives: | | Interest expense, net of amounts capitalized | $ | 15 |
| | $ | (1 | ) | Interest expense, net of amounts capitalized | $ | (9 | ) | | $ | 15 |
| $ | 15 |
| | $ | 19 |
|
| Georgia Power | | | | | | | | | | |
| Interest rate derivatives: | | Interest expense, net of amounts capitalized | $ | 7 |
| | $ | — |
| Interest expense, net of amounts capitalized | $ | (5 | ) | | $ | 7 |
| $ | 10 |
| | $ | 9 |
|
For the nine months ended September 30, 2015 and 2014, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were as follows:
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | |
| Derivatives in Fair Value Hedging Relationships | | |
| | | | Gain (Loss) |
| Derivative Category | | Statements of Income Location | 2015 | | 2014 |
| | | | (in millions) |
| Southern Company | | | | | |
| Interest rate derivatives: | | Interest expense, net of amounts capitalized | $ | 19 |
| | $ | (4 | ) |
| Georgia Power | | | | | |
| Interest rate derivatives: | | Interest expense, net of amounts capitalized | $ | 9 |
| | $ | — |
|
For the three and nine months ended September 30, 20152016 and 2014,2015, 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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
For the three and nine months ended September 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 registrantsSouthern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At September 30, 2015, the registrants'2016, Southern Company had $111 million of collateral posted with theirderivative counterparties. The amount of collateral posted with the derivative counterparties for all other registrants was immaterial.
At September 30, 2015,2016, the fair value of derivative liabilities with contingent features was $54$22 million for all registrants. The maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $54$22 million for all registrants and include certain agreements that could require collateral in the event that one or more Southern Company power pool participants or Southern Company 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, Southern Power, and Southern PowerCompany Gas are exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern Company, the traditional electric operating companies, Southern Power, and Southern PowerCompany Gas only enter into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. Southern Company, the traditional electric operating companies, Southern Power, and Southern PowerCompany Gas have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate Southern Company's, the traditional electric operating companies', Southern Power's, and Southern Power'sCompany Gas' exposure to counterparty credit risk. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary. 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
Proposed Merger with AGL Resources
On August 23, 2015, Southern Company Gas
Southern Company Gas, formerly known as AGL Resources and Merger Sub entered intoInc., 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 Agreement. Under the termsfor a total purchase price of the Merger Agreement, subject to the satisfaction or waiver (if permissible under applicable law) of specified conditions, Merger Sub will be merged withapproximately $8.0 billion and into AGL Resources. AGL Resources will survive the Merger and becomeSouthern Company Gas became a wholly-owned, direct subsidiary of Southern Company. Upon the consummation of the Merger, each share of common stock of AGL Resources issued and outstanding immediately prior to the effective time of the Merger (Effective Time), other than shares owned by AGL Resources as treasury stock, shares owned by a subsidiary of AGL Resources, and shares owned by shareholders who have properly exercised and perfected dissenters' rights, will be converted into the right to receive $66 in cash, without interest and less any applicable withholding taxes. Other equity-based securities of AGL Resources will be cancelled for cash consideration or converted into new awards from Southern Company as described in the Merger Agreement.
In accordance with GAAP, the Merger will be accounted for using the acquisition method of accounting whereby the assets acquired and liabilities assumed are recognized at fair value as of the acquisition date. The excess of the purchase price over the fair values of AGL Resources' assets and liabilities will be recorded as goodwill. Southern Company expects total cash of $8.2 billion to be required to fund the purchase price of approximately $8.0 billion to acquire AGL Resources common stock, options to purchase shares of AGL Resources common stock, and restricted stock units payable in shares of AGL Resources common stock and to fund acquisition-related expenses and financing costs of approximately $200 million. Southern Company will also assume AGL Resources' outstanding indebtedness.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
ConsummationThe Merger was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value as of the Merger is subject toacquisition date. The following table presents the satisfaction or waiver of certain closing conditions, including, among others, (i) approvalpreliminary purchase price allocation:
|
| | | |
| Southern Company Gas Purchase Price | September 30, 2016 |
| | (in millions) |
| Current assets | $ | 1,557 |
|
| Property, plant, and equipment | 10,108 |
|
| Goodwill | 5,937 |
|
| Intangible assets | 400 |
|
| Regulatory assets | 1,118 |
|
| Other assets | 229 |
|
| Current liabilities | (2,201 | ) |
| Other liabilities | (4,712 | ) |
| Long-term debt | (4,261 | ) |
| Noncontrolling interests | (174 | ) |
| Total purchase price | $ | 8,001 |
|
The excess of the Merger Agreement by AGL Resources' shareholders, which is scheduled for vote on November 19, 2015, (ii) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, (iii) the approval of the California Public Utilities Commission, Georgia PSC, Illinois Commerce Commission, Maryland PSC, New Jersey Board of Public Utilities, and Virginia State Corporation Commission, and other approvals required under applicable state laws, and the approval of the Federal Communications Commission (FCC) for the transfer of controlpurchase price over the FCC licenses of certain subsidiaries of AGL Resources and any other approval which Southern Company and AGL Resources agree are required, (iv) the absence of a judgment, order, decision, injunction, ruling, or other finding or agency requirement of a governmental entity prohibiting the consummation of the Merger, and (v) other customary closing conditions, including (a) subject to certain materiality qualifiers, the accuracy of each party's representations and warranties and (b) each party's performance in all material respects of its obligations under the Merger Agreement. Southern Company expects to complete the required state regulatory filings in the fourth quarter 2015.
Subject to certain limitations, either party may terminate the Merger Agreement if the Merger is not consummated by August 23, 2016, which date may be extended by either party to February 23, 2017 if, on August 23, 2016, all conditions to closing other than those relating to (i) regulatory approvals and (ii) the absence of legal restraints preventing consummation of the Merger (to the extent relating to regulatory approvals) have been satisfied. Upon termination of the Merger Agreement under certain specified circumstances, AGL Resources will be required to pay Southern Company a termination fee of $201 million or reimburse Southern Company's expenses up to $5 million (which reimbursement shall reduce on a dollar-for-dollar basis any termination fee subsequently payable by AGL Resources). Southern Company currently expects to complete the transaction in the second half of 2016.
The ultimate outcome of these matters cannot be determined at this time.
Merger Financing
Southern Company intends to initially fund the cash consideration for the Merger using approximately $7.0 billion of debt and $1.0 billion of equity. Southern Company expects to issue approximately $2.0 billion of additional equity through 2019 to offset a portion of the debt issued to fund the cash consideration for the Merger. In addition, Southern Company entered into the $8.1 billion Bridge Agreement on September 30, 2015 to provide financing for the Merger in the event long-term financing is not available. See Note (E) under "Bank Credit Arrangements" herein for additional information regarding the Bridge Agreement.
Southern Power
See Note 2 to the financial statements 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, theestimated fair values of the assets acquired and liabilities assumed of SG2 Imperial Valley, LLC were finalized$5.9 billion is recognized as goodwill, which is primarily attributable to positioning the Southern Company system to provide natural gas infrastructure to meet customers' growing energy needs and recordedto compete for growth across the energy value chain. Southern Company anticipates that much of the value assigned to goodwill will not be deductible for tax purposes. The estimated fair values noted above are preliminary and are subject to change upon finalization of the purchase accounting assessment as follows: $707 million as property, plant, and equipment and $20 million as prepaymentsadditional information related to transmission services.the fair value of assets and liabilities becomes available. Subsequent adjustments to the preliminary purchase price allocation are not expected to have a material impact on the results of operations and financial position of Southern Company.
The preliminary valuation of identifiable intangible assets included customer relationships, trade names, and storage and transportation contracts with estimated lives of one to 28 years. The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3).
The results of operations for Southern Company Gas have been included in the consolidated financial statements from the date of acquisition and consist of operating revenues of $543 million and net income of $4 million.
The following summarized unaudited pro forma consolidated statement of earnings information assumes that the acquisition of Southern Company Gas was completed on January 1, 2015. The summarized unaudited pro forma consolidated statement of earnings information includes adjustments for (i) intercompany sales, (ii) amortization of intangible assets, (iii) adjustments to interest expense to reflect current interest rates on Southern Company Gas debt and additional interest expense associated with borrowings by Southern Company to fund the Merger, and (iv) the elimination of nonrecurring expenses associated with the Merger.
|
| | | | | | |
| | For the Nine Months Ended September 30, |
| | 2016 | 2015 |
| | |
Operating revenues (in millions) | $ | 16,609 |
| $ | 16,865 |
|
Net income attributable to Southern Company (in millions) | $ | 2,369 |
| $ | 2,269 |
|
| Basic EPS | $ | 2.50 |
| $ | 2.43 |
|
| Diluted EPS | $ | 2.48 |
| $ | 2.42 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
These unaudited pro forma results are for comparative purposes only and may not be indicative of the results that would have occurred had this acquisition been completed on January 1, 2015 or the results that would be attained in the future.
During 2015,the three and nine months ended September 30, 2016, Southern Company recorded in its statements of income costs associated with the Merger of approximately $40.8 million and $104.1 million, respectively, of which $40.6 million and $73.5 million is included in operating expenses and $0.2 million and $30.6 million is included in other income and (expense), respectively. These costs include external transaction costs for financing, legal, and consulting services, as well as rate credits and additional compensation-related expenses.
See Note 12 to the financial statements of Southern Company under "Southern Company – Proposed Merger with AGL Resources" in Item 8 of the Form 10-K for additional information.
Acquisition of PowerSecure International, Inc.
On May 9, 2016, Southern Company acquired all of the outstanding stock of PowerSecure, a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure, for $18.75 per common share in cash, resulting in an aggregate purchase price of $429 million. As a result, PowerSecure became a wholly-owned subsidiary of Southern Company.
The acquisition of PowerSecure was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value as of the acquisition date. The allocation of the purchase price is as follows:
|
| | | |
| PowerSecure Purchase Price | September 30, 2016 |
| | (in millions) |
| Current assets | $ | 172 |
|
| Property, plant, and equipment | 46 |
|
| Goodwill | 284 |
|
| Intangible assets | 101 |
|
| Other assets | 6 |
|
| Current liabilities | (145 | ) |
| Long-term debt, including current portion | (18 | ) |
| Deferred credits and other liabilities | (17 | ) |
| Total purchase price | $ | 429 |
|
The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $284 million was recognized as goodwill, which is primarily attributable to expected business expansion opportunities for PowerSecure. Southern Company anticipates that the majority of the value assigned to goodwill will not be deductible for tax purposes.
The valuation of identifiable intangible assets included customer relationships, trade names, patents, backlog, and software with estimated lives of one to 26 years. The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3).
The results of operations for PowerSecure have been included in the consolidated financial statements from the date of acquisition and are immaterial to the consolidated financial results of Southern Company. Pro forma results of operations have not been presented for the acquisition because the effects of the acquisition were immaterial to Southern Company's consolidated financial results for all periods presented.
Alliance with Bloom Energy Corporation
On October 24, 2016, a subsidiary of Southern Company acquired from an affiliate of Bloom Energy Corporation (Bloom) all of the equity interests of 2016 ESA HoldCo, LLC and its subsidiary, 2016 ESA Project Company, LLC.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
2016 ESA Project Company, LLC expects to acquire 50 MWs of Bloom fuel cell systems to serve commercial and industrial customers under long-term PPAs. In connection with this transaction, PowerSecure and Bloom agreed to pursue a strategic alliance to develop technology for behind-the-meter energy solutions.
Investment in Southern Natural Gas
On July 10, 2016, Southern Company and Kinder Morgan, Inc. (Kinder Morgan) entered into a definitive agreement for Southern Company to acquire a 50% equity interest in SNG, which is the owner of a 7,000-mile pipeline system connecting natural gas supply basins in Texas, Louisiana, Mississippi, and Alabama to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee. On August 31, 2016, Southern Company assigned its rights and obligations under the definitive agreement to a wholly-owned, indirect subsidiary of Southern Company Gas. On September 1, 2016, Southern Company Gas completed the acquisition for a purchase price of approximately $1.4 billion. The investment in SNG is accounted for using the equity method.
Acquisition of Remaining Interest in SouthStar
SouthStar is a retail natural gas marketer and markets natural gas to residential, commercial, and industrial customers, primarily in Georgia and Illinois. At September 30, 2016, Southern Company Gas had an 85% ownership interest in SouthStar, with Piedmont owning the remaining 15%. Subsequent to September 30, 2016, Southern Company Gas purchased Piedmont's 15% interest in SouthStar for $160 million. Beginning in the fourth quarter 2016, SouthStar will be fully consolidated with Southern Company Gas.
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 nine months ended September 30, 2016, the fair values of the assets and liabilities acquired of Desert Stateline, Garland, Garland A, Lost Hills Blackwell, Morelos, North Star, Roserock, and Tranquillity were finalized with no changes to the fair values reported.
During 2016, in accordance with its overall growth strategy, Southern Power or contracted to acquire throughone of its wholly-owned subsidiaries, Southern Renewable Partnerships, LLC orand Southern Renewable Energy, Inc. (SRE), acquired or contracted to acquire the following projects in accordance with its overall growth strategy, which are included in its capital program estimates for 2015.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 Entity | Seller; Acquisition Date | Approx. Nameplate Capacity | Location | Southern Power Percentage Ownership | | Expected/Actual Commercial Operation Date | PPA
Counterparties for Entire Plant Output | PPA Contract Period | Approx. Purchase Price | |
| | | (MW) | | | | | | | (in millions) | |
| WIND |
| Kay Wind, LLC | Apex Clean Energy Holdings, LLC
| 299 | Kay County, Oklahoma | 100 | % | | Fourth quarter 2015 | Westar Energy, Inc. and Grant River Dam Authority | 20 years | $ | 492 |
| (a) |
| | | | | | | | | | | |
| Grant Wind, LLC | Apex Clean Energy Holdings, LLC
| 151 | Grant County, Oklahoma | 100 | % | | First quarter 2016 | Western Farmers, East Texas, and Northeast Texas Electric Cooperative | 20 years | $ | 264 |
| (a) |
| SOLAR |
| Lost Hills Blackwell Holdings, LLC (Lost Hills Blackwell) | First Solar, Inc. (First Solar)
April 15, 2015 | 35 | Kern County, California | 51 | % | (b) | April 17, 2015 | City of Roseville, California/Pacific Gas and Electric Company | 29 years | $ | 74 |
| (c) |
| | | | | | | | | | | |
| NS Solar Holdings, LLC (North Star) | First Solar
April 30, 2015 | 61 | Fresno County, California | 51 | % | (b) | June 20, 2015 | Pacific Gas and Electric Company | 20 years | $ | 211 |
| (d) |
| | | | | | | | | | | |
| Tranquillity | Recurrent Energy, LLC
August 28, 2015 | 204 | Fresno County, California | 51 | % | (b) | Fourth quarter 2016 | Shell Energy North America (US), LP/Southern California Edison Company | 18 years | $ | 100 |
| (e) |
| | | | | | | | | | | |
| Desert Stateline Holdings, LLC (Desert Stateline) | First Solar
August 31, 2015 | 300 | San Bernardino County, California | 51 | % | (b) | 8 Phases from December 2015 to Third quarter 2016 | Southern California Edison Company | 20 years | $ | 439 |
| (f) |
| | | | | | | | | | | |
| GASNA 31P, LLC (Morelos) | Solar Frontier Americas Holding, LLC
October 22, 2015 | 15 | Kern County, California | 90 | % | | Fourth quarter 2015 | Pacific Gas and Electric Company | 20 years | $ | 45 |
| (g) |
(a) On February 24, 2015 and September 4, 2015, Southern Power entered into agreements to acquire Kay Wind, LLC and Grant Wind, LLC, respectively. The completion of each acquisition is subject to the seller achieving certain construction and project milestones, as well as various other customary conditions to closing. Each acquisition is expected to close at or near the expected commercial operation date. In addition, the final purchase price may be adjusted based on performance testing as specified in the applicable purchase agreement. The Grant Wind, LLC purchase price includes contingent consideration. The ultimate outcome of this matter cannot be determined at this time.
(b) Southern Power owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. Southern Power and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the respective project. In addition, Southern Power is entitled to substantially all of the federal tax benefits with respect to the respective transaction.
(c) Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests for approximately $33 million. The fair values of the assets acquired through the business combination were recorded as follows: $98 million as property, plant, and
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | |
| Project Facility | Resource | Seller; Acquisition Date | Approximate Nameplate Capacity (MW) | | Location | Southern Power Percentage Ownership | Actual/Expected COD | PPA Counterparties for Plant Output | PPA Contract Period | |
| Acquisitions for the Nine Months Ended September 30, 2016 |
| Calipatria | Solar | Solar Frontier Americas Holding LLC
February 11, 2016 | 20 | | Imperial County, CA | 90 | % | | February 2016 | San Diego Gas & Electric Company | 20 years | |
| East Pecos | Solar | First Solar, Inc.
March 4, 2016 | 120 | | Pecos County, TX | 100 | % | | December 2016 | Austin Energy | 15 years | |
| Grant Plains | Wind | Apex Clean Energy Holdings, LLC
August 26, 2016 | 147 | | Grant County, OK | 100 | % | | December 2016 | Oklahoma Municipal Power Authority and Steelcase Inc. | 20 years and 12 years | (a) |
| Grant Wind | Wind | Apex Clean Energy Holdings, LLC
April 7, 2016 | 151 | | Grant County, OK | 100 | % | | April 2016 | Western Farmers, East Texas, and Northeast Texas Electric Cooperative | 20 years | |
| Henrietta | Solar | SunPower Corp.
July 1, 2016 | 102 | | Kings County, CA | 51 | % | (b) | July 2016 | Pacific Gas and Electric Company | 20 years | |
| Lamesa | Solar | RES America Developments Inc.
July 1, 2016 | 102 | | Dawson County, TX | 100 | % | | First quarter 2017 | City of Garland, Texas | 15 years | |
| Passadumkeag | Wind | Quantum Utility Generation, LLC
June 30, 2016 | 42 | | Penobscot County, ME | 100 | % | | July 2016 | Western Massachusetts Electric Company | 15 years | |
| Rutherford | Solar | Cypress Creek Renewables, LLC
July 1, 2016 | 74 | | Rutherford County, NC | 90 | % | | December 2016 | Duke Energy Carolinas, LLC | 15 years | |
| Acquisitions Subsequent to September 30, 2016 |
| Mankato | Natural Gas | Calpine Corporation October 26, 2016 | 375 | (c) | Mankato, MN | 100 | % | | N/A(c) | Northern States Power Company | 10 years | |
| Wake Wind | Wind | Invenergy Wind Global LLC October 26, 2016 | 257 | | Floyd and Crosby Counties, TX | 90.1 | % | | October 2016 | Equinix Enterprises, Inc. and Owens Corning | 12 years | |
| |
| (a) | In addition to the 20-year and 12-year PPAs, the facility has a 10-year contract with Allianz Risk Transfer (Bermuda) Ltd. |
| |
| (b) | Southern Power owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. Southern Power and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the project. In addition, Southern Power is entitled to substantially all of the federal tax benefits with respect to the transaction. |
| |
| (c) | The Mankato facility is a fully operational 375-MW natural gas-fired combined-cycle facility with an additional 345-MW expansion under development. |
Acquisitions During the Nine Months Ended September 30, 2016
Southern Power's aggregate purchase price for the project facilities acquired during the nine months ended September 30, 2016 was approximately $830 million, which includes $145 million of contingent consideration. Including the minority owner Turner Renewable Energy, LLC's (TRE) 10% ownership interest in Calipatria and $9Rutherford, SunPower Corp's 49% ownership interest in Henrietta, and the assumption of $217 million in
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
construction debt (non-recourse to Southern Power), the total aggregate purchase price is approximately $923 million for the project facilities acquired during the nine months ended September 30, 2016. The fair values of the assets and liabilities acquired through the business combinations were recorded as follows: $1.0 billion as CWIP, $58 million as a receivable related to transmission interconnection costs;property, plant, and equipment, $77 million as an intangible asset, $24 million as other assets, and $5 million as accounts payable; however, the allocationallocations of the purchase price to individual assets has not been finalized.
(d) Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests for approximately $100 million. The fair values of the assets acquired through the business combination 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.
(e) Concurrently, a wholly-owned subsidiary of Recurrent Energy, LLC converted all its membership interests to 100% of the class B membership interests of Tranquillity after contributing approximately $157 million of assets and receiving an initial distribution of $100 million. The fair values of the assets acquired were recorded as follows: $170 million as CWIP, $24 million as other receivables, and $37 million as payables; however, the allocation of the purchase price to individual assets has not been finalized. Subsequent to the acquisition, Southern Power and Recurrent Energy, LLC are expected to make additional construction payments of approximately $215 million and $106 million, respectively. The ultimate outcome of this matter cannot be determined at this time.
(f) Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests for approximately $223 million. As of September 30, 2015, the fair values of the assets acquired, which includes Southern Power's and First Solar's initial payments due under the related construction agreement, were recorded as follows: $413 million as CWIP and $249 million as an intangible asset; however, the allocation of the purchase price to individual assets hashave not been finalized. The intangible asset consists of an acquired PPA that will be amortized over its 20-year term. The estimated amortization for future periods is approximately $6.2$1 million in 2016 $12.5and $4 million per year for 2017 through 2020,thereafter. For East Pecos, Grant Plains, Lamesa, and $192.8Rutherford, which are currently under construction, total aggregate construction costs, excluding the acquisition costs, are expected to be $708 million thereafter. to $775 million. The ultimate outcome of these matters cannot be determined at this time.
Acquisitions Subsequent to September 30, 2016
Southern Power's and First Solar's remaining combined future payments, includingaggregate purchase price for acquisitions subsequent to September 30, 2016 was approximately $873 million. Including the minority owner Invenergy Wind Global LLC's 9.9% ownership interest in Wake Wind, the total aggregate purchase price is approximately $924 million.
As part of Southern Power's acquisition of Mankato, which has a fully operational 375-MW natural gas-fired combined-cycle facility, Southern Power has commenced construction payments,of an additional 345-MW expansion which is covered with a 20-year PPA. Total aggregate construction costs, excluding the acquisition costs allocated to CWIP, are estimatedexpected to be between $827$170 million to $844$190 million. The ultimate outcome of this matter cannot be determined at this time.
(g) On October 22, 2015, SREAcquisition Agreements Executed but Not Yet Closed
During the nine months ended September 30, 2016 and Turner Renewable Energy, LLC (TRE), throughsubsequent to that date, Southern Turner Renewable Energy, LLC, a jointly-owned subsidiary owned 90% by SRE, acquired allPower entered into agreements to acquire the following projects for an aggregate purchase price of approximately $1.2 billion:
51% ownership interest (through 100% ownership of the outstandingclass A membership interests of Morelos. The total purchase price, including TRE's 10% ownership, is approximately $50 million.
Construction Projects
In December 2014,entitling Southern Power Company announced plans to build51% of all cash distributions and most of the federal tax benefits) in a 100-MW solar photovoltaic facility in Nevada covered with a 20-year PPA, which is expected to close in November 2016;
100% ownership interests in two wind facilities in Texas totaling 299 MWs, the majority of which is contracted under PPAs for the first 12 to 14 years of operation and during 2015, Southern Power Company acquired allare expected to close before the outstanding membership interestsend of five separate solar project development entities. The construction projects are2016; and
100% ownership interest in accordance with Southern Power's overall growth strategya 275-MW wind facility in Texas, the majority of which is contracted under a 12-year PPA and includedis expected to close in its capital program estimates for 2015. The total cost of construction incurred for these projects through September 30, 2015 was $299 million. January 2017.
The ultimate outcome of these matters cannot be determined at this time.
The aggregate amount of revenue recognized by Southern Power related to the project facilities acquired during the nine months ended September 30, 2016 included in the condensed consolidated statements of income for year-to-date 2016 is $14 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 nine months ended September 30, 2016 included in the condensed consolidated statements 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 nine months ended September 30, 2016, in accordance with its overall growth strategy, Southern Power completed construction of and placed in service, or continued construction of, the projects set forth in the following table. Through September 30, 2016, total costs of construction incurred for the following projects were $3.0 billion, of which $1.2 billion remains in CWIP. Including the total construction costs incurred through September 30, 2016
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Southern Power Company'sand the acquisition prices allocated to CWIP, total aggregate construction costs for the following projects excluding the Tranquillity and Desert Stateline construction projects discussed above, are detailed in the table below:estimated to be $3.1 billion to $3.2 billion. The ultimate outcome of these matters cannot be determined at this time.
|
| | | | | | | | | | | | |
| Solar Project | Seller | Approx. Nameplate Capacity | County Location in Georgia | Expected Commercial Operation Date | PPA Counterparties
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 | (c) |
| Decatur County | TradeWind Energy, Inc. | 20 | Decatur | December 2015 | Georgia Power(b) | 20 years | $ | 45 |
| - | $47 | (c) |
| Butler | CERSM, LLC and Community Energy, Inc. | 103 | Taylor | December 2016 | Georgia Power(b) | 30 years | $ | 220 |
| - | $230 | (c) |
| Pawpaw | Longview Solar, LLC | 30 | Taylor | December 2015 | Georgia Power(a) | 30 years | $ | 70 |
| - | $80 | (c) |
| Butler Solar Farm | Strata Solar Development, LLC | 20 | Taylor | December 2015 | Georgia Power(b) | 20 years | $ | 42 |
| - | $48 | (c) |
|
| | | | | | |
| Solar Facility | Seller | Approximate Nameplate Capacity (MW) | Location | Actual/Expected COD | PPA Counterparties for Plant Output | PPA Contract Period |
| Projects Completed During the Nine Months Ended September 30, 2016 |
| Butler Solar Farm | Strata Solar Development, LLC | 22 | Taylor County, GA | February 2016 | Georgia Power(a) | 20 years |
Desert Stateline(b) | First Solar Development, LLC | 299(c) | San Bernardino County, CA | Through July 2016 | Southern California Edison Company (SCE) | 20 years |
| Garland A | Recurrent Energy, LLC | 20 | Kern County, CA | August 2016 | SCE | 20 years |
| Pawpaw | Longview Solar, LLC | 30 | Taylor County, GA | March 2016 | Georgia Power(a) | 30 years |
| Tranquillity | Recurrent Energy, LLC | 205 | Fresno County, CA | July 2016 | Shell Energy North America (US), LP/SCE | 18 years |
| Projects Under Construction as of September 30, 2016 |
| Butler | CERSM, LLC and Community Energy, Inc. | 103 | Taylor County, GA | December 2016 | Georgia Power(a) | 30 years |
| Garland | Recurrent Energy, LLC | 185 | Kern County, CA | October 2016 | SCE | 15 years |
| Roserock | Recurrent Energy, LLC | 160 | Pecos County, TX | November 2016 | Austin Energy | 20 years |
| Sandhills | N/A | 146 | Taylor County, GA | October 2016 | Cobb, Flint, Irwin, Middle Georgia and Sawnee Electric Membership Corporations | 25 years |
| |
| (a) | ApprovedAffiliate PPA approved by the FERC subsequent to September 30, 2015.FERC. |
| |
| (b) | SubjectOn 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 FERC approval. |
| |
(c) | Includes the acquisition price66% and 34%, respectively, of all outstanding membership interests.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. |
(c) The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and 189 MWs were placed in service during the nine months ended September 30, 2016.
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.Power and, as a result of closing the Merger, the distribution of natural gas by Southern Company Gas. The four traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through seven natural gas distribution utilities and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations.
Southern Company's reportable business segments are the sale of electricity by the four traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other products and services by Southern Power.Company Gas. Revenues from sales by Southern Power to the traditional electric operating companies were $110 million and $313 million for the three and nine months ended September 30, 2016, respectively, and $104 million and $303 million for the three and nine months ended September 30, 2015, respectively, and $103 million and $243 million for the three and nine months ended September 30, 2014, respectively. The "All Other" column includes parentthe Southern Company parent entity, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include 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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Financial data for business segments and products and services for the three and nine months ended September 30, 20152016 and 20142015 was as follows:
| | | | Electric Utilities | | | | | | | Electric Utilities | |
| | Traditional Operating Companies | | Southern Power | | Eliminations | | Total | | All Other | | Eliminations | | Consolidated | Traditional Electric Operating Companies | Southern Power | Eliminations | Total | Southern Company Gas | All Other | Eliminations | Consolidated |
| | (in millions) | (in millions) |
Three Months Ended
September 30, 2016: | | |
| Operating revenues | | $ | 5,236 |
| $ | 500 |
| $ | (117 | ) | $ | 5,619 |
| $ | 543 |
| $ | 139 |
| $ | (37 | ) | $ | 6,264 |
|
Segment net income (loss)(a)(b) | | 1,018 |
| 176 |
| — |
| 1,194 |
| 4 |
| (67 | ) | (1 | ) | 1,130 |
|
Nine Months Ended
September 30, 2016: | | |
| Operating revenues | | $ | 13,120 |
| $ | 1,189 |
| $ | (330 | ) | $ | 13,979 |
| $ | 543 |
| $ | 311 |
| $ | (118 | ) | $ | 14,715 |
|
Segment net income (loss)(a)(c) | | 2,076 |
| 315 |
| — |
| 2,391 |
| 4 |
| (161 | ) | (8 | ) | 2,226 |
|
| Total assets at September 30, 2016 | | $ | 71,448 |
| $ | 12,351 |
| $ | (440 | ) | $ | 83,359 |
| $ | 21,185 |
| $ | 2,974 |
| $ | (1,156 | ) | $ | 106,362 |
|
| Three Months Ended September 30, 2015: | | | | | | | | | | | | | | |
| Operating revenues | $ | 5,098 |
| | $ | 401 |
| | $ | (109 | ) | | $ | 5,390 |
| | $ | 37 |
| | $ | (26 | ) | | $ | 5,401 |
| $ | 5,098 |
| $ | 401 |
| $ | (109 | ) | $ | 5,390 |
| $ | — |
| $ | 37 |
| $ | (26 | ) | $ | 5,401 |
|
Segment net income (loss)(a)(b) | 874 |
| | 102 |
| | — |
| | 976 |
| | (18 | ) | | 1 |
| | 959 |
| 874 |
| 102 |
| — |
| 976 |
| — |
| (18 | ) | 1 |
| 959 |
|
| Nine Months Ended September 30, 2015: | | | | | | | | | | | | | | |
| Operating revenues | $ | 13,123 |
| | $ | 1,086 |
| | $ | (322 | ) | | $ | 13,887 |
| | $ | 120 |
| | $ | (86 | ) | | $ | 13,921 |
| $ | 13,123 |
| $ | 1,086 |
| $ | (322 | ) | $ | 13,887 |
| $ | — |
| $ | 120 |
| $ | (86 | ) | $ | 13,921 |
|
Segment net income (loss)(a)(c) | 1,912 |
| | 181 |
| | — |
| | 2,093 |
| | 3 |
| | — |
| | 2,096 |
| 1,912 |
| 181 |
| — |
| 2,093 |
| — |
| 3 |
| — |
| 2,096 |
|
| Total assets at September 30, 2015 | $ | 67,750 |
| | $ | 7,040 |
| | $ | (404 | ) | | $ | 74,386 |
| | $ | 1,480 |
| | $ | (651 | ) | | $ | 75,215 |
| |
| Three Months Ended September 30, 2014: | | | | | | | | | | | | | | |
| Operating revenues | $ | 5,007 |
| | $ | 435 |
| | $ | (115 | ) | | $ | 5,327 |
| | $ | 34 |
| | $ | (22 | ) | | $ | 5,339 |
| |
Segment net income (loss)(a)(b) | 658 |
| | 64 |
| | — |
| | 722 |
| | (2 | ) | | (2 | ) | | 718 |
| |
| Nine Months Ended September 30, 2014: | | | | | | | | | | | | | | |
| Operating revenues | $ | 13,594 |
| | $ | 1,115 |
| | $ | (301 | ) | | $ | 14,408 |
| | $ | 114 |
| | $ | (72 | ) | | $ | 14,450 |
| |
Segment net income (loss)(a)(c) | 1,557 |
| | 128 |
| | — |
| | 1,685 |
| | — |
| | (5 | ) | | 1,680 |
| |
| Total assets at December 31, 2014 | $ | 64,644 |
| | $ | 5,550 |
| | $ | (131 | ) | | $ | 70,063 |
| | $ | 1,156 |
| | $ | (296 | ) | | $ | 70,923 |
| |
| Total assets at December 31, 2015 | | $ | 69,052 |
| $ | 8,905 |
| $ | (397 | ) | $ | 77,560 |
| $ | — |
| $ | 1,819 |
| $ | (1,061 | ) | $ | 78,318 |
|
| |
| (a) | After dividends on preferred and preference stock of subsidiaries.Attributable to Southern Company. |
| |
| (b) | Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated probable losses on the Kemper IGCC of $88 million ($54 million after tax) and $150 million ($93 million after tax) for the three months ended September 30, 2016 and 2015, and September 30, 2014 includes pre-tax charges of $150 million ($93 million after tax) and a pre-tax charge of $418 million ($258 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. |
| |
(c) | (c) Segment net income (loss) for the traditional electric operating companies for the nine months ended September 30, 2015 and September 30, 2014 includes pre-tax charges of $182 million ($112 million after tax) and pre-tax charges of $798 million ($493 million after tax), respectively, 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. |
Table of Contents$222 million ($137 million after tax) and $182 million ($112 million after tax) for the nine months ended September 30, 2016 and 2015, respectively. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" 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 September 30, 2016 | | | $ | 4,808 |
| | $ | 613 |
| | $ | 198 |
| | $ | 5,619 |
|
| Three Months Ended September 30, 2015 | | $ | 4,701 |
| | $ | 520 |
| | $ | 169 |
| | $ | 5,390 |
| | 4,701 |
| | 520 |
| | 169 |
| | 5,390 |
|
| Three Months Ended September 30, 2014 | | 4,558 |
| | 600 |
| | 169 |
| | 5,327 |
| |
| | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2016 | | | $ | 11,932 |
| | $ | 1,455 |
| | $ | 592 |
| | $ | 13,979 |
|
| Nine Months Ended September 30, 2015 | | $ | 11,958 |
| | $ | 1,435 |
| | $ | 494 |
| | $ | 13,887 |
| | 11,958 |
| | 1,435 |
| | 494 |
| | 13,887 |
|
| Nine Months Ended September 30, 2014 | | 12,186 |
| | 1,719 |
| | 503 |
| | 14,408 |
| |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | |
| | Southern Company Gas' Revenues |
| Period | Gas
Distribution
Operations | Gas
Marketing
Services | All Other | Total |
| | (in millions) |
| Three and Nine Months Ended September 30, 2016 | $ | 420 |
| $ | 126 |
| $ | (3 | ) | $ | 543 |
|
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.
In addition to the factors described inSee RISK FACTORS in Item 1A of the Form 10-K Southern Company facesfor a discussion of the following additional risks:risk factors of the registrants. Except as described below, there have been no material changes to these risk factors from those previously disclosed in the Form 10-K.
Risks Related to the Proposed Merger with AGL Resources
Southern Company and AGL Resources may encounter difficulties in satisfying the conditions forWith the completion of the Merger, including receipt of all required regulatory approvals, which could delay the completion of the Merger or impose conditions that could have a material adverse effect on the combined company or that could cause either party to abandon the Merger.
Consummation of the Merger is subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) approval of the Merger Agreement by AGL Resources' shareholders, which is scheduled for vote on November 19, 2015, (ii) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, (iii) the approval of the California Public Utilities Commission, Georgia PSC, Illinois Commerce Commission, Maryland PSC, New Jersey Board of Public Utilities, and Virginia State Corporation Commission, and other approvals required under applicable state laws, and the approval of the Federal Communications Commission (FCC) for the transfer of control over the FCC licenses of certain subsidiaries of AGL Resources and any other approval which Southern Company and AGL Resources agree are required, (iv) the absence of a judgment, order, decision, injunction, ruling, or other finding or agency requirement of a governmental entity prohibiting the consummation of the Merger, and (v) other customary closing conditions, including (a) subject to certain materiality qualifiers, the accuracy of each party's representations and warranties and (b) each party's performance in all material respects of its obligations under the Merger Agreement.
now owns Southern Company expects to complete the required state regulatory filings in the fourth quarter 2015. These governmental entities may decline to approve the Merger or may impose conditions on the completion, or require changes to the terms, of the Merger, including restrictions or conditions on the business, operations, or financial performance of the combined company following the Merger.
Satisfying the conditions to completion of the Merger may take longer, and could cost more, than Southern Company expects. Any delay in completing the Merger or any additional conditions imposed in order to complete the Merger may materially adversely affect the benefits that Southern Company expects to achieve from the Merger and the integration of the companies' respective businesses.
In addition, conditions to the completion of the Merger may fail to be satisfied. Subject to certain limitations, either party may terminate the Merger Agreement if the Merger is not consummated by August 23, 2016, which date may be extended by either party to February 23, 2017 if, on August 23, 2016, all conditions to closing other than those relating to (i) regulatory approvals and (ii) the absence of legal restraints preventing consummation of the Merger (to the extent relating to regulatory approvals) have been satisfied.
Any delay in completing the Merger, conditions imposed by governmental entities, or failure to complete the Merger could have a material adverse effect on the financial condition, net income, and cash flows of Southern Company.
Failure to complete the Merger could negatively impact Southern Company's stock price and Southern Company's future business and financial results.
Completion of the Merger is not assured and is subject to risks, including the risks that approval of the transaction by governmental entities will not be obtained or that certain other closing conditions will not be satisfied. If the Merger is not completed, Southern Company's ongoing businesses and financial results may be adversely affected and Southern Company will be subject to a number of risks, including the following:
Southern Company will be required to pay significant costs relating to the Merger, including legal, accounting, and financial advisory costs, whether or not the Merger is completed;
matters relating to the Merger (including integration planning) may require substantial commitments of time and resources by Southern Company management, which could otherwise have been devoted to other opportunities that may have been beneficial to Southern Company; and
negative publicity and a negative impression of Southern Company in the investment community.
The occurrence of any of these events, individually or in combination, could cause the share price of Southern Company to decline if and to the extent that the current market prices reflect an assumption by the market that the Merger will be completed.
If completed, the Merger may not achieve its intended results.
Southern Company entered into the Merger Agreement with the expectation that the Merger would result in various benefits. Achieving the anticipated benefits of the Merger is subject to a number of uncertainties, including whether the business of AGL Resources is integrated in an efficient and effective manner, conditions imposed on the Merger by federal and state public utility, antitrust, and other regulatory authorities prior to approval, general market and economic conditions, and general competitive factors in the market place. Failure to achieve these anticipated benefits could result in increased costs, decreases in the amount of expected revenues generated by the combined company, and diversion of management's time and energy and could have an adverse effect on the combined company's financial condition, net income, and cash flows.
The Southern Company system will be subject to business uncertainties while the Merger is pending that could adversely affect Southern Company's financial results.
Uncertainty about the effect of the Merger on employees, suppliers, and customers of the Southern Company system may have an adverse effect on Southern Company. These uncertainties may impair the Southern Company system's ability to attract, retain, and motivate key personnel until the Merger is completed and for a period of time thereafter and could cause customers, suppliers, and others that deal with the Southern Company system to seek to change existing business relationships.
Employee retention and recruitment may be particularly challenging prior to the completion of the Merger, as employees and prospective employees may experience uncertainty about their future roles with the combined company. If key employees depart or fail to accept employment with the Southern Company system because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the combined company, Southern Company's financial results could be adversely affected.
The pursuit of the Merger and the preparation for the integration of AGL Resources into the Southern Company system may place a significant burden on management and internal resources. The diversion of management attention away from day-to-day business concerns and any difficulties encountered in the transition and integration process could adversely affect Southern Company's financial results.
Southern Company is obligated to complete the Merger whether or not it has obtained the required financing.
Southern Company intends to initially fund the cash consideration for the Merger using approximately $7.0 billion of debt and $1.0 billion of equity. Southern Company expects to issue approximately $2.0 billion of additional equity through 2019 to offset a portion of the debt issued to fund the cash consideration for the Merger. In addition,
Southern Company entered into the $8.1 billion Bridge Agreement on September 30, 2015 to provide financing for the Merger in the event long-term financing is not available. The Bridge Agreement is subject to various conditions contained in the Bridge Agreement and the issuance of long-term debt and equity sales to finance the Merger will be subject to future market conditions.
Pending shareholder suits filed in connection with the Merger, the outcomes of which are uncertain, could delay or prevent the completion of the Merger.
AGL Resources and each member of the AGL Resources board of directors have been named as defendants in four purported shareholder class action lawsuits filed on behalf of named plaintiffs and other AGL Resources shareholders challenging the Merger and seeking, among other things, preliminary and permanent injunctive relief enjoining the Merger, and, in certain circumstances, damages. Southern Company and Merger Sub were also named as defendants in two of these lawsuits. If a plaintiff in these or any other future litigation is successful in obtaining an injunction prohibiting the parties from completing the Merger on the terms contemplated by the Merger Agreement, the injunction may prevent the completion of the Merger in the expected timeframe or altogether. If completion of the Merger is prevented or delayed, it could result in substantial costs to Southern Company. In addition, Southern Company could incur significant costs in connection with the lawsuits, including the costs associated with defending these lawsuits or any other liabilities or costs the parties may incur in connection with the litigation or settlement of these lawsuits.
Following the Merger, stockholders of Southern Company will own equity interests inGas, a company whose subsidiary ownssubsidiaries own and operatesoperate a natural gas business.
AGL ResourcesSouthern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through natural gas distribution utilities. AGL ResourcesSouthern Company Gas is involved in several other businesses that are mainly related and complementary to its primary business including: retail operationsgas marketing services including the provision of natural gas commodity and related services to customers in competitive markets or markets that provide for customer choice, wholesale gas services including natural gas storage, gas pipeline arbitrage, and natural gas asset management and/or related logistics services, and gas midstream operations including high deliverability natural gas storage facilities and select pipelines. As a result, the combined company will beSouthern Company is now subject to various risks to which Southern Company isit was not currentlypreviously subject including risks related to transporting and storing natural gas. As stockholders of the combined company following the Merger, Southern Company stockholders may be adversely affected by these risks. 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 may record goodwill that could become impairedGas' natural gas distribution and adversely affect itsstorage activities involve a variety of inherent hazards and operating results.
In accordance with GAAP, the Merger will be accounted for using the acquisition method of accounting whereby the assets acquiredrisks, such as leaks, accidents, explosions, and liabilities assumed are recognized at fair value as of the acquisition date. The excess of the purchase price over the fair values of AGL Resources' assets and liabilities will be recorded as goodwill.
The amount of goodwill,mechanical problems, which could be material, will be allocated to the appropriate reporting units of the combined company. Southern Company is required to assess goodwill for impairment at least annually by comparing the fair value of reporting units to the carrying value of those reporting units. To the extent the carrying value of any of those reporting units is greater than the fair value, a second step comparing the implied fair value of goodwill to the carrying amount would be required to determine if the goodwill is impaired. Such a potential impairment could result in a material chargeserious injury to employees and non-employees, loss of human life, significant damage to property, environmental pollution, and impairment of its operations.
Southern Company Gas' natural gas business faces increasing competition. The natural gas business is highly competitive and increasingly complex. Southern Company Gas is facing increasing competition from other companies that would have a material impact on Southern Company's future operating resultssupply energy, including electric, oil, and consolidated balance sheet.
Item 2. Unregistered Sales of Equity Securitiespropane providers and, Use of Proceedsin some cases, energy marketing and trading companies.
(c) Issuer Purchases of Equity Securities
Southern Company Gas may experience reported net income volatility due to mark-to-market accounting. Southern Company Gas utilizes hedging instruments to lock in economic value in its wholesale natural gas segment, which are not designated as hedges for accounting purposes. The difference in accounting treatment for the underlying position and the financial instrument used to hedge the value of the contract can cause volatility in reported net income while the positions are open due to mark-to-market accounting.
|
| | | | | | | | | |
2015 | | Total Number of
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 (*)
|
July 1 – July 31 | | — |
| | N/A | | N/A | | N/A |
August 1 – August 31 | | — |
| | N/A | | N/A | | N/A |
September 1 – September 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 third quarter 2015. As of September 30, 2015, Southern Company had repurchased a total of 2,599,366 shares under this program. No further repurchases under this program are anticipated. |
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.
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| | | | |
| | | (2) Plan(3) Articles of acquisition, reorganization, arrangement, liquidation or successionIncorporation and By-Laws |
| | | | | |
| | | Southern CompanyGeorgia Power |
| | | | | |
| | | (a)1 | - | Agreement and PlanBy-Laws of Merger by and among Southern Company, Merger Sub, and AGL Resources, datedGeorgia Power, as amended effective August 23, 2015.17, 2016. (Designated in Form 8-K dated August 23, 2015,17, 2016, File No. 1-3526,1-6468, as Exhibit 2.1.3.1.) |
| | | | |
| | (3) Articles of Incorporation and By-Laws |
| | | | | |
| | | Mississippi Power |
| | | | | |
| | | (e)(a)1 | - | By-lawsBy-Laws of Mississippi Power, as amended, effective October 19, 2015, and as presently in effect.25, 2016. (Designated in Form 8-K dated October 19, 2015,25, 2016, File No. 1-3164,001-11229, as Exhibit 3.1.) |
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| | | | |
| | | |
| | | (4) Instruments Describing Rights of Security Holders, Including Indentures |
| | | | | |
| | | Southern Company |
| | | | | |
| | | (a)1 | - | Second Supplemental Indenture to Junior Subordinated Note Indenture, dated as of October 1, 2015, between Southern Company and Wells Fargo Bank, National Association, as Trustee. (Designated in Form 8-K dated October 1, 2015, File No. 1-3526, as Exhibit 4.3.) |
| | | | |
| | (a)2 | - | First Supplemental Indenture to Subordinated Note Indenture, dated as of October 8, 2015,September 15, 2016, providing for the issuance of the Series 2015A 6.25%2016A 5.25% Junior Subordinated Notes due October 15, 2075.1, 2076. (Designated in Form 8-K dated October 1, 2015,September 12, 2016, File No. 1-3526, as Exhibit 4.4.) |
| | | | | |
| | | (10) Material ContractsSouthern Power |
| | | |
| | * | Southern Company |
| | | | |
| | (a)(f)1 | - | Commitment Letter, dated August 23, 2015. (Designated in Form 8-K dated August 23, 2015, File No. 1-3526, as Exhibit 10.1.) |
| | | | |
�� | | (a)2 | - | Bridge Credit Agreement,Twelfth Supplemental Indenture to Senior Note Indenture, dated as of September 30, 2015, among Southern Company, as the Borrower, the Lenders identified therein, and Citibank, N.A., as Administrative Agent. (Designated in Form 8-K dated September 30, 2015, File No. 1-3526, as Exhibit 10.1.) |
| | |
| | Southern Power7, 2016. |
| | | | | |
| | * | (f)12 | - | Amended and Restated Engineering, Procurement and Construction Agreement between Desert Stateline Holdings, LLC and First Solar Electric (California), Inc.Thirteenth Supplemental Indenture to Senior Note Indenture, dated as of August 31, 2015. (Southern Power has requested confidential treatmentSeptember 20, 2016, providing for certain portionsthe issuance of this document pursuant to an application for confidential treatment sent to the SEC. Southern Power omitted such portions from the filing and filed them separately with the SEC.)Series 2016C 2.75% Senior Notes due September 20, 2023. |
| | | | | |
| | | (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. (Designated in the Form 10-Q for the quarter ended June 30, 2015, File No. 001-31737 as Exhibit 24(d)2.) |
| | | | | |
| | | 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: November 5, 20154, 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: November 5, 20154, 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, and Treasurer |
| | | (Principal Financial Officer) |
| | | | |
| By | | /s/ Melissa K. Caen | |
| | | (Melissa K. Caen, Attorney-in-fact) | |
Date: November 5, 20154, 2016
GULF POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
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| | | |
| | | GULF POWER COMPANY |
| | | | |
| By | | S. W. Connally, Jr. |
| | | Chairman, President and Chief Executive Officer |
| | | (Principal Executive Officer) |
| | | | |
| By | | Xia Liu |
| | | Vice President and Chief Financial Officer |
| | | (Principal Financial Officer) |
| | | | |
| By | | /s/ Melissa K. Caen | |
| | | (Melissa K. Caen, Attorney-in-fact) | |
Date: November 5, 20154, 2016
MISSISSIPPI POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
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| | | |
| | | MISSISSIPPI POWER COMPANY |
| | | | |
| By | | G. Edison Holland, Jr.Anthony L. Wilson |
| | | ChairmanPresident 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: November 5, 20154, 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: November 5, 20154, 2016