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 SeptemberJune 30, 20162017
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 |
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| 1-3164 | | Alabama Power Company (An Alabama Corporation) 600 North 18th Street Birmingham, Alabama 35203 (205) 257-1000 | | 63-0004250 |
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| 1-6468 | | Georgia Power Company (A Georgia Corporation) 241 Ralph McGill Boulevard, N.E. Atlanta, Georgia 30308 (404) 506-6526 | | 58-0257110 |
| | | | | |
| 001-31737 | | Gulf Power Company (A Florida Corporation) One Energy Place Pensacola, Florida 32520 (850) 444-6111 | | 59-0276810 |
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| 001-11229 | | Mississippi Power Company (A Mississippi Corporation) 2992 West Beach Boulevard Gulfport, Mississippi 39501 (228) 864-1211 | | 64-0205820 |
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| 001-37803 | | Southern Power Company (A Delaware Corporation) 30 Ivan Allen Jr. Boulevard, N.W. Atlanta, Georgia 30308 (404) 506-5000 | | 58-2598670 |
| | | | |
| 1-14174 | | Southern Company Gas
(A Georgia Corporation)
Ten Peachtree Place, N.E. Atlanta, Georgia 30309
(404) 584-4000 | | 58-2210952 |
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes þ No ¨
Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files). Yes þ No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer"filer," "smaller reporting company," and "smaller reporting"emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
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| | | | | | | | | | |
| Registrant | | Large Accelerated Filer | | Accelerated Filer | | Non- accelerated Filer | | Smaller Reporting Company | | Emerging Growth Company |
| The Southern Company | | X | | | | | | | | |
| Alabama Power Company | | | | | | X | | | | |
| Georgia Power Company | | | | | | X | | | | |
| Gulf Power Company | | | | | | X | | | | |
| Mississippi Power Company | | | | | | X | | | | |
| Southern Power Company | | | | | | X | | | | |
| Southern Company Gas | | | | | | X | | | | |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No þ (Response applicable to all registrants.)
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| | | | | |
| Registrant | | Description of Common Stock | | Shares Outstanding at SeptemberJune 30, 20162017 |
|
| The Southern Company | | Par Value $5 Per Share | | 979,999,480999,474,028 |
|
| Alabama Power Company | | Par Value $40 Per Share | | 30,537,500 |
|
| Georgia Power Company | | Without Par Value | | 9,261,500 |
|
| Gulf Power Company | | Without Par Value | | 5,642,7177,392,717 |
|
| Mississippi Power Company | | Without Par Value | | 1,121,000 |
|
| Southern Power Company | | Par Value $0.01 Per Share | | 1,000 |
|
| Southern Company Gas | | Par Value $0.01 Per Share | | 100 |
|
This combined Form 10-Q is separately filed by The Southern Company, Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, Southern Power Company, and Southern Power Company.Company Gas. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.
INDEX TO QUARTERLY REPORT ON FORM 10-Q
SeptemberJune 30, 20162017
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| | PART I—FINANCIAL INFORMATION | |
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| Item 1. | Financial Statements (Unaudited) | |
| Item 2. | Management's Discussion and Analysis of Financial Condition and Results of Operations | |
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Item 3. | | |
Item 4. | | |
INDEX TO QUARTERLY REPORT ON FORM 10-Q
SeptemberJune 30, 20162017
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Number |
| PART I—FINANCIAL INFORMATION (CONTINUED) | |
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| Item 3. | | |
| Item 4. | | |
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| Item 1. | | |
| Item 1A. | | |
| Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds | Inapplicable |
| Item 3. | Defaults Upon Senior Securities | Inapplicable |
| Item 4. | Mine Safety Disclosures | Inapplicable |
| Item 5. | 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 |
| Alabama Power | Alabama Power Company |
| ASC | Accounting Standards Codification |
| ASU | Accounting Standards Update |
| Atlanta Gas Light | Atlanta Gas Light Company, a wholly-owned subsidiary of Southern Company Gas |
| Baseload Act | State of Mississippi legislation designed to enhance the Mississippi PSC's authority to facilitate development and construction of baseload generation in the State of Mississippi |
Bridge Agreement | Senior unsecured Bridge Credit Agreement, dated as of September 30, 2015, among Southern Company, the lenders identified therein, and Citibank, N.A. |
| CCR | Coal combustion residuals |
| Clean Power Plan | Final action published by the EPA in 2015 that established guidelines for states to develop plans to meet EPA-mandated CO2 emission rates or emission reduction goals for existing electric generating units |
CO2 | Carbon dioxide |
| COD | Commercial operation date |
| Contractor Settlement Agreement | The December 31, 2015 agreement between 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.the Vogtle Owners resolving disputes between the Vogtle Owners and Chicago Bridge & Iron Company N.V.the EPC Contractor under the Vogtle 3 and 4 Agreement |
| CPCN | Certificate of public convenience and necessity |
| CWIP | Construction work in progress |
| Dalton Pipeline | A 50% undivided ownership interest of Southern Company Gas in a pipeline facility in Georgia |
| DOE | U.S. Department of Energy |
| ECO Plan | Mississippi Power's Environmental Compliance Overview Plan |
| Eligible Project Costs | Certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Title XVII Loan Guarantee Program |
| EPA | U.S. Environmental Protection Agency |
| EPC Contractor | Westinghouse and its affiliate, WECTEC (formerly known as CB&I Stone & Webster, Inc.), formerly a subsidiary of The Shaw Group Inc. and Chicago Bridge & Iron Company N.V.; the former engineering, procurement, and construction contractor for Plant Vogtle Units 3 and 4 |
| FASB | Financial Accounting Standards Board |
| FERC | Federal Energy Regulatory Commission |
| FFB | Federal Financing Bank |
| Fitch | Fitch Ratings, Inc. |
| Form 10-K | Combined Annual Report on Form 10-K of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern PowerCompany Gas for the year ended December 31, 20152016, as applicable |
| GAAP | U.S. generally accepted accounting principles |
| Georgia Power | Georgia Power Company |
| Gulf Power | Gulf Power Company |
| Heating Degree Days | A measure of weather, calculated when the average daily temperatures are less than 65 degrees Fahrenheit |
| Horizon Pipeline | Horizon Pipeline Company, LLC |
| IGCC | Integrated coal gasification combined cycle |
| IIC | Intercompany interchange contract |
Internal Revenue CodeIllinois Commission | Illinois Commerce Commission, the state regulatory agency for Nicor Gas |
| IRC | Internal Revenue Code of 1986, as amended |
DEFINITIONS
(continued)
|
| |
| Term | Meaning |
| |
| IRS | Internal Revenue Service |
| ITC | Investment tax credit |
| Kemper IGCC | Mississippi Power's IGCC facility under construction by Mississippi Powerproject in Kemper County, Mississippi |
| KWH | Kilowatt-hour |
| LIBOR | London Interbank Offered Rate |
| LIFO | Last-in, first-out |
| LNG | Liquefied natural gas |
| LOCOM | Lower of weighted average cost or current market price |
| LTSA | Long-term service agreement |
| MATS rule | Mercury and Air Toxics Standards rule |
| Merger | The merger, effective July 1, 2016, of a wholly-owned, direct subsidiary of Southern Company with and into Southern Company Gas, with Southern Company Gas continuing as the surviving corporation |
| Mirror CWIP | A regulatory liability used by Mississippi Power to record customer refunds resulting from a 2015 Mississippi PSC order |
DEFINITIONS
(continued)
|
| |
Term | Meaning |
| |
| Mississippi Power | Mississippi Power Company |
| mmBtu | Million British thermal units |
| Moody's | Moody's Investors Service, Inc. |
| MRA | Municipal and Rural Associations |
| MW | Megawatt |
| natural gas distribution utilities | Southern Company Gas' seven natural gas distribution utilities (Nicor Gas, Atlanta Gas Light, Virginia Natural Gas, Elizabethtown Gas, Florida City Gas, Chattanooga Gas Company, and Elkton Gas) |
| NCCR | Georgia Power's Nuclear Construction Cost Recovery |
| New Jersey BPU | New Jersey Board of Public Utilities, the state regulatory agency for Elizabethtown Gas |
| Nicor Gas | Northern Illinois Gas Company, a wholly-owned subsidiary of Southern Company Gas |
| NRC | U.S. Nuclear Regulatory Commission |
| NYMEX | New York Mercantile Exchange, Inc. |
| OCI | Other comprehensive income |
PATH ActPennEast Pipeline | The Protecting Americans from Tax Hikes ActPennEast Pipeline Company, LLC |
| PEP | Mississippi Power's Performance Evaluation Plan |
| Piedmont | Piedmont Natural Gas Company, Inc. |
| Pivotal Utility Holdings | Pivotal Utility Holdings, Inc., a wholly-owned subsidiary of Southern Company Gas, doing business as Elizabethtown Gas, Elkton Gas, and Florida City Gas |
| Plant Vogtle Units 3 and 4 | Two new nuclear generating units under construction at Georgia Power's Plant Vogtle |
| PowerSecure | PowerSecure, Inc. |
| power pool | The operating arrangement whereby the integrated generating resources of the traditional electric operating companies and Southern Power Company (excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations |
| PPA | Power purchase agreements, andas well as, for Southern Power, contracts for differences that provide the owner of thea renewable facility a certain fixed price for the electricity sold to the grid |
| PSC | Public Service Commission |
| PTC | Production tax credit |
| Rate CNP | Alabama Power's Rate Certificated New Plant |
| Rate CNP Compliance | Alabama Power's Rate Certificated New Plant Compliance |
DEFINITIONS
(continued)
|
| |
| Term | Meaning |
| |
| Rate CNP PPA | Alabama Power's Rate Certificated New Plant Power Purchase Agreement |
| Rate ECR | Alabama Power's Rate Energy Cost Recovery |
| Rate NDR | Alabama Power's Rate Natural Disaster Reserve |
| Rate RSE | Alabama Power's Rate Stabilization and Equalization plan |
| registrants | Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power Company, and Southern Company Gas |
| ROE | Return on equity |
| S&P | S&P Global Ratings, a division of S&P Global Inc. |
| scrubber | Flue gas desulfurization system |
| SCS | Southern Company Services, Inc. (the Southern Company system service company) |
| SEC | U.S. Securities and Exchange Commission |
| SMEPA | South Mississippi Electric Power Association (now known as Cooperative Energy) |
| SNG | Southern Natural Gas Company, L.L.C. |
| Southern Company | The Southern Company |
| Southern Company Gas | Southern Company Gas (formerly known as AGL Resources Inc.) and its subsidiaries |
| Southern Company Gas Capital | Southern Company Gas Capital Corporation, a wholly-owned100%-owned subsidiary of Southern Company Gas |
| Southern Company system | Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), Southern Electric Generating Company, Southern Nuclear, SCS, Southern Communications Services, Inc., PowerSecure (as of May 9, 2016), and other subsidiaries and, as of July 1, 2016, Southern Company Gas |
| Southern Nuclear | Southern Nuclear Operating Company, Inc. |
| Southern Power | Southern Power Company and its subsidiaries |
| SouthStar | SouthStar Energy Services, LLC |
| STRIDE | Atlanta Gas Light's Strategic Infrastructure Development and Enhancement program |
| Toshiba | Toshiba Corporation, parent company of Westinghouse |
| Toshiba Guarantee | Certain payment obligations of the EPC Contractor guaranteed by Toshiba |
| traditional electric operating companies | Alabama Power, Georgia Power, Gulf Power, and Mississippi Power |
| Triton | Triton Container Investments, LLC |
| Virginia Commission | Virginia State Corporation Commission, the state regulatory agency for Virginia Natural Gas |
| Virginia Natural Gas | Virginia Natural Gas, Inc., a wholly-owned subsidiary of Southern Company Gas |
| Vogtle 3 and 4 Agreement | Agreement entered into with the EPC Contractor in 2008 by Georgia Power, acting for itself and as agent for the Vogtle Owners, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4 |
| Vogtle Owners | Georgia Power, Oglethorpe Power Corporation, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light, and Sinking Fund Commissioners |
| WACOG | Weighted average cost of gas |
| WECTEC | WECTEC Global Project Services Inc. |
| Westinghouse | Westinghouse Electric Company LLC |
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This Quarterly Report on Form 10-Q contains forward-looking statements. Forward-looking statements include, among other things, statements concerning regulated rates, the strategic goals for the wholesale business, economic conditions, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, financing activities, completion dates of acquisitions and construction projects, filings with state and federal regulatory authorities, federal income tax benefits, estimated sales and purchases under power sale and purchase agreements, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
the impact of recent and future federal and state regulatory changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the utility industry, environmental laws regulating emissions, discharges, and disposal to air, water, and land, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;
current and future litigation, regulatory investigations, proceedings, or inquiries, including, without limitation, IRS and state tax audits;
the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company's subsidiaries operate;
variations in demand for electricity and natural gas, including those relating to weather, the general economy and recovery from the last recession, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;
available sources and costs of natural gas and other fuels;
limits on pipeline capacity;
effects of inflation;
the ability to control costs and avoid cost overruns during the development and construction of facilities, which include the development and construction of generating facilities with designs that have not been finalized or previously constructed, including changes in labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, sustaining nitrogen supply, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by any PSC);
the ability to construct facilities in accordance with the requirements of permits and licenses, to satisfy any environmental performance standards and the requirements of tax credits and other incentives, and to integrate facilities into the Southern Company system upon completion of construction;
investment performance of Southern Company's employee and retiree benefit plans and the Southern Company system's nuclear decommissioning trust funds;
advances in technology;
state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;
legal proceedings and regulatory approvals and actions related to Plant Vogtle Units 3 and 4, including Georgia PSC approvals and NRC actions;
actions related to cost recovery for the Kemper IGCC, including the ultimate impact of the 2015 decision of the Mississippi Supreme Court, the Mississippi PSC's December 2015 rate order, and related legal or regulatory proceedings, Mississippi PSC review of the prudence of Kemper IGCC costs and approval of further permanent rate recovery plans, actions relating to proposed securitization, satisfaction of requirements to utilize grants, and the ultimate impact of the termination of the proposed sale of an interest in the Kemper IGCC to SMEPA;
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This Quarterly Report on Form 10-Q contains forward-looking statements. Forward-looking statements include, among other things, statements concerning regulated rates, the strategic goals for the wholesale business, customer and sales growth, economic conditions, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, financing activities, completion dates of construction projects, filings with state and federal regulatory authorities, federal income tax benefits, estimated sales and purchases under power sale and purchase agreements, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
the impact of recent and future federal and state regulatory changes, including environmental laws regulating emissions, discharges, and disposal to air, water, and land, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, including potential tax reform legislation, as well as changes in application of existing laws and regulations;
current and future litigation, regulatory investigations, proceedings, or inquiries;
the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company's subsidiaries operate;
variations in demand for electricity and natural gas, including those relating to weather, the general economy and recovery from the last recession, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;
available sources and costs of natural gas and other fuels;
limits on pipeline capacity;
effects of inflation;
the ability to control costs and avoid cost overruns during the development, construction, and operation of facilities, which include the development and construction of generating facilities with designs that have not been finalized or previously constructed, including changes in labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, 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 impact of any inability or other failure of Toshiba to perform its obligations under the Toshiba Guarantee, including any effect on the construction of Plant Vogtle Units 3 and 4;
the ability to construct facilities in accordance with the requirements of permits and licenses, to satisfy any environmental performance standards and the requirements of tax credits and other incentives, and to integrate facilities into the Southern Company system upon completion of construction;
investment performance of the Southern Company system's employee and retiree benefit plans and nuclear decommissioning trust funds;
advances in technology;
ongoing renewable energy partnerships and development agreements;
state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;
legal proceedings and regulatory approvals and actions related to Plant Vogtle Units 3 and 4, including Georgia PSC approvals and NRC actions;
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
(continued)
actions related to cost recovery for the Kemper IGCC, including ongoing settlement discussions, Mississippi PSC review of the prudence of Kemper IGCC costs and approval of further permanent rate recovery plans, and related legal or regulatory proceedings;
the ability to successfully operate the electric utilities' generating, transmission, and distribution facilities and Southern Company Gas' natural gas distribution and storage facilities and the successful performance of necessary corporate functions;
the inherent risks involved in operating and constructing nuclear generating facilities, including environmental, health, regulatory, natural disaster, terrorism, and financial risks;
the inherent risks involved in transporting and storing natural gas;
the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities;
internal restructuring or other restructuring options that may be pursued;
potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries;
the possibility that the anticipated benefits from the Merger cannot be fully realized or may take longer to realize than expected, the possibility that costs related to the integration of Southern Company and Southern Company Gas will be greater than expected, the ability to retain and hire key personnel and maintain relationships with customers, suppliers, or other business partners, and the diversion of management time on integration-related issues;
the ability of counterparties of Southern Company and its subsidiaries to make payments as and when due and to perform as required;
the ability to obtain new short- and long-term contracts with wholesale customers;
the direct or indirect effect on the Southern Company system's business resulting from cyber intrusion or terrorist incidents and the threat of terrorist incidents;
interest rate fluctuations and financial market conditions and the results of financing efforts;
changes in Southern Company's and any of its subsidiaries' credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;
the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general, as well as potential impacts on the benefits of the DOE loan guarantees;
the ability of Southern Company's electric utilities to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;
catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;
the direct or indirect effects on the Southern Company system's business resulting from incidents affecting the U.S. electric grid, natural gas pipeline infrastructure, or operation of generating or storage resources;
the effect of accounting pronouncements issued periodically by standard-setting bodies; and
other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the registrants from time to time with the SEC.
The registrants expressly disclaim any obligation to update any forward-looking statements.
THE SOUTHERN COMPANY
AND SUBSIDIARY COMPANIES
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
| | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2016 | | 2015 | | 2016 | | 2015 | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | | | | | | | | |
| Retail electric revenues | $ | 4,808 |
| | $ | 4,701 |
| | $ | 11,932 |
| | $ | 11,958 |
| $ | 3,777 |
| | $ | 3,748 |
| | $ | 7,171 |
| | $ | 7,124 |
|
| Wholesale electric revenues | 613 |
| | 520 |
| | 1,455 |
| | 1,435 |
| 618 |
| | 446 |
| | 1,149 |
| | 842 |
|
| Other electric revenues | 181 |
| | 169 |
| | 529 |
| | 494 |
| 167 |
| | 166 |
| | 342 |
| | 348 |
|
| Natural gas revenues | 518 |
| | — |
| | 518 |
| | — |
| 684 |
| | — |
| | 2,214 |
| | — |
|
| Other revenues | 144 |
| | 11 |
| | 281 |
| | 34 |
| 184 |
| | 99 |
| | 326 |
| | 137 |
|
| Total operating revenues | 6,264 |
| | 5,401 |
| | 14,715 |
| | 13,921 |
| 5,430 |
| | 4,459 |
| | 11,202 |
| | 8,451 |
|
| Operating Expenses: | | | | | | | | | | | | | | |
| Fuel | 1,400 |
| | 1,520 |
| | 3,334 |
| | 3,932 |
| 1,092 |
| | 1,023 |
| | 2,088 |
| | 1,934 |
|
| Purchased power | 227 |
| | 193 |
| | 581 |
| | 507 |
| 211 |
| | 189 |
| | 390 |
| | 354 |
|
| Cost of natural gas | 133 |
| | — |
| | 133 |
| | — |
| 232 |
| | — |
| | 951 |
| | — |
|
| Cost of other sales | 84 |
| | — |
| | 161 |
| | — |
| 114 |
| | 58 |
| | 203 |
| | 77 |
|
| Other operations and maintenance | 1,411 |
| | 1,097 |
| | 3,616 |
| | 3,320 |
| 1,301 |
| | 1,099 |
| | 2,631 |
| | 2,206 |
|
| Depreciation and amortization | 695 |
| | 528 |
| | 1,805 |
| | 1,515 |
| 754 |
| | 569 |
| | 1,469 |
| | 1,110 |
|
| Taxes other than income taxes | 309 |
| | 264 |
| | 821 |
| | 761 |
| 308 |
| | 255 |
| | 638 |
| | 511 |
|
| Estimated loss on Kemper IGCC | 88 |
| | 150 |
| | 222 |
| | 182 |
| 3,012 |
| | 81 |
| | 3,120 |
| | 134 |
|
| Total operating expenses | 4,347 |
| | 3,752 |
| | 10,673 |
| | 10,217 |
| 7,024 |
| | 3,274 |
| | 11,490 |
| | 6,326 |
|
| Operating Income | 1,917 |
| | 1,649 |
| | 4,042 |
| | 3,704 |
| |
| Operating Income (Loss) | | (1,594 | ) | | 1,185 |
| | (288 | ) | | 2,125 |
|
| Other Income and (Expense): | | | | | | | | | | | | | | |
| Allowance for equity funds used during construction | 52 |
| | 60 |
| | 150 |
| | 163 |
| 58 |
| | 45 |
| | 115 |
| | 98 |
|
| Earnings (loss) from equity method investments | | 28 |
| | (1 | ) | | 67 |
| | (1 | ) |
| Interest expense, net of amounts capitalized | (374 | ) | | (218 | ) | | (913 | ) | | (612 | ) | (424 | ) | | (293 | ) | | (840 | ) | | (539 | ) |
| Other income (expense), net | 21 |
| | (21 | ) | | (38 | ) | | (41 | ) | (3 | ) | | (28 | ) | | (11 | ) | | (56 | ) |
| Total other income and (expense) | (301 | ) | | (179 | ) | | (801 | ) | | (490 | ) | (341 | ) | | (277 | ) | | (669 | ) | | (498 | ) |
| Earnings Before Income Taxes | 1,616 |
| | 1,470 |
| | 3,241 |
| | 3,214 |
| |
| Income taxes | 448 |
| | 500 |
| | 942 |
| | 1,076 |
| |
| Consolidated Net Income | 1,168 |
| | 970 |
| | 2,299 |
| | 2,138 |
| |
| Earnings (Loss) Before Income Taxes | | (1,935 | ) | | 908 |
| | (957 | ) | | 1,627 |
|
| Income taxes (benefit) | | (587 | ) | | 261 |
| | (273 | ) | | 479 |
|
| Consolidated Net Income (Loss) | | (1,348 | ) | | 647 |
| | (684 | ) | | 1,148 |
|
| Less: | | | | | | | | | | | | | | |
| Dividends on Preferred and Preference Stock of Subsidiaries | 11 |
| | 11 |
| | 34 |
| | 42 |
| |
| Dividends on preferred and preference stock of subsidiaries | | 11 |
| | 12 |
| | 22 |
| | 23 |
|
| Net income attributable to noncontrolling interests | 27 |
| | — |
| | 39 |
| | — |
| 22 |
| | 12 |
| | 17 |
| | 13 |
|
| Consolidated Net Income Attributable to Southern Company | $ | 1,130 |
| | $ | 959 |
| | $ | 2,226 |
| | $ | 2,096 |
| |
Consolidated Net Income (Loss) Attributable to Southern Company | | $ | (1,381 | ) | | $ | 623 |
| | $ | (723 | ) | | $ | 1,112 |
|
| Common Stock Data: | | | | | | | | | | | | | | |
| Earnings per share (EPS) — | | | | | | | | |
| Basic EPS | $ | 1.17 |
| | $ | 1.05 |
| | $ | 2.37 |
| | $ | 2.30 |
| |
| Diluted EPS | $ | 1.16 |
| | $ | 1.05 |
| | $ | 2.36 |
| | $ | 2.30 |
| |
| Earnings (loss) per share — | | | | | | | | |
| Basic | | $ | (1.38 | ) | | $ | 0.67 |
| | $ | (0.73 | ) | | $ | 1.20 |
|
| Diluted | | $ | (1.37 | ) | | $ | 0.66 |
| | $ | (0.72 | ) | | $ | 1.20 |
|
| Average number of shares of common stock outstanding (in millions) | | | | | | | | | | | | | | |
| Basic | 968 |
| | 910 |
| | 940 |
| | 910 |
| 998 |
| | 934 |
| | 996 |
| | 925 |
|
| Diluted | 975 |
| | 912 |
| | 945 |
| | 913 |
| 1,005 |
| | 940 |
| | 1,003 |
| | 931 |
|
| Cash dividends paid per share of common stock | $ | 0.5600 |
| | $ | 0.5425 |
| | $ | 1.6625 |
| | $ | 1.6100 |
| $ | 0.5800 |
| | $ | 0.5600 |
| | $ | 1.1400 |
| | $ | 1.1025 |
|
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 June 30, | | For the Six Months Ended June 30, |
| | 2016 | | 2015 | | 2016 | | 2015 | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Consolidated Net Income | $ | 1,168 |
| | $ | 970 |
| | $ | 2,299 |
| | $ | 2,138 |
| |
| Consolidated Net Income (Loss) | | $ | (1,348 | ) | | $ | 647 |
| | $ | (684 | ) | | $ | 1,148 |
|
| Other comprehensive income (loss): | | | | | | | | | | | | | | |
| Qualifying hedges: | | | | | | | | | | | | | | |
Changes in fair value, net of tax of $12, $(11), $(74), and $(10),
respectively | 19 |
| | (18 | ) | | (118 | ) | | (16 | ) | |
Reclassification adjustment for amounts included in net income,
net of tax of $2, $1, $13, and $3, respectively | 2 |
| | 1 |
| | 20 |
| | 4 |
| |
Changes in fair value, net of tax of
$23, $(13), $17, and $(85), respectively | | 38 |
| | (20 | ) | | 29 |
| | (137 | ) |
Reclassification adjustment for amounts included in net income,
net of tax of $(25), $10, $(26), and $11, respectively | | (41 | ) | | 16 |
| | (42 | ) | | 18 |
|
| 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 |
| |
Reclassification adjustment for amounts included in net income,
net of tax of $1, $-, $1, and $1, respectively | | 1 |
| | 1 |
| | 2 |
| | 2 |
|
| Total other comprehensive income (loss) | 22 |
| | (15 | ) | | (95 | ) | | (7 | ) | (2 | ) | | (3 | ) | | (11 | ) | | (117 | ) |
| Comprehensive Income (Loss) | | (1,350 | ) | | 644 |
| | (695 | ) | | 1,031 |
|
| Less: | | | | | | | | | | | | | | |
| Dividends on preferred and preference stock of subsidiaries | 11 |
| | 11 |
| | 34 |
| | 42 |
| 11 |
| | 12 |
| | 22 |
| | 23 |
|
| Comprehensive income attributable to noncontrolling interests | 27 |
| | — |
| | 39 |
| | — |
| 22 |
| | 12 |
| | 17 |
| | 13 |
|
Consolidated Comprehensive Income Attributable to Southern Company | $ | 1,152 |
| | $ | 944 |
| | $ | 2,131 |
| | $ | 2,089 |
| |
Consolidated Comprehensive Income (Loss) Attributable to Southern Company | | $ | (1,383 | ) | | $ | 620 |
| | $ | (734 | ) | | $ | 995 |
|
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 Six Months Ended June 30, |
| | 2016 | | 2015 | 2017 | | 2016 |
| | (in millions) | (in millions) |
| Operating Activities: | | | | | | |
| Consolidated net income | $ | 2,299 |
| | $ | 2,138 |
| |
| Adjustments to reconcile consolidated net income to net cash provided from operating activities — | | | | |
| Consolidated net income (loss) | | $ | (684 | ) | | $ | 1,148 |
|
| Adjustments to reconcile consolidated net income (loss) to net cash provided from operating activities — | | | | |
| Depreciation and amortization, total | 2,109 |
| | 1,787 |
| 1,683 |
| | 1,306 |
|
| Deferred income taxes | (22 | ) | | 821 |
| (270 | ) | | 279 |
|
| Investment tax credits | — |
| | 319 |
| |
| Allowance for equity funds used during construction | (150 | ) | | (163 | ) | (115 | ) | | (98 | ) |
| Pension, postretirement, and other employee benefits | (158 | ) | | 79 |
| (83 | ) | | (56 | ) |
| Settlement of asset retirement obligations | (117 | ) | | (20 | ) | (87 | ) | | (66 | ) |
| Stock based compensation expense | 87 |
| | 77 |
| 73 |
| | 69 |
|
| Hedge settlements | (236 | ) | | (4 | ) | 1 |
| | (201 | ) |
| Estimated loss on Kemper IGCC | 222 |
| | 182 |
| 3,120 |
| | 134 |
|
| Income taxes receivable, non-current | — |
| | (444 | ) | (58 | ) | | — |
|
| Other, net | (98 | ) | | (48 | ) | (63 | ) | | 63 |
|
| Changes in certain current assets and liabilities — | | | | | | |
| -Receivables | (458 | ) | | (118 | ) | 110 |
| | (197 | ) |
| -Prepayments | | (61 | ) | | (28 | ) |
| -Fossil fuel for generation | 204 |
| | 239 |
| 6 |
| | 70 |
|
| -Natural gas for sale | (222 | ) | | — |
| |
| -Natural gas for sale, net of temporary LIFO liquidation | | 223 |
| | — |
|
| -Other current assets | (111 | ) | | (40 | ) | (36 | ) | | (25 | ) |
| -Accounts payable | (9 | ) | | (266 | ) | (353 | ) | | (71 | ) |
| -Accrued taxes | 1,062 |
| | 408 |
| (132 | ) | | 74 |
|
| -Accrued compensation | (122 | ) | | (129 | ) | (331 | ) | | (222 | ) |
| -Mirror CWIP | — |
| | 99 |
| |
| -Retail fuel cost over recovery | | (187 | ) | | (54 | ) |
| -Other current liabilities | (18 | ) | | 171 |
| (14 | ) | | 15 |
|
| Net cash provided from operating activities | 4,262 |
| | 5,088 |
| 2,742 |
| | 2,140 |
|
| Investing Activities: | | | | | | |
| Business acquisitions, net of cash acquired | (9,513 | ) | | (1,128 | ) | (1,062 | ) | | (897 | ) |
| Property additions | (5,252 | ) | | (3,490 | ) | (3,398 | ) | | (3,486 | ) |
| Investment in restricted cash | (750 | ) | | — |
| (16 | ) | | (8,608 | ) |
| Distribution of restricted cash | 746 |
| | — |
| 27 |
| | 649 |
|
| Nuclear decommissioning trust fund purchases | (838 | ) | | (1,164 | ) | (388 | ) | | (585 | ) |
| Nuclear decommissioning trust fund sales | 832 |
| | 1,159 |
| 383 |
| | 580 |
|
| Cost of removal, net of salvage | (155 | ) | | (118 | ) | (128 | ) | | (99 | ) |
| Change in construction payables, net | (259 | ) | | 20 |
| (117 | ) | | (260 | ) |
| Investment in unconsolidated subsidiaries | (1,421 | ) | | — |
| (116 | ) | | — |
|
| Prepaid long-term service agreement | (125 | ) | | (166 | ) | |
| Payments pursuant to LTSAs | | (132 | ) | | (82 | ) |
| Other investing activities | 95 |
| | 7 |
| 58 |
| | 113 |
|
| Net cash used for investing activities | (16,640 | ) | | (4,880 | ) | (4,889 | ) | | (12,675 | ) |
| Financing Activities: | | | | | | |
| Increase in notes payable, net | 655 |
| | 662 |
| 30 |
| | 471 |
|
| Proceeds — | | | | | | |
| Long-term debt | 14,091 |
| | 3,992 |
| 2,958 |
| | 12,038 |
|
| Common stock | 3,265 |
| | 136 |
| 417 |
| | 1,383 |
|
| Short-term borrowings | — |
| | 280 |
| 1,004 |
| | — |
|
| Redemptions and repurchases — | | | | | | |
| Long-term debt | (2,405 | ) | | (2,562 | ) | (1,478 | ) | | (1,272 | ) |
| Interest-bearing refundable deposits | — |
| | (275 | ) | |
| Preferred and preference stock | — |
| | (412 | ) | |
| Common stock | — |
| | (115 | ) | |
| Preference stock | | (150 | ) | | — |
|
| Short-term borrowings | (475 | ) | | (255 | ) | — |
| | (475 | ) |
| Distributions to noncontrolling interests | (22 | ) | | (6 | ) | (40 | ) | | (11 | ) |
| Capital contributions from noncontrolling interests | 367 |
| | 274 |
| 73 |
| | 179 |
|
| Purchase of membership interests from noncontrolling interests | (129 | ) | | — |
| — |
| | (129 | ) |
| Payment of common stock dividends | (1,553 | ) | | (1,465 | ) | (1,134 | ) | | (1,023 | ) |
| Other financing activities | (151 | ) | | (63 | ) | (75 | ) | | (133 | ) |
| Net cash provided from financing activities | 13,643 |
| | 191 |
| 1,605 |
| | 11,028 |
|
| Net Change in Cash and Cash Equivalents | 1,265 |
| | 399 |
| (542 | ) | | 493 |
|
| Cash and Cash Equivalents at Beginning of Period | 1,404 |
| | 710 |
| 1,975 |
| | 1,404 |
|
| Cash and Cash Equivalents at End of Period | $ | 2,669 |
| | $ | 1,109 |
| $ | 1,433 |
| | $ | 1,897 |
|
| Supplemental Cash Flow Information: | | | | | | |
| Cash paid (received) during the period for — | | | | | | |
| Interest (net of $94 and $88 capitalized for 2016 and 2015, respectively) | $ | 766 |
| | $ | 590 |
| |
| Interest (net of $55 and $61 capitalized for 2017 and 2016, respectively) | | $ | 833 |
| | $ | 458 |
|
| Income taxes, net | (151 | ) | | (13 | ) | 1 |
| | (138 | ) |
| Noncash transactions — Accrued property additions at end of period | 578 |
| | 483 |
| 629 |
| | 549 |
|
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
| | | Assets | | At September 30, 2016 | | At December 31, 2015 | | At June 30, 2017 | | At December 31, 2016 |
| | | (in millions) | | (in millions) |
| Current Assets: | | | | | | | | |
| Cash and cash equivalents | | $ | 2,669 |
| | $ | 1,404 |
| | $ | 1,433 |
| | $ | 1,975 |
|
| Receivables — | | | | | | | | |
| Customer accounts receivable | | 1,718 |
| | 1,058 |
| | 1,600 |
| | 1,565 |
|
| Energy marketing receivable | | 526 |
| | — |
| |
| Energy marketing receivables | | | 482 |
| | 623 |
|
| Unbilled revenues | | 639 |
| | 397 |
| | 593 |
| | 706 |
|
| Under recovered regulatory clause revenues | | 54 |
| | 63 |
| | 26 |
| | 18 |
|
| Income taxes receivable, current | | — |
| | 144 |
| | 544 |
| | 544 |
|
| Other accounts and notes receivable | | 317 |
| | 398 |
| | 513 |
| | 377 |
|
| Accumulated provision for uncollectible accounts | | (43 | ) | | (13 | ) | | (52 | ) | | (43 | ) |
| Materials and supplies | | 1,268 |
| | 1,061 |
| | 1,461 |
| | 1,462 |
|
| Fossil fuel for generation | | 664 |
| | 868 |
| | 624 |
| | 689 |
|
| Natural gas for sale | | 627 |
| | — |
| | 477 |
| | 631 |
|
| Vacation pay | | 178 |
| | 178 |
| |
| Prepaid expenses | | 459 |
| | 495 |
| | 361 |
| | 364 |
|
| Other regulatory assets, current | | 414 |
| | 402 |
| | 569 |
| | 581 |
|
| Other current assets | | 168 |
| | 71 |
| | 206 |
| | 230 |
|
| Total current assets | | 9,658 |
| | 6,526 |
| | 8,837 |
| | 9,722 |
|
| Property, Plant, and Equipment: | | | | | | | | |
| In service | | 94,174 |
| | 75,118 |
| | 101,021 |
| | 98,416 |
|
| Less accumulated depreciation | | 29,590 |
| | 24,253 |
| |
| Less: Accumulated depreciation | | | 30,667 |
| | 29,852 |
|
| Plant in service, net of depreciation | | 64,584 |
| | 50,865 |
| | 70,354 |
| | 68,564 |
|
| Other utility plant, net | | — |
| | 233 |
| |
| Nuclear fuel, at amortized cost | | 901 |
| | 934 |
| | 892 |
| | 905 |
|
| Construction work in progress | | 10,069 |
| | 9,082 |
| | 7,440 |
| | 8,977 |
|
| Total property, plant, and equipment | | 75,554 |
| | 61,114 |
| | 78,686 |
| | 78,446 |
|
| Other Property and Investments: | | | | | | | | |
| Goodwill | | 6,223 |
| | 2 |
| | 6,271 |
| | 6,251 |
|
| Equity investments in unconsolidated subsidiaries | | 1,541 |
| | 6 |
| | 1,632 |
| | 1,549 |
|
Other intangible assets, net of amortization of $39 and $12
at September 30, 2016 and December 31, 2015, respectively | | 942 |
| | 317 |
| |
Other intangible assets, net of amortization of $126 and $62
at June 30, 2017 and December 31, 2016, respectively | | | 929 |
| | 970 |
|
| Nuclear decommissioning trusts, at fair value | | 1,616 |
| | 1,512 |
| | 1,722 |
| | 1,606 |
|
| Leveraged leases | | 769 |
| | 755 |
| | 782 |
| | 774 |
|
| Miscellaneous property and investments | | 249 |
| | 160 |
| | 230 |
| | 270 |
|
| Total other property and investments | | 11,340 |
| | 2,752 |
| | 11,566 |
| | 11,420 |
|
| Deferred Charges and Other Assets: | | | | | | | | |
| Deferred charges related to income taxes | | 1,590 |
| | 1,560 |
| | 1,325 |
| | 1,629 |
|
| Unamortized loss on reacquired debt | | 228 |
| | 227 |
| | 215 |
| | 223 |
|
| Other regulatory assets, deferred | | 6,446 |
| | 4,989 |
| | 6,668 |
| | 6,851 |
|
| Income taxes receivable, non-current | | 413 |
| | 413 |
| |
| Other deferred charges and assets | | 1,133 |
| | 737 |
| | 1,387 |
| | 1,406 |
|
| Total deferred charges and other assets | | 9,810 |
| | 7,926 |
| | 9,595 |
| | 10,109 |
|
| Total Assets | | $ | 106,362 |
| | $ | 78,318 |
| | $ | 108,684 |
| | $ | 109,697 |
|
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
| | | Liabilities and Stockholders' Equity | | At September 30, 2016 | | At December 31, 2015 | | At June 30, 2017 | | At December 31, 2016 |
| | | (in millions) | | (in millions) |
| Current Liabilities: | | | | | | | | |
| Securities due within one year | | $ | 2,254 |
| | $ | 2,674 |
| | $ | 3,031 |
| | $ | 2,587 |
|
| Notes payable | | 1,670 |
| | 1,376 |
| | 3,274 |
| | 2,241 |
|
| Energy marketing trade payables | | 533 |
| | — |
| | 534 |
| | 597 |
|
| Accounts payable | | 1,732 |
| | 1,905 |
| | 1,920 |
| | 2,228 |
|
| Customer deposits | | 577 |
| | 404 |
| | 546 |
| | 558 |
|
| Accrued taxes — | | | | | | | | |
| Accrued income taxes | | 375 |
| | 19 |
| | 125 |
| | 193 |
|
| Unrecognized tax benefits | | | 400 |
| | 385 |
|
| Other accrued taxes | | 641 |
| | 484 |
| | 490 |
| | 667 |
|
| Accrued interest | | 410 |
| | 249 |
| | 508 |
| | 518 |
|
| Accrued vacation pay | | 231 |
| | 228 |
| |
| Accrued compensation | | 505 |
| | 549 |
| | 584 |
| | 915 |
|
| Asset retirement obligations, current | | 390 |
| | 217 |
| | 300 |
| | 378 |
|
| Liabilities from risk management activities, net of collateral | | 125 |
| | 156 |
| | 71 |
| | 107 |
|
| Acquisitions payable | | | — |
| | 489 |
|
| Other regulatory liabilities, current | | 99 |
| | 278 |
| | 169 |
| | 236 |
|
| Mandatorily redeemable noncontrolling interest | | 174 |
| | — |
| |
| Other current liabilities | | 851 |
| | 590 |
| | 799 |
| | 818 |
|
| Total current liabilities | | 10,567 |
| | 9,129 |
| | 12,751 |
| | 12,917 |
|
| Long-term Debt | | 41,550 |
| | 24,688 |
| | 43,885 |
| | 42,629 |
|
| Deferred Credits and Other Liabilities: | | | | | | | | |
| Accumulated deferred income taxes | | 14,218 |
| | 12,322 |
| | 13,529 |
| | 14,092 |
|
| Deferred credits related to income taxes | | 204 |
| | 187 |
| | 212 |
| | 219 |
|
| Accumulated deferred investment tax credits | | 1,721 |
| | 1,219 |
| |
| Accumulated deferred ITCs | | | 2,301 |
| | 2,228 |
|
| Employee benefit obligations | | 3,022 |
| | 2,582 |
| | 2,156 |
| | 2,299 |
|
| Asset retirement obligations, deferred | | 4,124 |
| | 3,542 |
| | 4,297 |
| | 4,136 |
|
| Unrecognized tax benefits | | 381 |
| | 370 |
| |
| Accrued environmental remediation | | 415 |
| | 42 |
| | 399 |
| | 397 |
|
| Other cost of removal obligations | | 2,771 |
| | 1,162 |
| | 2,706 |
| | 2,748 |
|
| Other regulatory liabilities, deferred | | 401 |
| | 254 |
| | 233 |
| | 258 |
|
| Other deferred credits and liabilities | | 641 |
| | 678 |
| | 805 |
| | 880 |
|
| Total deferred credits and other liabilities | | 27,898 |
| | 22,358 |
| | 26,638 |
| | 27,257 |
|
| Total Liabilities | | 80,015 |
| | 56,175 |
| | 83,274 |
| | 82,803 |
|
| Redeemable Preferred Stock of Subsidiaries | | 118 |
| | 118 |
| | 118 |
| | 118 |
|
| Redeemable Noncontrolling Interests | | 49 |
| | 43 |
| | 51 |
| | 164 |
|
| Stockholders' Equity: | | | | | | | | |
| Common Stockholders' Equity: | | | | | | | | |
| Common stock, par value $5 per share — | | | | | | | | |
| Authorized — 1.5 billion shares | | | | | | | | |
| Issued — September 30, 2016: 981 million shares | | | | | |
| — December 31, 2015: 915 million shares | | | | | |
| Treasury — September 30, 2016: 0.8 million shares | | | | | |
| — December 31, 2015: 3.4 million shares | | | | | |
| Issued — June 30, 2017: 1.0 billion shares | | | | | |
| — December 31, 2016: 991 million shares | | | | | |
| Treasury — June 30, 2017: 0.9 million shares | | | | | |
| — December 31, 2016: 0.8 million shares | | | | | |
| Par value | | 4,900 |
| | 4,572 |
| | 4,997 |
| | 4,952 |
|
| Paid-in capital | | 9,217 |
| | 6,282 |
| | 10,106 |
| | 9,661 |
|
| Treasury, at cost | | (30 | ) | | (142 | ) | | (34 | ) | | (31 | ) |
| Retained earnings | | 10,685 |
| | 10,010 |
| | 8,494 |
| | 10,356 |
|
| Accumulated other comprehensive loss | | (225 | ) | | (130 | ) | | (191 | ) | | (180 | ) |
| Total Common Stockholders' Equity | | 24,547 |
| | 20,592 |
| | 23,372 |
| | 24,758 |
|
| Preferred and Preference Stock of Subsidiaries | | 609 |
| | 609 |
| | 462 |
| | 609 |
|
| Noncontrolling Interests | | 1,024 |
| | 781 |
| | 1,407 |
| | 1,245 |
|
| Total Stockholders' Equity | | 26,180 |
| | 21,982 |
| | 25,241 |
| | 26,612 |
|
| Total Liabilities and Stockholders' Equity | | $ | 106,362 |
| | $ | 78,318 |
| | $ | 108,684 |
| | $ | 109,697 |
|
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRDSECOND QUARTER 20162017 vs. THIRDSECOND QUARTER 20152016
AND
YEAR-TO-DATE 20162017 vs. YEAR-TO-DATE 20152016
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 businessbusinesses of electricity sales by the traditional electric operating companies and Southern Power and following the closing of the Merger on July 1, 2016, the distribution of natural gas by Southern Company Gas, formerly known as AGL Resources Inc.Gas. The four traditional electric operating companies are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas is an energy services holding company whose primary business is the distribution ofdistributes natural gas through seven natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. Southern Company's other business activities include providing energy technologies and services to electric utilities and large industrial, commercial, institutional, and municipal customers. Customer solutions include distributed generation systems, utility infrastructure solutions, and energy efficiency products and services in the areas of distributed generation, energy efficiency, and utility infrastructure, as well asservices. Other business activities also include investments in telecommunications, and leveraged lease projects.projects, and gas storage facilities. For additional information, see BUSINESS – "The Southern Company System – Traditional Electric Operating Companies," " – Southern Power," " – Southern Company Gas," and " – Other Businesses" in Item 1 of the Form 10-K.
Merger with Southern Company Gas
On July 1, 2016, Southern Company completed the Merger for a total purchase pricecontinues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, electric and natural gas system reliability, execution of approximately $8.0 billionmajor construction projects, and Southern Company Gas became a wholly-owned, direct subsidiary of Southern Company.earnings per share.
Prior to the completion of the Merger, Southern Company and Southern Company Gas operated as separate companies. The discussion and analysis of results of operations and financial condition set forth herein include Southern Company Gas' results of operations since July 1, 2016 and financial condition as of September 30, 2016. See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information regarding the Merger.
During the three and nine months ended September 30, 2016, Southern Company recorded in its statements of income costs associated with the Merger of approximately $40.8 million and $104.1 million, respectively, of which $40.6 million and $73.5 million is included in operating expenses and $0.2 million and $30.6 million is included in other income and (expense), respectively. These costs include external transaction costs for financing, legal, and consulting services, as well as rate credits and additional compensation-related expenses.
See RISK FACTORS in Item 1A herein for additional information related to the various risks related to the Merger.
Construction Program
Construction continues on Plant Vogtle Units 3 and 4 (45.7% ownership interest by Georgia Power in the two units, each with approximately 1,100 MWs) and Mississippi Power's 582-MW Kemper IGCC. See RESULTS OF OPERATIONS – "Estimated Loss on Kemper IGCC," FUTURE EARNINGS POTENTIAL – "Construction Program," and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for additional information.information regarding the construction program. For information about Southern Power's acquisitions and construction of renewable energy facilities, see Note (I) to the Condensed Financial Statements under "Southern Power" herein.
Kemper IGCC
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Key Performance Indicators
Southern Company continuesOn June 21, 2017, the Mississippi PSC stated its intent to focusissue an order (which occurred on several key performance indicators. These indicators include customer satisfaction,July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, availability, system reliability, execution of major construction projects,rather than an IGCC plant, 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 ofaddress all issues associated with 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)Kemper IGCC (Kemper Settlement Order). The Kemper Settlement Order established a new docket for the third quarter 2016 compared to $959 million ($1.05 per share) for the third quarter 2015. The increase was primarily the resultpurposes of an increase in retail electric revenues resulting from warmer weather and base rate increases,pursuing a decrease in income taxes primarily from income tax benefits at Southern Power, and lower charges related to revisionsglobal settlement 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(Kemper IGCC Settlement Docket). The Mississippi PSC requested any such proposed settlement agreement reflect: (i) at a minimum, no rate increase to Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and amortization,related assets; and non-fuel operations and maintenance expenses. See Note (B) to(iii) modification or amendment of 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)CPCN 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 correctionKemper IGCC to allow only for ownership and operation 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.natural gas facility.
Although several individual income statement line items reflect variances resulting from the Merger on July 1, 2016 andability to achieve a negotiated settlement is uncertain, Mississippi Power intends to pursue any available settlement alternatives. In addition, the acquisition of PowerSecure International, Inc. (PowerSecure) on May 9, 2016, consolidated net incomeKemper Settlement Order provides that, in the event a settlement agreement is not reached, the Mississippi PSC reserves its right to take any appropriate steps, including issuing an order to show cause as to why the CPCN for the third quarter and year-to-date 2016 wasKemper IGCC should 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.be revoked.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
DetailsOn June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014.
At the time of project suspension, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in additional grants from the DOE received on April 8, 2016 (Additional DOE Grants). Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate subject to the construction cost cap totaling $196 million ($121 million after tax) in the second quarter through May 31, 2017 and a total of $305 million ($188 million after tax) for year-to-date through May 31, 2017. In the aggregate, Mississippi Power incurred charges of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017. The May 31, 2017 cost estimate included approximately $175 million of estimated costs to be incurred beyond the then-estimated in-service date of June 30, 2017 that were expected to be subject to the $2.88 billion cost cap.
At June 30, 2017, approximately $3.3 billion in actual Kemper IGCC costs were not reflected in Mississippi Power's retail electric revenues were as follows:and wholesale rates, of which $0.5 billion was related to the combined cycle and associated facilities and $2.8 billion was related to the gasification portions of the Kemper IGCC.
|
| | | | | | | | | | | | | |
| | 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 | )% |
RevenuesWhile the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper Settlement Order, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with changesthe gasification portions of the plant and lignite mine. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs currently estimated at approximately $100 million to $200 million are expected to be incurred.
Total pre-tax charges to income for the estimated probable losses on the Kemper IGCC were $3.0 billion ($2.1 billion after tax) for the second quarter 2017 and $3.1 billion ($2.2 billion after tax) for the six months ended June 30, 2017. In the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $6.0 billion ($3.9 billion after tax) through June 30, 2017.
As of June 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which $0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility, as well as the 15% that was previously contracted to SMEPA. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and pricing increasedexpects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC 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.Settlement Docket proceedings.
SeeFor additional information on the Kemper IGCC, including information on the project economic viability analysis, pending lawsuits, and an ongoing SEC investigation, see Note 3 to the financial statements of Southern Company under "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"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 hereinunder "Integrated Coal Gasification Combined Cycle" herein.
Nuclear Construction
On March 29, 2017, the EPC Contractor filed for additional information.
Revenues attributable to changes in sales decreased inbankruptcy protection under Chapter 11 of the third quarter 2016 when compared toU.S. Bankruptcy Code. To provide for a continuation of work at Plant Vogtle Units 3 and 4, Georgia Power, acting for itself and as agent for 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 fromVogtle Owners, entered into 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 consistentinterim assessment agreement with the actual allocation in 2016. Without this adjustment, year-to-date 2016 weather-adjusted residential sales increased 0.3%EPC Contractor (Interim Assessment Agreement), weather-adjusted commercial sales decreased 0.5%, and industrial KWH sales decreased 2.0% as compared towhich 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 inbankruptcy court approved on March 30, 2017. On June 9, 2017, Georgia Power
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
and the other Vogtle Owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion (Guarantee Obligations), of which Georgia Power's proportionate share is approximately $1.7 billion, and that the Guarantee Obligations exist regardless of whether Plant Vogtle Units 3 and 4 are completed. Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into a services agreement (Services Agreement), which was amended and restated on July 20, 2017, for the EPC Contractor to transition construction management of Plant Vogtle Units 3 and 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear. On July 27, 2017, the Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE and the Interim Assessment Agreement expired pursuant to its terms. The Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.
Georgia Power and the other Vogtle Owners are continuing to conduct comprehensive schedule and cost-to-complete assessments, as well as cancellation cost assessments, to determine the impact of the EPC Contractor's bankruptcy filing on the construction cost and schedule for Plant Vogtle Units 3 and 4. Georgia Power will continue working with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4, including, but not limited to, the status of construction and rate recovery, and currently expects to include its recommendation in its seventeenth Vogtle Construction Monitoring (VCM) report to be filed with the Georgia PSC in late August 2017.
An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Southern Company's financial statements. The ultimate outcome of these matters also is dependent on the completion of the assessments described above, as well as the related regulatory treatment, and cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Construction Program – Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4, including Georgia Power's preliminary cost-to-complete and cancellation cost assessments for Plant Vogtle Units 3 and 4.
RESULTS OF OPERATIONS
Net Income (Loss)
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(2,004) | | N/M | | $(1,835) | | N/M |
N/M - Not meaningful
Consolidated net loss attributable to Southern Company was $(1.4) billion ($(1.38) per share) for the second quarter 2017 compared to net income of $623 million ($0.67 per share) for the corresponding period in 2016. The decrease was primarily due to charges of $3.0 billion and $81 million in the second quarter 2017 and 2016, respectively, related to the Kemper IGCC at Mississippi Power. Also contributing to the change were increases in renewable energy sales at Southern Power, higher retail electric revenues resulting from increases in base rates, and $49 million in net income from Southern Company Gas, which was acquired on July 1, 2016, partially offset by higher interest expense.
Consolidated net loss attributable to Southern Company was $(723) million ($(0.73) per share) for year-to-date 2017 compared to net income of $1.1 billion ($1.20 per share) for the corresponding period in 2016. The decrease was primarily due to charges of $3.1 billion and $134 million for year-to-date 2017 and 2016, respectively, related to the Kemper IGCC at Mississippi Power. Also contributing to the change was $288 million in net income from Southern Company Gas, increases in renewable energy sales at Southern Power, and higher retail electric revenues
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
resulting from increases in base rates, partially offset by higher interest expense and a decrease in retail electric revenues resulting from milder weather for year-to-date 2017 compared to the corresponding period in 2016.
See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the Kemper IGCC and Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information on the Merger.
Retail Electric Revenues
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $29 | | 0.8 | | $47 | | 0.7 |
In the second quarter 2017, retail electric revenues were $3.8 billioncompared to $3.7 billion for the corresponding period in 2016. For year-to-date 2017, retail revenues were $7.2 billion compared to $7.1 billion for the corresponding period in 2016.
Details of the changes in retail electric revenues were as follows:
|
| | | | | | | | | | | | | | |
| | | Second Quarter 2017 | | Year-to-Date 2017 |
| | | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail electric – prior year | | $ | 3,748 |
| | | | $ | 7,124 |
| | |
| Estimated change resulting from – | | | | | | | | |
| Rates and pricing | | 81 |
| | 2.2 |
| | 200 |
| | 2.8 |
|
| Sales decline | | (12 | ) | | (0.3 | ) | | (22 | ) | | (0.3 | ) |
| Weather | | (51 | ) | | (1.4 | ) | | (189 | ) | | (2.6 | ) |
| Fuel and other cost recovery | | 11 |
| | 0.3 |
| | 58 |
| | 0.8 |
|
| Retail electric – current year | | $ | 3,777 |
| | 0.8 | % | | $ | 7,171 |
| | 0.7 | % |
Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2017 when compared to the corresponding periods in 2016 primarily due to a Rate RSE increase at Alabama Power effective January 1, 2017, the recovery of Plant Vogtle Units 3 and 4 construction financing costs under the NCCR tariff at Georgia Power, and an ECO Plan rate increase at Mississippi Power implemented in the third quarter 2016. Additionally, the second quarter 2017 increase was partially offset by the rate pricing effect of decreased customer usage and lower contributions from commercial and industrial customers under a rate plan for variable demand-driven pricing at Georgia Power.
See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Alabama Power" and " – Georgia Power – Rate Plans" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.
Revenues attributable to changes in sales decreased in the second quarter 2017when compared to the corresponding period in 2016. Industrial KWH sales decreased 0.8% in the second quarter 2017 primarily in the paper, primary metals, and transportation sectors, partially offset by increased sales in the chemicals sector. Despite a more stable dollar and improving global economy, the industrial sector remains constrained by economic policy uncertainty. Weather-adjusted residential KWH sales decreased 0.4% in the second quarter 2017primarily due to decreased customer usage primarily resulting from increased efficiency improvements in residential appliances and lighting, partially offset by customer growth. Weather-adjusted commercial KWH sales were flat in thesecond quarter 2017 primarily due to decreased customer usage resulting from an increase in electronic commerce transactions and energy saving initiatives, offset by customer growth.
Revenues attributable to changes in sales decreased for year-to-date 2017 when compared to the corresponding period in 2016. Industrial KWH sales decreased 1.5% for year-to-date 2017 primarily in the paper, stone, clay, and
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
glass, and transportation sectors. Despite a more stable dollar and improving global economy, the industrial sector remains constrained by economic policy uncertainty. Weather-adjusted commercial KWH sales decreased 0.9% foryear-to-date 2017 primarily due to decreased customer usage resulting from an increase in electronic commerce transactions and energy saving initiatives, partially offset by customer growth. Weather-adjusted residential KWH sales increased 0.2% for year-to-date 2017primarily due to customer growth, partially offset by decreased customer usage primarily resulting from efficiency improvements in residential appliances and lighting.
Fuel and other cost recovery revenues increased $11 million and $58 million in the second quarter and year-to-date 2017, respectively, when compared to the corresponding periods in 2016 primarily due to an increase in natural gas prices. Electric rates for the traditional electric operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of PPA costs, and do not affect net income. The traditional electric operating companies each have one or more regulatory mechanisms to recover other costs such as environmental and other compliance costs, storm damage, new plants, and PPA capacity costs.
Wholesale Electric Revenues
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $93 | | 17.9 | | $20 | | 1.4 |
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $172 | | 38.6 | | $307 | | 36.5 |
Wholesale electric revenues consist of PPAs primarily with investor-owned utilities and electric cooperatives and short-term opportunity sales. Wholesale electric revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues reflectgenerally represent the greatest contribution to net income and are designed to provide recovery of fixed costs andplus a return on investment. Energy revenues will vary depending on fuel prices, the market prices of wholesale energy compared to the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. SolarElectricity sales from solar and wind PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge.charge or through a fixed price for electricity. As a result, Southern Company's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, and other factors. Wholesale electric revenues at Mississippi Power include FERC-regulated municipal and rural association sales as well as market-based sales. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system's variable cost to produce the energy.
In the thirdsecond quarter 2016,2017, wholesale electric revenues were $613$618 million compared to $520$446 million for the corresponding period in 2015.2016. This increase was primarily related to a $121$158 million increase in energy revenues partially offset byand a $28$14 million decreaseincrease in capacity revenues. For year-to-date 2016,2017, wholesale electric revenues were $1.46$1.1 billion compared to $1.44 billion$842 million for the corresponding period in 2015.2016. This increase was primarily related to a $112$276 million increase in energy revenues partially offset byand a $92$31 million decreaseincrease in capacity revenues. The increases in energy revenues were primarily duerelated to an increaseSouthern Power increases in short-term sales and renewable energy sales at Southern Power, partially offset by lower fuel prices.arising from new solar and wind facilities, sales from new natural gas PPAs, and non-PPA revenues from short-term sales. The decreasesincreases in capacity revenues were primarily dueresulted from PPAs related to the elimination in consolidation of anew natural gas facilities and additional customer load requirements at 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 ElectricNatural Gas 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 electricNatural gas revenues were $529represent sales from the natural gas distribution utilities and certain non-regulated operations of Southern Company Gas. Following the Merger, $684 million compared to $494 millionand $2.2 billion of natural gas revenues are included in the consolidated statements of income for the corresponding period in 2015. The increase was primarily due to increases in customer temporary facilities services revenues, outdoor lighting revenues,second quarter and solar application fee revenues at Georgia Power.year-to-date 2017, respectively.
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 |
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $85 | | 85.9 | | $189 | | N/M |
N/M - Not meaningful
In the thirdsecond quarter 2016,2017, other revenues were $144$184 million compared to $11$99 million for the corresponding period in 2015.2016. For year-to-date 2016,2017, other revenues were $281$326 million compared to $34$137 million for the corresponding period in 2015.2016. These increases were primarily due to $91increases of $60 million and $150$130 million for the thirdsecond quarter and year-to-date 2016,2017, respectively, of revenues from products and services at PowerSecure, which was acquired on May 9, 2016, and $25$32 million and $62 million for the second quarter and year-to-date 2017, respectively, 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 | Second Quarter 2017
vs.
Second Quarter 2016 | | Year-to-Date 2017
vs.
Year-to-Date 2016 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | (120 | ) | | (7.9) | | $ | (598 | ) | | (15.2) | $ | 69 |
| | 6.7 | | $ | 154 |
| | 8.0 |
| Purchased power | 34 |
| | 17.6 | | 74 |
| | 14.6 | 22 |
| | 11.6 | | 36 |
| | 10.2 |
| Total fuel and purchased power expenses | $ | (86 | ) | | $ | (524 | ) | | $ | 91 |
| | $ | 190 |
| |
In the thirdsecond quarter 2016,2017, total fuel and purchased power expenses were $1.6$1.3 billion compared to $1.7$1.2 billion for the corresponding period in 2015.2016. The decreaseincrease was primarily the result of a $209$154 million decreaseincrease in the average cost of fuel and purchased power primarily due to lower coalhigher natural gas prices, partially offset by a $123$63 million increase indecrease primarily due to the volume of KWHs generated and purchased.
For year-to-date 2016,2017, total fuel and purchased power expenses were $3.9$2.5 billion compared to $4.4$2.3 billion for the corresponding period in 2015.2016. The decreaseincrease was primarily the result of a $573$277 million decreaseincrease in the average cost of fuel and purchased power primarily due to lower coal andhigher natural gas prices, partially offset by a $49an $87 million net increase indecrease primarily due to 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 | Second Quarter 2017 | | Second Quarter 2016 | | Year-to-Date 2017 | | Year-to-Date 2016 |
Total generation (in billions of KWHs) | 56 | | 53 | | 145 | | 146 | 49 | | 45 | | 93 | | 89 |
Total purchased power (in billions of KWHs) | 5 | | 4 | | 13 | | 10 | 3 | | 4 | | 7 | | 8 |
Sources of generation (percent) — | | | | |
| Coal | 38 | | 40 | | 33 | | 37 | 31 | | 32 | | 30 | | 30 |
| Nuclear | 15 | | 15 | | 16 | | 16 | 16 | | 16 | | 16 | | 17 |
| Gas | 44 | | 43 | | 46 | | 44 | 43 | | 48 | | 45 | | 47 |
| Hydro | 1 | | 1 | | 3 | | 2 | 3 | | 2 | | 3 | | 4 |
| Other Renewables | 2 | | 1 | | 2 | | 1 | |
| Other | | 7 | | 2 | | 6 | | 2 |
Cost of fuel, generated (in cents per net KWH) — | | | | |
| Coal | 2.97 | | 3.86 | | 3.10 | | 3.65 | 2.77 | | 3.20 | | 2.82 | | 3.22 |
| Nuclear | 0.81 | | 0.84 | | 0.82 | | 0.78 | 0.80 | | 0.82 | | 0.80 | | 0.82 |
| Gas | 2.74 | | 2.71 | | 2.40 | | 2.72 | 2.94 | | 2.24 | | 2.93 | | 2.20 |
Average cost of fuel, generated (in cents per net KWH) | 2.54 | | 2.90 | | 2.38 | | 2.78 | 2.49 | | 2.33 | | 2.49 | | 2.28 |
Average cost of purchased power (in cents per net KWH)(*) | 5.57 | | 5.95 | | 5.31 | | 6.13 | 7.70 | | 5.03 | | 6.85 | | 5.14 |
| |
| (*) | 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 thirdsecond quarter 2016,2017, fuel expense was $1.4$1.1 billion compared to $1.5$1.0 billion for the corresponding period in 2015.2016. The decreaseincrease was primarily due to a 23.1%31.3% increase in the average cost of natural gas per KWH generated and a 3.0% increase in the volume of KWHs generated by coal, partially offset by a 13.4% decrease in the average cost of coal per KWH generated partially offsetand a 4.8% decrease in the volume of KWHs generated by an 8.7%natural gas.
For year-to-date 2017, fuel expense was $2.1 billion compared to $1.9 billion for the corresponding period in 2016. The increase was primarily due to a 33.2% increase in the average cost of natural gas per KWH generated and a 4.1% 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 tocoal, partially offset by a 15.1%12.4% decrease in the average cost of coal per KWH generated an 11.9%and a 6.6% 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 thirdsecond quarter 2016,2017, purchased power expense was $227$211 million compared to $193$189 million for the corresponding period in 2015.2016. The increase was primarily due to a 24.1%53.1% 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.higher natural gas prices, partially offset by a 28.0% decrease in the volume of KWHs purchased.
For year-to-date 2016,2017, purchased power expense was $581$390 million compared to $507$354 million for the corresponding period in 2015.2016. The increase was primarily due to a 29.4%33.3% 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.higher natural gas prices, partially offset by a 16.8% decrease in the volume of KWHs purchased.
Energy purchases will vary depending on demand for energy within the Southern Company system's electric service territory, the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, and the availability of the Southern Company system's generation.
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$232 millionand$951 million of natural gas costs iswere included in the consolidated statements of income for the thirdsecond quarter and year-to-date 2016.2017, respectively.
See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
Cost of Other Sales
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $56 | | 96.6% | | $126 | | N/M |
N/M - Not meaningful
In the thirdsecond quarter and year-to-date 2016,2017, cost of other sales were $84was $114 million and $161compared to $58 million respectively.for the corresponding period in 2016. For year-to-date 2017, cost of other sales was $203 million compared to $77 million for the corresponding period in 2016. These costsincreases were primarily due to costs 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 ofgas marketing 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.
Merger. 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 informationinformation.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $202 | | 18.4 | | $425 | | 19.3 |
In the second quarter 2017, other operations and maintenance expenses were $1.3 billion compared to $1.1 billion for the corresponding period in 2016. The increase was primarily due to $213 million in operations and maintenance expenses at Southern Company Gas following the Merger, a $19 million increase associated with new solar, wind, and gas facilities at Southern Power, and a $15 million increase in operations and maintenance expenses at PowerSecure, which was acquired on May 9, 2016. These increases were partially offset by a $24 million decrease in acquisition-related expenses and a $7 million decrease in scheduled outage and maintenance costs at generation facilities.
For year-to-date 2017, other operations and maintenance expenses were $2.6 billion compared to $2.2 billion for the corresponding period in 2016. The increase was primarily due to increases of $467 million and $36 million in operations and maintenance expenses from Southern Company Gas and PowerSecure, respectively, a $35 million increase associated with new solar, wind, and gas facilities at Southern Power, and $32.5 million resulting from the write-down of Gulf Power's ownership of Plant Scherer Unit 3 in accordance with a settlement agreement approved by the Florida PSC on April 4, 2017 (2017 Rate Case Settlement Agreement). These increases were partially offset by a $46 million decrease in scheduled outage and maintenance costs at generation facilities, a $26 million decrease in acquisition-related expenses, a $19 million increase in gains from sales of integrated transmission system assets at Georgia Power, a $16 million decrease in customer accounts, service, and sales costs primarily associated with demand-side management costs related to the Mergertiming of new programs at Georgia Power, and a $14 million decrease in employee compensation and benefits including pension costs.
See Note (B) to the acquisition of PowerSecure.Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information regarding the 2017 Rate Case Settlement Agreement and Note (I) to the
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Condensed Financial Statements under "Southern Company" herein for additional information related to the Merger and the acquisition of PowerSecure.
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 |
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $185 | | 32.5 | | $359 | | 32.3 |
In the thirdsecond quarter 2016,2017, depreciation and amortization was $695$754 million compared to $528$569 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 2015.2016. Following the Merger, $116$125 million in depreciation and amortization for Southern Company Gas is included in the consolidated financial statements of income for the thirdsecond quarter and year-to-date 2016.2017. Additionally, the increases were dueincrease reflects $61 million related to additional plant in service at the traditional electric operating companies and Southern Power.Power, partially offset by $8 million more of a reduction in depreciation in the second quarter 2017 compared to the corresponding period in 2016 at Gulf Power, as authorized in its 2013 rate case settlement approved by the Florida PSC.
For year-to-date 2017, depreciation and amortization was $1.5 billion compared to $1.1 billion for the corresponding period in 2016. Following the Merger, $244 million in depreciation and amortization for Southern Company Gas is included in the consolidated statements of income for year-to-date 2017. Additionally, the increase reflects $122 million related to additional plant in service at the traditional electric operating companies and Southern Power, partially offset by $28 million more of a reduction in depreciation for year-to-date 2017 compared to the corresponding period in 2016 at Gulf Power, as authorized in its 2013 rate case settlement approved by the Florida PSC.
See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information. Also see Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
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 |
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $53 | | 20.8 | | $127 | | 24.9 |
In the thirdsecond quarter 2016,2017, taxes other than income taxes were $309$308 million compared to $264$255 million for the corresponding period in 2015.2016. For year-to-date 2016,2017, taxes other than income taxes were $821$638 million compared to $761$511 million for the corresponding period in 2015. Following2016. These increases were primarily related to $44 million and $114 million in the Merger, $29 millionsecond quarter and year-to-date 2017, respectively, in taxes other than income taxes associated with Southern Company Gas is included infollowing the consolidated financial statements for the third quarter and year-to-date 2016. Additionally, property taxes at the traditional electric operating companies increased for the third quarter and year-to-date 2016 primarily due to an increase in the assessed value of property.Merger.
See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 |
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $2,931 | | N/M | | $2,986 | | N/M |
N/M - Not meaningful
InPrior to the third quarter 2016 and 2015,project suspension on June 28, 2017, estimated probable losses on the Kemper IGCC of $88$196 million and $150$305 million respectively, were recorded at Southern Company. ForMississippi Power in the second quarter and year-to-date 2017, respectively, compared to $81 millionand $134 million in the second quarter and 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.respectively. These losses reflectreflected revisions of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC prior to project suspension 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).
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper Settlement Order, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion, which includes estimated costs associated with the gasification portions of the plant and lignite mine.
See FUTURE EARNINGS POTENTIAL – "Construction Program – Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Allowance for Equity Funds Used During Construction
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $13 | | 28.9 | | $17 | | 17.3 |
In the second quarter 2017, AFUDC equity was $58 million compared to $45 million in the corresponding period in 2016. For year-to-date 2017, AFUDC equity was $115 million compared to $98 million in the corresponding period in 2016. These increases primarily resulted from a higher AFUDC rate and an increase in Kemper IGCC CWIP subject to AFUDC prior to project suspension at Mississippi Power.
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
Earnings from Equity Method Investments
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $29 | | N/M | | $68 | | N/M |
N/M - Not meaningful
In the second quarter and year-to-date 2017, earnings from equity method investments were $28 million and $67 million, respectively, primarily related to earnings from Southern Company Gas' equity method investment in SNG effective September 2016.
See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
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 |
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $131 | | 44.7 | | $301 | | 55.8 |
In the thirdsecond quarter 2016,2017, interest expense, net of amounts capitalized was $374$424 million compared to $218$293 million in the corresponding period in 2015.2016. For year-to-date 2016,2017, interest expense, net of amounts capitalized was $913$840 million compared to $612$539 million in the corresponding period in 2015.2016. These increases were primarily due to an increase in average outstanding long-term debt primarily related to the financingMerger and the funding of the Merger.Southern Power's acquisitions and construction projects. In addition, following the Merger, $39$48 million and $94 million in interest expense of Southern Company Gas iswas included in the consolidated financial statements of income for the thirdsecond quarter and year-to-date 2016. Also contributing to the year-to-date 2016 increase was the May 2015 termination of an asset purchase agreement between Mississippi Power and SMEPA and the resulting reversal of accrued interest on related deposits.2017, respectively.
See Note (E) to the Condensed Financial Statements herein for additional information.
Other Income (Expense), Net |
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $42 | | N/M | | $3 | | 7.3 |
N/M - Not meaningful
In the third quarter 2016, other income (expense), net was $21 million compared to $(21) million for the corresponding period in 2015. For year-to-date 2016, other income (expense), net was $(38) million compared to $(41) million for the corresponding period in 2015. Following the Merger, $38 million in other income of Southern Company Gas is included in the consolidated financial statements for the third quarter and year-to-date 2016, primarily related to $27 million of earnings from the equity method investment in Southern Natural Gas Company, L.L.C. (SNG) in September 2016. Additionally, in the third quarter 2016, revenues and costs associated with certain non-regulated sales of products and services by the traditional electric operating companies were reclassified to other revenues and cost of other sales for consistency of presentation on a consolidated basis following the PowerSecure acquisition. For the third quarter and year-to-date 2016, net amounts reclassified were $6 million and $20 million, respectively. The year-to-date 2016 increase was partially offset by fees associated with the Bridge Agreement for the Merger.
See "Other Revenues" and "Cost of Other Sales" herein and Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information. Also see 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.
Other Income Taxes(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) |
| $(52) | | (10.4) | | $(134) | | (12.5) |
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $25 | | 89.3 | | $45 | | 80.4 |
In the thirdsecond quarter 2016,2017, other income taxes were $448(expense), net was $(3) million compared to $500$(28) 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.
2016. For year-to-date 2016,2017, other income taxes were $942(expense), net was $(11) million compared to $1.1 billion$(56) million for the corresponding period in 2015. The decrease was2016. These changes were primarily due to increased federal income tax benefitsexpenses incurred in 2016 associated with bridge financing for the Merger. These changes also include increases of $99 million and $116 million in currency losses arising from ITCsa translation of euro-denominated fixed-rate notes into U.S. dollars for the second quarter and PTCsyear-to-date 2017, respectively, fully offset by an equal change in gains on the foreign currency hedges that were reclassified from accumulated OCI into earnings at Southern Power.
See Note (H) to the Condensed Financial Statements under "Foreign Currency Derivatives" herein for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Income Taxes (Benefit)
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(848) | | N/M | | $(752) | | N/M |
N/M - Not meaningful
In the second quarter 2017, income tax benefit was $587 million compared to income tax expense of $261 million for the corresponding period in 2016. The decrease was primarily due to $865 million in tax benefits related to the estimated probable losses on the Kemper IGCC at Mississippi Power, partially offset by an$31 million in taxes at Southern Company Gas following the Merger.
For year-to-date 2017, income tax benefit was $273 million compared to income tax expense of $479 million for the corresponding period in 2016, primarily due to $886 million in tax benefits related to the estimated probable losses on the Kemper IGCC at Mississippi Power. In addition, the change reflects $180 million in taxes at Southern Company Gas following the Merger, partially offset by a net increase in pre-tax earnings and an increase related to state income tax benefits realized in 2015.of $16 million from renewable tax credits at Southern Power.
See Note (G) to the Condensed Financial Statements herein and Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern Company's future earnings potential. The level of Southern Company's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Southern Company system's primary businessbusinesses of selling electricity and as a result of closing the Merger, the distribution ofdistributing natural gas. These factors include the traditional electric operating companies' and Southern Company Gas'the natural gas distribution utilities' ability to maintain a constructive regulatory environment that allows for the timely recovery of prudently-incurred costs during a time of increasing costs and limited projected demand growth over the completionnext several years. Completion of cost assessments and subsequent operationthe determination of the Kemper IGCC andfuture actions related to Plant Vogtle Units 3 and 4 as well as other ongoing construction projects. Otherand rate recovery and the ability to recover costs for the remainder of the Kemper County energy facility not included in current rates are also major factors includefactors. In addition, the profitability of Southern Power's competitive wholesale business and successful additional investments in renewable and other energy projects. projects are also major factors.
Current proposals related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals, including any potential changes to the availability or realizability of ITCs and PTCs, is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Southern Company's financial statements.
Future earnings for the electricity and natural gas businesses will be driven primarily by customer growth. Earnings in the near termelectricity business will also depend in part, upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies, increasing volumes of electronic commerce transactions, and customers whichhigher multi-family home construction. Earnings for both the electricity and natural gas businesses are subject to a numbervariety of other factors. These factors include weather, competition, new energy contracts with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the prices of electricity and natural gas, the price elasticity of demand, and the rate of economic growth or decline in the service territory. In addition, the level of future earnings for the wholesale electric business also depends on numerous factors including regulatory matters, creditworthiness of customers, total electric generating capacity available and related costs, future acquisitions and construction of electric generating facilities, the impact of tax credits from renewable energy projects, and the successful remarketing of capacity as current contracts expire. Demand for electricity and natural gas is primarily driven by economic growth. The pace of economic growth and electricity and natural gas demand may be affected by changes
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
in regional and global economic conditions, which may impact future earnings.
Volatility In addition, the volatility of natural gas prices has a significant impact on Southern Company Gas'the natural gas distribution utilities' customer rates, long-term competitive position against other energy sources, and the ability of Southern Company Gas' gas marketing services and wholesale gas services businesses to capture value from locational and seasonal spreads. Additionally, changes in commodity prices subject a significant portion of Southern Company Gas' operations to earnings variability.
As part of its ongoing effort to adapt to changing market conditions, Southern Company continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, partnerships, and acquisitions involving other utility or non-utility businesses or properties, disposition of certain assets or businesses, internal restructuring, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations, risks, and financial condition of Southern Company.
On July 10, 2016, Southern Company and Kinder Morgan, Inc. (Kinder Morgan) entered into a definitive agreement for Southern Company to acquire a 50% equity interest in SNG, which is the owner of a 7,000-mile pipeline system connecting natural gas supply basins in Texas, Louisiana, Mississippi, and Alabama to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee. In addition, the agreement committed Southern Company and Kinder Morgan to cooperatively pursue specific growth opportunities to develop natural gas infrastructure through SNG. On August 31, 2016, Southern Company assigned its rights and obligations under the definitive agreement to a wholly-owned, indirect subsidiary of Southern Company Gas. On September 1, 2016, Southern Company Gas completed the acquisition for a purchase price of approximately $1.4 billion. The investment in SNG is accounted for using the equity method.
For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Company in Item 7 of the Form 10-K and RISK FACTORS in Item 1A herein.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis for the traditional electric operating companies and the natural gas distribution utilities or through market-based contracts.long-term wholesale agreements for the traditional electric operating companies and Southern Power. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity and natural gas, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company in Item 7 and Note 3 to the financial 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 mattereight-hour ozone National Ambient Air Quality StandardsStandard (NAAQS), and the Cross State Air Pollution Rule (CSAPR).
On April 25, 2016, in response to a June 2015 U.S. Supreme Court opinion,2, 2017, the EPA published its supplemental finding regarding consideration of costs in support ofa final rule redesignating a 15-county area within metropolitan Atlanta to attainment for 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.2008 eight-hour ozone NAAQS.
Also on April 25, 2016,On June 18, 2017, the EPA issued proposed revisions topublished a notice delaying attainment designations for the regional haze regulations.2015 eight-hour ozone NAAQS by one year, setting a revised deadline of October 1, 2018. The ultimate impactoutcome of the proposed revisions will depend on their ultimate adoption, implementation, and any legal challenges andthis matter 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 ResidualsWater Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Residuals"Water Quality" of Southern Company in Item 7 of the Form 10-K for additional information regarding the EPA's regulationfinal effluent guidelines rule and the final rule revising the regulatory definition 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 requirementswaters of the EPA's Disposal of Coal Combustion Residuals from Electric Utilities Rule (CCR Rule) and establish additional requirementsU.S. 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) toClean Water Act (CWA) programs.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
On April 25, 2017, the Condensed Financial Statements hereinEPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. On June 6, 2017, the EPA proposed a rule establishing a stay of the compliance deadlines for information regarding Southern Company's asset retirement obligations (ARO) ascertain effluent limitations and pretreatment standards under the rule.
On June 27, 2017, the EPA and the U.S. Army Corps of September 30, 2016.Engineers proposed to rescind the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.
Environmental RemediationThe ultimate outcome of these matters cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – EnvironmentalRemediation"Global Climate Issues" of Southern Company in Item 7 of the Form 10-K for additional information.
As a resultOn March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of closingdomestically produced energy resources. The executive order specifically directs the Merger, Southern Company's Consolidated Balance SheetEPA to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules.
On June 1, 2017, the U.S. President announced that the United States will withdraw from the non-binding Paris Agreement and begin renegotiation of its terms.
The ultimate outcome of these matters cannot be determined at September 30, 2016 includes the environmental remediation liabilitiesthis time.
FERC Matters
Market-Based Rate Authority
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters – Market-Based Rate Authority" of Southern Company Gas. See Note (B) toin Item 7 of 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" hereinForm 10-K for additional information regarding the Merger.traditional electric operating companies' and Southern Power's market power proceeding and amendment to their market-rate tariff.
On May 17, 2017, the FERC accepted the traditional electric operating companies' and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' and Southern Power's market power proceeding, it remains a separate, ongoing matter.
Southern Company Gas
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters – Southern Company Gas" of Southern Company in Item 7 and Note 4 to the financial statements of Southern Company in Item 8 of the Form 10-K for additional information regarding Southern Company Gas' pipeline projects.
On August 1, 2017, the Dalton Pipeline was placed in service as authorized by the FERC and transportation service for customers commenced.
Regulatory Matters
Fuel Cost Recovery
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory"Regulatory Matters – Retail Fuel Cost Recovery" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Retail Regulatory"Regulatory Matters – Alabama Power – Rate ECR" and "Retail Regulatory"Regulatory Matters – Georgia Power –
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding retail fuel cost recovery.recovery for the traditional electric operating companies.
The traditional electric operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow. The traditional electric operating companies continuously monitor their under or over recovered fuel cost balances and make appropriate filings with their state PSCs to adjust fuel cost recovery rates as necessary.
On May 17, 2016, the Georgia PSC approved Georgia Power's request to decrease fuel rates by 15% effective June 1, 2016, which will reduce annual billings by approximately $313 million. Georgia Power is currently scheduled to file its next fuel case by February 28, 2017.
Renewables
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory"Regulatory Matters – Renewables" of Southern Company in Item 7 of the Form 10-K for additional information regarding the Southern Company system's renewables activity.
In accordance with the Alabama PSC order approving up to 500 MWs of renewable projects, Alabama Power has entered into agreements to purchase power from or to build renewable generation sources, including a 72-MW solar PPA approved by the Alabama PSC in June 2016. Alabama Power is marketing the associated renewable energy credits (REC) generated by this solar PPA to customers interested in supporting renewable energy development. The terms of the renewable agreements permit Alabama Power to use the energy and retire the associated RECs in service of its customers or to sell RECs, separately or bundled with energy.
As part of the Georgia Power Advanced Solar Initiative (ASI), four PPAs totaling 149 MWs of Georgia Power's solar contracted capacity from Southern Power began in the first quarter 2016. During the second quarter 2016, Georgia Power executed PPAs to purchase an additional 41 MWs of solar capacity under the ASI. Ownership of any associated RECs is specified in each respective PPA. The party that owns the RECs retains the right to use them.
On October 4, 2016, two 30-MW solar generating facilities at Fort Gordon and Fort Stewart Army bases began commercial operation. These solar generating facilities were approved byMay 16, 2017, 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 issuedapproved Georgia Power's request to build, own, and operate 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 of139-MW solar generation facility at a solar photovoltaic facility with electric generating capacity of up to 1 MW through annual subscriptions. The energy generated from the solar facilityU.S. Air Force base that 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 beplaced in service by the second quarterend of 2019.
During the six months ended June 30, 2017, and the resulting energy purchases areGeorgia Power continued construction of a 31-MW solar generation facility at a U.S. Marine Corps base that is expected to be recovered through placed in service in the fourth quarter 2017.
Mississippi Power's fuel cost recovery mechanism.Power placed in service two solar projects in January 2017 and June 2017. A third solar project is expected to be placed in service in the third quarter 2017. Mississippi Power may retire the RECsrenewable energy credits (REC) generated on behalf of its customers or sell the RECs, separately or bundled with energy, to third parties.
On June 9, 2017, Mississippi Power submitted a CPCN to the Mississippi PSC for the approval of construction, operation, and maintenance of a 52.5-MW solar energy generating facility, which, if approved, is expected to be placed in service by January 2020.
The ultimate outcome of these matters cannot be determined at this time.
Alabama Power
Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business primarily through its Rate RSE, Rate CNP, Compliance, rate energy cost recovery,Rate ECR, and rate natural disaster reserve.Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See Note 3 to the financial statements of Southern Company under "Retail Regulatory"Regulatory Matters – Alabama Power" in Item 8 of the Form 10-K for additional information regarding Alabama Power's rate mechanisms and accounting orders. The recovery balance of each regulatory clause for Alabama Power is reported in Note (B) to the Condensed Financial Statements herein.
Environmental Accounting Order
In April 2016, as part of its environmental compliance strategy, Alabama Power ceased using coal at Plant Greene County Units 1 and 2 (300 MWs representing Alabama Power's ownership interest) and began operating Units 1 and 2 solely on natural gas in June 2016 and July 2016, respectively.
Georgia Power
Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, Environmental Compliance Cost Recovery tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to the construction of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a separate fuel cost recovery tariffs.tariff. See Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction"Construction" herein and Note 3 to the financial statements of Southern Company under "Retail Regulatory"Regulatory Matters – Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding Georgia Power's NCCR tariff. Also see Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" herein for additional information regarding Georgia Power's fuel cost recovery.
Pursuant to the terms and conditions of a settlement agreement related to Southern Company's acquisition of Southern Company Gas approved by the Georgia PSC on April 14, 2016, Georgia Power's 2013 ARP will continue in effect until December 31, 2019, and Georgia Power will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, Georgia Power and Atlanta Gas Light Company (collectively, Utilities) each will retain their respective merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, such net merger savings applicable to each utility will be shared on a 60/40 basis between their respective customers and the Utilities; thereafter, all merger savings will be retained by customers.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power" in Item 8 of the Form 10-K for additional information regarding the 2013 ARP and Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information regarding the Merger.
Integrated Resource Plan
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory"Regulatory Matters – Georgia Power – Integrated Resource Plan" of Southern Company in Item 7 of the Form 10-K for additional information regarding Georgia Power's triennial Integrated Resource Plan (2016 IRP).Plan.
On July 28, 2016, the Georgia PSC voted to approve the 2016 IRP including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 combustion turbine (17 MWs), as well as the decertification of the Intercession City unit (143 MWs total capacity). On August 2, 2016, the Plant Mitchell and Plant Kraft units were retired. On August 31, 2016, Georgia Power sold its 33% ownership interest in the Intercession City unit to Duke Energy Florida, Inc.
Additionally,March 7, 2017, the Georgia PSC approved Georgia Power's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures takendecision to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4.
The Georgia PSC approved the reclassification of the remaining net book value of Plant Mitchell Unit 3 and costs associated with materials and supplies remaining at the unit retirement date to a regulatory asset. Recovery of the unit's net book value will continue through December 31, 2019, as provided in the 2013 ARP. The timing of the recovery of the remaining balance of the unit's net book value as of December 31, 2019 and costs associated with materials and supplies remaining at the unit retirement date will be deferred for consideration in Georgia Power's base rate case required to be filed by July 1, 2019.
The Georgia PSC also approved the Renewable Energy Development Initiative to procure an additional 1,200 MWs of renewable resources primarily utilizing market-based prices established through a competitive bidding process with expected in-service dates between 2018 and 2021. Additionally, 200 MWs of self-build capacity for use by Georgia Power was approved, as well as consideration for no more than 200 MWs of capacity as part of a renewable commercial and industrial program.
The Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve the nuclear optionsuspend work at a future generation site in Stewart County, Georgia.Georgia, due to changing economics, including load forecasts and lower fuel costs. The timing of cost recovery for costs incurred of approximately $50 million will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time.
Storm Damage Recovery
As of September 30, 2016, the balance in Georgia Power's regulatory asset related to storm damage was $94 million. During October 2016, Hurricane Matthew caused significant damage to Georgia Power's transmission and distribution facilities. The total amount of restoration costs related to this hurricane is estimated to be between $130 million and $155 million, which will be charged to capital accounts or to the storm damage reserve. Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, to the storm damage reserve to cover the operating and maintenance costs of damages from major storms to its transmission and distribution facilities, which is recoverable through base rates. The rate of recovery of storm damage costs after December 31, 2019 is expected to be adjusted in Georgia Power's base rate case required to be filed by July 1, 2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's financial statements. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Storm Damage Recovery" in Item 8 of the Form 10-K for additional information regarding Georgia Power's storm damage reserve.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Gulf Power
Through 2015, long-term non-affiliateSee MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Gulf Power" of Southern Company in Item 7 of the Form 10-K for additional information regarding Gulf Power's October 2016 request to the Florida PSC to increase retail base rates and Gulf Power's ownership of Plant Scherer Unit 3.
On April 4, 2017, the Florida PSC approved the 2017 Rate Case Settlement Agreement among Gulf Power and three intervenors with respect to Gulf Power's request to increase retail base rates. Under the terms of the 2017 Rate Case Settlement Agreement, Gulf Power increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consists of a $62.0 million increase in annual base revenues less an annual equivalent credit of approximately $7.7 million for 2017 for certain wholesale revenues to be provided through December 2019 through the purchased power capacity sales fromcost recovery clause. In addition, Gulf Power continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%) and is deemed to have an equity ratio of 52.5% for all retail regulatory purposes. Gulf Power will also begin amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 (357 MWs) over 15 years effective January 1, 2018 and will implement new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs) provided, which was recorded in the majorityfirst quarter 2017. The remaining issues related to the inclusion of Gulf Power's wholesale earnings. The revenues from wholesale contracts covering 100% of this capacity represented 82% of Gulf Power's wholesale capacity revenues in 2015. Following contract expirations at the end of 2015 and the end of May 2016, Gulf Power's remaining contracted sales from the unit cover approximately 24% of Gulf Power's ownership of the unit through 2019. The expiration of these contracts is not expected to have a material impact on Southern Company's earnings. On May 5, 2016, Gulf Power delivered a letter to the Florida PSC requesting recognition of Gulf Power's ownershipinvestment in Plant Scherer Unit 3 as being in service to retail customers when and as its existing wholesale contracts expire. As a result, on September 13, 2016, the Florida PSC instructed Gulf Power to file its monthly earnings surveillance reports both including and excluding its share of investment and expenses related to Plant Scherer Unit 3 that is not covered by contracts.
On October 12, 2016, Gulf Power filed a petition (2016 Rate Case) with the Florida PSC requesting an increase in retail rates and charges of $106.8 million based on the projected test year of January 1, 2017 through December 31, 2017 andhave been resolved as a retail ROE of 11% compared to the current retail ROE of 10.25%. The recoverabilityresult of the costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 will be decided in this matter. The Florida PSC is expected to make a decision on the 20162017 Rate Case in the second quarter 2017. Gulf Power has requested that the increase in base rates, if approved by the Florida PSC, become effective in July 2017.
On November 2, 2016, the Florida PSC approved Gulf Power's annual rate clause request for its cost recovery clause factors for 2017. The fuel and environmental factors includeSettlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3. See Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters– Gulf Power– Cost Recovery Clauses" herein for additional information.
The ultimate outcome of these matters cannot be determined at this time.unit through the environmental cost recovery clause rate approved by the Florida PSC in November 2016.
Southern Company Gas
Natural Gas Cost Recovery
Southern Company Gas has established natural gas cost recovery rates approved by the relevant state regulatory agencies in the states in which it serves. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Accordingly, changesChanges in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow.flows.
Regulatory Infrastructure ProgramsBase Rate Cases
Southern Company Gas' natural gas distribution utilities are involved in ongoing capital projects associated with infrastructure improvement programs that have been previously approved by their applicable state regulatory agencies and provide an appropriate return on invested capital. These infrastructure improvement programs update or expand the natural gas distribution systems of the utilities to improve safety and reliability and meet operational flexibility and growth. Southern CompanyOn March 10, 2017, Nicor Gas currently has approved infrastructure improvement programs in six different states with initial program lengths ranging from four to 10 years,filed a general base rate case with the longest setIllinois Commission requesting a $208 million increase in annual base rate revenues. The requested increase is based on a 2018 projected test year and a ROE of 10.7%. The Illinois Commission is expected to expire in 2025. The average annual spend under these programs ranges from $10 million to $250 million.
Southern Company Gas currently has proposed infrastructure improvement programs pending approval byrule on the applicable state regulatory agencies in Georgia and New Jersey requesting average annual spending of $44 million through 2020 and $110 million through 2027, respectively.requested increase within the 11-month statutory time limit, after which rate adjustments will be effective. The ultimate outcome of these mattersthis matter cannot be determined at this time.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 forenvironmental modifications to certain existing units, adding environmental control equipment, expanding the electric transmission and distribution systems, and updating and expanding the natural gas distribution systems. For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. Southern Company Gas is engaged in various infrastructure improvement programs thatdesigned to update or expand itsthe natural gas distribution systems of the natural gas distribution utilities to improve reliability and ensure the safety of its utility infrastructuremeet operational flexibility and recovers in rates itsgrowth. The natural gas distribution utilities recover their investment and a return associated with these infrastructure programs.programs through their regulated rates.
The two largest construction projectsproject currently underway in the Southern Company system areis Plant Vogtle Units 3 and 4 (45.7% ownership interest by Georgia Power in the two units, each with approximately 1,100 MWs). Georgia Power and the other Vogtle Owners are continuing to conduct comprehensive schedule and cost-to-complete assessments, as well as cancellation cost assessments, to determine the impact of the EPC Contractor's bankruptcy filing on the construction cost and schedule for Plant Vogtle Units 3 and 4. Georgia Power will continue working with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4, including, but not limited to, the status of construction and rate recovery, and currently expects to include its recommendation in its seventeenth VCM report to be filed with the Georgia PSC in late August 2017. On June 21, 2017, the Mississippi Power's 582-MWPSC directed Mississippi Power to pursue a settlement under which the Kemper IGCC.IGCC would be operated as a natural gas plant rather than an IGCC plant and, on June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the plant. See Note 3 to the financial statements of Southern Company under "Retail Regulatory"Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for additional information. For additional information about costs relating to Southern Power's acquisitions that involve construction of renewable energy facilities, see Note 12 to the financial statements of Southern Company under "Southern Power – Construction Projects" in Item 8 of the Form 10-K and Note (I) to the Condensed Financial Statements under "Southern Power – Construction Projects" herein. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Southern Company Gas – Regulatory Infrastructure Programs" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters –Southern Company Gas –Regulatory Infrastructure Programs"Programs" herein for additional information regarding infrastructure improvement programs at Southern Company Gas'the natural gas distribution utilities.
Also see FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information regarding Southern Company's capital requirements for its subsidiaries' construction programs.
Integrated Coal Gasification Combined Cycle
Mississippi Power's current cost estimate for theThe Kemper IGCC was approved by the Mississippi PSC in total is approximately $6.82 billion, which includes approximately $5.52 billion of coststhe 2010 CPCN proceedings, subject to thea construction cost cap and isof $2.88 billion, net of $137$245 million in additional DOE grants Mississippi Power received for the Kemper IGCC on April 8, 2016 (Additional DOE Grants), which are expected to be used to reduce future rate impacts for customers. Mississippi Power does not intend to seek any rate recovery for any related costs that exceed the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. 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"combined cycle 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 costsassociated common facilities portion of the Kemper IGCC subjectwere placed in service in August 2014.
In December 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order), based on a stipulation between Mississippi Power and the Mississippi Public Utilities Staff, authorizing rates that provide for the recovery of approximately $126 million annually related to the $2.88 billion cost cap, netcombined cycle and associated common facilities portion of Kemper IGCC assets previously placed in service. As required by 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.
The ultimate outcome of these matters cannot be determined at this time.In-Service Asset Rate Order, on June 5, 2017,
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Mississippi Power made a rate filing requesting to adjust the amortization schedules of the regulatory assets reviewed and determined prudent in a manner that would not change customer rates or annual revenues. On June 28, 2017, the Mississippi PSC suspended this filing. On July 6, 2017, the Mississippi PSC issued an order requiring Mississippi Power to establish a regulatory liability account to maintain current rates related to the Kemper IGCC following the July 2017 completion of the amortization period for certain regulatory assets approved in the In-Service Asset Rate Order that would allow for subsequent refund if the Mississippi PSC deems the rates unjust and unreasonable.
The remainder of the plant includes 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." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO2, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. Most recently, in May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast has decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations increased significantly since certification.
On June 21, 2017, the Mississippi PSC stated its intent to issue the Kemper Settlement Order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC. The Kemper Settlement Order established the Kemper IGCC Settlement Docket for the purposes of pursuing a global settlement of costs of the Kemper IGCC. The Mississippi PSC requested any such proposed settlement agreement reflect: (i) at a minimum, no rate increase to Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and related assets; and (iii) modification or amendment of the CPCN for the Kemper IGCC to allow only for ownership and operation of a natural gas facility. The Kemper Settlement Order provides that any related settlement agreement be filed within 45 days from the effective date of the Kemper Settlement Order. If a settlement agreement is filed, a hearing will be set 45 days from the date of the settlement's filing, and the appropriate scheduling order will be established.
Although the ability to achieve a negotiated settlement is uncertain, Mississippi Power intends to pursue any available settlement alternatives. In addition, the Kemper Settlement Order provides that, in the event a settlement agreement is not reached, the Mississippi PSC reserves its right to take any appropriate steps, including issuing an order to show cause as to why the CPCN for the Kemper IGCC should not be revoked.
On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014.
At the time of project suspension, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate subject to the construction cost cap totaling $196 million ($121 million after tax) in the second quarter through May 31, 2017 and a total of $305 million ($188 million after tax) for year-to-date through May 31, 2017. In the aggregate, Mississippi Power incurred charges of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017. The May 31, 2017 cost estimate included approximately $175 million of estimated costs to be incurred beyond the then-estimated in-service date of June 30, 2017 that were expected to be subject to the $2.88 billion cost cap.
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
At June 30, 2017, approximately $3.3 billion in actual Kemper IGCC costs were not reflected in Mississippi Power's retail and wholesale rates, of which $0.5 billion was related to the combined cycle and associated facilities and $2.8 billion was related to the gasification portions of the Kemper IGCC.
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper Settlement Order, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs currently estimated at approximately $100 million to $200 million are expected to be incurred.
Total pre-tax charges to income for the estimated probable losses on the Kemper IGCC were $3.0 billion ($2.1 billion after tax) for the second quarter 2017 and $3.1 billion ($2.2 billion after tax) for the six months ended June 30, 2017. In the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $6.0 billion ($3.9 billion after tax) through June 30, 2017.
As of June 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which $0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility, as well as the 15% that was previously contracted to SMEPA. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.
For additional information on the Kemper IGCC, including information on the project economic viability analysis, pending lawsuits, and an ongoing SEC investigation, see Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and "Other Matters" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein. Also see "Litigation" herein.
Litigation
On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. On August 12, 2016, Southern Company and Mississippi Power removed the case to the U.S. District Court for the Southern District of Mississippi, where the case is currently pending. However, 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 23, 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the plaintiffs filed notice to appeal to the Mississippi Supreme Court.
On June 9, 2016, Treetop Midstream Services, LLC (Treetop) and other related parties filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint relates to the cancelled CO2 contract with Treetop and alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and seeks
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS have moved to compel arbitration pursuant to the terms of the CO2 contract.contract, which the court granted on May 4, 2017. On June 28, 2017, Treetop and other related parties filed a claim for arbitration requesting $500 million in damages.
Southern Company believes these legal challenges have no merit; however, an adverse outcome in these proceedings could have ana material impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, and the ultimate outcome of these matters cannot be determined at this time.
Nuclear Construction
See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the construction of Plant Vogtle Units 3 and 4, VCM reports, the NCCR tariff, and the Contractor Settlement Agreement.
Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcy
In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Vogtle 3 and 4 Agreement, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4. 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. Georgia Power's proportionate share of Plant Vogtle Units 3 and 4 is 45.7%.
The Vogtle 3 and 4 Agreement also provided for liquidated damages upon the EPC Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to an aggregate cap of 10% of the contract price, or approximately $920 million (approximately $420 million based on Georgia Power's ownership interest). Under the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. In January 2016, Westinghouse delivered to the Vogtle Owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020 and require 60 days' written notice to Georgia Power in the event the Westinghouse Letters of Credit will not be renewed.
Under the terms of the Vogtle 3 and 4 Agreement, the EPC Contractor did not have the right to terminate the Vogtle 3 and 4 Agreement for convenience. In the event of an abandonment of work by the EPC Contractor, the maximum liability of the EPC Contractor under the Vogtle 3 and 4 Agreement was 40% of the contract price (approximately $1.7 billion based on Georgia Power's ownership interest).
On October 20, 2016,March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. To provide for a continuation of work at Plant Vogtle Units 3 and 4, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Interim Assessment Agreement, which the bankruptcy court approved on March 30, 2017.
The Interim Assessment Agreement provided, among other items, that during the term of the Interim Assessment Agreement (i) Georgia Power was obligated to pay, on behalf of the Vogtle Owners, all costs accrued by the EPC Contractor for subcontractors and vendors for services performed or goods provided, with these amounts paid to the EPC Contractor, except that amounts accrued for Fluor Corporation (Fluor) were paid directly to Fluor; (ii) the EPC Contractor provided certain engineering, procurement, and management services for Plant Vogtle Units 3 and 4, to the same extent as contemplated by the Vogtle 3 and 4 Agreement, and Georgia Power, on behalf of the Vogtle Owners, made payments of $5.4 million per week for these services; (iii) Georgia Power had the right to make payments, on behalf of the Vogtle Owners, directly to subcontractors and vendors who had accounts past due with the EPC Contractor; (iv) the EPC Contractor used commercially reasonable efforts to provide information reasonably requested by Georgia Power as was necessary to continue construction and investigation of the
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
completion status of Plant Vogtle Units 3 and 4; (v) the EPC Contractor rejected or accepted the Vogtle 3 and 4 Agreement by the termination of the Interim Assessment Agreement; and (vi) Georgia Power did not exercise any remedies against Toshiba under the Toshiba Guarantee. Under the Interim Assessment Agreement, all parties expressly reserved all rights and remedies under the Vogtle 3 and 4 Agreement and all related security and collateral under applicable law.
The Interim Assessment Agreement, as amended, expired on July 27, 2017. Georgia Power's aggregate liability for the Vogtle Owners under the Interim Assessment Agreement totaled approximately $650 million, of which $552 million had been paid or accrued as of June 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $297 million.
Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor, including Fluor Enterprises, Inc., a subsidiary of Fluor, alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken, and continues to take, actions to remove liens filed by these subcontractors through the posting of surety bonds. Georgia Power estimates the aggregate liability, through July 31, 2017, of the Vogtle Owners for the removal of subcontractor liens and payment of other EPC Contractor pre-petition accounts payable to total approximately $400 million, of which $354 million had been paid or accrued as of June 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $183 million.
On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered the Guarantee Settlement Agreement. Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion, of which Georgia Power's proportionate share is approximately $1.7 billion, and that the Guarantee Obligations exist regardless of whether Plant Vogtle Units 3 and 4 are completed. The Guarantee Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations, beginning in October 2017 and continuing through January 2021. In the event Toshiba receives certain payments, including sale proceeds, from or related to Westinghouse (or its subsidiaries) or Toshiba Nuclear Energy Holdings (UK) Limited (or its subsidiaries), it will hold a portion of such payments in trust for the Vogtle Owners and promptly pay them as offsets against any remaining Guarantee Obligations. Under the Guarantee Settlement Agreement, the Vogtle Owners will forbear from exercising certain remedies, including drawing on the Westinghouse Letters of Credit, until June 30, 2020, unless certain events of nonpayment, insolvency, or other material breach of the Guarantee Settlement Agreement by Toshiba occur. If such an event occurs, the balance of the Guarantee Obligations will become immediately due and payable, and the Vogtle Owners may exercise any and all rights and remedies, including drawing on the Westinghouse Letters of Credit without restriction. In addition, the Guarantee Settlement Agreement does not restrict the Vogtle Owners from fully drawing on the Westinghouse Letters of Credit in the event they are not renewed or replaced prior to the expiration date.
On June 23, 2017, Toshiba released a revised outlook for fiscal year 2016, which reflected a negative shareholders' equity balance of approximately $5 billion as of March 31, 2017, and announced that its independent audit process was continuing. Toshiba has also announced the existence of material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern. As a result, substantial risk regarding the Vogtle Owners' ability to fully collect the Guarantee Obligations continues to exist. An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Southern Company's financial statements.
Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Services Agreement, which was amended and restated on July 20, 2017, for the EPC Contractor to transition construction management of Plant Vogtle Units 3 and 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Services Agreement, (ii) assume and assign to the Vogtle Owners certain project-related contracts, (iii) join the Vogtle Owners as counterparties to certain assumed project-related contracts, and (iv) reject the Vogtle 3 and 4 Agreement.
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE on July 27, 2017. The Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.
The ultimate outcome of these matters cannot be determined at this time.
Regulatory Matters
In 2009, the Georgia PSC Staff entered intovoted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by including the related CWIP accounts in rate base during the construction period. As of June 30, 2017, Georgia Power had recovered approximately $1.4 billion of financing costs.
On December 20, 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving the following prudence and cost recovery matters related to Plant Vogtle Units 3 and 4:matters: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth Vogtle Construction MonitoringVCM report will be disallowed from rate base on the basis of imprudence; (ii) the definitive settlement agreement entered into on December 31, 2015 by Westinghouse and the Vogtle Owners (ContractorContractor Settlement Agreement)Agreement is reasonable and prudent and none of the amounts paid or to be paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) financing costs on verified and approved capital costs will be deemed prudent provided they are incurred prior to December 31, 2019 and December 31, 2020 for Plant Vogtle Units 3 and 4, respectively; and (iv) (a) the in-service capital cost forecast will be adjusted to $5.680 billion (Revised Forecast), which includes a contingency of $240 million above Georgia Power's then current forecast of $5.440 billion, (b) capital costs incurred up to the Revised Forecast will be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, and (c) Georgia Power would have the burden to show that any capital costs above the Revised Forecast are reasonable and prudent. Under the terms of the Vogtle Cost Settlement Agreement, the certified in-service capital cost for purposes of calculating the NCCR tariff will remain at $4.418 billion. Construction capital costs above $4.418 billion will accrue AFUDC through commercial operation.the date each unit is placed in service. The ROE used to calculate the NCCR tariff will bewas reduced from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016. For purposes of the AFUDC calculation, the ROE on costs between $4.418 billion and $5.440 billion will also be 10.00% and the ROE on any amounts above $5.440 billion would be Georgia Power's average cost of long-term debt. If the Georgia PSC adjusts Georgia Power's ROE rate setting point in a rate case prior to Plant Vogtle Units 3 and 4 being placed into retail rate base, then the ROE for purposes of calculating both
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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 operationalplaced in service by December 31, 2020, then (i) the ROE for purposes of calculating the NCCR tariff will be reduced an additional 300 basis points, or $8 million per month, and may, at the Georgia PSC's discretion, be accrued to be used for the benefit of customers, until such time as the units reach commercial operationare placed in service and (ii) the ROE used to calculate AFUDC will be Georgia Power's average cost of long-term debt.
Under the terms of the Vogtle Cost Settlement Agreement, Plant Vogtle Units 3 and 4 will be placed into retail rate base on December 31, 2020 or upon reaching commercial operation, whichever is later. Thethe Georgia PSC will determine, for retail ratemaking purposes, the process of transitioning Plant Vogtle Units 3 and 4 from a construction project to an operating plant no later than Georgia Power's base rate case required to be filed by July 1, 2019.
The Vogtle Cost Settlement Agreement is subject toGeorgia PSC has approved fifteen VCM reports covering the periods through June 30, 2016, including construction capital costs incurred, which through that date totaled $3.7 billion. Georgia Power filed its sixteenth VCM report, covering the period from July 1 through December 31, 2016, requesting approval byof $222 million of construction capital costs incurred during that period, with the Georgia PSC which is scheduled to vote on this matter on December 20, 2016. Accordingly, the terms of the Vogtle Cost Settlement Agreement are subject to change and the terms of any final agreement approved by the Georgia PSC may differ materially from the terms of the Vogtle Cost Settlement Agreement. If approved, the Vogtle Cost Settlement Agreement is expected to 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.February 27, 2017.
The ultimate outcome of these matters cannot be determined at this time.
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Revised Cost and Schedule
Georgia Power and the other Vogtle Owners are continuing to conduct comprehensive schedule and cost-to-complete assessments, as well as cancellation cost assessments, to determine the impact of the EPC Contractor's bankruptcy filing on the construction cost and schedule for Plant Vogtle Units 3 and 4. Georgia Power's preliminary assessment results indicate that its proportionate share of the remaining estimated cost to complete Plant Vogtle Units 3 and 4 ranges as follows:
|
| | | | | | | |
| Preliminary in-service dates | | | |
| Unit 3 | February 2021 | – | March 2022 |
| Unit 4 | February 2022 | – | March 2023 |
| | (in billions) |
| Preliminary estimated cost to complete | $ | 3.9 |
| – | $ | 4.6 |
|
| CWIP as of June 30, 2017 | 4.5 |
| | 4.5 |
|
| Guarantee Obligations | (1.7 | ) | | (1.7 | ) |
| Estimated capital costs | $ | 6.7 |
| – | $ | 7.4 |
|
| Vogtle Cost Settlement Agreement Revised Forecast | (5.7 | ) | | (5.7 | ) |
| Estimated net additional capital costs | $ | 1.0 |
| – | $ | 1.7 |
|
Georgia Power's estimates for cost to complete and schedule are based on preliminary analysis and remain subject to further refinement of labor productivity and consumable and commodity quantities and costs.
Georgia Power's estimated financing costs during the construction period total approximately $3.1 billion to $3.5 billion, of which approximately $1.4 billion had been incurred through June 30, 2017.
Georgia Power's preliminary cancellation cost estimate results indicate that its proportionate share of the estimated cancellation costs is approximately $400 million. As a result, as of June 30, 2017, total estimated costs subject to evaluation by Georgia Power and the Georgia PSC in the event of a cancellation decision are as follows:
|
| | | |
| | Preliminary Cancellation Cost Estimate |
| | (in billions) |
| CWIP as of June 30, 2017 | $ | 4.5 |
|
| Financing costs collected, net of tax | 1.4 |
|
Cancellation costs(*) | 0.4 |
|
| Total | $ | 6.3 |
|
| |
| (*) | The estimate for cancellation costs includes, but is not limited to, costs to terminate contracts for construction and other services, as well as costs to secure the Plant Vogtle Units 3 and 4 construction site. |
The Guarantee Obligations continue to exist in the event of cancellation. In addition, under Georgia law, prudently incurred costs related to certificated projects cancelled by the Georgia PSC are allowed recovery, including carrying costs, in future retail rates. Georgia Power will continue working with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4, including, but not limited to, the status of construction and rate recovery, and currently expects to include its recommendation in its seventeenth VCM report to be filed with the Georgia PSC in late August 2017.
The ultimate outcome of these matters is dependent on the completion of the assessments described above, as well as the related regulatory treatment, and cannot be determined at this time.
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Other Matters
As of June 30, 2017, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through a loan guarantee agreement between Georgia Power and the DOE and a multi-advance credit facility among Georgia Power, the DOE, and the FFB. See Note 6 to the financial statements of Southern Company under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
The IRS has allocated PTCs to Plant Vogtle Units 3 and 4 which require that the applicable unit be placed in service prior to 2021. The net present value of Georgia Power's PTCs is estimated at approximately $400 million per unit.
There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise if 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 if 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.
If construction continues, the risk remains that challenges with labor productivity, fabrication, delivery, assembly, and installation of plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost.
The ultimate outcome of these matters cannot be determined at this time.
See RISK FACTORS of Southern Company in Item 1A of the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world. See additional risks in Item 1A herein regarding the EPC Contractor's bankruptcy.
Income Tax Matters
Bonus Depreciation
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Bonus Depreciation"Matters" of Southern Company in Item 7 of the Form 10-K and Note (G) to the Condensed Financial Statements herein for additional information.
The extension of 50% bonus depreciation included in the PATH Act is expected to result in approximately $1.7Bonus Depreciation
Approximately $1.2 billion of positive cash flows is expected to result from bonus depreciation for the 20162017 tax year, whichbut may not all be realized in 20162017 due to a projected consolidated net operating loss projections for Southern Company.the 2017 tax year. Approximately $370 million of the 2017 benefit is dependent upon placing the remainder of the Kemper IGCC in service by December 31, 2016.2017. If the suspension of the Kemper IGCC start-up activities results in an abandonment, any amount previously estimated as bonus depreciation would be claimed as a deduction under IRC Section 165. As of June 30, 2017, $82 million has been received through quarterly income tax refunds for bonus depreciation related to the Kemper IGCC, which may be subject to repayment. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein and Note (G) to the Condensed Financial Statements herein for additional information. The ultimate outcome of this matter cannot be determined at this time.
Section 174 Research and Experimental Deduction
Southern Company has reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and filed amended federal income tax returns for
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
2008 through 2013 to also include such deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, subject to approval of the U.S. Congress Joint Committee on Taxation, resolving a methodology for these deductions. Due to the uncertainty related to this tax position, Southern Company had unrecognized tax benefits associated with these R&E deductions totaling approximately $464 million as of June 30, 2017. If the suspension of the Kemper IGCC start-up activities results in an abandonment, any amount not allowed under IRC Section 174 would be claimed as a deduction under IRC Section 165, and would result in a reversal of the related unrecognized tax benefits, excluding interest. See Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and Note (G) tothe Condensed Financial Statements under "Current"Section 174 Research and Deferred Income Taxes – Net Operating LossExperimental Deduction," respectively, herein for additional information. TheThis matter is expected to be resolved in the next 12 months; however, the ultimate outcome of this matter cannot be determined at this time.
Other Matters
Southern Company and its subsidiaries are involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. The business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation against Southern Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, orinNote3tothefinancialstatementsofSouthernCompanyinItem8ofthe Form 10-K,management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
On January 20, 2017, a purported securities class action complaint was filed against Southern Company, certain of its officers, and certain former Mississippi Power officers in the U.S. District Court for the Northern District of Georgia, Atlanta Division, by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint alleges that Southern Company, certain of its officers, and certain former Mississippi Power officers made materially false and misleading statements regarding the Kemper IGCC in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. On June 12, 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. On July 27, 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice.
On February 27, 2017, Jean Vineyard filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the defendants caused Southern Company to make false or misleading statements regarding the Kemper IGCC cost and schedule. Further, the complaint alleges that the defendants were unjustly enriched and caused the waste of corporate assets. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on her own behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. On March 27, 2017, the court deferred this lawsuit until 30 days after certain further action in the purported securities class action complaint discussed above.
On May 15, 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia, that names as defendants Southern Company, certain of its directors, certain of
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Statements hereinits officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper IGCC. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper IGCC schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes.
On June 1, 2017, Judy Mesirov filed a shareholder derivative lawsuit in the U.S. District Court for a discussionthe Northern District of variousGeorgia, that names as defendants Southern Company, certain of its current and former directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other contingencies, regulatorythings, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper IGCC. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper IGCC schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages, disgorgement of profits, and equitable relief and, on her own behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes.
Southern Company believes these legal challenges have no merit; however, an adverse outcome in any of these proceedings could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, and other matters being litigatedthe ultimate outcome of which may affect future earnings potential.cannot be determined at this time.
The SEC is conducting a formal investigation of Southern Company and Mississippi Power concerning the estimated costs and expected in-service date of the Kemper IGCC. Southern Company and Mississippi Power believebelieves the investigation is focused primarily on periods subsequent to 2010 and on accounting matters, disclosure controls and procedures, and internal controls over financial reporting associated with the Kemper IGCC. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" herein for additional information on the Kemper IGCC estimated construction costs and expected in-service date.IGCC. The ultimate outcome of this matter cannot be determined at this time; however, it is not expected to have a material impact on the financial statements of Southern Company.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Company in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Company in Item 7 of the Form 10-K for a complete discussion of Southern Company's critical accounting policies and estimates related to Electric Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, Goodwill and Other Intangible Assets, Derivatives and Hedging Activities, and Contingent Obligations.
Kemper IGCC Rate Recovery
For periods prior to the second quarter 2017, significant accounting estimates included Kemper IGCC estimated construction costs, project completion date, and rate recovery. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "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-upRecovery" of Southern Company in Item 7 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.Form 10-K for additional information. 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 $2.63 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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
potential improvement projects that ultimately mayPower recorded total pre-tax charges to income related to the Kemper IGCC of $428 million ($264 million after tax) in 2016, $365 million ($226 million after tax) in 2015, $868 million ($536 million after tax) in 2014, and $1.2 billion ($729 million after tax) in prior years.
As a result of the Mississippi PSC's June 21, 2017 stated intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be completed subsequent to placingoperated as a natural gas plant rather than an IGCC plant, as well as Mississippi Power's June 28, 2017 suspension of the remainderoperation and start-up of the gasifier portion of the Kemper IGCC, in service. If completed, such improvement projects would be expected to enhance plant performance, safety, and/or operations. The related potentialthe estimated construction costs have yet to be fully evaluated, have not been included inand project completion date are no longer considered significant accounting estimates. Significant accounting estimates for the current cost estimates,June 30, 2017 financial statements presented herein include the overall assessment of rate recovery for the Kemper County energy facility and may be subject to the $2.88 billion cost cap. In subsequent periods, any further changes in the estimated costs for the potential cancellation of the Kemper IGCC.
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the $2.88 billion cost cap, netMississippi PSC's jurisdiction, including the potential resolution of the Initial DOE Grants and excludingmatters addressed in the Cost Cap Exceptions, will be reflected in Southern Company's statements of income and these changes could be material.
Any extensionKemper Settlement Order, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the in-service date beyond December 31, 2016gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs currently estimated at approximately $100 million to result in additional base costs$200 million are expected to be incurred.
As of June 30, 2017, Mississippi Power has recorded a total of approximately $25 million to $35 million per month,$1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which $0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes maintaining necessary levelscosts in excess of start-up labor, materials, and fuel,the original 2010 estimate for the combined cycle portion of the facility, as well as operational resources requiredthe 15% that was previously contracted to execute start-upSMEPA. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and commissioning activities. However, additional costs mayexpects them to be required for remediation of any further equipment and/or design issues identified. Any extension ofrecovered through rates consistent with the in-service date with respect toMississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC beyond December 31, 2016 would also increase costsSettlement Docket proceedings.
In the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $5.96 billion ($3.94 billion after tax) through June 30, 2017. Mississippi Power recorded total pre-tax charges to income for the Cost Cap Exceptions, which are not subject toestimated probable losses on 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 placedof $3.0 billion ($2.1 billion after tax) and $81 million ($50 million after tax) in servicethe second quarter 2017 and consultingthe second quarter 2016, respectively, and legal feestotal pre-tax charges of approximately $3$3.1 billion ($2.2 billion after tax) and $134 million per month.($83 million after tax) year-to-date in 2017 and 2016, respectively.
Given the significant judgment involved in estimating the future costs to complete construction and start-up,cancel the project completion date,gasifier portion of the Kemper IGCC, the ultimate rate recovery for the Kemper IGCC, including the $0.5 billion of combined cycle-related costs not yet in rates, 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.
Recently Issued Accounting Standards
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
Goodwill and Other Intangible Assets
While Southern Company accounts for acquisitions using the acquisition methodexpects most of accounting, which requires the assets acquired and liabilities assumedits revenue to be recorded at the date of acquisition at their respective estimated fair values. Southern Company recognizes goodwill as of the acquisition date, as a residual over the fair values of the identifiable net assets acquired. Goodwill will be tested for impairment on an annual basisincluded in the fourth quarterscope of the year as well as on an interim basis as events and changes in circumstances occur. Primarily as a resultASC 606, it has not fully completed its evaluation of the acquisitionsall revenue arrangements. The majority of Southern Company Gas and PowerSecure in 2016, goodwill totaled approximately $6.2 billion at September 30, 2016.
Definite-lived intangible assets acquired are amortized over the estimated useful lives of the respective assetsCompany's revenue, including energy provided to reflect the pattern in which the economic benefits of the intangible assets are consumed. Whenever eventscustomers, is from tariff offerings that provide electricity or changes in circumstances indicate that the carrying amount of the intangible assets may not be recoverable, the intangible assets will be reviewed for impairment. Primarily asnatural gas without a result of the acquisitions of Southern Company Gas and PowerSecure in 2016, other intangible assets, net of amortization totaled approximately $0.9 billion at September 30, 2016.
The judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, as well as asset lives, can significantly impact Southern Company's results of operations. Fair values and useful lives are determined based on, among other factors, the expected future period of benefit of the asset, the various characteristics of the asset, and projected cash flows. As the determination of an asset's fair value and useful life involves management making certain estimates and because these estimates form the basis for the determination of whether or not an impairment charge should be recorded, Southern Company considers these estimates to be critical accounting estimates.
See Note (A) to the Condensed Financial Statements under "Goodwill and Other Intangible Assets" herein for additional information regarding Southern Company's goodwill and other intangible assets as of September 30, 2016 and Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information related to Southern Company's recent acquisitions.defined
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Derivativescontractual term, as well as longer-term contractual commitments, including PPAs and Hedging Activitiesnon-derivative natural gas asset management and optimization arrangements. Southern Company expects the adoption of ASC 606 will not result in a significant shift from the current timing of revenue recognition for such transactions.
Derivative instrumentsSouthern Company's ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements, such as certain PPAs, energy-related derivatives, and alternative revenue programs, are recordedexcluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Southern Company's financial statements. In addition, the balance sheets as either assets or liabilities measured at their fair value, unlesspower and utilities industry continues to evaluate other specific industry issues, including the transactions qualify for the normal purchases or normal sales scope exception and are instead subjectapplicability of ASC 606 to traditional accrual accounting. For those transactions that docontributions in aid of construction (CIAC). Although final implementation guidance has 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 resultsbeen issued, Southern Company expects CIAC to be out of the hedged item in the income statement in the casescope of a fair value hedge, or gainsASC 606.
The new standard is effective for interim and losses are deferred in OCI until the hedged transaction occurs in the case of a cash flow hedge. Certain subsidiaries ofannual reporting periods beginning after December 15, 2017. 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 asintends to use the underlying fuel is used in operations and ultimately recovered through billings to customers.
modified retrospective method of adoption effective January 1, 2018. Southern Company uses derivative instrumentshas also elected to reduceutilize practical expedients which allow it to apply the impactstandard 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 theopen contracts at the reportingdate of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. To determineUnder the fair valuemodified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the derivative instruments,adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Southern Company's financial statements, Southern Company utilizes market data or assumptionswill continue to evaluate the requirements, as well as any additional clarifying guidance that market participants would use in pricing the derivative asset or liability, including assumptions about risk and the risks inherent in the inputs of the valuation technique.
Southern Company classifies derivative assets and liabilities based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The determination of the fair value of the derivative instruments incorporates various factors required under the guidance. These factors include:
the creditworthiness of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit);
events specific to a given counterparty; and
the impact of Southern Company's nonperformance risk on its liabilities.
Given the assumptions used in pricing the derivative asset or liability, Southern Company considers the valuation of derivative assets and liabilities a critical accounting estimate. See "Quantitative and Qualitative Disclosures About Market Risk" in Item 3 herein for more information.
Recently Issued Accounting Standardsbe issued.
On February 25, 2016,January 26, 2017, the FASB issued ASU No. 2016-02,2017-04, Leases(Topic 842)Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2016-02)2017-04). ASU 2016-022017-04 removes the requirement to compare the implied fair value of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for annual and interim periods beginning on or after December 15, 2019, and early adoption is permitted on testing dates after January 1, 2017.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires lesseesthat an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to recognize onbe separately presented in the balance sheet a lease liability and a right-of-use assetincome statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all leases.cost components remain eligible for capitalization under FERC regulations. ASU 2016-02 also changes2017-07 will be applied retrospectively for the recognition, measurement, and presentation of expense associated with leasesthe service cost component and provides clarification regarding the identification of certainother components of contracts that would representnet periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for existing leveraged leases.prospective basis. ASU 2016-022017-07 is effective for fiscal yearsannual periods beginning after December 15, 2018, with early adoption permitted.2017, including interim periods within those annual periods. Southern Company is currently evaluating the new standardstandard. The presentation changes required for net periodic pension and has not yet determined its ultimate impact; however,postretirement benefit costs will result in a decrease in Southern Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2016-022017-07 is not expected to have a significantmaterial 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 stockfinancial statements.
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 2016. The adoption is not expected to 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 SeptemberJune 30, 2016. Through September 30, 2016, Southern Company has incurred non-recoverable cash expenditures of $2.42 billion and is expected to incur approximately $0.21 billion in additional non-recoverable cash expenditures through completion of the construction and start-up of the Kemper IGCC, which includes certain post-in-service costs expected to be subject to the cost cap.2017. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $4.3$2.7 billion for the first ninesix months of 2016, a decrease2017, an increase of $0.8$0.6 billion from the corresponding period in 2015.2016. The decreaseincrease in net cash provided from operating activities was primarily due to $1.2 billion of net cash provided from operating activities of Southern Company Gas, which was acquired on July 1, 2016, partially offset by the timing of vendor payments and an increase in unutilized ITCs and PTCs.under-recovered fuel costs. Net cash used for investing activities totaled $16.6$4.9 billion for the first ninesix months of 20162017 primarily due to the closing of the Merger, the construction oftraditional electric generation, transmission, and distribution facilities andoperating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities, capital expenditures for Southern Company Gas' infrastructure replacement programs, and Southern Power's acquisitions and construction ofpayments for renewable facilities.acquisitions. Net cash provided from financing activities totaled $13.6$1.6 billion for the first ninesix months of 20162017 primarily due to issuances of long-term debt and common stock associated with financing and completing the Merger and Southern Company Gas' investment in SNG,short-term debt, partially offset by redemptions of long-term debt and common stock dividend payments. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first ninesix months of 20162017 include an increase of $14.4$1.8 billion in total property, plant, and equipment in service, net of depreciation primarily related to the inclusiontraditional electric operating companies' installation of Southern Company Gas as a result of the Merger, constructionequipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities; an increase of $6.2 billion in goodwill related to the acquisitions offacilities, Southern Company GasGas' infrastructure replacement programs, and PowerSecure; an increaseSouthern Power's renewable acquisitions; a decrease of $1.5 billion in equity investments in unconsolidated subsidiariesCWIP primarily related to Southern Company Gas' investment in SNG; increasesthe estimated probable losses on the Kemper IGCC; a decrease of $1.5$0.5 billion in other regulatory assets, deferredcash and $0.8 billion in AROscash equivalents primarily related to changes in ash pond closure strategy principally for Georgiaacquisition payments at Southern Power; increasesa decrease of $16.9 billion in long-term debt and $4.0$1.4 billion in total common stockholder's equity primarily associated with financing and completing the Merger and Southern Company Gas' investment in SNG; and increases of $1.9 billion in accumulated deferred income taxes and $1.6 billion in other cost of removal obligations primarily related to the inclusionestimated probable losses on the Kemper IGCC, partially offset by the issuance of additional shares of common stock; an increase of $1.3 billion in long-term debt (excluding amounts due within a year) to fund the Southern Company Gas as a resultsystem's continuous construction programs and for general corporate purposes; and an increase of the Merger. See Notes (A) and (I)$1.0 billion in notes payable primarily due to the Condensed Financial Statements herein under "Asset Retirement Obligations" and "Southern Company," respectively,issuances of short-term bank debt for additional information.general corporate purposes.
At the end of the thirdsecond quarter 2016,2017, the market price of Southern Company's common stock was $51.30$47.88 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $25.05$23.38 per share, representing a market-to-book ratio of 205%, compared to $46.79, $22.59,$49.19, $25.00, and 207%197%, respectively, at the end of 2015.2016. Southern Company's common stock dividend for the thirdsecond quarter 20162017 was $0.560$0.58 per share compared to $0.5425$0.56 per share in the thirdsecond quarter 2015.2016.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company in Item 7 of the Form 10-K for a
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, pipeline charges, storage capacity, and gas supply, asset management agreements, standby letters of credit and performance/surety bonds, trust funding requirements, and unrecognized tax benefits. Subsequent to September 30, 2016, Mississippi Power repaid at maturity $300 million aggregate principal amount of its Series 2011A 2.35% Senior Notes due October 15, 2016 and Southern Company Gas repaid at maturity $120 million aggregate principal amount of Series A Floating Rate Senior Notes due October 27, 2016. An additional $1.8Approximately $3.0 billion will be required through SeptemberJune 30, 20172018 to fund maturities of long-term debt. During the nine months ended September 30, 2016, and subsequent to that date, Southern Power entered into new long-term service agreements, which begin between 2017 and 2020 and result in additional future commitments totaling approximately $927 million. See "Sources of Capital" herein for additional information.
The Southern Company system's construction program is currently estimated to total $10.2 billion for 2016, $8.9 billion for 2017, $8.2 billion for 2018, $7.6 billion for 2019, $7.3 billion for 2020, and $6.6 billion for 2021. These amounts include expenditures
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; state regulatory agency approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Additionally, planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power's ability to execute its growth strategy. See Note 12 to the financial statements of Southern Company under "Southern Power" in Item 8 of the Form 10-K and Note (I) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding Southern Power's plant acquisitions. See Note 3 to the financial statements of Southern Company under "Retail Regulatory"Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for information regarding additional factors that may impact construction expenditures.expenditures, including Georgia Power's preliminary cost-to-complete and cancellation cost assessments for Plant Vogtle Units 3 and 4.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
As a result of closing the Merger, the funding requirements of the Southern Company system include the contractual obligations of Southern Company Gas. The following table details the amounts related to Southern Company Gas as of September 30, 2016:
|
| | | | | | | | | | | | | | | | | | | |
| | 2016 | | 2017- 2018 | | 2019- 2020 | | After 2020 | | Total |
| | (in millions) |
Long-term debt(a) — | | | | | | | | | |
| Principal | $ | 120 |
| | $ | 177 |
| | $ | 350 |
| | $ | 4,185 |
| | $ | 4,832 |
|
| Interest | 48 |
| | 412 |
| | 382 |
| | 2,641 |
| | 3,483 |
|
Pipeline charges, storage capacity, and gas supply(b) | 308 |
| | 1,350 |
| | 806 |
| | 2,913 |
| | 5,377 |
|
Operating leases(c) | 6 |
| | 44 |
| | 31 |
| | 52 |
| | 133 |
|
Asset management agreements(d) | 2 |
| | 15 |
| | 2 |
| | — |
| | 19 |
|
Standby letters of credit, performance/surety bonds(e) | 33 |
| | 51 |
| | — |
| | — |
| | 84 |
|
Financial derivative obligations(f) | 195 |
| | 211 |
| | 21 |
| | 2 |
| | 429 |
|
Pension and other postretirement benefit plans(g) | 5 |
| | 44 |
| | — |
| | — |
| | 49 |
|
Purchase commitments — | | | | | | | | | |
Capital(h) | 401 |
| | 3,540 |
| | 3,058 |
| | 1,221 |
| | 8,220 |
|
Other(i) | 11 |
| | 53 |
| | — |
| | — |
| | 64 |
|
| Total | $ | 1,129 |
| | $ | 5,897 |
| | $ | 4,650 |
| | $ | 11,014 |
| | $ | 22,690 |
|
| |
(a) | Amounts are reflected based on final maturity dates. Variable rate interest obligations are estimated based on rates as of September 30, 2016. |
| |
(b) | Includes charges recoverable through a natural gas cost recovery mechanism or alternatively billed to marketers and demand charges associated with wholesale gas services. |
| |
(c) | Certain operating leases have provisions for step rent or escalation payments and certain lease concessions are accounted for by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms. |
| |
(d) | Represents fixed-fee minimum payments for asset management agreements at wholesale gas services. |
| |
(e) | Guarantees are provided to certain municipalities and other agencies and certain natural gas suppliers of SouthStar Energy Services, LLC (SouthStar) in support of payment obligations. |
| |
(f) | Includes derivative liabilities related to energy-related derivatives. |
| |
(g) | Estimated benefit payments for Southern Company Gas' retirement benefit plans are provided through 2018. No mandatory contributions to the plans are anticipated during this period. |
| |
(h) | Estimated capital expenditures are provided through 2021. |
| |
(i) | Primarily consists of contractual environmental remediation liabilities that are primarily recoverable through base rates or rate rider mechanisms. |
Sources of Capital
Southern Company intends to meet its future capital needs through operating cash flows, short-term debt, term loans, and external security issuances. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings. The amount and timing of additional equity capital and debt issuances in 2016,2017, as well as in subsequent years, will be contingent on Southern Company's investment opportunities and the Southern Company system's capital requirements.requirements and will depend upon prevailing market conditions and other factors. See "Capital Requirements and Contractual Obligations" herein for additional information.
Except as described herein, the traditional electric operating companies, Southern Power, and Southern Company Gas plan to obtain the funds required for construction and other purposes from operating cash flows, external security issuances, term loans, short-term borrowings, and equity contributions or loans from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS –
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Company in Item 7 of the Form 10-K for additional information.
In addition, Georgia Power may make borrowings throughhas entered into a loan guarantee agreement (Loan Guarantee Agreement) between Georgia Power andwith the DOE, under which the proceeds of whichborrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4. Under the Loan Guarantee Agreement, the DOE agreed to guarantee borrowings of up to $3.46 billion (not to exceed 70% of Eligible Project Costs) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. Eligible Project Costs incurred through SeptemberJune 30, 20162017 would allow for borrowings of up to $2.6$3.1 billion under the FFB Credit Facility, of which Georgia Power has borrowed $2.5 billion.$2.6 billion; however, on July 27, 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement (LGA Amendment) to clarify the operation of the Loan Guarantee Agreement pending Georgia Power's completion of its comprehensive schedule, cost-to-complete, and cancellation cost assessments (Cost Assessments) for Plant Vogtle Units 3 and 4. Under the terms of the LGA Amendment, Georgia Power will not request any advances under the Loan Guarantee Agreement unless and until such time as Georgia Power has completed the Cost Assessments and made a determination to continue construction of Plant Vogtle Units 3 and 4 and satisfied certain other conditions related to continuing construction. See Note 6 to the financial statements of Southern Company under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information regarding the Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and additional conditions to borrowing. Also
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
see Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
Mississippi Power received $245 million of Initial DOE Grants in prior years that were used for the construction of the Kemper IGCC. An additional $25 million of grants from the DOE is expected to be received for commercial operation of the Kemper IGCC. 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 Southern Company 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.
As of SeptemberJune 30, 2016,2017, Southern Company's current liabilities exceeded current assets by $3.9 billion due to notes payable of $3.3 billion (comprised of approximately $0.9 billion primarily due toat the parent company, $1.2 billion at Georgia Power, $0.1 billion at Gulf Power, $0.4 billion at Southern Power, and $0.6 billion at Southern Company Gas) and long-term debt that is due within one year of $2.3$3.0 billion including(comprised of approximately $0.8$0.4 billion at the parent company, $0.2$0.4 billion at Alabama Power, $0.5$0.3 billion at Georgia Power, $0.2 billion at Gulf Power, $0.3$1.0 billion at Mississippi Power, $0.1and $0.9 billion at Southern Power, and $0.1 billion at Southern Company Gas.Power). To meet short-term cash needs and contingencies, the Southern Company system has substantial cash flow from operating activities and access to capital markets and financial institutions. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas intend to utilize operating cash flows, as well as commercial paper, lines of credit, bank notes, and securities issuances, as market conditions permit, as well as, under certain circumstances for the traditional electric operating companies, Southern Power, and Southern Company Gas, equity contributions and/or loans from Southern Company to meet their short-term capital needs. In addition, Georgia Power expects to utilize borrowings through the FFB Credit Facility as an additional source of long-term borrowed funds.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
At SeptemberJune 30, 2016,2017, Southern Company and its subsidiaries had approximately $2.7$1.4 billion of cash and cash equivalents. Committed credit arrangements with banks at SeptemberJune 30, 20162017 were as follows:
| | | | Expires | | | | Executable Term Loans | | Due Within One Year | Expires | | | | Executable Term Loans | | Expires Within One Year |
| Company | 2016 | 2017 | 2018 | 2020 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out | 2017 | 2018 | 2019 | 2020 | 2022 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out |
| | (in millions) | | (in millions) | | (in millions) | | (in millions) | (in millions) |
Southern Company(a) | $ | — |
| $ | — |
| $ | 1,000 |
| $ | 1,250 |
| | $ | 2,250 |
| | $ | 2,250 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 2,000 |
| | $ | 2,000 |
| | $ | 2,000 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Alabama Power | — |
| 35 |
| 500 |
| 800 |
| | 1,335 |
| | 1,335 |
| | — |
| | — |
| | — |
| | 35 |
| 3 |
| 532 |
| — |
| — |
| 800 |
| | 1,335 |
| | 1,335 |
| | — |
| | — |
| | — |
| | 35 |
|
| Georgia Power | — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,732 |
| | — |
| | — |
| | — |
| | — |
| — |
| — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,732 |
| | — |
| | — |
| | — |
| | — |
|
| Gulf Power | 50 |
| 65 |
| 165 |
| — |
| | 280 |
| | 280 |
| | 45 |
| | — |
| | 45 |
| | 70 |
| 30 |
| 195 |
| 25 |
| 30 |
| — |
| | 280 |
| | 280 |
| | 45 |
| | — |
| | — |
| | 40 |
|
| Mississippi Power | 100 |
| 75 |
| — |
| — |
| | 175 |
| | 150 |
| | — |
| | 15 |
| | 15 |
| | 160 |
| 113 |
| — |
| — |
| — |
| — |
| | 113 |
| | 100 |
| | — |
| | 13 |
| | 13 |
| | 100 |
|
Southern Power Company(b) | — |
| — |
| — |
| 600 |
| | 600 |
| | 532 |
| | — |
| | — |
| | — |
| | — |
| — |
| — |
| — |
| — |
| 750 |
| | 750 |
| | 675 |
| | — |
| | — |
| | — |
| | — |
|
Southern Company Gas(c)(b) | — |
| 75 |
| 1,925 |
| — |
| | 2,000 |
| | 1,947 |
| | — |
| | — |
| | — |
| | — |
| — |
| — |
| — |
| — |
| 1,900 |
| | 1,900 |
| | 1,849 |
| | — |
| | — |
| | — |
| | — |
|
| Other | — |
| 55 |
| — |
| — |
| | 55 |
| | 55 |
| | 20 |
| | — |
| | 20 |
| | 35 |
| 10 |
| 30 |
| — |
| — |
| — |
| | 40 |
| | 40 |
| | 20 |
| | — |
| | 20 |
| | 20 |
|
| Southern Company Consolidated | $ | 150 |
| $ | 305 |
| $ | 3,590 |
| $ | 4,400 |
| | $ | 8,445 |
| | $ | 8,281 |
| | $ | 65 |
| | $ | 15 |
| | $ | 80 |
| | $ | 300 |
| $ | 156 |
| $ | 757 |
| $ | 25 |
| $ | 30 |
| $ | 7,200 |
| | $ | 8,168 |
| | $ | 8,011 |
| | $ | 65 |
| | $ | 13 |
| | $ | 33 |
| | $ | 195 |
|
| |
| (a) | Represents the Southern Company parent entity. |
| |
| (b) | Excludes credit agreements (Project Credit Facilities) assumed with the acquisition of certain solar facilities, which are non-recourse to Southern Power Company, the proceeds of which are being used to finance project costs related to such solar facilities currently under construction. See Note (I) to the Condensed Financial Statements under "Southern Power" herein for additional information.
|
| |
(c) | Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.3$1.2 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $700 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. |
See Note 6 to the financial statements of Southern Company under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
OnAs reflected in the table above, in May 24, 2016,2017, Southern Company, Alabama Power, Georgia Power, and Southern Power Company each amended certain of their multi-year credit arrangements, which, among other things, extended the $8.1maturity dates from 2020 to 2022. Southern Company and Southern Power Company increased their borrowing ability under these arrangements to $2.0 billion Bridge Agreementfrom $1.25 billion and to provide Merger financing,$750 million from $600 million, respectively. Southern Company also terminated its $1.0 billion facility maturing in 2018. Also in May 2017, Southern Company Gas Capital and Nicor Gas terminated their existing credit arrangements for $1.3 billion and $700 million, respectively, which were to the extent necessary, was terminated.mature in 2017 and 2018, and entered into a new multi-year credit arrangement currently allocated for $1.2 billion and $700 million, respectively, with a maturity date of 2022.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Most of these bank credit arrangements, as well as the term loan arrangements of Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Power Company, contain covenants that limit debt levels and contain cross accelerationcross-acceleration or cross defaultcross-default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of the individual company. Such cross defaultcross-default provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness or guarantee obligations over a specified threshold. Such cross accelerationcross-acceleration provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness, the payment of which was then accelerated. At June 30, 2017, Southern Company, the traditional electric operating companies, Southern Power Company, and Southern Company Gas, are currentlyand Nicor Gas were in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the unused credit with banks is allocated to provide liquidity support to the traditional electric operating companies' pollution control revenue bonds of the traditional electric operating companies and the commercial paper programs.programs of Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas. The amount of variable rate pollution control revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of SeptemberJune 30, 20162017 was approximately $1.9$1.6 billion. In June 2017, Georgia Power remarketed $318 million of variable rate pollution control bonds in index rate modes, reducing the liquidity support utilized under Georgia Power's bank credit arrangement. In addition, at SeptemberJune 30, 2016,2017, the traditional electric operating companies had approximately $358$626 million of fixed rate pollution control revenue bonds outstanding that were required to be reofferedremarketed within the 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 (other than Mississippi Power), Southern Power andCompany, Southern Company Gas, and Nicor Gas make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas may also borrow through various other arrangements with banks. Short-term borrowings are included in notes payable in the balance sheets.
Details of short-term borrowings were as follows:
| | | | | Short-term Debt at September 30, 2016 | | Short-term Debt During the Period(*) | | Short-term Debt at June 30, 2017 | | Short-term Debt During the Period(*) |
| | | Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding | | Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) | | | | (in millions) | | (in millions) | | | | (in millions) | | | | (in millions) |
| Commercial paper | | $ | 717 |
| | 0.7 | % | | $ | 756 |
| | 0.7 | % | | $ | 1,499 |
| | $ | 2,257 |
| | 1.5 | % | | $ | 2,519 |
| | 1.3 | % | | $ | 2,946 |
|
| Short-term bank debt | | 125 |
| | 1.5 | % | | 125 |
| | 1.4 | % | | 127 |
| | 1,017 |
| | 2.0 | % | | 321 |
| | 2.0 | % | | 1,017 |
|
| Total | | $ | 842 |
| | 0.8 | % | | $ | 881 |
| | 0.8 | % | | | | $ | 3,274 |
| | 1.7 | % | | $ | 2,840 |
| | 1.4 | % | | |
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended SeptemberJune 30, 2016.2017. |
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 term loans, and operating cash flows.
Credit Rating Risk
At SeptemberJune 30, 2016,2017, Southern Company and its subsidiaries did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain subsidiaries to BBB and/or Baa2 or below. These contracts are for physical electricity and natural gas purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, interest rate management, and construction of new generation at Plant Vogtle Units 3 and 4.
The maximum potential collateral requirements under these contracts at September 30, 2016 were as follows:
|
| | | |
| Credit Ratings | Maximum Potential
Collateral
Requirements |
| | (in millions) |
| At BBB and/or Baa2 | $ | 31 |
|
| At BBB- and/or Baa3 | $ | 665 |
|
| Below BBB- and/or Baa3 | $ | 2,570 |
|
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
transmission, interest rate management, and foreign currency risk management, and, at June 30, 2017, included contracts related to the construction of new generation at Plant Vogtle Units 3 and 4.
The maximum potential collateral requirements under these contracts at June 30, 2017 were as follows:
|
| | | |
| Credit Ratings | Maximum Potential
Collateral
Requirements |
| | (in millions) |
| At BBB and/or Baa2 | $ | 39 |
|
| At BBB- and/or Baa3 | $ | 642 |
|
At BB+ and/or Ba1(*) | $ | 2,555 |
|
| |
| (*) | Any additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $38 million. |
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Company and its subsidiaries to access capital markets, and would be likely to impact the cost at which they do so.
On May 12, 2016, FitchMarch 1, 2017, Moody's downgraded the senior unsecured long-term debt rating of Southern Company to A- from A and revised the ratings outlook from negative to stable. Fitch also downgraded the senior unsecured long-term debt rating of Mississippi Power to BBB+Ba1 from A- and revised the ratings outlook from negative to stable.Baa3.
On May 13, 2016,March 20, 2017, Moody's downgradedrevised its rating outlook for Georgia Power from stable to negative.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including the senior unsecured long-term debt ratingtraditional electric operating companies, Southern Power, Southern Company Gas, Southern Company Gas Capital, and Nicor Gas) from stable to negative.
On March 30, 2017, Fitch placed the ratings of Southern Company, to Baa2 from Baa1Georgia Power, and revisedMississippi Power on rating watch negative.
On June 22, 2017, Moody's placed 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 positive to negative.of Mississippi Power on review for downgrade.
Financing Activities
On May 11, 2016, Southern Company issued 18.3 million shares of common stock in an underwritten offering for an aggregate purchase price of approximately $889 million. Of the 18.3 million shares, approximately 2.6 million were issued from treasury and the remainder were newly issued shares. The proceeds were used to fund a portion of the consideration for the Merger and for other general corporate purposes.
On August 19, 2016, Southern Company issued 32.5 million shares of common stock in an underwritten offering for an aggregate purchase price of approximately $1.6 billion. The proceeds were used to fund a portion of the purchase price for the SNG investment and related transaction costs and for other general corporate purposes.
In addition, duringDuring the first ninesix months of 2016,2017, Southern Company issued approximately 17.57.8 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $782$352 million.
In addition, during the second quarter 2017, Southern Company issued approximately 1.3 million shares of common stock through at-the-market issuances pursuant to sales agency agreements related to Southern Company's continuous equity offering program and received cash proceeds of approximately $65 million, net of $553,000 in fees and commissions.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first ninesix months of 2016:2017:
| | | Company | Senior Note Issuances | | Senior Note Maturities and Redemptions | | Revenue Bond Maturities, Redemptions, and Repurchases | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(a) | Senior Note Issuances | | Senior Note Maturities and Redemptions | | Revenue Bond Maturities, Redemptions, and Repurchases | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(a) |
| | (in millions) | (in millions) |
Southern Company(b) | $ | 8,500 |
| | $ | 500 |
| | $ | — |
| | $ | 800 |
| | $ | — |
| $ | 300 |
| | $ | — |
| | $ | — |
| | $ | 500 |
| | $ | 400 |
|
| Alabama Power | 400 |
| | 200 |
| | — |
| | 45 |
| | — |
| 550 |
| | 200 |
| | — |
| | — |
| | — |
|
| Georgia Power | 650 |
| | 700 |
| | 4 |
| | 300 |
| | 5 |
| 850 |
| | 450 |
| | 27 |
| | — |
| | 3 |
|
| Gulf Power | — |
| | 125 |
| | — |
| | 2 |
| | — |
| 300 |
| | 85 |
| | — |
| | 6 |
| | — |
|
| Mississippi Power | — |
| | — |
| | — |
| | 1,100 |
| | 652 |
| — |
| | — |
| | — |
| | 40 |
| | 893 |
|
| Southern Power | 1,531 |
| | — |
| | — |
| | 63 |
| | 84 |
| — |
| | — |
| | — |
| | 3 |
| | 3 |
|
Southern Company Gas(c) | 900 |
| | 300 |
| | — |
| | — |
| | — |
| 450 |
| | — |
| | — |
| | — |
| | — |
|
| Other | — |
| | — |
| | — |
| | — |
| | 60 |
| — |
| | — |
| | — |
| | — |
| | 8 |
|
Elimination(d) | — |
| | — |
| | — |
| | (200 | ) | | (225 | ) | — |
| | — |
| | — |
| | (40 | ) | | (591 | ) |
| Southern Company Consolidated | $ | 11,981 |
| | $ | 1,825 |
| | $ | 4 |
| | $ | 2,110 |
| | $ | 576 |
| $ | 2,450 |
| | $ | 735 |
| | $ | 27 |
| | $ | 509 |
| | $ | 716 |
|
| |
| (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 the Southern Company Gas.Gas parent entity. |
| |
| (d) | Intercompany loans from Southern Company to Mississippi Power eliminated in Southern Company's Consolidated Financial Statements. |
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In March 2017, Southern Company repaid at maturity a $400 million 18-month floating rate bank loan.
In February 2016, Southern Company entered into $700 million notional amount of forward-starting interest rate swaps to hedge exposure to interest rate changes related to anticipated debt issuances. These interest rate swaps were settled in May 2016.
In May 2016,June 2017, Southern Company issued the following series of senior notes for an aggregate principal amount of $8.5 billion:
$0.5 billion of 1.55% Senior Notes due July 1, 2018;
$1.0 billion of 1.85% Senior Notes due July 1, 2019;
$1.5 billion of 2.35% Senior Notes due July 1, 2021;
$1.25 billion of 2.95% Senior Notes due July 1, 2023;
$1.75 billion of 3.25% Senior Notes due July 1, 2026;
$0.5 billion of 4.25% Senior Notes due July 1, 2036; and
$2.0 billion of 4.40% Senior Notes due July 1, 2046.
The net proceeds were used to fund a portion of the consideration for the Merger and related transaction costs and for other general corporate purposes.
In September 2016, Southern Company issued $800$500 million aggregate principal amount of Series 2016A 5.25%2017A 5.325% Junior Subordinated Notes due October 1, 2076.June 21, 2057. The proceeds were used to repay short-term indebtedness that was incurred to repay at maturity $500and for other general corporate purposes.
Also in June 2017, Southern Company issued $300 million aggregate principal amount of Southern Company's Series 2011A 1.95%2017A Floating Rate Senior Notes due September 1, 201630, 2020, which bear interest at a floating rate based on three-month LIBOR. The proceeds were used to repay short-term indebtedness and for other general corporate purposes.
Also in June 2017, Southern Company entered into two $100 million aggregate principal amount floating rate bank term loan agreements, which mature on June 21, 2018 and June 29, 2018 and bear interest based on one-month LIBOR. The proceeds were used for working capital and 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.programs.
On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicateA portion of financial institutions for anthe proceeds of Gulf Power's senior note issuances was used in June 2017 to redeem 550,000 shares ($55 million aggregate amountliquidation amount) of $1.2 billion. Mississippi Power borrowed $900Gulf Power's 6.00% Series Preference Stock, 450,000 shares ($45 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 Mississippiaggregate liquidation amount) of Gulf Power's Series 2011A 2.35% Senior Notes due October 15, 2016. The term loan pursuant to this agreement matures on April 1, 20182007A 6.45% Preference Stock, and bears interest based on one-month LIBOR.500,000 shares ($50 million aggregate liquidation amount) of Gulf Power's Series 2013A 5.60% Preference Stock.
In May 2016,March 2017, Gulf Power entered into an 11-monthextended the maturity of a $100 million short-term floating rate bank loan bearing interest based on one-month LIBOR. This short-termLIBOR from April 2017 to October 2017 and subsequently repaid the loan was for $100 million aggregate principal amount and the proceeds were used to repay existing indebtedness and for working capital and other general corporate purposes.
Georgia Power's "Other Long-Term Debt Issuances" reflected in the table above include borrowings in June 2016 under the FFB Credit Facility in an aggregate principal amount of $300 million at a 2.571% interest rate through the final maturity date of February 20, 2044. The proceeds were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4.
During the nine months ended September 30, 2016, Southern Power's subsidiaries incurred an additional $691 million of short-term borrowings pursuant to the Project Credit Facilities at a weighted average interest rate of 2.05%. Furthermore, in connection with the acquisition of a solar facility, a subsidiary of Southern Power assumed a $217 million construction loan, which was fully repaid prior to September 30, 2016. In addition, on October 14, 2016, Southern Power repaid at maturity $246 million of Project Credit Facility debt.May 2017.
In June 2016, Southern2017, Georgia Power issued €600 millionentered into three floating rate bank loans in aggregate principal amountamounts of Series 2016A 1.00% Senior Notes due$50 million, $150 million, and $100 million, which mature on December 1, 2017, May 31, 2018, and 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. See28, 2018,
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 loanrespectively, 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 bearingbear interest based on one-month LIBOR due September 2017.LIBOR. Also in June 2017, Georgia Power borrowed $500 million pursuant to an uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Georgia Power and the bank from time to time and is payable on no less than 30 days' demand by the bank. The proceeds from these bank loans were used to repay a portion of Georgia Power's existing indebtedness and for working capital and other general corporate purposes.purposes, including Georgia Power's continuous construction program.
In September 2016, Southern CompanyJune 2017, Mississippi Power prepaid $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018.
Subsequent to June 30, 2017, Nicor Gas Capital issued $350agreed to issue $400 million aggregate principal amount of 2.45% Senior Notes due October 1, 2023 and $550First Mortgage Bonds in a private placement, $200 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 usedis expected to repay a $360 million promissory notebe issued to Southern Company for the purposein each 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,August 2017 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.November 2017.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company and its subsidiaries plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
PART I
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
Other thanDuring the changes resulting from the Merger discussed below, during the ninesix months ended SeptemberJune 30, 2016,2017, there were no material changes to Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, orand Southern Power's disclosures about market risk. For additional market risk disclosures relating to Gulf Power and Southern Company Gas, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Gulf Power and Southern Company Gas, respectively, herein. For an in-depth discussion of each registrant's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of each registrant in Item 7 of the Form 10-K and Note 1 to the financial statements of each registrant under "Financial Instruments," Note 11 to the financial statements of Southern Company, Alabama Power, and Georgia Power, Note 10 to the financial statements of Gulf Power, and Mississippi Power, and Southern Company Gas, and Note 9 to the financial statements of Southern Power in Item 8 of the Form 10-K. Also see Note (C) and Note (H) to the Condensed Financial Statements herein for information relating to derivative instruments.
As a result of closing the Merger, the Southern Company system's exposure to market risks includes Southern Company Gas. Southern Company Gas is exposed to market risks, primarily commodity price risk, interest rate risk, and weather risk. Due to various cost recovery mechanisms, the natural gas distribution utilities of Southern Company Gas that sell natural gas directly to their end-use customers have limited exposure to market volatility of natural gas prices. Certain natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs implemented per the guidelines of their respective state regulatory agencies to hedge the impact of market fluctuations in natural gas prices for customers. For the weather risk associated with Nicor Gas, Southern Company Gas has a corporate weather hedging program that utilizes weather derivatives to reduce the risk of lower operating margins potentially resulting from significantly warmer-than-normal weather. In addition, certain non-regulated operations routinely utilize various types of derivative instruments to economically hedge certain commodity price and weather risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and over-the-counter energy contracts, such as forward contracts, futures contracts, options contracts, and swap agreements. Some of these economic hedge activities may not qualify, or are not designated, for hedge accounting treatment. If there is a significant change in the underlying market prices or pricing assumptions Southern Company uses to price the derivative assets or liabilities, such changes may have a significant impact on Southern Company's financial position, results of operations, and cash flows.
Item 4. Controls and Procedures.
| |
| (a) | Evaluation of disclosure controls and procedures. |
As of the end of the period covered by this Quarterly Report on Form 10-Q, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern PowerCompany Gas conducted separate evaluations under the supervision and with the participation of each company's management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Sections 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended). Based upon these evaluations, the Chief Executive Officer and the Chief Financial Officer, in each case, concluded that the disclosure controls and procedures are effective.
| |
| (b) | Changes in internal controls over financial reporting. |
Other than the changes resulting from the Merger discussed below, thereThere have been no changes in Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, Southern Power's, or Southern Power'sCompany Gas' internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended) during the thirdsecond quarter 20162017 that have materially affected or are reasonably likely to materially affect Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, Southern Power's, or Southern Power'sCompany Gas' internal control over financial reporting.
Southern Company completed the Merger on July 1, 2016, with Southern Company Gas surviving the Merger as a wholly-owned, direct subsidiary of Southern Company. Southern Company is currently in the process of integrating Southern Company Gas' operations and conducting control reviews pursuant to Section 404 of the Sarbanes-Oxley
Act of 2002. See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information regarding the Merger.
ALABAMA POWER COMPANY
ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
| | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2016 | | 2015 | | 2016 | | 2015 | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | | | | | | | | |
| Retail revenues | $ | 1,629 |
| | $ | 1,558 |
| | $ | 4,139 |
| | $ | 4,151 |
| $ | 1,333 |
| | $ | 1,316 |
| | $ | 2,560 |
| | $ | 2,510 |
|
| Wholesale revenues, non-affiliates | 82 |
| | 65 |
| | 211 |
| | 188 |
| 68 |
| | 67 |
| | 133 |
| | 130 |
|
| Wholesale revenues, affiliates | 18 |
| | 20 |
| | 49 |
| | 55 |
| 32 |
| | 9 |
| | 65 |
| | 31 |
|
| Other revenues | 56 |
| | 52 |
| | 162 |
| | 157 |
| 51 |
| | 52 |
| | 108 |
| | 105 |
|
| Total operating revenues | 1,785 |
| | 1,695 |
| | 4,561 |
| | 4,551 |
| 1,484 |
| | 1,444 |
| | 2,866 |
| | 2,776 |
|
| Operating Expenses: | | | | | | | | | | | | | | |
| Fuel | 410 |
| | 408 |
| | 973 |
| | 1,061 |
| 303 |
| | 295 |
| | 601 |
| | 564 |
|
| Purchased power, non-affiliates | 63 |
| | 56 |
| | 139 |
| | 142 |
| 40 |
| | 40 |
| | 75 |
| | 76 |
|
| Purchased power, affiliates | 41 |
| | 51 |
| | 129 |
| | 153 |
| 34 |
| | 55 |
| | 62 |
| | 88 |
|
| Other operations and maintenance | 348 |
| | 371 |
| | 1,097 |
| | 1,140 |
| 375 |
| | 355 |
| | 743 |
| | 747 |
|
| Depreciation and amortization | 177 |
| | 163 |
| | 524 |
| | 481 |
| 183 |
| | 175 |
| | 364 |
| | 347 |
|
| Taxes other than income taxes | 96 |
| | 91 |
| | 286 |
| | 275 |
| 95 |
| | 94 |
| | 191 |
| | 191 |
|
| Total operating expenses | 1,135 |
| | 1,140 |
| | 3,148 |
| | 3,252 |
| 1,030 |
| | 1,014 |
| | 2,036 |
| | 2,013 |
|
| Operating Income | 650 |
| | 555 |
| | 1,413 |
| | 1,299 |
| 454 |
| | 430 |
| | 830 |
| | 763 |
|
| Other Income and (Expense): | | | | | | | | | | | | | | |
| Allowance for equity funds used during construction | 7 |
| | 14 |
| | 23 |
| | 43 |
| 8 |
| | 6 |
| | 16 |
| | 16 |
|
| Interest expense, net of amounts capitalized | (77 | ) | | (71 | ) | | (224 | ) | | (205 | ) | (77 | ) | | (74 | ) | | (153 | ) | | (147 | ) |
| Other income (expense), net | (5 | ) | | (7 | ) | | (16 | ) | | (24 | ) | 1 |
| | (4 | ) | | (4 | ) | | (11 | ) |
| Total other income and (expense) | (75 | ) | | (64 | ) | | (217 | ) | | (186 | ) | (68 | ) | | (72 | ) | | (141 | ) | | (142 | ) |
| Earnings Before Income Taxes | 575 |
| | 491 |
| | 1,196 |
| | 1,113 |
| 386 |
| | 358 |
| | 689 |
| | 621 |
|
| Income taxes | 221 |
| | 192 |
| | 466 |
| | 427 |
| 151 |
| | 140 |
| | 277 |
| | 242 |
|
| Net Income | 354 |
| | 299 |
| | 730 |
| | 686 |
| 235 |
| | 218 |
| | 412 |
| | 379 |
|
| Dividends on Preferred and Preference Stock | 4 |
| | 4 |
| | 13 |
| | 21 |
| 5 |
| | 5 |
| | 9 |
| | 9 |
|
| Net Income After Dividends on Preferred and Preference Stock | $ | 350 |
| | $ | 295 |
| | $ | 717 |
| | $ | 665 |
| $ | 230 |
| | $ | 213 |
| | $ | 403 |
| | $ | 370 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
| | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2016 | | 2015 | | 2016 | | 2015 | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Net Income | $ | 354 |
| | $ | 299 |
| | $ | 730 |
| | $ | 686 |
| $ | 235 |
| | $ | 218 |
| | $ | 412 |
| | $ | 379 |
|
| Other comprehensive income (loss): | | | | | | | | | | | | | | |
| Qualifying hedges: | | | | | | | | | | | | | | |
Changes in fair value, net of tax of $-, $(4), $(1), and $(4),
respectively | — |
| | (6 | ) | | (2 | ) | | (6 | ) | |
Reclassification adjustment for amounts included in net income,
net of tax of $1, $-, $2, and $1, respectively | 1 |
| | — |
| | 3 |
| | 1 |
| |
| Changes in fair value, net of tax of $-, $-, $-, and $(1), respectively | | — |
| | — |
| | — |
| | (2 | ) |
Reclassification adjustment for amounts included in net income,
net of tax of $1, $-, $1, and $1, respectively | | 1 |
| | 1 |
| | 2 |
| | 2 |
|
| Total other comprehensive income (loss) | 1 |
| | (6 | ) | | 1 |
| | (5 | ) | 1 |
| | 1 |
| | 2 |
| | — |
|
| Comprehensive Income | $ | 355 |
| | $ | 293 |
| | $ | 731 |
| | $ | 681 |
| $ | 236 |
| | $ | 219 |
| | $ | 414 |
| | $ | 379 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
| | | | For the Nine Months Ended September 30, | For the Six Months Ended June 30, |
| | 2016 | | 2015 | 2017 | | 2016 |
| | (in millions) | (in millions) |
| Operating Activities: | | | | | | |
| Net income | $ | 730 |
| | $ | 686 |
| $ | 412 |
| | $ | 379 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | | | | |
| Depreciation and amortization, total | 634 |
| | 585 |
| 442 |
| | 419 |
|
| Deferred income taxes | 267 |
| | 85 |
| 192 |
| | 175 |
|
| Allowance for equity funds used during construction | (23 | ) | | (43 | ) | |
| Pension, postretirement, and other employee benefits | | (24 | ) | | (23 | ) |
| Other, net | (23 | ) | | 23 |
| 4 |
| | (33 | ) |
| Changes in certain current assets and liabilities — | | | | | | |
| -Receivables | (4 | ) | | (160 | ) | (58 | ) | | 64 |
|
| -Fossil fuel stock | 18 |
| | 69 |
| 13 |
| | (32 | ) |
| -Other current assets | (46 | ) | | (10 | ) | (75 | ) | | (67 | ) |
| -Accounts payable | (113 | ) | | (106 | ) | (154 | ) | | (75 | ) |
| -Accrued taxes | 203 |
| | 371 |
| 52 |
| | 102 |
|
| -Accrued compensation | | (74 | ) | | (50 | ) |
| -Retail fuel cost over recovery | (104 | ) | | 81 |
| (65 | ) | | (60 | ) |
| -Other current liabilities | (4 | ) | | (2 | ) | 7 |
| | 8 |
|
| Net cash provided from operating activities | 1,535 |
| | 1,579 |
| 672 |
| | 807 |
|
| Investing Activities: | | | | | | |
| Property additions | (947 | ) | | (938 | ) | (738 | ) | | (645 | ) |
| Nuclear decommissioning trust fund purchases | (275 | ) | | (349 | ) | (117 | ) | | (200 | ) |
| Nuclear decommissioning trust fund sales | 275 |
| | 349 |
| 117 |
| | 200 |
|
| Cost of removal, net of salvage | (70 | ) | | (41 | ) | (54 | ) | | (51 | ) |
| Change in construction payables | (37 | ) | | (48 | ) | 48 |
| | (27 | ) |
| Other investing activities | (28 | ) | | (22 | ) | (15 | ) | | (18 | ) |
| Net cash used for investing activities | (1,082 | ) | | (1,049 | ) | (759 | ) | | (741 | ) |
| Financing Activities: | | | | | | |
| Proceeds — | | | | | | |
| Senior notes | 400 |
| | 975 |
| 550 |
| | 400 |
|
| Capital contributions from parent company | 253 |
| | 13 |
| 327 |
| | 237 |
|
| Pollution control revenue bonds | — |
| | 80 |
| |
| Other long-term debt | 45 |
| | — |
| — |
| | 45 |
|
| Redemptions and repurchases — |
|
| |
| |
| Preferred and preference stock | — |
| | (412 | ) | |
| Pollution control revenue bonds | — |
| | (134 | ) | |
| Senior notes | (200 | ) | | (250 | ) | |
| Redemptions — Senior notes | | (200 | ) | | (200 | ) |
| Payment of common stock dividends | (574 | ) | | (428 | ) | (357 | ) | | (382 | ) |
| Other financing activities | (15 | ) | | (38 | ) | (14 | ) | | (17 | ) |
| Net cash used for financing activities | (91 | ) | | (194 | ) | |
| Net cash provided from financing activities | | 306 |
| | 83 |
|
| Net Change in Cash and Cash Equivalents | 362 |
| | 336 |
| 219 |
| | 149 |
|
| Cash and Cash Equivalents at Beginning of Period | 194 |
| | 273 |
| 420 |
| | 194 |
|
| Cash and Cash Equivalents at End of Period | $ | 556 |
| | $ | 609 |
| $ | 639 |
| | $ | 343 |
|
| Supplemental Cash Flow Information: | | | | | | |
| Cash paid (received) during the period for — | | | | | | |
| Interest (net of $8 and $15 capitalized for 2016 and 2015, respectively) | $ | 215 |
| | $ | 192 |
| |
| Interest (net of $6 and $7 capitalized for 2017 and 2016, respectively) | | $ | 140 |
| | $ | 131 |
|
| Income taxes, net | (70 | ) | | 47 |
| 88 |
| | (122 | ) |
| Noncash transactions — Accrued property additions at end of period | 84 |
| | 88 |
| 132 |
| | 94 |
|
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 | | At June 30, 2017 | | At December 31, 2016 |
| | | (in millions) | | (in millions) |
| Current Assets: | | | | | | | | |
| Cash and cash equivalents | | $ | 556 |
| | $ | 194 |
| | $ | 639 |
| | $ | 420 |
|
| Receivables — | | | | | | | | |
| Customer accounts receivable | | 440 |
| | 332 |
| | 357 |
| | 348 |
|
| Unbilled revenues | | 155 |
| | 119 |
| | 161 |
| | 146 |
|
| Under recovered regulatory clause revenues | | 52 |
| | 43 |
| |
| Income taxes receivable, current | | — |
| | 142 |
| |
| Other accounts and notes receivable | | 43 |
| | 20 |
| | 36 |
| | 27 |
|
| Affiliated | | 30 |
| | 50 |
| | 33 |
| | 40 |
|
| Accumulated provision for uncollectible accounts | | (9 | ) | | (10 | ) | | (9 | ) | | (10 | ) |
| Fossil fuel stock | | 220 |
| | 239 |
| | 191 |
| | 205 |
|
| Materials and supplies | | 420 |
| | 398 |
| | 443 |
| | 435 |
|
| Vacation pay | | 66 |
| | 66 |
| |
| Prepaid expenses | | 56 |
| | 83 |
| | 86 |
| | 34 |
|
| Other regulatory assets, current | | 73 |
| | 115 |
| | 135 |
| | 149 |
|
| Other current assets | | 9 |
| | 10 |
| | 7 |
| | 11 |
|
| Total current assets | | 2,111 |
| | 1,801 |
| | 2,079 |
| | 1,805 |
|
| Property, Plant, and Equipment: | | | | | | | | |
| In service | | 25,800 |
| | 24,750 |
| | 26,466 |
| | 26,031 |
|
| Less accumulated provision for depreciation | | 9,018 |
| | 8,736 |
| |
| Less: Accumulated provision for depreciation | | | 9,354 |
| | 9,112 |
|
| Plant in service, net of depreciation | | 16,782 |
| | 16,014 |
| | 17,112 |
| | 16,919 |
|
| Nuclear fuel, at amortized cost | | 345 |
| | 363 |
| | 333 |
| | 336 |
|
| Construction work in progress | | 473 |
| | 801 |
| | 668 |
| | 491 |
|
| Total property, plant, and equipment | | 17,600 |
| | 17,178 |
| | 18,113 |
| | 17,746 |
|
| Other Property and Investments: | | | | | | | | |
| Equity investments in unconsolidated subsidiaries | | 67 |
| | 71 |
| | 67 |
| | 66 |
|
| Nuclear decommissioning trusts, at fair value | | 781 |
| | 737 |
| | 848 |
| | 792 |
|
| Miscellaneous property and investments | | 105 |
| | 96 |
| | 119 |
| | 112 |
|
| Total other property and investments | | 953 |
| | 904 |
| | 1,034 |
| | 970 |
|
| Deferred Charges and Other Assets: | | | | | | | | |
| Deferred charges related to income taxes | | 518 |
| | 522 |
| | 526 |
| | 525 |
|
| Deferred under recovered regulatory clause revenues | | 87 |
| | 99 |
| | 6 |
| | 150 |
|
| Other regulatory assets, deferred | | 1,070 |
| | 1,114 |
| | 1,209 |
| | 1,157 |
|
| Other deferred charges and assets | | 118 |
| | 103 |
| | 166 |
| | 163 |
|
| Total deferred charges and other assets | | 1,793 |
| | 1,838 |
| | 1,907 |
| | 1,995 |
|
| Total Assets | | $ | 22,457 |
| | $ | 21,721 |
| | $ | 23,133 |
| | $ | 22,516 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
| | | Liabilities and Stockholder's Equity | | At September 30, 2016 | | At December 31, 2015 | | At June 30, 2017 | | At December 31, 2016 |
| | | (in millions) | | (in millions) |
| Current Liabilities: | | | | | | | | |
| Securities due within one year | | $ | 236 |
| | $ | 200 |
| | $ | 361 |
| | $ | 561 |
|
| Accounts payable — | | | | | | | | |
| Affiliated | | 309 |
| | 278 |
| | 242 |
| | 297 |
|
| Other | | 233 |
| | 410 |
| | 317 |
| | 433 |
|
| Customer deposits | | 88 |
| | 88 |
| | 91 |
| | 88 |
|
| Accrued taxes — | | | | | | | | |
| Accrued income taxes | | 73 |
| | — |
| | 39 |
| | 45 |
|
| Other accrued taxes | | 125 |
| | 38 |
| | 97 |
| | 42 |
|
| Accrued interest | | 69 |
| | 73 |
| | 81 |
| | 78 |
|
| Accrued vacation pay | | 55 |
| | 55 |
| |
| Accrued compensation | | 97 |
| | 119 |
| | 125 |
| | 193 |
|
| Liabilities from risk management activities | | 10 |
| | 55 |
| |
| Other regulatory liabilities, current | | 1 |
| | 240 |
| | 15 |
| | 85 |
|
| Other current liabilities | | 65 |
| | 39 |
| | 63 |
| | 76 |
|
| Total current liabilities | | 1,361 |
| | 1,595 |
| | 1,431 |
| | 1,898 |
|
| Long-term Debt | | 6,859 |
| | 6,654 |
| | 7,082 |
| | 6,535 |
|
| Deferred Credits and Other Liabilities: | | | | | | | | |
| Accumulated deferred income taxes | | 4,505 |
| | 4,241 |
| | 4,842 |
| | 4,654 |
|
| Deferred credits related to income taxes | | 67 |
| | 70 |
| | 64 |
| | 65 |
|
| Accumulated deferred investment tax credits | | 112 |
| | 118 |
| |
| Accumulated deferred ITCs | | | 113 |
| | 110 |
|
| Employee benefit obligations | | 366 |
| | 388 |
| | 269 |
| | 300 |
|
| Asset retirement obligations | | 1,501 |
| | 1,448 |
| | 1,543 |
| | 1,503 |
|
| Other cost of removal obligations | | 695 |
| | 722 |
| | 648 |
| | 684 |
|
| Other regulatory liabilities, deferred | | 95 |
| | 136 |
| | 84 |
| | 100 |
|
| Deferred over recovered regulatory clause revenues | | 157 |
| | — |
| |
| Other deferred credits and liabilities | | 56 |
| | 76 |
| | 69 |
| | 63 |
|
| Total deferred credits and other liabilities | | 7,554 |
| | 7,199 |
| | 7,632 |
| | 7,479 |
|
| Total Liabilities | | 15,774 |
| | 15,448 |
| | 16,145 |
| | 15,912 |
|
| Redeemable Preferred Stock | | 85 |
| | 85 |
| | 85 |
| | 85 |
|
| Preference Stock | | 196 |
| | 196 |
| | 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 |
| | 1,222 |
| | 1,222 |
|
| Paid-in capital | | 2,607 |
| | 2,341 |
| | 2,950 |
| | 2,613 |
|
| Retained earnings | | 2,604 |
| | 2,461 |
| | 2,564 |
| | 2,518 |
|
| Accumulated other comprehensive loss | | (31 | ) | | (32 | ) | | (29 | ) | | (30 | ) |
| Total common stockholder's equity | | 6,402 |
| | 5,992 |
| | 6,707 |
| | 6,323 |
|
| Total Liabilities and Stockholder's Equity | | $ | 22,457 |
| | $ | 21,721 |
| | $ | 23,133 |
| | $ | 22,516 |
|
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
THIRDSECOND QUARTER 20162017 vs. THIRDSECOND QUARTER 20152016
AND
YEAR-TO-DATE 20162017 vs. YEAR-TO-DATE 20152016
OVERVIEW
Alabama Power operates as a vertically integrated utility providing electricityelectric service to retail and wholesale customers within its traditional service territory located withinin the State of Alabama in addition to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of Alabama Power's business of selling electricity.providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, reliability, fuel, capital expenditures, and restoration following major storms. Alabama Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Alabama Power for the foreseeable future.
Alabama Power continues to focus on several key performance indicators. These indicators includeincluding, but not limited to, customer satisfaction, plant availability, system reliability, and net income after dividends on preferred and preference stock. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Alabama Power in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net IncomeAllowance 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) |
| $55 | | 18.6 | | $52 | | 7.8 |
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $13 | | 28.9 | | $17 | | 17.3 |
Alabama Power's net income after dividends on preferred and preference stock forIn the thirdsecond quarter 20162017, AFUDC equity was $350$58 million compared to $295$45 million in the corresponding period in 2016. For year-to-date 2017, AFUDC equity was $115 million compared to $98 million in the corresponding period in 2016. These increases primarily resulted from a higher AFUDC rate and an increase in Kemper IGCC CWIP subject to AFUDC prior to project suspension at Mississippi Power.
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
Earnings from Equity Method Investments
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $29 | | N/M | | $68 | | N/M |
N/M - Not meaningful
In the second quarter and year-to-date 2017, earnings from equity method investments were $28 million and $67 million, respectively, primarily related to earnings from Southern Company Gas' equity method investment in SNG effective September 2016.
See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
Interest Expense, Net of Amounts Capitalized
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $131 | | 44.7 | | $301 | | 55.8 |
In the second quarter 2017, interest expense, net of amounts capitalized was $424 million compared to $293 million in the corresponding period in 2016. For year-to-date 2017, interest expense, net of amounts capitalized was $840 million compared to $539 million in the corresponding period in 2016. These increases were primarily due to an increase in average outstanding long-term debt primarily related to the Merger and the funding of Southern Power's acquisitions and construction projects. In addition, following the Merger, $48 million and $94 million in interest expense of Southern Company Gas was included in the consolidated statements of income for the second quarter and year-to-date 2017, respectively.
See Note (E) to the Condensed Financial Statements herein and Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
Other Income (Expense), Net
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $25 | | 89.3 | | $45 | | 80.4 |
In the second quarter 2017, other income (expense), net was $(3) million compared to $(28) million for the corresponding period in 2015. The increase in2016. For year-to-date 2017, other income (expense), net income was related to an increase in revenue primarily due to warmer weather in the third quarter 2016 as compared to the corresponding period in 2015, an increase in retail revenues under Rate CNP Compliance, and a decrease in non-fuel operations and maintenance expenses. These increases to income were partially offset by a decrease in AFUDC and an increase in depreciation and amortization.
Alabama Power's net income after dividends on preferred and preference stock for year-to-date 2016 was $717$(11) million compared to $665$(56) million for the corresponding period in 2016. These changes were primarily due to expenses incurred in 2016 associated with bridge financing for the Merger. These changes also include increases of $99 million and $116 million in currency losses arising from a translation of euro-denominated fixed-rate notes into U.S. dollars for the second quarter and year-to-date 2017, respectively, fully offset by an equal change in gains on the foreign currency hedges that were reclassified from accumulated OCI into earnings at Southern Power.
See Note (H) to the Condensed Financial Statements under "Foreign Currency Derivatives" herein for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Income Taxes (Benefit)
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(848) | | N/M | | $(752) | | N/M |
N/M - Not meaningful
In the second quarter 2017, income tax benefit was $587 million compared to income tax expense of $261 million for the corresponding period in 2016. The decrease was primarily due to $865 million in tax benefits related to the estimated probable losses on the Kemper IGCC at Mississippi Power, partially offset by $31 million in taxes at Southern Company Gas following the Merger.
For year-to-date 2017, income tax benefit was $273 million compared to income tax expense of $479 million for the corresponding period in 2016, primarily due to $886 million in tax benefits related to the estimated probable losses on the Kemper IGCC at Mississippi Power. In addition, the change reflects $180 million in taxes at Southern Company Gas following the Merger, partially offset by a net increase in tax benefits of $16 million from renewable tax credits at Southern Power.
See Note (G) to the Condensed Financial Statements herein and Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern Company's future earnings potential. The level of Southern Company's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Southern Company system's primary businesses of selling electricity and distributing natural gas. These factors include the traditional electric operating companies' and the natural gas distribution utilities' ability to maintain a constructive regulatory environment that allows for the timely recovery of prudently-incurred costs during a time of increasing costs and limited projected demand growth over the next several years. Completion of cost assessments and the determination of future actions related to Plant Vogtle Units 3 and 4 construction and rate recovery and the ability to recover costs for the remainder of the Kemper County energy facility not included in current rates are also major factors. In addition, the profitability of Southern Power's competitive wholesale business and successful additional investments in renewable and other energy projects are also major factors.
Current proposals related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals, including any potential changes to the availability or realizability of ITCs and PTCs, is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Southern Company's financial statements.
Future earnings for the electricity and natural gas businesses will be driven primarily by customer growth. Earnings in the electricity business will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies, increasing volumes of electronic commerce transactions, and higher multi-family home construction. Earnings for both the electricity and natural gas businesses are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the prices of electricity and natural gas, the price elasticity of demand, and the rate of economic growth or decline in the service territory. In addition, the level of future earnings for the wholesale electric business also depends on numerous factors including regulatory matters, creditworthiness of customers, total electric generating capacity available and related costs, future acquisitions and construction of electric generating facilities, the impact of tax credits from renewable energy projects, and the successful remarketing of capacity as current contracts expire. Demand for electricity and natural gas is primarily driven by economic growth. The pace of economic growth and electricity and natural gasdemand may be affected by changes
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
in regional and global economic conditions, which may impact future earnings. In addition, the volatility of natural gas prices has a significant impact on the natural gas distribution utilities' customer rates, long-term competitive position against other energy sources, and the ability of Southern Company Gas' gas marketing services and wholesale gas services businesses to capture value from locational and seasonal spreads. Additionally, changes in commodity prices subject a significant portion of Southern Company Gas' operations to earnings variability.
As part of its ongoing effort to adapt to changing market conditions, Southern Company continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, partnerships, and acquisitions involving other utility or non-utility businesses or properties, disposition of certain assets or businesses, internal restructuring, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations, risks, and financial condition of Southern Company.
For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Company in Item 7 of the Form 10-K and RISK FACTORS in Item 1A herein.
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis for the traditional electric operating companies and the natural gas distribution utilities or through long-term wholesale agreements for the traditional electric operating companies and Southern Power. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity and natural gas, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company in Item 7 and Note 3 to the financial 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 eight-hour ozone National Ambient Air Quality Standard (NAAQS).
On June 2, 2017, the EPA published a final rule redesignating a 15-county area within metropolitan Atlanta to attainment for the 2008 eight-hour ozone NAAQS.
On June 18, 2017, the EPA published a notice delaying attainment designations for the 2015 eight-hour ozone NAAQS by one year, setting a revised deadline of October 1, 2018. The ultimate outcome of this matter 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 final effluent guidelines rule and the final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
On April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. On June 6, 2017, the EPA proposed a rule establishing a stay of the compliance deadlines for certain effluent limitations and pretreatment standards under the rule.
On June 27, 2017, the EPA and the U.S. Army Corps of Engineers proposed to rescind the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.
The ultimate outcome of these matters cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Southern Company in Item 7 of the Form 10-K for additional information.
On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules.
On June 1, 2017, the U.S. President announced that the United States will withdraw from the non-binding Paris Agreement and begin renegotiation of its terms.
The ultimate outcome of these matters cannot be determined at this time.
FERC Matters
Market-Based Rate Authority
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters – Market-Based Rate Authority" of Southern Company in Item 7 of the Form 10-K for additional information regarding the traditional electric operating companies' and Southern Power's market power proceeding and amendment to their market-rate tariff.
On May 17, 2017, the FERC accepted the traditional electric operating companies' and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' and Southern Power's market power proceeding, it remains a separate, ongoing matter.
Southern Company Gas
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters – Southern Company Gas" of Southern Company in Item 7 and Note 4 to the financial statements of Southern Company in Item 8 of the Form 10-K for additional information regarding Southern Company Gas' pipeline projects.
On August 1, 2017, the Dalton Pipeline was placed in service as authorized by the FERC and transportation service for customers commenced.
Regulatory Matters
Fuel Cost Recovery
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Fuel Cost Recovery" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Regulatory Matters – Alabama Power – Rate ECR" and "Regulatory Matters – Georgia Power –
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding fuel cost recovery for the traditional electric operating companies.
The traditional electric operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow. The traditional electric operating companies continuously monitor their under or over recovered fuel cost balances and make appropriate filings with their state PSCs to adjust fuel cost recovery rates as necessary.
Renewables
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "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.
On May 16, 2017, the Georgia PSC approved Georgia Power's request to build, own, and operate a 139-MW solar generation facility at a U.S. Air Force base that is expected to be placed in service by the end of 2019.
During the six months ended June 30, 2017, Georgia Power continued construction of a 31-MW solar generation facility at a U.S. Marine Corps base that is expected to be placed in service in the fourth quarter 2017.
Mississippi Power placed in service two solar projects in January 2017 and June 2017. A third solar project is expected to be placed in service in the third quarter 2017. Mississippi Power may retire the renewable energy credits (REC) generated on behalf of its customers or sell the RECs, separately or bundled with energy, to third parties.
On June 9, 2017, Mississippi Power submitted a CPCN to the Mississippi PSC for the approval of construction, operation, and maintenance of a 52.5-MW solar energy generating facility, which, if approved, is expected to be placed in service by January 2020.
The ultimate outcome of these matters cannot be determined at this time.
Alabama Power
Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See Note 3 to the financial statements of Southern Company under "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.
Georgia Power
Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, Environmental Compliance Cost Recovery tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to the construction of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a separate fuel cost recovery tariff. See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein and Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding Georgia Power's NCCR tariff. Also see Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Fuel Cost Recovery" herein for additional information regarding Georgia Power's fuel cost recovery.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Integrated Resource Plan
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "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.
On March 7, 2017, the Georgia PSC approved Georgia Power's decision to suspend work at a future generation site in Stewart County, Georgia, due to changing economics, including load forecasts and lower fuel costs. The timing of recovery for costs incurred of approximately $50 million will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time.
Gulf Power
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Gulf Power" of Southern Company in Item 7 of the Form 10-K for additional information regarding Gulf Power's October 2016 request to the Florida PSC to increase retail base rates and Gulf Power's ownership of Plant Scherer Unit 3.
On April 4, 2017, the Florida PSC approved the 2017 Rate Case Settlement Agreement among Gulf Power and three intervenors with respect to Gulf Power's request to increase retail base rates. Under the terms of the 2017 Rate Case Settlement Agreement, Gulf Power increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consists of a $62.0 million increase in annual base revenues less an annual equivalent credit of approximately $7.7 million for 2017 for certain wholesale revenues to be provided through December 2019 through the purchased power capacity cost recovery clause. In addition, Gulf Power continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%) and is deemed to have an equity ratio of 52.5% for all retail regulatory purposes. Gulf Power will also begin amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 (357 MWs) over 15 years effective January 1, 2018 and will implement new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs), which was recorded in the first quarter 2017. The remaining issues related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause rate approved by the Florida PSC in November 2016.
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. Changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flows.
Base Rate Cases
On March 10, 2017, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $208 million increase in annual base rate revenues. The requested increase is based on a 2018 projected test year and a ROE of 10.7%. The Illinois Commission is expected to rule on the requested increase within the 11-month statutory time limit, after which rate adjustments will be effective. The ultimate outcome of this matter cannot be determined at this time.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Construction Program
Overview
The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue its strategy of developing and constructing new electric generating facilities, adding environmental modifications to certain existing units, expanding the electric transmission and distribution systems, and updating and expanding the natural gas distribution systems. For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. Southern Company Gas is engaged in various infrastructure improvement programs designed to update or expand the natural gas distribution systems of the natural gas distribution utilities to improve reliability and meet operational flexibility and growth. The natural gas distribution utilities recover their investment and a return associated with these infrastructure programs through their regulated rates.
The largest construction project currently underway in the Southern Company system is Plant Vogtle Units 3 and 4 (45.7% ownership interest by Georgia Power in the two units, each with approximately 1,100 MWs). Georgia Power and the other Vogtle Owners are continuing to conduct comprehensive schedule and cost-to-complete assessments, as well as cancellation cost assessments, to determine the impact of the EPC Contractor's bankruptcy filing on the construction cost and schedule for Plant Vogtle Units 3 and 4. Georgia Power will continue working with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4, including, but not limited to, the status of construction and rate recovery, and currently expects to include its recommendation in its seventeenth VCM report to be filed with the Georgia PSC in late August 2017. On June 21, 2017, the Mississippi PSC directed Mississippi Power to pursue a settlement under which the Kemper IGCC would be operated as a natural gas plant rather than an IGCC plant and, on June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the plant. See Note 3 to the financial statements of Southern Company under "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 "Regulatory Matters– Georgia Power– Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for additional information. For additional information about costs relating to Southern Power's acquisitions that involve construction of renewable energy facilities, see Note 12 to the financial statements of Southern Company under "Southern Power – Construction Projects" in Item 8 of the Form 10-K and Note (I) to the Condensed Financial Statements under "Southern Power" herein. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Southern Company Gas – Regulatory Infrastructure Programs" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters–Southern Company Gas–Regulatory Infrastructure Programs" herein for information regarding infrastructure improvement programs at the natural gas distribution utilities.
Also see FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information regarding Southern Company's capital requirements for its subsidiaries' construction programs.
Integrated Coal Gasification Combined Cycle
The Kemper IGCC was approved by the Mississippi PSC in the 2010 CPCN proceedings, subject to a construction cost cap of $2.88 billion, net of $245 million of Initial DOE Grants and excluding the Cost Cap Exceptions. The combined cycle and associated common facilities portion of the Kemper IGCC were placed in service in August 2014.
In December 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order), based on a stipulation between Mississippi Power and the Mississippi Public Utilities Staff, authorizing rates that provide for the recovery of approximately $126 million annually related to the combined cycle and associated common facilities portion of Kemper IGCC assets previously placed in service. As required by the In-Service Asset Rate Order, on June 5, 2017,
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Mississippi Power made a rate filing requesting to adjust the amortization schedules of the regulatory assets reviewed and determined prudent in a manner that would not change customer rates or annual revenues. On June 28, 2017, the Mississippi PSC suspended this filing. On July 6, 2017, the Mississippi PSC issued an order requiring Mississippi Power to establish a regulatory liability account to maintain current rates related to the Kemper IGCC following the July 2017 completion of the amortization period for certain regulatory assets approved in the In-Service Asset Rate Order that would allow for subsequent refund if the Mississippi PSC deems the rates unjust and unreasonable.
The remainder of the plant includes 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." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO2, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. Most recently, in May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast has decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations increased significantly since certification.
On June 21, 2017, the Mississippi PSC stated its intent to issue the Kemper Settlement Order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC. The Kemper Settlement Order established the Kemper IGCC Settlement Docket for the purposes of pursuing a global settlement of costs of the Kemper IGCC. The Mississippi PSC requested any such proposed settlement agreement reflect: (i) at a minimum, no rate increase to Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and related assets; and (iii) modification or amendment of the CPCN for the Kemper IGCC to allow only for ownership and operation of a natural gas facility. The Kemper Settlement Order provides that any related settlement agreement be filed within 45 days from the effective date of the Kemper Settlement Order. If a settlement agreement is filed, a hearing will be set 45 days from the date of the settlement's filing, and the appropriate scheduling order will be established.
Although the ability to achieve a negotiated settlement is uncertain, Mississippi Power intends to pursue any available settlement alternatives. In addition, the Kemper Settlement Order provides that, in the event a settlement agreement is not reached, the Mississippi PSC reserves its right to take any appropriate steps, including issuing an order to show cause as to why the CPCN for the Kemper IGCC should not be revoked.
On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014.
At the time of project suspension, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate subject to the construction cost cap totaling $196 million ($121 million after tax) in the second quarter through May 31, 2017 and a total of $305 million ($188 million after tax) for year-to-date through May 31, 2017. In the aggregate, Mississippi Power incurred charges of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017. The May 31, 2017 cost estimate included approximately $175 million of estimated costs to be incurred beyond the then-estimated in-service date of June 30, 2017 that were expected to be subject to the $2.88 billion cost cap.
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At June 30, 2017, approximately $3.3 billion in actual Kemper IGCC costs were not reflected in Mississippi Power's retail and wholesale rates, of which $0.5 billion was related to the combined cycle and associated facilities and $2.8 billion was related to the gasification portions of the Kemper IGCC.
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper Settlement Order, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs currently estimated at approximately $100 million to $200 million are expected to be incurred.
Total pre-tax charges to income for the estimated probable losses on the Kemper IGCC were $3.0 billion ($2.1 billion after tax) for the second quarter 2017 and $3.1 billion ($2.2 billion after tax) for the six months ended June 30, 2017. In the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $6.0 billion ($3.9 billion after tax) through June 30, 2017.
As of June 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which $0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility, as well as the 15% that was previously contracted to SMEPA. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.
For additional information on the Kemper IGCC, including information on the project economic viability analysis, pending lawsuits, and an ongoing SEC investigation, see Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and "Other Matters" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein. Also see "Litigation" herein.
Litigation
On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff alleges that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper 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 23, 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the plaintiffs filed notice to appeal to the Mississippi Supreme Court.
On June 9, 2016, Treetop Midstream Services, LLC (Treetop) and other related parties filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint relates to the cancelled CO2 contract with Treetop and alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and seeks
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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, which the court granted on May 4, 2017. On June 28, 2017, Treetop and other related parties filed a claim for arbitration requesting $500 million in damages.
Southern Company believes these legal challenges have no merit; however, an adverse outcome in these proceedings could have a material impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, and the ultimate outcome of these matters cannot be determined at this time.
Nuclear Construction
See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the construction of Plant Vogtle Units 3 and 4, VCM reports, the NCCR tariff, and the Contractor Settlement Agreement.
Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcy
In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Vogtle 3 and 4 Agreement, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4. 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. Georgia Power's proportionate share of Plant Vogtle Units 3 and 4 is 45.7%.
The Vogtle 3 and 4 Agreement also provided for liquidated damages upon the EPC Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to an aggregate cap of 10% of the contract price, or approximately $920 million (approximately $420 million based on Georgia Power's ownership interest). Under the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. In January 2016, Westinghouse delivered to the Vogtle Owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020 and require 60 days' written notice to Georgia Power in the event the Westinghouse Letters of Credit will not be renewed.
Under the terms of the Vogtle 3 and 4 Agreement, the EPC Contractor did not have the right to terminate the Vogtle 3 and 4 Agreement for convenience. In the event of an abandonment of work by the EPC Contractor, the maximum liability of the EPC Contractor under the Vogtle 3 and 4 Agreement was 40% of the contract price (approximately $1.7 billion based on Georgia Power's ownership interest).
On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. To provide for a continuation of work at Plant Vogtle Units 3 and 4, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Interim Assessment Agreement, which the bankruptcy court approved on March 30, 2017.
The Interim Assessment Agreement provided, among other items, that during the term of the Interim Assessment Agreement (i) Georgia Power was obligated to pay, on behalf of the Vogtle Owners, all costs accrued by the EPC Contractor for subcontractors and vendors for services performed or goods provided, with these amounts paid to the EPC Contractor, except that amounts accrued for Fluor Corporation (Fluor) were paid directly to Fluor; (ii) the EPC Contractor provided certain engineering, procurement, and management services for Plant Vogtle Units 3 and 4, to the same extent as contemplated by the Vogtle 3 and 4 Agreement, and Georgia Power, on behalf of the Vogtle Owners, made payments of $5.4 million per week for these services; (iii) Georgia Power had the right to make payments, on behalf of the Vogtle Owners, directly to subcontractors and vendors who had accounts past due with the EPC Contractor; (iv) the EPC Contractor used commercially reasonable efforts to provide information reasonably requested by Georgia Power as was necessary to continue construction and investigation of the
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completion status of Plant Vogtle Units 3 and 4; (v) the EPC Contractor rejected or accepted the Vogtle 3 and 4 Agreement by the termination of the Interim Assessment Agreement; and (vi) Georgia Power did not exercise any remedies against Toshiba under the Toshiba Guarantee. Under the Interim Assessment Agreement, all parties expressly reserved all rights and remedies under the Vogtle 3 and 4 Agreement and all related security and collateral under applicable law.
The Interim Assessment Agreement, as amended, expired on July 27, 2017. Georgia Power's aggregate liability for the Vogtle Owners under the Interim Assessment Agreement totaled approximately $650 million, of which $552 million had been paid or accrued as of June 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $297 million.
Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor, including Fluor Enterprises, Inc., a subsidiary of Fluor, alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken, and continues to take, actions to remove liens filed by these subcontractors through the posting of surety bonds. Georgia Power estimates the aggregate liability, through July 31, 2017, of the Vogtle Owners for the removal of subcontractor liens and payment of other EPC Contractor pre-petition accounts payable to total approximately $400 million, of which $354 million had been paid or accrued as of June 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $183 million.
On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered the Guarantee Settlement Agreement. Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion, of which Georgia Power's proportionate share is approximately $1.7 billion, and that the Guarantee Obligations exist regardless of whether Plant Vogtle Units 3 and 4 are completed. The Guarantee Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations, beginning in October 2017 and continuing through January 2021. In the event Toshiba receives certain payments, including sale proceeds, from or related to Westinghouse (or its subsidiaries) or Toshiba Nuclear Energy Holdings (UK) Limited (or its subsidiaries), it will hold a portion of such payments in trust for the Vogtle Owners and promptly pay them as offsets against any remaining Guarantee Obligations. Under the Guarantee Settlement Agreement, the Vogtle Owners will forbear from exercising certain remedies, including drawing on the Westinghouse Letters of Credit, until June 30, 2020, unless certain events of nonpayment, insolvency, or other material breach of the Guarantee Settlement Agreement by Toshiba occur. If such an event occurs, the balance of the Guarantee Obligations will become immediately due and payable, and the Vogtle Owners may exercise any and all rights and remedies, including drawing on the Westinghouse Letters of Credit without restriction. In addition, the Guarantee Settlement Agreement does not restrict the Vogtle Owners from fully drawing on the Westinghouse Letters of Credit in the event they are not renewed or replaced prior to the expiration date.
On June 23, 2017, Toshiba released a revised outlook for fiscal year 2016, which reflected a negative shareholders' equity balance of approximately $5 billion as of March 31, 2017, and announced that its independent audit process was continuing. Toshiba has also announced the existence of material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern. As a result, substantial risk regarding the Vogtle Owners' ability to fully collect the Guarantee Obligations continues to exist. An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Southern Company's financial statements.
Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Services Agreement, which was amended and restated on July 20, 2017, for the EPC Contractor to transition construction management of Plant Vogtle Units 3 and 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Services Agreement, (ii) assume and assign to the Vogtle Owners certain project-related contracts, (iii) join the Vogtle Owners as counterparties to certain assumed project-related contracts, and (iv) reject the Vogtle 3 and 4 Agreement.
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The Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE on July 27, 2017. The Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.
The ultimate outcome of these matters cannot be determined at this time.
Regulatory Matters
In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by including the related CWIP accounts in rate base during the construction period. As of June 30, 2017, Georgia Power had recovered approximately $1.4 billion of financing costs.
On December 20, 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving the following prudence matters: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report will be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement is reasonable and prudent and none of the amounts paid or to be paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) financing costs on verified and approved capital costs will be deemed prudent provided they are incurred prior to December 31, 2019 and December 31, 2020 for Plant Vogtle Units 3 and 4, respectively; and (iv) (a) the in-service capital cost forecast will be adjusted to $5.680 billion (Revised Forecast), which includes a contingency of $240 million above Georgia Power's then current forecast of $5.440 billion, (b) capital costs incurred up to the Revised Forecast will be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, and (c) Georgia Power would have the burden to show that any capital costs above the Revised Forecast are reasonable and prudent. Under the terms of the Vogtle Cost Settlement Agreement, the certified in-service capital cost for purposes of calculating the NCCR tariff will remain at $4.418 billion. Construction capital costs above $4.418 billion will accrue AFUDC through the date each unit is placed in service. The ROE used to calculate the NCCR tariff was reduced from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016. For purposes of the AFUDC calculation, the ROE on costs between $4.418 billion and $5.440 billion will also be 10.00% and the ROE on any amounts above $5.440 billion would be Georgia Power's average cost of long-term debt. If the Georgia PSC adjusts Georgia Power's ROE rate setting point in a rate case prior to Plant Vogtle Units 3 and 4 being placed into retail rate base, then the ROE for purposes of calculating both the NCCR tariff and AFUDC will likewise be 95 basis points lower than the revised ROE rate setting point. If Plant Vogtle Units 3 and 4 are not placed in service by December 31, 2020, then (i) the ROE for purposes of calculating the NCCR tariff will be reduced an additional 300 basis points, or $8 million per month, and may, at the Georgia PSC's discretion, be accrued to be used for the benefit of customers, until such time as the units are placed in service and (ii) the ROE used to calculate AFUDC will be Georgia Power's average cost of long-term debt.
Under the terms of the Vogtle Cost Settlement Agreement, the Georgia PSC will determine, for retail ratemaking purposes, the process of transitioning Plant Vogtle Units 3 and 4 from a construction project to an operating plant no later than Georgia Power's base rate case required to be filed by July 1, 2019.
The Georgia PSC has approved fifteen VCM reports covering the periods through June 30, 2016, including construction capital costs incurred, which through that date totaled $3.7 billion. Georgia Power filed its sixteenth VCM report, covering the period from July 1 through December 31, 2016, requesting approval of $222 million of construction capital costs incurred during that period, with the Georgia PSC on February 27, 2017.
The ultimate outcome of these matters cannot be determined at this time.
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Revised Cost and Schedule
Georgia Power and the other Vogtle Owners are continuing to conduct comprehensive schedule and cost-to-complete assessments, as well as cancellation cost assessments, to determine the impact of the EPC Contractor's bankruptcy filing on the construction cost and schedule for Plant Vogtle Units 3 and 4. Georgia Power's preliminary assessment results indicate that its proportionate share of the remaining estimated cost to complete Plant Vogtle Units 3 and 4 ranges as follows:
|
| | | | | | | |
| Preliminary in-service dates | | | |
| Unit 3 | February 2021 | – | March 2022 |
| Unit 4 | February 2022 | – | March 2023 |
| | (in billions) |
| Preliminary estimated cost to complete | $ | 3.9 |
| – | $ | 4.6 |
|
| CWIP as of June 30, 2017 | 4.5 |
| | 4.5 |
|
| Guarantee Obligations | (1.7 | ) | | (1.7 | ) |
| Estimated capital costs | $ | 6.7 |
| – | $ | 7.4 |
|
| Vogtle Cost Settlement Agreement Revised Forecast | (5.7 | ) | | (5.7 | ) |
| Estimated net additional capital costs | $ | 1.0 |
| – | $ | 1.7 |
|
Georgia Power's estimates for cost to complete and schedule are based on preliminary analysis and remain subject to further refinement of labor productivity and consumable and commodity quantities and costs.
Georgia Power's estimated financing costs during the construction period total approximately $3.1 billion to $3.5 billion, of which approximately $1.4 billion had been incurred through June 30, 2017.
Georgia Power's preliminary cancellation cost estimate results indicate that its proportionate share of the estimated cancellation costs is approximately $400 million. As a result, as of June 30, 2017, total estimated costs subject to evaluation by Georgia Power and the Georgia PSC in the event of a cancellation decision are as follows:
|
| | | |
| | Preliminary Cancellation Cost Estimate |
| | (in billions) |
| CWIP as of June 30, 2017 | $ | 4.5 |
|
| Financing costs collected, net of tax | 1.4 |
|
Cancellation costs(*) | 0.4 |
|
| Total | $ | 6.3 |
|
| |
| (*) | The estimate for cancellation costs includes, but is not limited to, costs to terminate contracts for construction and other services, as well as costs to secure the Plant Vogtle Units 3 and 4 construction site. |
The Guarantee Obligations continue to exist in the event of cancellation. In addition, under Georgia law, prudently incurred costs related to certificated projects cancelled by the Georgia PSC are allowed recovery, including carrying costs, in future retail rates. Georgia Power will continue working with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4, including, but not limited to, the status of construction and rate recovery, and currently expects to include its recommendation in its seventeenth VCM report to be filed with the Georgia PSC in late August 2017.
The ultimate outcome of these matters is dependent on the completion of the assessments described above, as well as the related regulatory treatment, and cannot be determined at this time.
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Matters
As of June 30, 2017, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through a loan guarantee agreement between Georgia Power and the DOE and a multi-advance credit facility among Georgia Power, the DOE, and the FFB. See Note 6 to the financial statements of Southern Company under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
The IRS has allocated PTCs to Plant Vogtle Units 3 and 4 which require that the applicable unit be placed in service prior to 2021. The net present value of Georgia Power's PTCs is estimated at approximately $400 million per unit.
There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise if 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 if 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.
If construction continues, the risk remains that challenges with labor productivity, fabrication, delivery, assembly, and installation of plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost.
The ultimate outcome of these matters cannot be determined at this time.
See RISK FACTORS of Southern Company in Item 1A of the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world. See additional risks in Item 1A herein regarding the EPC Contractor's bankruptcy.
Income Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Southern Company in Item 7 of the Form 10-K and Note (G) to the Condensed Financial Statements herein for additional information.
Bonus Depreciation
Approximately $1.2 billion of positive cash flows is expected to result from bonus depreciation for the 2017 tax year, but may not all be realized in 2017 due to net operating loss projections for the 2017 tax year. Approximately $370 million of the 2017 benefit is dependent upon placing the remainder of the Kemper IGCC in service by December 31, 2017. If the suspension of the Kemper IGCC start-up activities results in an abandonment, any amount previously estimated as bonus depreciation would be claimed as a deduction under IRC Section 165. As of June 30, 2017, $82 million has been received through quarterly income tax refunds for bonus depreciation related to the Kemper IGCC, which may be subject to repayment. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein and Note (G) to the Condensed Financial Statements herein for additional information. The ultimate outcome of this matter cannot be determined at this time.
Section 174 Research and Experimental Deduction
Southern Company has reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and filed amended federal income tax returns for
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
2008 through 2013 to also include such deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, subject to approval of the U.S. Congress Joint Committee on Taxation, resolving a methodology for these deductions. Due to the uncertainty related to this tax position, Southern Company had unrecognized tax benefits associated with these R&E deductions totaling approximately $464 million as of June 30, 2017. If the suspension of the Kemper IGCC start-up activities results in an abandonment, any amount not allowed under IRC Section 174 would be claimed as a deduction under IRC Section 165, and would result in a reversal of the related unrecognized tax benefits, excluding interest. See Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Section 174 Research and Experimental Deduction," respectively, herein for additional information. This matter is expected to be resolved in the next 12 months; however, the ultimate outcome of this matter cannot be determined at this time.
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.
TheultimateoutcomeofsuchpendingorpotentiallitigationagainstSouthernCompanyanditssubsidiariescannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatementsherein,management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
On January 20, 2017, a purported securities class action complaint was filed against Southern Company, certain of its officers, and certain former Mississippi Power officers in the U.S. District Court for the Northern District of Georgia, Atlanta Division, by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint alleges that Southern Company, certain of its officers, and certain former Mississippi Power officers made materially false and misleading statements regarding the Kemper IGCC in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. On June 12, 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. On July 27, 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice.
On February 27, 2017, Jean Vineyard filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the defendants caused Southern Company to make false or misleading statements regarding the Kemper IGCC cost and schedule. Further, the complaint alleges that the defendants were unjustly enriched and caused the waste of corporate assets. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on her own behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. On March 27, 2017, the court deferred this lawsuit until 30 days after certain further action in the purported securities class action complaint discussed above.
On May 15, 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia, that names as defendants Southern Company, certain of its directors, certain of
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its officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper IGCC. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper IGCC schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes.
On June 1, 2017, Judy Mesirov filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia, that names as defendants Southern Company, certain of its current and former directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper IGCC. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper IGCC schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages, disgorgement of profits, and equitable relief and, on her own behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes.
Southern Company believes these legal challenges have no merit; however, an adverse outcome in any of these proceedings could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, the ultimate outcome of which cannot be determined at this time.
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 believes 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. 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 Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, Goodwill and Other Intangible Assets, Derivatives and Hedging Activities, and Contingent Obligations.
Kemper IGCC Rate Recovery
For periods prior to the second quarter 2017, significant accounting estimates included Kemper IGCC estimated construction costs, project completion date, and rate recovery. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Kemper IGCC Estimated Construction Costs, Project Completion Date, and Rate Recovery" of Southern Company in Item 7 of the Form 10-K for additional information. Mississippi
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Power recorded total pre-tax charges to income related to the Kemper IGCC of $428 million ($264 million after tax) in 2016, $365 million ($226 million after tax) in 2015, $868 million ($536 million after tax) in 2014, and $1.2 billion ($729 million after tax) in prior years.
As a result of the Mississippi PSC's June 21, 2017 stated intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant rather than an IGCC plant, as well as Mississippi Power's June 28, 2017 suspension of the operation and start-up of the gasifier portion of the Kemper IGCC, the estimated construction costs and project completion date are no longer considered significant accounting estimates. Significant accounting estimates for the June 30, 2017 financial statements presented herein include the overall assessment of rate recovery for the Kemper County energy facility and the estimated costs for the potential cancellation of the Kemper IGCC.
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper Settlement Order, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs currently estimated at approximately $100 million to $200 million are expected to be incurred.
As of June 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which $0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility, as well as the 15% that was previously contracted to SMEPA. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.
In the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $5.96 billion ($3.94 billion after tax) through June 30, 2017. Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $3.0 billion ($2.1 billion after tax) and $81 million ($50 million after tax) in the second quarter 2017 and the second quarter 2016, respectively, and total pre-tax charges of $3.1 billion ($2.2 billion after tax) and $134 million ($83 million after tax) year-to-date in 2017 and 2016, respectively.
Given the significant judgment involved in estimating the costs to cancel the gasifier portion of the Kemper IGCC, the ultimate rate recovery for the Kemper IGCC, including the $0.5 billion of combined cycle-related costs not yet in rates, and the impact on Southern Company's results of operations, Southern Company considers these items to be critical accounting estimates. See Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Recently Issued Accounting Standards
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
While Southern Company expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Southern Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity or natural gas without a defined
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
contractual term, as well as longer-term contractual commitments, including PPAs and non-derivative natural gas asset management and optimization arrangements. Southern Company expects the adoption of ASC 606 will not result in a significant shift from the current timing of revenue recognition for such transactions.
Southern Company's ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements, such as certain PPAs, energy-related derivatives, and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Southern Company's financial statements. In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Southern Company expects CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Southern Company intends to use the modified retrospective method of adoption effective January 1, 2018. Southern Company has also elected to utilize practical expedients which allow it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Southern Company's financial statements, Southern Company will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.
On January 26, 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for annual and interim periods beginning on or after December 15, 2019, and early adoption is permitted on testing dates after January 1, 2017.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. Southern Company is currently evaluating the new standard. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Southern Company's financial statements.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company in Item 7 of the Form 10-K for additional information. Southern Company's financial condition remained stable at June 30, 2017. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $2.7 billion for the first six months of 2017, an increase of $0.6 billion from the corresponding period in 2016. The increase in net cash provided from operating activities was primarily due to $1.2 billion of net cash provided from operating activities of Southern Company Gas, which was acquired on July 1, 2016, partially offset by the timing of vendor payments and an increase in under-recovered fuel costs. Net cash used for investing activities totaled $4.9 billion for the first six months of 2017 primarily due to the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities, capital expenditures for Southern Company Gas' infrastructure replacement programs, and Southern Power's payments for renewable acquisitions. Net cash provided from financing activities totaled $1.6 billion for the first six months of 2017 primarily due to issuances of long-term and short-term debt, partially offset by redemptions of long-term debt and common stock dividend payments. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first six months of 2017 include an increase of $1.8 billion in property, plant, and equipment in service, net of depreciation primarily related to the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities, Southern Company Gas' infrastructure replacement programs, and Southern Power's renewable acquisitions; a decrease of $1.5 billion in CWIP primarily related to the estimated probable losses on the Kemper IGCC; a decrease of $0.5 billion in cash and cash equivalents primarily related to acquisition payments at Southern Power; a decrease of $1.4 billion in total common stockholder's equity primarily related to the estimated probable losses on the Kemper IGCC, partially offset by the issuance of additional shares of common stock; an increase of $1.3 billion in retail revenues under Rate CNP Compliancelong-term debt (excluding amounts due within a year) to fund the Southern Company system's continuous construction programs and decreasesfor general corporate purposes; and an increase of $1.0 billion in non-fuel operationsnotes payable primarily due to issuances of short-term bank debt for general corporate purposes.
At the end of the second quarter 2017, the market price of Southern Company's common stock was $47.88 per share (based on the closing price as reported on the New York Stock Exchange) and maintenance expensesthe book value was $23.38 per share, representing a market-to-book ratio of 205%, compared to $49.19, $25.00, and dividends on197%, respectively, at the end of 2016. Southern Company's common stock dividend for the second quarter 2017 was $0.58 per share compared to $0.56 per share in the second quarter 2016.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company in Item 7 of the Form 10-K for a description of Southern Company's capital requirements for the construction programs of the Southern Company system, including estimated capital expenditures for new electric generating facilities and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, pipeline charges, storage capacity, and gas supply, asset management agreements, standby letters of credit and performance/surety bonds, trust funding requirements, and unrecognized tax benefits. Approximately $3.0 billion will be required through June 30, 2018 to fund maturities of long-term debt. See "Sources of Capital" herein 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 and depreciation and amortization.additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; state regulatory agency approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Additionally, planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power's ability to execute its growth strategy. See Note 12 to the financial statements of Southern Company under "Southern Power" in Item 8 of the Form 10-K and Note (I) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding Southern Power's plant acquisitions. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein for information regarding additional factors that may impact construction expenditures, including Georgia Power's preliminary cost-to-complete and cancellation cost assessments for Plant Vogtle Units 3 and 4.
Sources of Capital
Southern Company intends to meet its future capital needs through operating cash flows, short-term debt, term loans, and external security issuances. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings. The amount and timing of additional equity capital and debt issuances in 2017, as well as in subsequent years, will be contingent on Southern Company's investment opportunities and the Southern Company system's capital requirements and will depend upon prevailing market conditions and other factors. See "Capital Requirements and Contractual Obligations" herein for additional information.
Except as described herein, the traditional electric operating companies, Southern Power, and Southern Company Gas plan to obtain the funds required for construction and other purposes from operating cash flows, external security issuances, term loans, short-term borrowings, and equity contributions or loans from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Company in Item 7 of the Form 10-K for additional information.
In addition, Georgia Power has entered into a loan guarantee agreement (Loan Guarantee Agreement) with the DOE, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4. Under the Loan Guarantee Agreement, the DOE agreed to guarantee borrowings of up to $3.46 billion (not to exceed 70% of Eligible Project Costs) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. Eligible Project Costs incurred through June 30, 2017 would allow for borrowings of up to $3.1 billion under the FFB Credit Facility, of which Georgia Power has borrowed $2.6 billion; however, on July 27, 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement (LGA Amendment) to clarify the operation of the Loan Guarantee Agreement pending Georgia Power's completion of its comprehensive schedule, cost-to-complete, and cancellation cost assessments (Cost Assessments) for Plant Vogtle Units 3 and 4. Under the terms of the LGA Amendment, Georgia Power will not request any advances under the Loan Guarantee Agreement unless and until such time as Georgia Power has completed the Cost Assessments and made a determination to continue construction of Plant Vogtle Units 3 and 4 and satisfied certain other conditions related to continuing construction. See Note 6 to the financial statements of Southern Company under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information regarding the Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and additional conditions to borrowing. Also
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
see Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
As of June 30, 2017, Southern Company's current liabilities exceeded current assets by $3.9 billion due to notes payable of $3.3 billion (comprised of approximately $0.9 billion at the parent company, $1.2 billion at Georgia Power, $0.1 billion at Gulf Power, $0.4 billion at Southern Power, and $0.6 billion at Southern Company Gas) and long-term debt that is due within one year of $3.0 billion (comprised of approximately $0.4 billion at the parent company, $0.4 billion at Alabama Power, $0.3 billion at Georgia Power, $1.0 billion at Mississippi Power, and $0.9 billion at Southern Power). To meet short-term cash needs and contingencies, the Southern Company system has substantial cash flow from operating activities and access to capital markets and financial institutions. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas intend to utilize operating cash flows, as well as commercial paper, lines of credit, bank notes, and securities issuances, as market conditions permit, as well as, under certain circumstances for the traditional electric operating companies, Southern Power, and Southern Company Gas, equity contributions and/or loans from Southern Company to meet their short-term capital needs.
At June 30, 2017, Southern Company and its subsidiaries had approximately $1.4 billion of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2017 were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Expires | | | | Executable Term Loans | | Expires Within One Year |
| Company | 2017 | 2018 | 2019 | 2020 | 2022 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out |
| | (in millions) |
Southern Company(a) | $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 2,000 |
| | $ | 2,000 |
| | $ | 2,000 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Alabama Power | 3 |
| 532 |
| — |
| — |
| 800 |
| | 1,335 |
| | 1,335 |
| | — |
| | — |
| | — |
| | 35 |
|
| Georgia Power | — |
| — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,732 |
| | — |
| | — |
| | — |
| | — |
|
| Gulf Power | 30 |
| 195 |
| 25 |
| 30 |
| — |
| | 280 |
| | 280 |
| | 45 |
| | — |
| | — |
| | 40 |
|
| Mississippi Power | 113 |
| — |
| — |
| — |
| — |
| | 113 |
| | 100 |
| | — |
| | 13 |
| | 13 |
| | 100 |
|
| Southern Power Company | — |
| — |
| — |
| — |
| 750 |
| | 750 |
| | 675 |
| | — |
| | — |
| | — |
| | — |
|
Southern Company Gas(b) | — |
| — |
| — |
| — |
| 1,900 |
| | 1,900 |
| | 1,849 |
| | — |
| | — |
| | — |
| | — |
|
| Other | 10 |
| 30 |
| — |
| — |
| — |
| | 40 |
| | 40 |
| | 20 |
| | — |
| | 20 |
| | 20 |
|
| Southern Company Consolidated | $ | 156 |
| $ | 757 |
| $ | 25 |
| $ | 30 |
| $ | 7,200 |
| | $ | 8,168 |
| | $ | 8,011 |
| | $ | 65 |
| | $ | 13 |
| | $ | 33 |
| | $ | 195 |
|
| |
| (a) | Represents the Southern Company parent entity. |
| |
| (b) | Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.2 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $700 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. |
See Note 6 to the financial statements of Southern Company under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
As reflected in the table above, in May 2017, Southern Company, Alabama Power, Georgia Power, and Southern Power Company each amended certain of their multi-year credit arrangements, which, among other things, extended the maturity dates from 2020 to 2022. Southern Company and Southern Power Company increased their borrowing ability under these arrangements to $2.0 billion from $1.25 billion and to $750 million from $600 million, respectively. Southern Company also terminated its $1.0 billion facility maturing in 2018. Also in May 2017, Southern Company Gas Capital and Nicor Gas terminated their existing credit arrangements for $1.3 billion and $700 million, respectively, which were to mature in 2017 and 2018, and entered into a new multi-year credit arrangement currently allocated for $1.2 billion and $700 million, respectively, with a maturity date of 2022.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Most of these bank credit arrangements, as well as the term loan arrangements of Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Power Company, contain covenants that limit debt levels and contain cross-acceleration or cross-default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of the individual company. Such cross-default provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness or guarantee obligations over a specified threshold. Such cross-acceleration provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness, the payment of which was then accelerated. At June 30, 2017, Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas were in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the unused credit with banks is allocated to provide liquidity support to the pollution control revenue bonds of the traditional electric operating companies and the commercial paper programs of Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas. The amount of variable rate pollution control revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of June 30, 2017 was approximately $1.6 billion. In June 2017, Georgia Power remarketed $318 million of variable rate pollution control bonds in index rate modes, reducing the liquidity support utilized under Georgia Power's bank credit arrangement. In addition, at June 30, 2017, the traditional electric operating companies had approximately $626 million of pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months.
Southern Company, the traditional electric operating companies (other than Mississippi Power), Southern Power Company, Southern Company Gas, and Nicor Gas make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Short-term borrowings are included in notes payable in the balance sheets.
Details of short-term borrowings were as follows:
|
| | | | | | | | | | | | | | | | | | |
| | | Short-term Debt at June 30, 2017 | | Short-term Debt During the Period(*) |
| | | Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) | | | | (in millions) |
| Commercial paper | | $ | 2,257 |
| | 1.5 | % | | $ | 2,519 |
| | 1.3 | % | | $ | 2,946 |
|
| Short-term bank debt | | 1,017 |
| | 2.0 | % | | 321 |
| | 2.0 | % | | 1,017 |
|
| Total | | $ | 3,274 |
| | 1.7 | % | | $ | 2,840 |
| | 1.4 | % | | |
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2017. |
Southern Company believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, bank term loans, and operating cash flows.
Credit Rating Risk
At June 30, 2017, Southern Company and its subsidiaries did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain subsidiaries to BBB and/or Baa2 or below. These contracts are for physical electricity and natural gas purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management,
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
transmission, interest rate management, and foreign currency risk management, and, at June 30, 2017, included contracts related to the construction of new generation at Plant Vogtle Units 3 and 4.
The maximum potential collateral requirements under these contracts at June 30, 2017 were as follows:
|
| | | |
| Credit Ratings | Maximum Potential
Collateral
Requirements |
| | (in millions) |
| At BBB and/or Baa2 | $ | 39 |
|
| At BBB- and/or Baa3 | $ | 642 |
|
At BB+ and/or Ba1(*) | $ | 2,555 |
|
| |
| (*) | Any additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $38 million. |
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Company and its subsidiaries to access capital markets, and would be likely to impact the cost at which they do so.
On March 1, 2017, Moody's downgraded the senior unsecured debt rating of Mississippi Power to Ba1 from Baa3.
On March 20, 2017, Moody's revised its rating outlook for Georgia Power from stable to negative.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including the traditional electric operating companies, Southern Power, Southern Company Gas, Southern Company Gas Capital, and Nicor Gas) from stable to negative.
On March 30, 2017, Fitch placed the ratings of Southern Company, Georgia Power, and Mississippi Power on rating watch negative.
On June 22, 2017, Moody's placed the ratings of Mississippi Power on review for downgrade.
Financing Activities
During the first six months of 2017, Southern Company issued approximately 7.8 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $352 million.
In addition, during the second quarter 2017, Southern Company issued approximately 1.3 million shares of common stock through at-the-market issuances pursuant to sales agency agreements related to Southern Company's continuous equity offering program and received cash proceeds of approximately $65 million, net of $553,000 in fees and commissions.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first six months of 2017:
|
| | | | | | | | | | | | | | | | | | | |
| Company | Senior Note Issuances | | Senior Note Maturities and Redemptions | | Revenue Bond Maturities, Redemptions, and Repurchases | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(a) |
| | (in millions) |
Southern Company(b) | $ | 300 |
| | $ | — |
| | $ | — |
| | $ | 500 |
| | $ | 400 |
|
| Alabama Power | 550 |
| | 200 |
| | — |
| | — |
| | — |
|
| Georgia Power | 850 |
| | 450 |
| | 27 |
| | — |
| | 3 |
|
| Gulf Power | 300 |
| | 85 |
| | — |
| | 6 |
| | — |
|
| Mississippi Power | — |
| | — |
| | — |
| | 40 |
| | 893 |
|
| Southern Power | — |
| | — |
| | — |
| | 3 |
| | 3 |
|
Southern Company Gas(c) | 450 |
| | — |
| | — |
| | — |
| | — |
|
| Other | — |
| | — |
| | — |
| | — |
| | 8 |
|
Elimination(d) | — |
| | — |
| | — |
| | (40 | ) | | (591 | ) |
| Southern Company Consolidated | $ | 2,450 |
| | $ | 735 |
| | $ | 27 |
| | $ | 509 |
| | $ | 716 |
|
| |
| (a) | Includes reductions in capital lease obligations resulting from cash payments under capital leases. |
| |
| (b) | Represents the Southern Company parent entity. |
| |
| (c) | The senior notes were issued by Southern Company Gas Capital and guaranteed by the Southern Company Gas parent entity. |
| |
| (d) | Intercompany loans from Southern Company to Mississippi Power eliminated in Southern Company's Consolidated Financial Statements. |
In March 2017, Southern Company repaid at maturity a $400 million 18-month floating rate bank loan.
In June 2017, Southern Company issued $500 million aggregate principal amount of Series 2017A 5.325% Junior Subordinated Notes due June 21, 2057. The proceeds were used to repay short-term indebtedness and for other general corporate purposes.
Also in June 2017, Southern Company issued $300 million aggregate principal amount of Series 2017A Floating Rate Senior Notes due September 30, 2020, which bear interest at a floating rate based on three-month LIBOR. The proceeds were used to repay short-term indebtedness and for other general corporate purposes.
Also in June 2017, Southern Company entered into two $100 million aggregate principal amount floating rate bank term loan agreements, which mature on June 21, 2018 and June 29, 2018 and bear interest based on one-month LIBOR. The proceeds were used for working capital and 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.
A portion of the proceeds of Gulf Power's senior note issuances was used in June 2017 to redeem 550,000 shares ($55 million aggregate liquidation amount) of Gulf Power's 6.00% Series Preference Stock, 450,000 shares ($45 million aggregate liquidation amount) of Gulf Power's Series 2007A 6.45% Preference Stock, and 500,000 shares ($50 million aggregate liquidation amount) of Gulf Power's Series 2013A 5.60% Preference Stock.
In March 2017, Gulf Power extended the maturity of a $100 million short-term floating rate bank loan bearing interest based on one-month LIBOR from April 2017 to October 2017 and subsequently repaid the loan in May 2017.
In June 2017, Georgia Power entered into three floating rate bank loans in aggregate principal amounts of $50 million, $150 million, and $100 million, which mature on December 1, 2017, May 31, 2018, and June 28, 2018,
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
respectively, and bear interest based on one-month LIBOR. Also in June 2017, Georgia Power borrowed $500 million pursuant to an uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Georgia Power and the bank from time to time and is payable on no less than 30 days' demand by the bank. The proceeds from these bank loans were used to repay a portion of Georgia Power's existing indebtedness and for working capital and other general corporate purposes, including Georgia Power's continuous construction program.
In June 2017, Mississippi Power prepaid $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018.
Subsequent to June 30, 2017, Nicor Gas agreed to issue $400 million aggregate principal amount of First Mortgage Bonds in a private placement, $200 million of which is expected to be issued in each of August 2017 and November 2017.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company and its subsidiaries plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
PART I
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
During the six months ended June 30, 2017, there were no material changes to Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, and Southern Power's disclosures about market risk. For additional market risk disclosures relating to Gulf Power and Southern Company Gas, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Gulf Power and Southern Company Gas, respectively, herein. For an in-depth discussion of each registrant's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of each registrant in Item 7 of the Form 10-K and Note 1 to the financial statements of each registrant under "Financial Instruments," Note 11 to the financial statements of Southern Company, Alabama Power, and Georgia Power, Note 10 to the financial statements of Gulf Power, Mississippi Power, and Southern Company Gas, and Note 9 to the financial statements of Southern Power in Item 8 of the Form 10-K. Also see Note (C) and Note (H) to the Condensed Financial Statements herein for information relating to derivative instruments.
Item 4. Controls and Procedures.
| |
| (a) | Evaluation of disclosure controls and procedures. |
As of the end of the period covered by this Quarterly Report on Form 10-Q, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas conducted separate evaluations under the supervision and with the participation of each company's management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Sections 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended). Based upon these evaluations, the Chief Executive Officer and the Chief Financial Officer, in each case, concluded that the disclosure controls and procedures are effective.
| |
| (b) | Changes in internal controls over financial reporting. |
There have been no changes in Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended) during the second quarter 2017 that have materially affected or are reasonably likely to materially affect Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting.
ALABAMA POWER COMPANY
ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | |
| Retail revenues | $ | 1,333 |
| | $ | 1,316 |
| | $ | 2,560 |
| | $ | 2,510 |
|
| Wholesale revenues, non-affiliates | 68 |
| | 67 |
| | 133 |
| | 130 |
|
| Wholesale revenues, affiliates | 32 |
| | 9 |
| | 65 |
| | 31 |
|
| Other revenues | 51 |
| | 52 |
| | 108 |
| | 105 |
|
| Total operating revenues | 1,484 |
| | 1,444 |
| | 2,866 |
| | 2,776 |
|
| Operating Expenses: | | | | | | | |
| Fuel | 303 |
| | 295 |
| | 601 |
| | 564 |
|
| Purchased power, non-affiliates | 40 |
| | 40 |
| | 75 |
| | 76 |
|
| Purchased power, affiliates | 34 |
| | 55 |
| | 62 |
| | 88 |
|
| Other operations and maintenance | 375 |
| | 355 |
| | 743 |
| | 747 |
|
| Depreciation and amortization | 183 |
| | 175 |
| | 364 |
| | 347 |
|
| Taxes other than income taxes | 95 |
| | 94 |
| | 191 |
| | 191 |
|
| Total operating expenses | 1,030 |
| | 1,014 |
| | 2,036 |
| | 2,013 |
|
| Operating Income | 454 |
| | 430 |
| | 830 |
| | 763 |
|
| Other Income and (Expense): | | | | | | | |
| Allowance for equity funds used during construction | 8 |
| | 6 |
| | 16 |
| | 16 |
|
| Interest expense, net of amounts capitalized | (77 | ) | | (74 | ) | | (153 | ) | | (147 | ) |
| Other income (expense), net | 1 |
| | (4 | ) | | (4 | ) | | (11 | ) |
| Total other income and (expense) | (68 | ) | | (72 | ) | | (141 | ) | | (142 | ) |
| Earnings Before Income Taxes | 386 |
| | 358 |
| | 689 |
| | 621 |
|
| Income taxes | 151 |
| | 140 |
| | 277 |
| | 242 |
|
| Net Income | 235 |
| | 218 |
| | 412 |
| | 379 |
|
| Dividends on Preferred and Preference Stock | 5 |
| | 5 |
| | 9 |
| | 9 |
|
| Net Income After Dividends on Preferred and Preference Stock | $ | 230 |
| | $ | 213 |
| | $ | 403 |
| | $ | 370 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) |
| Net Income | $ | 235 |
| | $ | 218 |
| | $ | 412 |
| | $ | 379 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
| Changes in fair value, net of tax of $-, $-, $-, and $(1), respectively | — |
| | — |
| | — |
| | (2 | ) |
Reclassification adjustment for amounts included in net income,
net of tax of $1, $-, $1, and $1, respectively | 1 |
| | 1 |
| | 2 |
| | 2 |
|
| Total other comprehensive income (loss) | 1 |
| | 1 |
| | 2 |
| | — |
|
| Comprehensive Income | $ | 236 |
| | $ | 219 |
| | $ | 414 |
| | $ | 379 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
|
| | | | | | | |
| | For the Six Months Ended June 30, |
| | 2017 | | 2016 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 412 |
| | $ | 379 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 442 |
| | 419 |
|
| Deferred income taxes | 192 |
| | 175 |
|
| Pension, postretirement, and other employee benefits | (24 | ) | | (23 | ) |
| Other, net | 4 |
| | (33 | ) |
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (58 | ) | | 64 |
|
| -Fossil fuel stock | 13 |
| | (32 | ) |
| -Other current assets | (75 | ) | | (67 | ) |
| -Accounts payable | (154 | ) | | (75 | ) |
| -Accrued taxes | 52 |
| | 102 |
|
| -Accrued compensation | (74 | ) | | (50 | ) |
| -Retail fuel cost over recovery | (65 | ) | | (60 | ) |
| -Other current liabilities | 7 |
| | 8 |
|
| Net cash provided from operating activities | 672 |
| | 807 |
|
| Investing Activities: | | | |
| Property additions | (738 | ) | | (645 | ) |
| Nuclear decommissioning trust fund purchases | (117 | ) | | (200 | ) |
| Nuclear decommissioning trust fund sales | 117 |
| | 200 |
|
| Cost of removal, net of salvage | (54 | ) | | (51 | ) |
| Change in construction payables | 48 |
| | (27 | ) |
| Other investing activities | (15 | ) | | (18 | ) |
| Net cash used for investing activities | (759 | ) | | (741 | ) |
| Financing Activities: | | | |
| Proceeds — | | | |
| Senior notes | 550 |
| | 400 |
|
| Capital contributions from parent company | 327 |
| | 237 |
|
| Other long-term debt | — |
| | 45 |
|
| Redemptions — Senior notes | (200 | ) | | (200 | ) |
| Payment of common stock dividends | (357 | ) | | (382 | ) |
| Other financing activities | (14 | ) | | (17 | ) |
| Net cash provided from financing activities | 306 |
| | 83 |
|
| Net Change in Cash and Cash Equivalents | 219 |
| | 149 |
|
| Cash and Cash Equivalents at Beginning of Period | 420 |
| | 194 |
|
| Cash and Cash Equivalents at End of Period | $ | 639 |
| | $ | 343 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
| Interest (net of $6 and $7 capitalized for 2017 and 2016, respectively) | $ | 140 |
| | $ | 131 |
|
| Income taxes, net | 88 |
| | (122 | ) |
| Noncash transactions — Accrued property additions at end of period | 132 |
| | 94 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At June 30, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 639 |
| | $ | 420 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 357 |
| | 348 |
|
| Unbilled revenues | | 161 |
| | 146 |
|
| Other accounts and notes receivable | | 36 |
| | 27 |
|
| Affiliated | | 33 |
| | 40 |
|
| Accumulated provision for uncollectible accounts | | (9 | ) | | (10 | ) |
| Fossil fuel stock | | 191 |
| | 205 |
|
| Materials and supplies | | 443 |
| | 435 |
|
| Prepaid expenses | | 86 |
| | 34 |
|
| Other regulatory assets, current | | 135 |
| | 149 |
|
| Other current assets | | 7 |
| | 11 |
|
| Total current assets | | 2,079 |
| | 1,805 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 26,466 |
| | 26,031 |
|
| Less: Accumulated provision for depreciation | | 9,354 |
| | 9,112 |
|
| Plant in service, net of depreciation | | 17,112 |
| | 16,919 |
|
| Nuclear fuel, at amortized cost | | 333 |
| | 336 |
|
| Construction work in progress | | 668 |
| | 491 |
|
| Total property, plant, and equipment | | 18,113 |
| | 17,746 |
|
| Other Property and Investments: | | | | |
| Equity investments in unconsolidated subsidiaries | | 67 |
| | 66 |
|
| Nuclear decommissioning trusts, at fair value | | 848 |
| | 792 |
|
| Miscellaneous property and investments | | 119 |
| | 112 |
|
| Total other property and investments | | 1,034 |
| | 970 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 526 |
| | 525 |
|
| Deferred under recovered regulatory clause revenues | | 6 |
| | 150 |
|
| Other regulatory assets, deferred | | 1,209 |
| | 1,157 |
|
| Other deferred charges and assets | | 166 |
| | 163 |
|
| Total deferred charges and other assets | | 1,907 |
| | 1,995 |
|
| Total Assets | | $ | 23,133 |
| | $ | 22,516 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholder's Equity | | At June 30, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 361 |
| | $ | 561 |
|
| Accounts payable — | | | | |
| Affiliated | | 242 |
| | 297 |
|
| Other | | 317 |
| | 433 |
|
| Customer deposits | | 91 |
| | 88 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 39 |
| | 45 |
|
| Other accrued taxes | | 97 |
| | 42 |
|
| Accrued interest | | 81 |
| | 78 |
|
| Accrued compensation | | 125 |
| | 193 |
|
| Other regulatory liabilities, current | | 15 |
| | 85 |
|
| Other current liabilities | | 63 |
| | 76 |
|
| Total current liabilities | | 1,431 |
| | 1,898 |
|
| Long-term Debt | | 7,082 |
| | 6,535 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 4,842 |
| | 4,654 |
|
| Deferred credits related to income taxes | | 64 |
| | 65 |
|
| Accumulated deferred ITCs | | 113 |
| | 110 |
|
| Employee benefit obligations | | 269 |
| | 300 |
|
| Asset retirement obligations | | 1,543 |
| | 1,503 |
|
| Other cost of removal obligations | | 648 |
| | 684 |
|
| Other regulatory liabilities, deferred | | 84 |
| | 100 |
|
| Other deferred credits and liabilities | | 69 |
| | 63 |
|
| Total deferred credits and other liabilities | | 7,632 |
| | 7,479 |
|
| Total Liabilities | | 16,145 |
| | 15,912 |
|
| Redeemable Preferred Stock | | 85 |
| | 85 |
|
| Preference Stock | | 196 |
| | 196 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, par value $40 per share — | | | | |
| Authorized — 40,000,000 shares | | | | |
| Outstanding — 30,537,500 shares | | 1,222 |
| | 1,222 |
|
| Paid-in capital | | 2,950 |
| | 2,613 |
|
| Retained earnings | | 2,564 |
| | 2,518 |
|
| Accumulated other comprehensive loss | | (29 | ) | | (30 | ) |
| Total common stockholder's equity | | 6,707 |
| | 6,323 |
|
| Total Liabilities and Stockholder's Equity | | $ | 23,133 |
| | $ | 22,516 |
|
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
Retail RevenuesSECOND QUARTER 2017 vs. SECOND QUARTER 2016
|
| | | | | | |
| 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 quarterYEAR-TO-DATE 2017 vs. YEAR-TO-DATE 2016 retail revenues were $1.63 billion compared to $1.56 billion for the corresponding period in 2015. For year-to-date 2016, retail revenues were $4.14 billion compared to $4.15 billion for the corresponding period in 2015.
Details of the changes in retail revenues were as follows:
|
| | | | | | | | | | | | | |
| | Third Quarter 2016 |
| Year-to-Date 2016 |
| | (in millions) |
| (% change) |
| (in millions) |
| (% change) |
| Retail – prior year | $ | 1,558 |
| | | | $ | 4,151 |
| | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 42 |
| | 2.7 |
| | 119 |
| | 2.9 |
|
| Sales growth (decline) | (14 | ) | | (0.9 | ) | | (15 | ) | | (0.4 | ) |
| Weather | 52 |
| | 3.4 |
| | 5 |
| | 0.1 |
|
| Fuel and other cost recovery | (9 | ) | | (0.6 | ) | | (121 | ) | | (2.9 | ) |
| Retail – current year | $ | 1,629 |
| | 4.6 | % | | $ | 4,139 |
| | (0.3 | )% |
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 increased revenues under Rate 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 declined in the third quarter and year-to-date 2016 when compared to the corresponding periods in 2015. Industrial KWH sales decreased 6.3% and 5.1% for the third quarter and year-to-date 2016, respectively, when compared to the corresponding periods in 2015 as a result of a decrease in demand resulting from changes in production levels primarily in the primary metals, chemicals, pipelines, paper, and stone, clay, and glass sectors. A strong dollar, low oil prices, and weak global economic conditions have constrained 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 2016 when compared to the corresponding period in 2015 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
OVERVIEW
Alabama Power operates as a vertically integrated utility providing electric service to retail and wholesale customers within its traditional service territory located in the State of Alabama in addition to wholesale customers in the Southeast.
Wholesale Revenues – Non-Affiliates
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $17 | | 26.2 | | $23 | | 12.2 |
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices,Many factors affect the market prices of wholesale energy compared to the costopportunities, challenges, and risks of Alabama Power's business of providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and the Southern Company system's generation,grow energy sales, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand for energy within the Southern Company system's electric service territory,growth, stringent environmental standards, reliability, fuel, capital expenditures, and the availability of the Southern Company system's generation. Increasesrestoration following major storms. Alabama Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuelappropriately balancing required costs and do not affect net income.
In the third quarter 2016, wholesale revenues from salescapital expenditures with customer prices will continue to non-affiliates were $82 million compared to $65 millionchallenge Alabama Power for the corresponding period in 2015. The increase was primarily due to a 45.3% increase in KWH sales as the result of a new wholesale contract effective December 2015, partially offset by a 13.4% decrease in the price of energy as a result of lower gas prices. For year-to-date 2016, wholesale revenues from sales to non-affiliates were $211 million compared to $188 million for the corresponding period in 2015. The increase was primarily due to a 29.7% increase in KWH sales as a result of a new wholesale contract effective December 2015, partially offset by a 13.1% decrease in the price of energy as a result of lower gas prices.foreseeable future.
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | | | |
| | | Third Quarter 2016
vs.
Third Quarter 2015 | | Year-to-Date 2016
vs.
Year-to-Date 2015 |
| | | (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| Fuel | | $ | 2 |
| | 0.5 | | $ | (88 | ) | | (8.3 | ) |
| Purchased power – non-affiliates | | 7 |
| | 12.5 | | (3 | ) | | (2.1 | ) |
| Purchased power – affiliates | | (10 | ) | | (19.6) | | (24 | ) | | (15.7 | ) |
| Total fuel and purchased power expenses | | $ | (1 | ) | | | | $ | (115 | ) | | |
For year-to-date 2016, fuel and purchased power expenses were $1.24 billion compared to $1.36 billion for the corresponding period in 2015. The decrease was primarily due to a $56 million decrease related to the average cost of fuel, a $43 million decrease related to the average cost of purchased power, and a $35 million decrease related to the volume of KWHs generated. These decreases were partially offset by a $19 million increase in the volume of KWHs purchased.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Alabama Power's energy cost recovery clause. Alabama Power along with the Alabama PSC, continuously monitors the under/over recovered balancecontinues to determine whether adjustmentsfocus on several key performance indicators including, but not limited 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.customer satisfaction, plant availability, system reliability, and net income after dividends on preferred and preference stock.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of Alabama Power's generation and purchased power were as follows:
|
| | | | | | | |
| | Third Quarter 2016 | | Third Quarter 2015 | | Year-to-Date 2016 |
| Year-to-Date 2015 |
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 | 59 | | 61 | | 51 | | 56 |
| Nuclear | 22 | | 23 | | 24 | | 23 |
| Gas | 18 | | 14 | | 19 | | 16 |
| Hydro | 1 | | 2 | | 6 | | 5 |
Cost of fuel, generated (in cents per net KWH) — | | | | | | | |
| Coal | 2.73 | | 2.79 | | 2.80 | | 2.85 |
| Nuclear | 0.77 | | 0.81 | | 0.78 | | 0.81 |
| Gas | 2.85 | | 3.11 | | 2.62 | | 3.08 |
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
For year-to-date 2016, fuel expense was $0.97 billion compared to $1.06 billion for the corresponding period in 2015. The decrease was primarily due to a 14.9% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, and a 10.4% decrease in the volume of KWHs generated by coal, partially offset by a 17.4% increase in the volume of KWHs generated by natural gas.
Purchased Power – Non-Affiliates
In the third quarter 2016, purchased power expense from non-affiliates was $63 million compared to $56 million for the corresponding period in 2015. The increase was primarily due to a 47.8% increase in the amount of energy purchased as a result of lower cost generation, partially offset by a 23.5% decrease in the average cost of purchased power per KHW due to a decrease in transmission capacity charges.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the third quarter 2016, purchased power expense from affiliates was $41 million compared to $51 million for the corresponding period in 2015. The decrease was primarily due to a 14.4% decrease in the average cost of purchased power per KWH as a result of lower capacity charges and a 4.4% decrease in the amount of energy purchased due to the availability of lower cost energy.
For year-to-date 2016, purchased power expense from affiliates was $129 million compared to $153 million for the corresponding period in 2015. The decrease was primarily related to a 17.3% decrease in the average cost of purchased power per KWH as a result of lower natural gas prices.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(23) | | (6.2) | | $(43) | | (3.8) |
In the third quarter 2016, other operations and maintenance expenses were $348 million compared to $371 million for the corresponding period in 2015. The decrease was primarily due to a net decrease of $8 million in employee compensation and benefits, including pension costs. In addition, scheduled other power generation outage costs and uncollectible customer account expenses decreased $8 million and $3 million, respectively.
For year-to-date 2016, other operations and maintenance expenses were $1.10 billion compared to $1.14 billion for the corresponding period in 2015. The decrease was primarily due to a net decrease of $22 million in employee compensation and benefits, including pension costs. In addition, scheduled steam and other power generation outage costs decreased $18 million.
See Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.
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) |
| $14 | | 8.6 | | $43 | | 8.9 |
In the third quarter 2016, depreciation and amortization was $177 million compared to $163 million for the corresponding period in 2015. For year-to-date 2016, depreciation and amortization was $524 million compared to $481 million for the corresponding period in 2015. These increases were primarily the result of an increase in depreciation of compliance related steam equipment. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate CNP" in Item 8 of the Form 10-K for additional information.
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) |
| $5 | | 5.5 | | $11 | | 4.0 |
In the third quarter 2016, taxes other than income taxes were $96 million compared to $91 million for the corresponding period in 2015. For year-to-date 2016, taxes other than income taxes were $286 million compared to $275 million for the corresponding period in 2015. These increases were primarily due to increases in state and municipal utility license tax bases and increases in ad valorem taxes primarily due to an increase in assessed value of 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) |
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $13 | | 28.9 | | $17 | | 17.3 |
In the thirdsecond quarter 2016,2017, AFUDC equity was $7$58 million compared to $14$45 million forin the corresponding period in 2015.2016. For year-to-date 2016,2017, AFUDC equity was $23$115 million compared to $43$98 million forin the corresponding period in 2015.2016. These decreasesincreases primarily resulted from a higher AFUDC rate and an increase in Kemper IGCC CWIP subject to AFUDC prior to project suspension at Mississippi Power.
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
Earnings from Equity Method Investments
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $29 | | N/M | | $68 | | N/M |
N/M - Not meaningful
In the second quarter and year-to-date 2017, earnings from equity method investments were $28 million and $67 million, respectively, primarily associatedrelated to earnings from Southern Company Gas' equity method investment in SNG effective September 2016.
See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with environmental compliance and steam generation capital projects being placed in service in 2016.Southern Company Gas" herein for additional information.
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 |
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $131 | | 44.7 | | $301 | | 55.8 |
In the thirdsecond quarter 2016,2017, interest expense, net of amounts capitalized was $77$424 million compared to $71$293 million forin the corresponding period in 2015. The increase was primarily due to an increase in debt outstanding and a reduction in amounts capitalized.
2016. For year-to-date 2016,2017, interest expense, net of amounts capitalized was $224$840 million compared to $205$539 million in the corresponding period in 2016. These increases were primarily due to an increase in average outstanding long-term debt primarily related to the Merger and the funding of Southern Power's acquisitions and construction projects. In addition, following the Merger, $48 million and $94 million in interest expense of Southern Company Gas was included in the consolidated statements of income for the second quarter and year-to-date 2017, respectively.
See Note (E) to the Condensed Financial Statements herein and Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
Other Income (Expense), Net
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $25 | | 89.3 | | $45 | | 80.4 |
In the second quarter 2017, other income (expense), net was $(3) million compared to $(28) million for the corresponding period in 2015.2016. For year-to-date 2017, other income (expense), net was $(11) million compared to $(56) million for the corresponding period in 2016. These changes were primarily due to expenses incurred in 2016 associated with bridge financing for the Merger. These changes also include increases of $99 million and $116 million in currency losses arising from a translation of euro-denominated fixed-rate notes into U.S. dollars for the second quarter and year-to-date 2017, respectively, fully offset by an equal change in gains on the foreign currency hedges that were reclassified from accumulated OCI into earnings at Southern Power.
See Note (H) to the Condensed Financial Statements under "Foreign Currency Derivatives" herein for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Income Taxes (Benefit)
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(848) | | N/M | | $(752) | | N/M |
N/M - Not meaningful
In the second quarter 2017, income tax benefit was $587 million compared to income tax expense of $261 million for the corresponding period in 2016. The increasedecrease was primarily due to an$865 million in tax benefits related to the estimated probable losses on the Kemper IGCC at Mississippi Power, partially offset by $31 million in taxes at Southern Company Gas following the Merger.
For year-to-date 2017, income tax benefit was $273 million compared to income tax expense of $479 million for the corresponding period in 2016, primarily due to $886 million in tax benefits related to the estimated probable losses on the Kemper IGCC at Mississippi Power. In addition, the change reflects $180 million in taxes at Southern Company Gas following the Merger, partially offset by a net increase in debt outstandingtax benefits of $16 million from renewable tax credits at Southern Power.
See Note (G) to the Condensed Financial Statements herein and Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern Company's future earnings potential. The level of Southern Company's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Southern Company system's primary businesses of selling electricity and distributing natural gas. These factors include the traditional electric operating companies' and the natural gas distribution utilities' ability to maintain a reductionconstructive regulatory environment that allows for the timely recovery of prudently-incurred costs during a time of increasing costs and limited projected demand growth over the next several years. Completion of cost assessments and the determination of future actions related to Plant Vogtle Units 3 and 4 construction and rate recovery and the ability to recover costs for the remainder of the Kemper County energy facility not included in amounts capitalized. See "Allowancecurrent rates are also major factors. In addition, the profitability of Southern Power's competitive wholesale business and successful additional investments in renewable and other energy projects are also major factors.
Current proposals related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals, including any potential changes to the availability or realizability of ITCs and PTCs, is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Southern Company's financial statements.
Future earnings for Equity Funds Used During Construction" herein,the electricity and natural gas businesses will be driven primarily by customer growth. Earnings in the electricity business will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies, increasing volumes of electronic commerce transactions, and higher multi-family home construction. Earnings for both the electricity and natural gas businesses are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the prices of electricity and natural gas, the price elasticity of demand, and the rate of economic growth or decline in the service territory. In addition, the level of future earnings for the wholesale electric business also depends on numerous factors including regulatory matters, creditworthiness of customers, total electric generating capacity available and related costs, future acquisitions and construction of electric generating facilities, the impact of tax credits from renewable energy projects, and the successful remarketing of capacity as current contracts expire. Demand for electricity and natural gas is primarily driven by economic growth. The pace of economic growth and electricity and natural gasdemand may be affected by changes
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
in regional and global economic conditions, which may impact future earnings. In addition, the volatility of natural gas prices has a significant impact on the natural gas distribution utilities' customer rates, long-term competitive position against other energy sources, and the ability of Southern Company Gas' gas marketing services and wholesale gas services businesses to capture value from locational and seasonal spreads. Additionally, changes in commodity prices subject a significant portion of Southern Company Gas' operations to earnings variability.
As part of its ongoing effort to adapt to changing market conditions, Southern Company continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, partnerships, and acquisitions involving other utility or non-utility businesses or properties, disposition of certain assets or businesses, internal restructuring, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations, risks, and financial condition of Southern Company.
For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Financing Activities – Financial Conditionof Southern Company in Item 7 of the Form 10-K and Liquidity" herein,RISK FACTORS in Item 1A herein.
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis for the traditional electric operating companies and the natural gas distribution utilities or through long-term wholesale agreements for the traditional electric operating companies and Southern Power. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity and natural gas, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company in Item 7 and Note 63 to the financial statements of Alabama PowerSouthern Company under "Senior Notes""Environmental Matters" in Item 8 of the Form 10-K for additional information.
Other Income (Expense)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 eight-hour ozone National Ambient Air Quality Standard (NAAQS).
On June 2, 2017, the EPA published a final rule redesignating a 15-county area within metropolitan Atlanta to attainment for the 2008 eight-hour ozone NAAQS.
On June 18, 2017, the EPA published a notice delaying attainment designations for the 2015 eight-hour ozone NAAQS by one year, setting a revised deadline of October 1, 2018. The ultimate outcome of this matter 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 final effluent guidelines rule and the final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
On April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. On June 6, 2017, the EPA proposed a rule establishing a stay of the compliance deadlines for certain effluent limitations and pretreatment standards under the rule.
On June 27, 2017, the EPA and the U.S. Army Corps of Engineers proposed to rescind the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.
The ultimate outcome of these matters cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Southern Company in Item 7 of the Form 10-K for additional information.
On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules.
On June 1, 2017, the U.S. President announced that the United States will withdraw from the non-binding Paris Agreement and begin renegotiation of its terms.
The ultimate outcome of these matters cannot be determined at this time.
FERC Matters
Market-Based Rate Authority
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters – Market-Based Rate Authority" of Southern Company in Item 7 of the Form 10-K for additional information regarding the traditional electric operating companies' and Southern Power's market power proceeding and amendment to their market-rate tariff.
On May 17, 2017, the FERC accepted the traditional electric operating companies' and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' and Southern Power's market power proceeding, it remains a separate, ongoing matter.
Southern Company Gas
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters – Southern Company Gas" of Southern Company in Item 7 and Note 4 to the financial statements of Southern Company in Item 8 of the Form 10-K for additional information regarding Southern Company Gas' pipeline projects.
On August 1, 2017, the Dalton Pipeline was placed in service as authorized by the FERC and transportation service for customers commenced.
Regulatory Matters
Fuel Cost Recovery
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Fuel Cost Recovery" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Regulatory Matters – Alabama Power – Rate ECR" and "Regulatory Matters – Georgia Power –
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding fuel cost recovery for the traditional electric operating companies.
The traditional electric operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow. The traditional electric operating companies continuously monitor their under or over recovered fuel cost balances and make appropriate filings with their state PSCs to adjust fuel cost recovery rates as necessary.
Renewables
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "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.
On May 16, 2017, the Georgia PSC approved Georgia Power's request to build, own, and operate a 139-MW solar generation facility at a U.S. Air Force base that is expected to be placed in service by the end of 2019.
During the six months ended June 30, 2017, Georgia Power continued construction of a 31-MW solar generation facility at a U.S. Marine Corps base that is expected to be placed in service in the fourth quarter 2017.
Mississippi Power placed in service two solar projects in January 2017 and June 2017. A third solar project is expected to be placed in service in the third quarter 2017. Mississippi Power may retire the renewable energy credits (REC) generated on behalf of its customers or sell the RECs, separately or bundled with energy, to third parties.
On June 9, 2017, Mississippi Power submitted a CPCN to the Mississippi PSC for the approval of construction, operation, and maintenance of a 52.5-MW solar energy generating facility, which, if approved, is expected to be placed in service by January 2020.
The ultimate outcome of these matters cannot be determined at this time.
Alabama Power
Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See Note 3 to the financial statements of Southern Company under "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.
Georgia Power
Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, Environmental Compliance Cost Recovery tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to the construction of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a separate fuel cost recovery tariff. See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein and Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding Georgia Power's NCCR tariff. Also see Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Fuel Cost Recovery" herein for additional information regarding Georgia Power's fuel cost recovery.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Integrated Resource Plan
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "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.
On March 7, 2017, the Georgia PSC approved Georgia Power's decision to suspend work at a future generation site in Stewart County, Georgia, due to changing economics, including load forecasts and lower fuel costs. The timing of recovery for costs incurred of approximately $50 million will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time.
Gulf Power
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Gulf Power" of Southern Company in Item 7 of the Form 10-K for additional information regarding Gulf Power's October 2016 request to the Florida PSC to increase retail base rates and Gulf Power's ownership of Plant Scherer Unit 3.
On April 4, 2017, the Florida PSC approved the 2017 Rate Case Settlement Agreement among Gulf Power and three intervenors with respect to Gulf Power's request to increase retail base rates. Under the terms of the 2017 Rate Case Settlement Agreement, Gulf Power increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consists of a $62.0 million increase in annual base revenues less an annual equivalent credit of approximately $7.7 million for 2017 for certain wholesale revenues to be provided through December 2019 through the purchased power capacity cost recovery clause. In addition, Gulf Power continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%) and is deemed to have an equity ratio of 52.5% for all retail regulatory purposes. Gulf Power will also begin amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 (357 MWs) over 15 years effective January 1, 2018 and will implement new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs), Netwhich was recorded in the first quarter 2017. The remaining issues related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause rate approved by the Florida PSC in November 2016.
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. Changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flows.
Base Rate Cases
On March 10, 2017, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $208 million increase in annual base rate revenues. The requested increase is based on a 2018 projected test year and a ROE of 10.7%. The Illinois Commission is expected to rule on the requested increase within the 11-month statutory time limit, after which rate adjustments will be effective. The ultimate outcome of this matter cannot be determined at this time.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Construction Program
Overview
The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue its strategy of developing and constructing new electric generating facilities, adding environmental modifications to certain existing units, expanding the electric transmission and distribution systems, and updating and expanding the natural gas distribution systems. For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. Southern Company Gas is engaged in various infrastructure improvement programs designed to update or expand the natural gas distribution systems of the natural gas distribution utilities to improve reliability and meet operational flexibility and growth. The natural gas distribution utilities recover their investment and a return associated with these infrastructure programs through their regulated rates.
The largest construction project currently underway in the Southern Company system is Plant Vogtle Units 3 and 4 (45.7% ownership interest by Georgia Power in the two units, each with approximately 1,100 MWs). Georgia Power and the other Vogtle Owners are continuing to conduct comprehensive schedule and cost-to-complete assessments, as well as cancellation cost assessments, to determine the impact of the EPC Contractor's bankruptcy filing on the construction cost and schedule for Plant Vogtle Units 3 and 4. Georgia Power will continue working with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4, including, but not limited to, the status of construction and rate recovery, and currently expects to include its recommendation in its seventeenth VCM report to be filed with the Georgia PSC in late August 2017. On June 21, 2017, the Mississippi PSC directed Mississippi Power to pursue a settlement under which the Kemper IGCC would be operated as a natural gas plant rather than an IGCC plant and, on June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the plant. See Note 3 to the financial statements of Southern Company under "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 "Regulatory Matters– Georgia Power– Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for additional information. For additional information about costs relating to Southern Power's acquisitions that involve construction of renewable energy facilities, see Note 12 to the financial statements of Southern Company under "Southern Power – Construction Projects" in Item 8 of the Form 10-K and Note (I) to the Condensed Financial Statements under "Southern Power" herein. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Southern Company Gas – Regulatory Infrastructure Programs" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters–Southern Company Gas–Regulatory Infrastructure Programs" herein for information regarding infrastructure improvement programs at the natural gas distribution utilities.
Also see FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information regarding Southern Company's capital requirements for its subsidiaries' construction programs.
Integrated Coal Gasification Combined Cycle
The Kemper IGCC was approved by the Mississippi PSC in the 2010 CPCN proceedings, subject to a construction cost cap of $2.88 billion, net of $245 million of Initial DOE Grants and excluding the Cost Cap Exceptions. The combined cycle and associated common facilities portion of the Kemper IGCC were placed in service in August 2014.
In December 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order), based on a stipulation between Mississippi Power and the Mississippi Public Utilities Staff, authorizing rates that provide for the recovery of approximately $126 million annually related to the combined cycle and associated common facilities portion of Kemper IGCC assets previously placed in service. As required by the In-Service Asset Rate Order, on June 5, 2017,
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Mississippi Power made a rate filing requesting to adjust the amortization schedules of the regulatory assets reviewed and determined prudent in a manner that would not change customer rates or annual revenues. On June 28, 2017, the Mississippi PSC suspended this filing. On July 6, 2017, the Mississippi PSC issued an order requiring Mississippi Power to establish a regulatory liability account to maintain current rates related to the Kemper IGCC following the July 2017 completion of the amortization period for certain regulatory assets approved in the In-Service Asset Rate Order that would allow for subsequent refund if the Mississippi PSC deems the rates unjust and unreasonable.
The remainder of the plant includes 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." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO2, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. Most recently, in May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast has decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations increased significantly since certification.
On June 21, 2017, the Mississippi PSC stated its intent to issue the Kemper Settlement Order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC. The Kemper Settlement Order established the Kemper IGCC Settlement Docket for the purposes of pursuing a global settlement of costs of the Kemper IGCC. The Mississippi PSC requested any such proposed settlement agreement reflect: (i) at a minimum, no rate increase to Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and related assets; and (iii) modification or amendment of the CPCN for the Kemper IGCC to allow only for ownership and operation of a natural gas facility. The Kemper Settlement Order provides that any related settlement agreement be filed within 45 days from the effective date of the Kemper Settlement Order. If a settlement agreement is filed, a hearing will be set 45 days from the date of the settlement's filing, and the appropriate scheduling order will be established.
Although the ability to achieve a negotiated settlement is uncertain, Mississippi Power intends to pursue any available settlement alternatives. In addition, the Kemper Settlement Order provides that, in the event a settlement agreement is not reached, the Mississippi PSC reserves its right to take any appropriate steps, including issuing an order to show cause as to why the CPCN for the Kemper IGCC should not be revoked.
On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014.
At the time of project suspension, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate subject to the construction cost cap totaling $196 million ($121 million after tax) in the second quarter through May 31, 2017 and a total of $305 million ($188 million after tax) for year-to-date through May 31, 2017. In the aggregate, Mississippi Power incurred charges of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017. The May 31, 2017 cost estimate included approximately $175 million of estimated costs to be incurred beyond the then-estimated in-service date of June 30, 2017 that were expected to be subject to the $2.88 billion cost cap.
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
At June 30, 2017, approximately $3.3 billion in actual Kemper IGCC costs were not reflected in Mississippi Power's retail and wholesale rates, of which $0.5 billion was related to the combined cycle and associated facilities and $2.8 billion was related to the gasification portions of the Kemper IGCC.
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper Settlement Order, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs currently estimated at approximately $100 million to $200 million are expected to be incurred.
Total pre-tax charges to income for the estimated probable losses on the Kemper IGCC were $3.0 billion ($2.1 billion after tax) for the second quarter 2017 and $3.1 billion ($2.2 billion after tax) for the six months ended June 30, 2017. In the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $6.0 billion ($3.9 billion after tax) through June 30, 2017.
As of June 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which $0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility, as well as the 15% that was previously contracted to SMEPA. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.
For additional information on the Kemper IGCC, including information on the project economic viability analysis, pending lawsuits, and an ongoing SEC investigation, see Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and "Other Matters" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein. Also see "Litigation" herein.
Litigation
On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff alleges that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper 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 23, 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the plaintiffs filed notice to appeal to the Mississippi Supreme Court.
On June 9, 2016, Treetop Midstream Services, LLC (Treetop) and other related parties filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint relates to the cancelled CO2 contract with Treetop and alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and seeks
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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, which the court granted on May 4, 2017. On June 28, 2017, Treetop and other related parties filed a claim for arbitration requesting $500 million in damages.
Southern Company believes these legal challenges have no merit; however, an adverse outcome in these proceedings could have a material impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, and the ultimate outcome of these matters cannot be determined at this time.
Nuclear Construction
See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the construction of Plant Vogtle Units 3 and 4, VCM reports, the NCCR tariff, and the Contractor Settlement Agreement.
Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcy
In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Vogtle 3 and 4 Agreement, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4. 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. Georgia Power's proportionate share of Plant Vogtle Units 3 and 4 is 45.7%.
The Vogtle 3 and 4 Agreement also provided for liquidated damages upon the EPC Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to an aggregate cap of 10% of the contract price, or approximately $920 million (approximately $420 million based on Georgia Power's ownership interest). Under the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. In January 2016, Westinghouse delivered to the Vogtle Owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020 and require 60 days' written notice to Georgia Power in the event the Westinghouse Letters of Credit will not be renewed.
Under the terms of the Vogtle 3 and 4 Agreement, the EPC Contractor did not have the right to terminate the Vogtle 3 and 4 Agreement for convenience. In the event of an abandonment of work by the EPC Contractor, the maximum liability of the EPC Contractor under the Vogtle 3 and 4 Agreement was 40% of the contract price (approximately $1.7 billion based on Georgia Power's ownership interest).
On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. To provide for a continuation of work at Plant Vogtle Units 3 and 4, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Interim Assessment Agreement, which the bankruptcy court approved on March 30, 2017.
The Interim Assessment Agreement provided, among other items, that during the term of the Interim Assessment Agreement (i) Georgia Power was obligated to pay, on behalf of the Vogtle Owners, all costs accrued by the EPC Contractor for subcontractors and vendors for services performed or goods provided, with these amounts paid to the EPC Contractor, except that amounts accrued for Fluor Corporation (Fluor) were paid directly to Fluor; (ii) the EPC Contractor provided certain engineering, procurement, and management services for Plant Vogtle Units 3 and 4, to the same extent as contemplated by the Vogtle 3 and 4 Agreement, and Georgia Power, on behalf of the Vogtle Owners, made payments of $5.4 million per week for these services; (iii) Georgia Power had the right to make payments, on behalf of the Vogtle Owners, directly to subcontractors and vendors who had accounts past due with the EPC Contractor; (iv) the EPC Contractor used commercially reasonable efforts to provide information reasonably requested by Georgia Power as was necessary to continue construction and investigation of the
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
completion status of Plant Vogtle Units 3 and 4; (v) the EPC Contractor rejected or accepted the Vogtle 3 and 4 Agreement by the termination of the Interim Assessment Agreement; and (vi) Georgia Power did not exercise any remedies against Toshiba under the Toshiba Guarantee. Under the Interim Assessment Agreement, all parties expressly reserved all rights and remedies under the Vogtle 3 and 4 Agreement and all related security and collateral under applicable law.
The Interim Assessment Agreement, as amended, expired on July 27, 2017. Georgia Power's aggregate liability for the Vogtle Owners under the Interim Assessment Agreement totaled approximately $650 million, of which $552 million had been paid or accrued as of June 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $297 million.
Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor, including Fluor Enterprises, Inc., a subsidiary of Fluor, alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken, and continues to take, actions to remove liens filed by these subcontractors through the posting of surety bonds. Georgia Power estimates the aggregate liability, through July 31, 2017, of the Vogtle Owners for the removal of subcontractor liens and payment of other EPC Contractor pre-petition accounts payable to total approximately $400 million, of which $354 million had been paid or accrued as of June 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $183 million.
On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered the Guarantee Settlement Agreement. Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion, of which Georgia Power's proportionate share is approximately $1.7 billion, and that the Guarantee Obligations exist regardless of whether Plant Vogtle Units 3 and 4 are completed. The Guarantee Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations, beginning in October 2017 and continuing through January 2021. In the event Toshiba receives certain payments, including sale proceeds, from or related to Westinghouse (or its subsidiaries) or Toshiba Nuclear Energy Holdings (UK) Limited (or its subsidiaries), it will hold a portion of such payments in trust for the Vogtle Owners and promptly pay them as offsets against any remaining Guarantee Obligations. Under the Guarantee Settlement Agreement, the Vogtle Owners will forbear from exercising certain remedies, including drawing on the Westinghouse Letters of Credit, until June 30, 2020, unless certain events of nonpayment, insolvency, or other material breach of the Guarantee Settlement Agreement by Toshiba occur. If such an event occurs, the balance of the Guarantee Obligations will become immediately due and payable, and the Vogtle Owners may exercise any and all rights and remedies, including drawing on the Westinghouse Letters of Credit without restriction. In addition, the Guarantee Settlement Agreement does not restrict the Vogtle Owners from fully drawing on the Westinghouse Letters of Credit in the event they are not renewed or replaced prior to the expiration date.
On June 23, 2017, Toshiba released a revised outlook for fiscal year 2016, which reflected a negative shareholders' equity balance of approximately $5 billion as of March 31, 2017, and announced that its independent audit process was continuing. Toshiba has also announced the existence of material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern. As a result, substantial risk regarding the Vogtle Owners' ability to fully collect the Guarantee Obligations continues to exist. An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Southern Company's financial statements.
Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Services Agreement, which was amended and restated on July 20, 2017, for the EPC Contractor to transition construction management of Plant Vogtle Units 3 and 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Services Agreement, (ii) assume and assign to the Vogtle Owners certain project-related contracts, (iii) join the Vogtle Owners as counterparties to certain assumed project-related contracts, and (iv) reject the Vogtle 3 and 4 Agreement.
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE on July 27, 2017. The Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.
The ultimate outcome of these matters cannot be determined at this time.
Regulatory Matters
In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by including the related CWIP accounts in rate base during the construction period. As of June 30, 2017, Georgia Power had recovered approximately $1.4 billion of financing costs.
On December 20, 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving the following prudence matters: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report will be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement is reasonable and prudent and none of the amounts paid or to be paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) financing costs on verified and approved capital costs will be deemed prudent provided they are incurred prior to December 31, 2019 and December 31, 2020 for Plant Vogtle Units 3 and 4, respectively; and (iv) (a) the in-service capital cost forecast will be adjusted to $5.680 billion (Revised Forecast), which includes a contingency of $240 million above Georgia Power's then current forecast of $5.440 billion, (b) capital costs incurred up to the Revised Forecast will be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, and (c) Georgia Power would have the burden to show that any capital costs above the Revised Forecast are reasonable and prudent. Under the terms of the Vogtle Cost Settlement Agreement, the certified in-service capital cost for purposes of calculating the NCCR tariff will remain at $4.418 billion. Construction capital costs above $4.418 billion will accrue AFUDC through the date each unit is placed in service. The ROE used to calculate the NCCR tariff was reduced from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016. For purposes of the AFUDC calculation, the ROE on costs between $4.418 billion and $5.440 billion will also be 10.00% and the ROE on any amounts above $5.440 billion would be Georgia Power's average cost of long-term debt. If the Georgia PSC adjusts Georgia Power's ROE rate setting point in a rate case prior to Plant Vogtle Units 3 and 4 being placed into retail rate base, then the ROE for purposes of calculating both the NCCR tariff and AFUDC will likewise be 95 basis points lower than the revised ROE rate setting point. If Plant Vogtle Units 3 and 4 are not placed in service by December 31, 2020, then (i) the ROE for purposes of calculating the NCCR tariff will be reduced an additional 300 basis points, or $8 million per month, and may, at the Georgia PSC's discretion, be accrued to be used for the benefit of customers, until such time as the units are placed in service and (ii) the ROE used to calculate AFUDC will be Georgia Power's average cost of long-term debt.
Under the terms of the Vogtle Cost Settlement Agreement, the Georgia PSC will determine, for retail ratemaking purposes, the process of transitioning Plant Vogtle Units 3 and 4 from a construction project to an operating plant no later than Georgia Power's base rate case required to be filed by July 1, 2019.
The Georgia PSC has approved fifteen VCM reports covering the periods through June 30, 2016, including construction capital costs incurred, which through that date totaled $3.7 billion. Georgia Power filed its sixteenth VCM report, covering the period from July 1 through December 31, 2016, requesting approval of $222 million of construction capital costs incurred during that period, with the Georgia PSC on February 27, 2017.
The ultimate outcome of these matters cannot be determined at this time.
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Revised Cost and Schedule
Georgia Power and the other Vogtle Owners are continuing to conduct comprehensive schedule and cost-to-complete assessments, as well as cancellation cost assessments, to determine the impact of the EPC Contractor's bankruptcy filing on the construction cost and schedule for Plant Vogtle Units 3 and 4. Georgia Power's preliminary assessment results indicate that its proportionate share of the remaining estimated cost to complete Plant Vogtle Units 3 and 4 ranges as follows:
|
| | | | | | |
| 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 |
|
| | | | | | | |
| Preliminary in-service dates | | | |
| Unit 3 | February 2021 | – | March 2022 |
| Unit 4 | February 2022 | – | March 2023 |
| | (in billions) |
| Preliminary estimated cost to complete | $ | 3.9 |
| – | $ | 4.6 |
|
| CWIP as of June 30, 2017 | 4.5 |
| | 4.5 |
|
| Guarantee Obligations | (1.7 | ) | | (1.7 | ) |
| Estimated capital costs | $ | 6.7 |
| – | $ | 7.4 |
|
| Vogtle Cost Settlement Agreement Revised Forecast | (5.7 | ) | | (5.7 | ) |
| Estimated net additional capital costs | $ | 1.0 |
| – | $ | 1.7 |
|
Georgia Power's estimates for cost to complete and schedule are based on preliminary analysis and remain subject to further refinement of labor productivity and consumable and commodity quantities and costs.
Georgia Power's estimated financing costs during the construction period total approximately $3.1 billion to $3.5 billion, of which approximately $1.4 billion had been incurred through June 30, 2017.
Georgia Power's preliminary cancellation cost estimate results indicate that its proportionate share of the estimated cancellation costs is approximately $400 million. As a result, as of June 30, 2017, total estimated costs subject to evaluation by Georgia Power and the Georgia PSC in the event of a cancellation decision are as follows:
|
| | | |
| | Preliminary Cancellation Cost Estimate |
| | (in billions) |
| CWIP as of June 30, 2017 | $ | 4.5 |
|
| Financing costs collected, net of tax | 1.4 |
|
Cancellation costs(*) | 0.4 |
|
| Total | $ | 6.3 |
|
| |
| (*) | The estimate for cancellation costs includes, but is not limited to, costs to terminate contracts for construction and other services, as well as costs to secure the Plant Vogtle Units 3 and 4 construction site. |
The Guarantee Obligations continue to exist in the event of cancellation. In addition, under Georgia law, prudently incurred costs related to certificated projects cancelled by the Georgia PSC are allowed recovery, including carrying costs, in future retail rates. Georgia Power will continue working with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4, including, but not limited to, the status of construction and rate recovery, and currently expects to include its recommendation in its seventeenth VCM report to be filed with the Georgia PSC in late August 2017.
The ultimate outcome of these matters is dependent on the completion of the assessments described above, as well as the related regulatory treatment, and cannot be determined at this time.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Matters
As of June 30, 2017, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through a loan guarantee agreement between Georgia Power and the DOE and a multi-advance credit facility among Georgia Power, the DOE, and the FFB. See Note 6 to the financial statements of Southern Company under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
The IRS has allocated PTCs to Plant Vogtle Units 3 and 4 which require that the applicable unit be placed in service prior to 2021. The net present value of Georgia Power's PTCs is estimated at approximately $400 million per unit.
There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise if 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 if 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.
If construction continues, the risk remains that challenges with labor productivity, fabrication, delivery, assembly, and installation of plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost.
The ultimate outcome of these matters cannot be determined at this time.
See RISK FACTORS of Southern Company in Item 1A of the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world. See additional risks in Item 1A herein regarding the EPC Contractor's bankruptcy.
Income Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Southern Company in Item 7 of the Form 10-K and Note (G) to the Condensed Financial Statements herein for additional information.
Bonus Depreciation
Approximately $1.2 billion of positive cash flows is expected to result from bonus depreciation for the 2017 tax year, but may not all be realized in 2017 due to net operating loss projections for the 2017 tax year. Approximately $370 million of the 2017 benefit is dependent upon placing the remainder of the Kemper IGCC in service by December 31, 2017. If the suspension of the Kemper IGCC start-up activities results in an abandonment, any amount previously estimated as bonus depreciation would be claimed as a deduction under IRC Section 165. As of June 30, 2017, $82 million has been received through quarterly income tax refunds for bonus depreciation related to the Kemper IGCC, which may be subject to repayment. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein and Note (G) to the Condensed Financial Statements herein for additional information. The ultimate outcome of this matter cannot be determined at this time.
Section 174 Research and Experimental Deduction
Southern Company has reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and filed amended federal income tax returns for
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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2008 through 2013 to also include such deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, subject to approval of the U.S. Congress Joint Committee on Taxation, resolving a methodology for these deductions. Due to the uncertainty related to this tax position, Southern Company had unrecognized tax benefits associated with these R&E deductions totaling approximately $464 million as of June 30, 2017. If the suspension of the Kemper IGCC start-up activities results in an abandonment, any amount not allowed under IRC Section 174 would be claimed as a deduction under IRC Section 165, and would result in a reversal of the related unrecognized tax benefits, excluding interest. See Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Section 174 Research and Experimental Deduction," respectively, herein for additional information. This matter is expected to be resolved in the next 12 months; however, the ultimate outcome of this matter cannot be determined at this time.
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.
TheultimateoutcomeofsuchpendingorpotentiallitigationagainstSouthernCompanyanditssubsidiariescannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatementsherein,management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
On January 20, 2017, a purported securities class action complaint was filed against Southern Company, certain of its officers, and certain former Mississippi Power officers in the U.S. District Court for the Northern District of Georgia, Atlanta Division, by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint alleges that Southern Company, certain of its officers, and certain former Mississippi Power officers made materially false and misleading statements regarding the Kemper IGCC in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. On June 12, 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. On July 27, 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice.
On February 27, 2017, Jean Vineyard filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the defendants caused Southern Company to make false or misleading statements regarding the Kemper IGCC cost and schedule. Further, the complaint alleges that the defendants were unjustly enriched and caused the waste of corporate assets. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on her own behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. On March 27, 2017, the court deferred this lawsuit until 30 days after certain further action in the purported securities class action complaint discussed above.
On May 15, 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia, that names as defendants Southern Company, certain of its directors, certain of
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
its officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper IGCC. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper IGCC schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes.
On June 1, 2017, Judy Mesirov filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia, that names as defendants Southern Company, certain of its current and former directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper IGCC. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper IGCC schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages, disgorgement of profits, and equitable relief and, on her own behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes.
Southern Company believes these legal challenges have no merit; however, an adverse outcome in any of these proceedings could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, the ultimate outcome of which cannot be determined at this time.
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 believes 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. 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 Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, Goodwill and Other Intangible Assets, Derivatives and Hedging Activities, and Contingent Obligations.
Kemper IGCC Rate Recovery
For periods prior to the second quarter 2017, significant accounting estimates included Kemper IGCC estimated construction costs, project completion date, and rate recovery. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Kemper IGCC Estimated Construction Costs, Project Completion Date, and Rate Recovery" of Southern Company in Item 7 of the Form 10-K for additional information. Mississippi
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Power recorded total pre-tax charges to income related to the Kemper IGCC of $428 million ($264 million after tax) in 2016, $365 million ($226 million after tax) in 2015, $868 million ($536 million after tax) in 2014, and $1.2 billion ($729 million after tax) in prior years.
As a result of the Mississippi PSC's June 21, 2017 stated intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant rather than an IGCC plant, as well as Mississippi Power's June 28, 2017 suspension of the operation and start-up of the gasifier portion of the Kemper IGCC, the estimated construction costs and project completion date are no longer considered significant accounting estimates. Significant accounting estimates for the June 30, 2017 financial statements presented herein include the overall assessment of rate recovery for the Kemper County energy facility and the estimated costs for the potential cancellation of the Kemper IGCC.
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper Settlement Order, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs currently estimated at approximately $100 million to $200 million are expected to be incurred.
As of June 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which $0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility, as well as the 15% that was previously contracted to SMEPA. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.
In the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $5.96 billion ($3.94 billion after tax) through June 30, 2017. Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $3.0 billion ($2.1 billion after tax) and $81 million ($50 million after tax) in the second quarter 2017 and the second quarter 2016, respectively, and total pre-tax charges of $3.1 billion ($2.2 billion after tax) and $134 million ($83 million after tax) year-to-date in 2017 and 2016, respectively.
Given the significant judgment involved in estimating the costs to cancel the gasifier portion of the Kemper IGCC, the ultimate rate recovery for the Kemper IGCC, including the $0.5 billion of combined cycle-related costs not yet in rates, and the impact on Southern Company's results of operations, Southern Company considers these items to be critical accounting estimates. See Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Recently Issued Accounting Standards
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
While Southern Company expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Southern Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity or natural gas without a defined
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
contractual term, as well as longer-term contractual commitments, including PPAs and non-derivative natural gas asset management and optimization arrangements. Southern Company expects the adoption of ASC 606 will not result in a significant shift from the current timing of revenue recognition for such transactions.
Southern Company's ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements, such as certain PPAs, energy-related derivatives, and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Southern Company's financial statements. In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Southern Company expects CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Southern Company intends to use the modified retrospective method of adoption effective January 1, 2018. Southern Company has also elected to utilize practical expedients which allow it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Southern Company's financial statements, Southern Company will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.
On January 26, 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for annual and interim periods beginning on or after December 15, 2019, and early adoption is permitted on testing dates after January 1, 2017.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. Southern Company is currently evaluating the new standard. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company's operating income and an increase in other income (expense)for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Southern Company's financial statements.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company in Item 7 of the Form 10-K for additional information. Southern Company's financial condition remained stable at June 30, 2017. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $2.7 billion for the first six months of 2017, an increase of $0.6 billion from the corresponding period in 2016. The increase in net cash provided from operating activities was primarily due to $1.2 billion of net cash provided from operating activities of Southern Company Gas, which was acquired on July 1, 2016, partially offset by the timing of vendor payments and an increase in under-recovered fuel costs. Net cash used for investing activities totaled $4.9 billion for the first six months of 2017 primarily due to the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities, capital expenditures for Southern Company Gas' infrastructure replacement programs, and Southern Power's payments for renewable acquisitions. Net cash provided from financing activities totaled $1.6 billion for the first six months of 2017 primarily due to issuances of long-term and short-term debt, partially offset by redemptions of long-term debt and common stock dividend payments. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first six months of 2017 include an increase of $1.8 billion in property, plant, and equipment in service, net of depreciation primarily related to the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities, Southern Company Gas' infrastructure replacement programs, and Southern Power's renewable acquisitions; a decrease of $1.5 billion in CWIP primarily related to the estimated probable losses on the Kemper IGCC; a decrease of $0.5 billion in cash and cash equivalents primarily related to acquisition payments at Southern Power; a decrease of $1.4 billion in total common stockholder's equity primarily related to the estimated probable losses on the Kemper IGCC, partially offset by the issuance of additional shares of common stock; an increase of $1.3 billion in long-term debt (excluding amounts due within a year) to fund the Southern Company system's continuous construction programs and for general corporate purposes; and an increase of $1.0 billion in notes payable primarily due to issuances of short-term bank debt for general corporate purposes.
At the end of the second quarter 2017, the market price of Southern Company's common stock was $47.88 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $23.38 per share, representing a market-to-book ratio of 205%, compared to $49.19, $25.00, and 197%, respectively, at the end of 2016. Southern Company's common stock dividend for the second quarter 2017 was $0.58 per share compared to $0.56 per share in the second quarter 2016.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company in Item 7 of the Form 10-K for a description of Southern Company's capital requirements for the construction programs of the Southern Company system, including estimated capital expenditures for new electric generating facilities and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, pipeline charges, storage capacity, and gas supply, asset management agreements, standby letters of credit and performance/surety bonds, trust funding requirements, and unrecognized tax benefits. Approximately $3.0 billion will be required through June 30, 2018 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; state regulatory agency approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Additionally, planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power's ability to execute its growth strategy. See Note 12 to the financial statements of Southern Company under "Southern Power" in Item 8 of the Form 10-K and Note (I) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding Southern Power's plant acquisitions. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein for information regarding additional factors that may impact construction expenditures, including Georgia Power's preliminary cost-to-complete and cancellation cost assessments for Plant Vogtle Units 3 and 4.
Sources of Capital
Southern Company intends to meet its future capital needs through operating cash flows, short-term debt, term loans, and external security issuances. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings. The amount and timing of additional equity capital and debt issuances in 2017, as well as in subsequent years, will be contingent on Southern Company's investment opportunities and the Southern Company system's capital requirements and will depend upon prevailing market conditions and other factors. See "Capital Requirements and Contractual Obligations" herein for additional information.
Except as described herein, the traditional electric operating companies, Southern Power, and Southern Company Gas plan to obtain the funds required for construction and other purposes from operating cash flows, external security issuances, term loans, short-term borrowings, and equity contributions or loans from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Company in Item 7 of the Form 10-K for additional information.
In addition, Georgia Power has entered into a loan guarantee agreement (Loan Guarantee Agreement) with the DOE, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4. Under the Loan Guarantee Agreement, the DOE agreed to guarantee borrowings of up to $3.46 billion (not to exceed 70% of Eligible Project Costs) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. Eligible Project Costs incurred through June 30, 2017 would allow for borrowings of up to $3.1 billion under the FFB Credit Facility, of which Georgia Power has borrowed $2.6 billion; however, on July 27, 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement (LGA Amendment) to clarify the operation of the Loan Guarantee Agreement pending Georgia Power's completion of its comprehensive schedule, cost-to-complete, and cancellation cost assessments (Cost Assessments) for Plant Vogtle Units 3 and 4. Under the terms of the LGA Amendment, Georgia Power will not request any advances under the Loan Guarantee Agreement unless and until such time as Georgia Power has completed the Cost Assessments and made a determination to continue construction of Plant Vogtle Units 3 and 4 and satisfied certain other conditions related to continuing construction. See Note 6 to the financial statements of Southern Company under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information regarding the Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and additional conditions to borrowing. Also
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
see Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
As of June 30, 2017, Southern Company's current liabilities exceeded current assets by $3.9 billion due to notes payable of $3.3 billion (comprised of approximately $0.9 billion at the parent company, $1.2 billion at Georgia Power, $0.1 billion at Gulf Power, $0.4 billion at Southern Power, and $0.6 billion at Southern Company Gas) and long-term debt that is due within one year of $3.0 billion (comprised of approximately $0.4 billion at the parent company, $0.4 billion at Alabama Power, $0.3 billion at Georgia Power, $1.0 billion at Mississippi Power, and $0.9 billion at Southern Power). To meet short-term cash needs and contingencies, the Southern Company system has substantial cash flow from operating activities and access to capital markets and financial institutions. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas intend to utilize operating cash flows, as well as commercial paper, lines of credit, bank notes, and securities issuances, as market conditions permit, as well as, under certain circumstances for the traditional electric operating companies, Southern Power, and Southern Company Gas, equity contributions and/or loans from Southern Company to meet their short-term capital needs.
At June 30, 2017, Southern Company and its subsidiaries had approximately $1.4 billion of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2017 were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Expires | | | | Executable Term Loans | | Expires Within One Year |
| Company | 2017 | 2018 | 2019 | 2020 | 2022 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out |
| | (in millions) |
Southern Company(a) | $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 2,000 |
| | $ | 2,000 |
| | $ | 2,000 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Alabama Power | 3 |
| 532 |
| — |
| — |
| 800 |
| | 1,335 |
| | 1,335 |
| | — |
| | — |
| | — |
| | 35 |
|
| Georgia Power | — |
| — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,732 |
| | — |
| | — |
| | — |
| | — |
|
| Gulf Power | 30 |
| 195 |
| 25 |
| 30 |
| — |
| | 280 |
| | 280 |
| | 45 |
| | — |
| | — |
| | 40 |
|
| Mississippi Power | 113 |
| — |
| — |
| — |
| — |
| | 113 |
| | 100 |
| | — |
| | 13 |
| | 13 |
| | 100 |
|
| Southern Power Company | — |
| — |
| — |
| — |
| 750 |
| | 750 |
| | 675 |
| | — |
| | — |
| | — |
| | — |
|
Southern Company Gas(b) | — |
| — |
| — |
| — |
| 1,900 |
| | 1,900 |
| | 1,849 |
| | — |
| | — |
| | — |
| | — |
|
| Other | 10 |
| 30 |
| — |
| — |
| — |
| | 40 |
| | 40 |
| | 20 |
| | — |
| | 20 |
| | 20 |
|
| Southern Company Consolidated | $ | 156 |
| $ | 757 |
| $ | 25 |
| $ | 30 |
| $ | 7,200 |
| | $ | 8,168 |
| | $ | 8,011 |
| | $ | 65 |
| | $ | 13 |
| | $ | 33 |
| | $ | 195 |
|
| |
| (a) | Represents the Southern Company parent entity. |
| |
| (b) | Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.2 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $700 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. |
See Note 6 to the financial statements of Southern Company under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
As reflected in the table above, in May 2017, Southern Company, Alabama Power, Georgia Power, and Southern Power Company each amended certain of their multi-year credit arrangements, which, among other things, extended the maturity dates from 2020 to 2022. Southern Company and Southern Power Company increased their borrowing ability under these arrangements to $2.0 billion from $1.25 billion and to $750 million from $600 million, respectively. Southern Company also terminated its $1.0 billion facility maturing in 2018. Also in May 2017, Southern Company Gas Capital and Nicor Gas terminated their existing credit arrangements for $1.3 billion and $700 million, respectively, which were to mature in 2017 and 2018, and entered into a new multi-year credit arrangement currently allocated for $1.2 billion and $700 million, respectively, with a maturity date of 2022.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Most of these bank credit arrangements, as well as the term loan arrangements of Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Power Company, contain covenants that limit debt levels and contain cross-acceleration or cross-default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of the individual company. Such cross-default provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness or guarantee obligations over a specified threshold. Such cross-acceleration provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness, the payment of which was then accelerated. At June 30, 2017, Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas were in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the unused credit with banks is allocated to provide liquidity support to the pollution control revenue bonds of the traditional electric operating companies and the commercial paper programs of Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas. The amount of variable rate pollution control revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of June 30, 2017 was approximately $1.6 billion. In June 2017, Georgia Power remarketed $318 million of variable rate pollution control bonds in index rate modes, reducing the liquidity support utilized under Georgia Power's bank credit arrangement. In addition, at June 30, 2017, the traditional electric operating companies had approximately $626 million of pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months.
Southern Company, the traditional electric operating companies (other than Mississippi Power), Southern Power Company, Southern Company Gas, and Nicor Gas make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Short-term borrowings are included in notes payable in the balance sheets.
Details of short-term borrowings were as follows:
|
| | | | | | | | | | | | | | | | | | |
| | | Short-term Debt at June 30, 2017 | | Short-term Debt During the Period(*) |
| | | Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) | | | | (in millions) |
| Commercial paper | | $ | 2,257 |
| | 1.5 | % | | $ | 2,519 |
| | 1.3 | % | | $ | 2,946 |
|
| Short-term bank debt | | 1,017 |
| | 2.0 | % | | 321 |
| | 2.0 | % | | 1,017 |
|
| Total | | $ | 3,274 |
| | 1.7 | % | | $ | 2,840 |
| | 1.4 | % | | |
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2017. |
Southern Company believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, bank term loans, and operating cash flows.
Credit Rating Risk
At June 30, 2017, Southern Company and its subsidiaries did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain subsidiaries to BBB and/or Baa2 or below. These contracts are for physical electricity and natural gas purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management,
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
transmission, interest rate management, and foreign currency risk management, and, at June 30, 2017, included contracts related to the construction of new generation at Plant Vogtle Units 3 and 4.
The maximum potential collateral requirements under these contracts at June 30, 2017 were as follows:
|
| | | |
| Credit Ratings | Maximum Potential
Collateral
Requirements |
| | (in millions) |
| At BBB and/or Baa2 | $ | 39 |
|
| At BBB- and/or Baa3 | $ | 642 |
|
At BB+ and/or Ba1(*) | $ | 2,555 |
|
| |
| (*) | Any additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $38 million. |
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Company and its subsidiaries to access capital markets, and would be likely to impact the cost at which they do so.
On March 1, 2017, Moody's downgraded the senior unsecured debt rating of Mississippi Power to Ba1 from Baa3.
On March 20, 2017, Moody's revised its rating outlook for Georgia Power from stable to negative.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including the traditional electric operating companies, Southern Power, Southern Company Gas, Southern Company Gas Capital, and Nicor Gas) from stable to negative.
On March 30, 2017, Fitch placed the ratings of Southern Company, Georgia Power, and Mississippi Power on rating watch negative.
On June 22, 2017, Moody's placed the ratings of Mississippi Power on review for downgrade.
Financing Activities
During the first six months of 2017, Southern Company issued approximately 7.8 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $352 million.
In addition, during the second quarter 2017, Southern Company issued approximately 1.3 million shares of common stock through at-the-market issuances pursuant to sales agency agreements related to Southern Company's continuous equity offering program and received cash proceeds of approximately $65 million, net of $553,000 in fees and commissions.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first six months of 2017:
|
| | | | | | | | | | | | | | | | | | | |
| Company | Senior Note Issuances | | Senior Note Maturities and Redemptions | | Revenue Bond Maturities, Redemptions, and Repurchases | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(a) |
| | (in millions) |
Southern Company(b) | $ | 300 |
| | $ | — |
| | $ | — |
| | $ | 500 |
| | $ | 400 |
|
| Alabama Power | 550 |
| | 200 |
| | — |
| | — |
| | — |
|
| Georgia Power | 850 |
| | 450 |
| | 27 |
| | — |
| | 3 |
|
| Gulf Power | 300 |
| | 85 |
| | — |
| | 6 |
| | — |
|
| Mississippi Power | — |
| | — |
| | — |
| | 40 |
| | 893 |
|
| Southern Power | — |
| | — |
| | — |
| | 3 |
| | 3 |
|
Southern Company Gas(c) | 450 |
| | — |
| | — |
| | — |
| | — |
|
| Other | — |
| | — |
| | — |
| | — |
| | 8 |
|
Elimination(d) | — |
| | — |
| | — |
| | (40 | ) | | (591 | ) |
| Southern Company Consolidated | $ | 2,450 |
| | $ | 735 |
| | $ | 27 |
| | $ | 509 |
| | $ | 716 |
|
| |
| (a) | Includes reductions in capital lease obligations resulting from cash payments under capital leases. |
| |
| (b) | Represents the Southern Company parent entity. |
| |
| (c) | The senior notes were issued by Southern Company Gas Capital and guaranteed by the Southern Company Gas parent entity. |
| |
| (d) | Intercompany loans from Southern Company to Mississippi Power eliminated in Southern Company's Consolidated Financial Statements. |
In March 2017, Southern Company repaid at maturity a $400 million 18-month floating rate bank loan.
In June 2017, Southern Company issued $500 million aggregate principal amount of Series 2017A 5.325% Junior Subordinated Notes due June 21, 2057. The proceeds were used to repay short-term indebtedness and for other general corporate purposes.
Also in June 2017, Southern Company issued $300 million aggregate principal amount of Series 2017A Floating Rate Senior Notes due September 30, 2020, which bear interest at a floating rate based on three-month LIBOR. The proceeds were used to repay short-term indebtedness and for other general corporate purposes.
Also in June 2017, Southern Company entered into two $100 million aggregate principal amount floating rate bank term loan agreements, which mature on June 21, 2018 and June 29, 2018 and bear interest based on one-month LIBOR. The proceeds were used for working capital and 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.
A portion of the proceeds of Gulf Power's senior note issuances was $(16)used in June 2017 to redeem 550,000 shares ($55 million aggregate liquidation amount) of Gulf Power's 6.00% Series Preference Stock, 450,000 shares ($45 million aggregate liquidation amount) of Gulf Power's Series 2007A 6.45% Preference Stock, and 500,000 shares ($50 million aggregate liquidation amount) of Gulf Power's Series 2013A 5.60% Preference Stock.
In March 2017, Gulf Power extended the maturity of a $100 million short-term floating rate bank loan bearing interest based on one-month LIBOR from April 2017 to October 2017 and subsequently repaid the loan in May 2017.
In June 2017, Georgia Power entered into three floating rate bank loans in aggregate principal amounts of $50 million, $150 million, and $100 million, which mature on December 1, 2017, May 31, 2018, and June 28, 2018,
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
respectively, and bear interest based on one-month LIBOR. Also in June 2017, Georgia Power borrowed $500 million pursuant to an uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Georgia Power and the bank from time to time and is payable on no less than 30 days' demand by the bank. The proceeds from these bank loans were used to repay a portion of Georgia Power's existing indebtedness and for working capital and other general corporate purposes, including Georgia Power's continuous construction program.
In June 2017, Mississippi Power prepaid $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018.
Subsequent to June 30, 2017, Nicor Gas agreed to issue $400 million aggregate principal amount of First Mortgage Bonds in a private placement, $200 million of which is expected to be issued in each of August 2017 and November 2017.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company and its subsidiaries plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
PART I
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
During the six months ended June 30, 2017, there were no material changes to Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, and Southern Power's disclosures about market risk. For additional market risk disclosures relating to Gulf Power and Southern Company Gas, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Gulf Power and Southern Company Gas, respectively, herein. For an in-depth discussion of each registrant's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of each registrant in Item 7 of the Form 10-K and Note 1 to the financial statements of each registrant under "Financial Instruments," Note 11 to the financial statements of Southern Company, Alabama Power, and Georgia Power, Note 10 to the financial statements of Gulf Power, Mississippi Power, and Southern Company Gas, and Note 9 to the financial statements of Southern Power in Item 8 of the Form 10-K. Also see Note (C) and Note (H) to the Condensed Financial Statements herein for information relating to derivative instruments.
Item 4. Controls and Procedures.
| |
| (a) | Evaluation of disclosure controls and procedures. |
As of the end of the period covered by this Quarterly Report on Form 10-Q, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas conducted separate evaluations under the supervision and with the participation of each company's management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Sections 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended). Based upon these evaluations, the Chief Executive Officer and the Chief Financial Officer, in each case, concluded that the disclosure controls and procedures are effective.
| |
| (b) | Changes in internal controls over financial reporting. |
There have been no changes in Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended) during the second quarter 2017 that have materially affected or are reasonably likely to materially affect Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting.
ALABAMA POWER COMPANY
ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | |
| Retail revenues | $ | 1,333 |
| | $ | 1,316 |
| | $ | 2,560 |
| | $ | 2,510 |
|
| Wholesale revenues, non-affiliates | 68 |
| | 67 |
| | 133 |
| | 130 |
|
| Wholesale revenues, affiliates | 32 |
| | 9 |
| | 65 |
| | 31 |
|
| Other revenues | 51 |
| | 52 |
| | 108 |
| | 105 |
|
| Total operating revenues | 1,484 |
| | 1,444 |
| | 2,866 |
| | 2,776 |
|
| Operating Expenses: | | | | | | | |
| Fuel | 303 |
| | 295 |
| | 601 |
| | 564 |
|
| Purchased power, non-affiliates | 40 |
| | 40 |
| | 75 |
| | 76 |
|
| Purchased power, affiliates | 34 |
| | 55 |
| | 62 |
| | 88 |
|
| Other operations and maintenance | 375 |
| | 355 |
| | 743 |
| | 747 |
|
| Depreciation and amortization | 183 |
| | 175 |
| | 364 |
| | 347 |
|
| Taxes other than income taxes | 95 |
| | 94 |
| | 191 |
| | 191 |
|
| Total operating expenses | 1,030 |
| | 1,014 |
| | 2,036 |
| | 2,013 |
|
| Operating Income | 454 |
| | 430 |
| | 830 |
| | 763 |
|
| Other Income and (Expense): | | | | | | | |
| Allowance for equity funds used during construction | 8 |
| | 6 |
| | 16 |
| | 16 |
|
| Interest expense, net of amounts capitalized | (77 | ) | | (74 | ) | | (153 | ) | | (147 | ) |
| Other income (expense), net | 1 |
| | (4 | ) | | (4 | ) | | (11 | ) |
| Total other income and (expense) | (68 | ) | | (72 | ) | | (141 | ) | | (142 | ) |
| Earnings Before Income Taxes | 386 |
| | 358 |
| | 689 |
| | 621 |
|
| Income taxes | 151 |
| | 140 |
| | 277 |
| | 242 |
|
| Net Income | 235 |
| | 218 |
| | 412 |
| | 379 |
|
| Dividends on Preferred and Preference Stock | 5 |
| | 5 |
| | 9 |
| | 9 |
|
| Net Income After Dividends on Preferred and Preference Stock | $ | 230 |
| | $ | 213 |
| | $ | 403 |
| | $ | 370 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) |
| Net Income | $ | 235 |
| | $ | 218 |
| | $ | 412 |
| | $ | 379 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
| Changes in fair value, net of tax of $-, $-, $-, and $(1), respectively | — |
| | — |
| | — |
| | (2 | ) |
Reclassification adjustment for amounts included in net income,
net of tax of $1, $-, $1, and $1, respectively | 1 |
| | 1 |
| | 2 |
| | 2 |
|
| Total other comprehensive income (loss) | 1 |
| | 1 |
| | 2 |
| | — |
|
| Comprehensive Income | $ | 236 |
| | $ | 219 |
| | $ | 414 |
| | $ | 379 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
|
| | | | | | | |
| | For the Six Months Ended June 30, |
| | 2017 | | 2016 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 412 |
| | $ | 379 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 442 |
| | 419 |
|
| Deferred income taxes | 192 |
| | 175 |
|
| Pension, postretirement, and other employee benefits | (24 | ) | | (23 | ) |
| Other, net | 4 |
| | (33 | ) |
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (58 | ) | | 64 |
|
| -Fossil fuel stock | 13 |
| | (32 | ) |
| -Other current assets | (75 | ) | | (67 | ) |
| -Accounts payable | (154 | ) | | (75 | ) |
| -Accrued taxes | 52 |
| | 102 |
|
| -Accrued compensation | (74 | ) | | (50 | ) |
| -Retail fuel cost over recovery | (65 | ) | | (60 | ) |
| -Other current liabilities | 7 |
| | 8 |
|
| Net cash provided from operating activities | 672 |
| | 807 |
|
| Investing Activities: | | | |
| Property additions | (738 | ) | | (645 | ) |
| Nuclear decommissioning trust fund purchases | (117 | ) | | (200 | ) |
| Nuclear decommissioning trust fund sales | 117 |
| | 200 |
|
| Cost of removal, net of salvage | (54 | ) | | (51 | ) |
| Change in construction payables | 48 |
| | (27 | ) |
| Other investing activities | (15 | ) | | (18 | ) |
| Net cash used for investing activities | (759 | ) | | (741 | ) |
| Financing Activities: | | | |
| Proceeds — | | | |
| Senior notes | 550 |
| | 400 |
|
| Capital contributions from parent company | 327 |
| | 237 |
|
| Other long-term debt | — |
| | 45 |
|
| Redemptions — Senior notes | (200 | ) | | (200 | ) |
| Payment of common stock dividends | (357 | ) | | (382 | ) |
| Other financing activities | (14 | ) | | (17 | ) |
| Net cash provided from financing activities | 306 |
| | 83 |
|
| Net Change in Cash and Cash Equivalents | 219 |
| | 149 |
|
| Cash and Cash Equivalents at Beginning of Period | 420 |
| | 194 |
|
| Cash and Cash Equivalents at End of Period | $ | 639 |
| | $ | 343 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
| Interest (net of $6 and $7 capitalized for 2017 and 2016, respectively) | $ | 140 |
| | $ | 131 |
|
| Income taxes, net | 88 |
| | (122 | ) |
| Noncash transactions — Accrued property additions at end of period | 132 |
| | 94 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At June 30, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 639 |
| | $ | 420 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 357 |
| | 348 |
|
| Unbilled revenues | | 161 |
| | 146 |
|
| Other accounts and notes receivable | | 36 |
| | 27 |
|
| Affiliated | | 33 |
| | 40 |
|
| Accumulated provision for uncollectible accounts | | (9 | ) | | (10 | ) |
| Fossil fuel stock | | 191 |
| | 205 |
|
| Materials and supplies | | 443 |
| | 435 |
|
| Prepaid expenses | | 86 |
| | 34 |
|
| Other regulatory assets, current | | 135 |
| | 149 |
|
| Other current assets | | 7 |
| | 11 |
|
| Total current assets | | 2,079 |
| | 1,805 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 26,466 |
| | 26,031 |
|
| Less: Accumulated provision for depreciation | | 9,354 |
| | 9,112 |
|
| Plant in service, net of depreciation | | 17,112 |
| | 16,919 |
|
| Nuclear fuel, at amortized cost | | 333 |
| | 336 |
|
| Construction work in progress | | 668 |
| | 491 |
|
| Total property, plant, and equipment | | 18,113 |
| | 17,746 |
|
| Other Property and Investments: | | | | |
| Equity investments in unconsolidated subsidiaries | | 67 |
| | 66 |
|
| Nuclear decommissioning trusts, at fair value | | 848 |
| | 792 |
|
| Miscellaneous property and investments | | 119 |
| | 112 |
|
| Total other property and investments | | 1,034 |
| | 970 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 526 |
| | 525 |
|
| Deferred under recovered regulatory clause revenues | | 6 |
| | 150 |
|
| Other regulatory assets, deferred | | 1,209 |
| | 1,157 |
|
| Other deferred charges and assets | | 166 |
| | 163 |
|
| Total deferred charges and other assets | | 1,907 |
| | 1,995 |
|
| Total Assets | | $ | 23,133 |
| | $ | 22,516 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholder's Equity | | At June 30, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 361 |
| | $ | 561 |
|
| Accounts payable — | | | | |
| Affiliated | | 242 |
| | 297 |
|
| Other | | 317 |
| | 433 |
|
| Customer deposits | | 91 |
| | 88 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 39 |
| | 45 |
|
| Other accrued taxes | | 97 |
| | 42 |
|
| Accrued interest | | 81 |
| | 78 |
|
| Accrued compensation | | 125 |
| | 193 |
|
| Other regulatory liabilities, current | | 15 |
| | 85 |
|
| Other current liabilities | | 63 |
| | 76 |
|
| Total current liabilities | | 1,431 |
| | 1,898 |
|
| Long-term Debt | | 7,082 |
| | 6,535 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 4,842 |
| | 4,654 |
|
| Deferred credits related to income taxes | | 64 |
| | 65 |
|
| Accumulated deferred ITCs | | 113 |
| | 110 |
|
| Employee benefit obligations | | 269 |
| | 300 |
|
| Asset retirement obligations | | 1,543 |
| | 1,503 |
|
| Other cost of removal obligations | | 648 |
| | 684 |
|
| Other regulatory liabilities, deferred | | 84 |
| | 100 |
|
| Other deferred credits and liabilities | | 69 |
| | 63 |
|
| Total deferred credits and other liabilities | | 7,632 |
| | 7,479 |
|
| Total Liabilities | | 16,145 |
| | 15,912 |
|
| Redeemable Preferred Stock | | 85 |
| | 85 |
|
| Preference Stock | | 196 |
| | 196 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, par value $40 per share — | | | | |
| Authorized — 40,000,000 shares | | | | |
| Outstanding — 30,537,500 shares | | 1,222 |
| | 1,222 |
|
| Paid-in capital | | 2,950 |
| | 2,613 |
|
| Retained earnings | | 2,564 |
| | 2,518 |
|
| Accumulated other comprehensive loss | | (29 | ) | | (30 | ) |
| Total common stockholder's equity | | 6,707 |
| | 6,323 |
|
| Total Liabilities and Stockholder's Equity | | $ | 23,133 |
| | $ | 22,516 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
SECOND QUARTER 2017 vs. SECOND QUARTER 2016
AND
YEAR-TO-DATE 2017 vs. YEAR-TO-DATE 2016
OVERVIEW
Alabama Power operates as a vertically integrated utility providing electric service to retail and wholesale customers within its traditional service territory located in the State of Alabama in addition to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of Alabama Power's business of providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, reliability, fuel, capital expenditures, and restoration following major storms. Alabama Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Alabama Power for the foreseeable future.
Alabama Power continues to focus on several key performance indicators including, but not limited to, customer satisfaction, plant availability, system reliability, and net income after dividends on preferred and preference stock.
RESULTS OF OPERATIONS
Net Income
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) |
| (% change) |
| (change in millions) |
| (% change) |
| $17 | | 8.0 | | $33 | | 8.9 |
Alabama Power's net income after dividends on preferred and preference stock for the second quarter 2017 was $230 million compared to $(24)$213 million for the corresponding period in 2015.2016. The changeincrease was primarily duerelated to an increase in rates under Rate RSE effective January 1, 2017 and an increase in other income (expense), net. These increases were partially offset by an increase in operations and maintenance expenses and a decrease in donations,retail revenues associated with milder weather and lower customer usage in the second quarter 2017 compared to the corresponding period in 2016.
Alabama Power's net income after dividends on preferred and preference stock for year-to-date 2017 was $403 million compared to $370 million for the corresponding period in 2016. The increase was primarily related to an increase in rates under Rate RSE effective January 1, 2017, partially offset by a decrease in sales of non-utility propertyretail revenues associated with milder weather for year-to-date 2017 compared to the corresponding period in 2016.
Income TaxesRetail 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) |
| $29 | | 15.1 | | $39 | | 9.1 |
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $17 | | 1.3 | | $50 | | 2.0 |
In the thirdsecond quarter 2016, income taxes2017, retail revenues were $221 million$1.33 billion compared to $192 million$1.32 billion for the corresponding period in 2015. The increase was primarily due to higher pre-tax earnings in 2016.
For year-to-date 2016, income taxes2017, retail revenues were $466 million$2.56 billion compared to $427 million$2.51 billion for the corresponding period in 2015. The increase was primarily due to higher pre-tax earnings and state tax credits taken in 2015.2016.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Dividends on Preferred and Preference StockDetails of the changes in retail revenues were as follows:
|
| | | | | | |
| 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) |
|
| | | | | | | | | | | | | |
| | Second Quarter 2017 |
| Year-to-Date 2017 |
| | (in millions) |
| (% change) |
| (in millions) |
| (% change) |
| Retail – prior year | $ | 1,316 |
| | | | $ | 2,510 |
| | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 75 |
| | 5.7 |
| | 154 |
| | 6.2 |
|
| Sales decline | (11 | ) | | (0.8 | ) | | (12 | ) | | (0.5 | ) |
| Weather | (11 | ) | | (0.8 | ) | | (66 | ) | | (2.6 | ) |
| Fuel and other cost recovery | (36 | ) | | (2.8 | ) | | (26 | ) | | (1.1 | ) |
| Retail – current year | $ | 1,333 |
| | 1.3 | % | | $ | 2,560 |
| | 2.0 | % |
ForRevenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2016, dividends on preferred and preference stock were $13 million2017 when compared to $21 million for the corresponding periodperiods in 2015. This decrease was2016 primarily due to the redemptionan increase in May 2015 of certain series of preferred and preference stock.rates under Rate RSE effective January 1, 2017. See Note 63 to the financial statements of Alabama Power under "Redeemable Preferred and Preference Stock""Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales decreased in the second quarter and year-to-date 2017 when compared to the corresponding periods in 2016. Weather-adjusted residential KWH sales decreased 1.1% and 0.2% for the second quarter and year-to-date 2017, respectively, primarily due to lower customer usage resulting from an increase in efficiency improvements in residential appliances and lighting, partially offset by customer growth. Weather-adjusted commercial KWH sales decreased 0.4% and 0.8% for the second quarter and year-to-date 2017, respectively, primarily due to lower customer usage. Industrial KWH sales increased 1.0% for the second quarter 2017 when compared to the corresponding period in 2016 as a result of an increase in demand resulting from changes in production levels primarily in the chemicals and mining sectors, partially offset by a decrease in demand from the paper, primary metals, pipelines, and lumber sectors. Industrial KWH sales remained flat year-to-date 2017 when compared to the corresponding period in 2016 as a result of an increase in demand resulting from changes in production levels primarily in the chemicals and mining sectors, offset by a decrease in demand from the pipelines, lumber, and stone, clay, and glass sectors.
Revenues resulting from changes in weather decreased in the second quarter and year-to-date 2017 due to milder weather experienced in Alabama Power's service territory compared to the corresponding periods in 2016. For the second quarter 2017, the resulting decreases were 1.5% and 0.7% for residential and commercial sales revenues, respectively. For year-to-date 2017, the resulting decreases were 5.2% and 1.4% for residential and commercial sales revenues, respectively.
Fuel and other cost recovery revenues decreased in the second quarter 2017 and year-to-date 2017 when compared to the corresponding periods in 2016 primarily due to an increase in wholesale revenues to affiliates, which offsets retail fuel cost recovery. Electric rates include provisions to recognize the full recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the natural disaster reserve. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.
Wholesale Revenues – Affiliates
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $23 | | 255.6 | | $34 | | 109.7 |
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
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through Alabama Power's energy cost recovery clauses.
In the second quarter 2017, wholesale revenues from sales to affiliates were $32 million compared to $9 million for the corresponding period in 2016. The increase was primarily due to a 175.0% increase in KWH sales as a result of lower cost Alabama Power-owned generation available to the Southern Company system and a 29.3% increase in the price of energy due to an increase in natural gas prices. For year-to-date 2017, wholesale revenues from sales to affiliates were $65 million compared to $31 million for the corresponding period in 2016. The increase was primarily due to an 83.5% increase in KWH sales as a result of supporting Southern Company system transmission reliability and a 15.5% increase in the price of energy due to an increase in natural gas prices.
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | | |
| | Second Quarter 2017
vs.
Second Quarter 2016 | | Year-to-Date 2017
vs.
Year-to-Date 2016 |
| | (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| Fuel | $ | 8 |
| | 2.7 | | $ | 37 |
| | 6.6 |
|
| Purchased power – non-affiliates | — |
| | — | | (1 | ) | | (1.3 | ) |
| Purchased power – affiliates | (21 | ) | | (38.2) | | (26 | ) | | (29.5 | ) |
| Total fuel and purchased power expenses | $ | (13 | ) | | | | $ | 10 |
| | |
In the second quarter 2017, fuel and purchased power expenses were $377 million compared to $390 million for the corresponding period in 2016. The decrease was primarily due to a $55 million decrease in the volume of KWHs purchased. This decrease was partially offset by a $24 million net increase related to the average cost of purchased power and fuel and an $18 million increase related to the volume of KWHs generated.
For year-to-date 2017, fuel and purchased power expenses were $738 million compared to $728 million for the corresponding period in 2016. The increase was primarily due to a $58 million increase in the volume of KWHs generated and a $31 million net increase related to the average cost of purchased power and fuel. These increases were partially offset by a $79 million decrease in the volume of KWHs purchased.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Alabama Power's energy cost recovery clause. 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:
|
| | | | | | | |
| | Second Quarter 2017 | | Second Quarter 2016 | | Year-to-Date 2017 |
| Year-to-Date 2016 |
Total generation (in billions of KWHs) | 15 | | 13 | | 30 | | 28 |
Total purchased power (in billions of KWHs) | 1 | | 3 | | 2 | | 4 |
Sources of generation (percent) — | | | | | | | |
| Coal | 47 | | 53 | | 48 | | 46 |
| Nuclear | 25 | | 23 | | 26 | | 25 |
| Gas | 20 | | 20 | | 20 | | 19 |
| Hydro | 8 | | 4 | | 6 | | 10 |
Cost of fuel, generated (in cents per net KWH) — | | | | | | | |
| Coal | 2.63 | | 2.84 | | 2.61 | | 2.85 |
| Nuclear | 0.76 | | 0.79 | | 0.75 | | 0.78 |
| Gas | 2.75 | | 2.52 | | 2.76 | | 2.49 |
Average cost of fuel, generated (in cents per net KWH)(a) | 2.14 | | 2.28 | | 2.13 | | 2.20 |
Average cost of purchased power (in cents per net KWH)(b) | 7.11 | | 3.94 | | 6.92 | | 4.37 |
| |
(a) | KWHs generated by hydro are excluded from the average cost of fuel, generated. |
| |
(b) | Average cost of purchased power includes fuel, energy, and transmission purchased by Alabama Power for tolling agreements where power is generated by the provider. |
Fuel
For year-to-date 2017, fuel expense was $601 million compared to $564 million for the corresponding period in 2016. The increase was primarily due to increases of 11.0% and 8.4% in the volume of KWHs generated by coal and natural gas, respectively, a 10.8% increase in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, and a 28.1% decrease in the volume of KWHs generated by hydro facilities. The increase was partially offset by an 8.4% decrease in the average cost of coal per KWH generated.
Purchased Power – Affiliates
In the second quarter 2017, purchased power expense from affiliates was $34 million compared to $55 million for the corresponding period in 2016. The decrease was primarily related to a 61.1% decrease in the amount of energy purchased as a result of lower cost Alabama Power-owned generation, partially offset by a 60.3% increase in the average cost of purchased power per KWH as a result of higher natural gas prices.
For year-to-date 2017, purchased power expense from affiliates was $62 million compared to $88 million for the corresponding period in 2016. The decrease was primarily related to a 56.1% decrease in the amount of energy purchased due to an increase in generation as a result of supporting Southern Company system transmission reliability, partially offset by a 60.0% increase in the average cost of purchased power per KWH as a result of higher 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.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Operations and Maintenance Expenses
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $20 | | 5.6 | | $(4) | | (0.5) |
In the second quarter 2017, other operations and maintenance expenses were $375 million compared to $355 million for the corresponding period in 2016. The increase was primarily due to increases of $13 million in vegetation management costs, $7 million in nuclear generation plant improvement costs, and $3 million in employee benefit costs. The increase was partially offset by a $4 million decrease in scheduled other power generation outage costs.
Depreciation and Amortization
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $8 | | 4.6 | | $17 | | 4.9 |
In the second quarter 2017, depreciation and amortization was $183 million compared to $175 million for the corresponding period in 2016. For year-to-date 2017, depreciation and amortization was $364 million compared to $347 million for the corresponding period in 2016. These increases were primarily due to additional plant in service related to distribution, steam generation, and transmission assets. In addition, there was an increase in depreciation rates, effective January 1, 2017, associated with compliance-related steam projects, asset retirement obligation recovery, and other generation assets, partially offset by a decrease in distribution-related rates. See Note 1 to the financial statements of Alabama Power under "Depreciation and Amortization" in Item 8 of the Form 10-K for additional information.
Other Income (Expense), Net
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $5 | | 125.0 | | $7 | | 63.6 |
In the second quarter 2017, other income (expense), net was $1 million compared to $(4) million for the corresponding period in 2016. For year-to-date 2017, other income (expense), net was $(4) million compared to $(11) million for the corresponding period in 2016. The changes were primarily due to decreases in donations and increases in sales of non-utility property and unregulated lighting services in 2017.
Income Taxes
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $11 | | 7.9 | | $35 | | 14.5 |
In the second quarter 2017, income taxes were $151 million compared to $140 million for the corresponding period in 2016. The increase was primarily due to higher pre-tax earnings.
For year-to-date 2017, income taxes were $277 million compared to $242 million for the corresponding period in 2016. The increase was primarily due to higher pre-tax earnings and unrecognized tax benefits related to certain state deductions for federal income taxes.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.providing electric service. 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.costs and limited projected demand growth over the next several years. Future earnings in the near term will be driven primarily by customer growth. Earnings will also depend in part, upon maintaining and growing sales, whichconsidering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions. Earnings are subject to a numbervariety of other factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Alabama Power's service territory. Demand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, which may impact future earnings. Current proposals related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Alabama Power's financial statements. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of 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, as compliance plans are revised or updated, and as legal challenges to rules are completed. Environmental compliance costs are recovered through Rate CNP Compliance. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate CNP"CNP Compliance" in Item 8 of the Form 10-K for additional information. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Statutes and Regulations
AirWater Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – AirWater Quality" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the EPA's final MATSeffluent guidelines rule regional haze regulations, and the Cross State Air Pollution Rule (CSAPR).final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs.
On April 25, 2016, in response to a June 2015 U.S. Supreme Court opinion,2017, the EPA published its supplemental finding regarding consideration of costsa notice announcing it would reconsider the effluent guidelines rule, which had been finalized in supportNovember 2015. On June 6, 2017, the EPA proposed a rule establishing a stay of the MATScompliance deadlines for certain effluent limitations and pretreatment standards under the rule. This finding does not impact MATS
On June 27, 2017, the EPA and the U.S. Army Corps of Engineers proposed to rescind the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
compliance requirements, costs, or deadlines, and all Alabama Power units that are subject to the MATS rule completed the measures necessary to achieve compliance with the MATS rule by the applicable deadlines.
Also on April 25, 2016, the EPA issued proposed revisions to the regional haze regulations. The ultimate impactoutcome of the proposed revisions will depend on their ultimate adoption, implementation, and any legal challenges andthese matters cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Alabama Power in Item 7 of the Form 10-K for additional information.
On October 26, 2016,March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA published ato review the Clean Power Plan and final rulegreenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules.
On June 1, 2017, the U.S. President announced that updates the CSAPR ozone season nitrogen oxide program, including revising ozone-season emissions budgets in Alabama. United States will withdraw from the non-binding Paris Agreement and begin renegotiation of its terms.
The ultimate impact of this rule will depend on the outcome of any legal challenges and implementation at the state level andthese matters cannot be determined at this time.
FERC Matters
See BUSINESS MANAGEMENT'S DISCUSSION AND ANALYSIS – "Regulation FUTURE EARNINGS POTENTIAL – Federal "FERC Matters" of Alabama Power Act" in Item 17 of the Form 10-K for a discussion of Alabamaadditional information regarding the traditional electric operating companies' and Southern Power's hydroelectric developments on the Coosa River. On April 21, 2016, the FERC issued an order granting in partmarket power proceeding 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. amendment to their market-rate tariff.
On May 17, 2016,2017, the FERC accepted the traditional electric operating companies' (including Alabama Rivers AlliancePower's) and American Rivers filedSouthern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an additional rehearing request and also filed a petition for reviewamendment by the U.S. Court of Appeals fortraditional electric operating companies (including Alabama Power) and Southern Power to their market-based rate tariff. While the District of Columbia Circuit. On September 12, 2016,FERC's order references the FERC issued an order denying the second rehearing request,traditional electric operating companies' (including Alabama Power's) and Alabama Rivers Alliance and American Rivers filed an appeal of the April 21, 2016 order to the U.S. Court of Appeals for the District of Columbia Circuit. The ultimate outcome of this matter cannot be determined at this time.Southern Power's market power proceeding, it remains a separate, ongoing matter.
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,Rate ECR, and rate natural disaster reserve.Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See Notes 1 and 3 to the financial statements of Alabama Power under "Nuclear Outage Accounting Order" and "Retail Regulatory 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.
Environmental Accounting Order
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Environmental Accounting Order" of Alabama Power in Item 7 of the Form 10-K for 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 ownership 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 Alabama Power in Item 7 of the Form 10-K for information regarding renewable energy projects.
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
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
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.
The ultimate outcome of such pending or potential litigation against Alabama Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, orinNote3tothefinancialstatementsofAlabama PowerinItem8ofthe Form 10-K,management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Alabama Power's financial statements. See Note (B) to the Condensed Financial
ALABAMA POWER COMPANY
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.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Alabama Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Alabama Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Alabama Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Alabama Power in Item 7 of the Form 10-K for a complete discussion of Alabama Power's critical accounting policies and estimates related to Electric Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, and Contingent Obligations.
Recently Issued Accounting Standards
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
While Alabama Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Alabama Power's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs. Alabama Power expects that the revenue from contracts with these customers will not result in a significant shift in the timing of revenue recognition for such sales.
Alabama Power's ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements, such as alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Alabama Power's financial statements, if material. In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Alabama Power expects CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Alabama Power intends to use the modified retrospective method of adoption effective January 1, 2018. Alabama Power has also elected to utilize practical expedients which allow it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Alabama Power's financial statements, Alabama Power will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.
On February 25, 2016,March 10, 2017, the FASB issued ASU No. 2016-02,2017-07, Leases(Topic 842)Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2016-02)2017-07). ASU 2016-022017-07 requires lessees to recognize onthat an employer report the balance sheet a lease 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. Alabama Power is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on Alabama Power's balance sheet.
On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation(Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions. Most significantly, entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefitservice cost component in the income statement. Alabama 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. Earlysame line item or items
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
adoptionas other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside income from operations. Additionally, only the service cost component is permittedeligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. Alabama Power intendsis currently evaluating the new standard. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Alabama Power's operating income and an increase in other income for 2016 and 2017 and are expected to adopt theresult in a decrease in operating income and an increase in other income for 2018. The adoption of ASU in the fourth quarter 2016. The adoption2017-07 is not expected to have a material impact on the results of operations,Alabama Power's financial position, or cash flows of Alabama Power.statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Alabama Power in Item 7 of the Form 10-K for additional information. Alabama Power's financial condition remained stable at SeptemberJune 30, 2016.2017. Alabama Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $1.5 billion$672 million for the first ninesix months of 2016,2017, a decrease of $44$135 million as compared to the first ninesix months of 2015.2016. The decrease in net cash provided from operating activities was primarily due to lower fuel cost recovery revenues during 2016, partially offset by lower income tax payments and the receipt of income tax refunds in 2016 as a result of bonus depreciation. Net cash used for investing activities totaled $1.1 billion$759 million for the first ninesix months of 20162017 primarily due to gross property additions related to distribution, environmental, distribution,transmission, and steam generation, and transmission.generation. Net cash used forprovided from financing activities totaled $91$306 million for the first ninesix months of 20162017 primarily due to an issuance of long-term debt and additional capital contributions from Southern Company, partially offset by common stock dividend payments and a redemption of long-term debt, partially offset by issuances of long-term debt and additional capital contributions from Southern Company. Cashdebt. Fluctuations in 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 ninesix months of 20162017 include increases of $422$547 million in long-term debt, primarily due to the issuance of additional senior notes, $367 million in property, plant, and equipment, primarily due to additions to environmental, distribution, nuclearsteam generation, and transmission, $362 million in cash and cash equivalents, $266$337 million in additional paid-in capital due to capital contributions from Southern Company, $264and $219 million in accumulated deferred income taxes related to bonus depreciation,cash and $205cash equivalents, as well as a decrease of $200 million in long-term debt primarilysecurities due to the issuance of additional senior notes. Other significant changes include decreases of $239 million in other regulatory liabilities, current, primarily due to the timing of fuel cost recovery and $177 million in other accounts payable primarily due to the timing of vendor payments.
See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information regarding Alabama Power's rate mechanisms.within one year.
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 $236$361 million will be required through SeptemberJune 30, 20172018 to fund maturities of long-term debt.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – General" and " – Global Climate Issues" of Alabama Power in Item 7 of the Form 10-K for additional information on Alabama Power's environmental compliance strategy.
Alabama Power's approved construction program is currently estimated to total $1.9 billion for 2017, $1.6 billion for 2018, $1.2 billion for 2019, $1.3 billion for 2020, and $1.2 billion for 2021. The construction program includes capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreements. Estimated capital expenditures to comply with environmental statutes and
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
regulations included in these amounts are $0.5 billion for 2017, $0.3 billion for 2018, $0.1 billion for 2019, $0.1 billion for 2020, and $0.2 billion for 2021. These estimated expenditures include anticipated costs for compliance with the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) and the EPA's final effluent guidelines rule. These estimated expenditures do not include potential compliance costs that may arise from the EPA's final rules and guidelines or subsequently approved state plans that would limit 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 generating units, to meet regulatory requirements; changes in the expected environmental compliance program; changes in FERC rules and regulations; Alabama PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Sources of Capital
Alabama Power plans to obtain the funds to meet its future capital needs throughfrom sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, term loans, external security issuances, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Alabama Power in Item 7 of the Form 10-K for additional information.
Alabama Power's current liabilities sometimes exceed current assets because of long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs.
At SeptemberJune 30, 2016,2017, Alabama Power had approximately $556$639 million of cash and cash equivalents. Committed credit arrangements with banks at SeptemberJune 30, 20162017 were as follows:
| | | Expires | Expires | | | | | | Due Within One Year | Expires | | | | | | Expires Within One Year |
| 2017 | 2017 | | 2018 | | 2020 | | Total | | Unused | | Term Out | | No Term Out | 2017 | | 2018 | | 2022 | | Total | | Unused | | Term Out | | No Term Out |
| (in millions) | (in millions) | | (in millions) | | (in millions) | (in millions) |
| $ | 35 |
| | $ | 500 |
| | $ | 800 |
| | $ | 1,335 |
| | $ | 1,335 |
| | $ | — |
| | $ | 35 |
| 3 |
| | $ | 532 |
| | $ | 800 |
| | $ | 1,335 |
| | $ | 1,335 |
| | $ | — |
| | $ | 35 |
|
See Note 6 to the financial statements of Alabama Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
As reflected in the table above, in May 2017, Alabama Power amended its $800 million multi-year credit arrangement, which, among other things, extended the maturity date from 2020 to 2022.
Most of these bank credit arrangements, as well as Alabama Power's term loan arrangements, contain covenants that limit debt levels and contain cross accelerationcross-acceleration provisions to other indebtedness (including guarantee obligations) of Alabama Power. Such cross accelerationcross-acceleration provisions to other indebtedness would trigger an event of default if
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Alabama Power defaulted on indebtedness, the payment of which was then accelerated. At June 30, 2017, Alabama Power is currentlywas in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, 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.programs. 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 Septembermillion as of June 30, 2016,2017. At June 30, 2017, Alabama Power had $87 million ofno fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Alabama Power also has substantial cash flow from operating activities and access to capital markets, including a commercial paper program, to meet liquidity needs. Alabama Power may meet short-term cash needs through its commercial paper program. Alabama Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Alabama Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Alabama Power are loaned directly to Alabama Power. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support.
Details of short-termcommercial paper borrowings were as follows:
|
| | | | | | | | | | | |
| | | Short-term Debt During the Period(*) |
| | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) |
| Commercial paper | | $ | 15 |
| | 0.6 | % | | $ | 100 |
|
|
| | | | | | | | | | | |
| | | Short-term Debt During the Period(*) |
| | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) |
| Commercial paper | | $ | 28 |
| | 1.1 | % | | $ | 200 |
|
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended SeptemberJune 30, 2016.2017. No short-term debt was outstanding at SeptemberJune 30, 2016.2017. |
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
At June 30, 2017, Alabama Power doesdid not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or 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 SeptemberJune 30, 20162017 were as follows:
|
| | | |
| Credit Ratings | Maximum Potential Collateral Requirements |
| | (in millions) |
| At BBB and/or Baa2 | $ | 1 |
|
| At BBB- and/or Baa3 | $ | 2 |
|
| Below BBB- and/or Baa3 | $ | 347 |
|
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
| | | |
| Credit Ratings | Maximum Potential Collateral Requirements |
| | (in millions) |
| At BBB and/or Baa2 | $ | 1 |
|
| At BBB- and/or Baa3 | $ | 2 |
|
| Below BBB- and/or Baa3 | $ | 326 |
|
Included in these amounts are certain agreements that could require collateral in the event that oneeither Alabama Power or more Southern Company system power pool participantsGeorgia Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Alabama Power to access capital markets and would be likely to impact the cost at which it does so.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including Alabama Power) from stable to negative.
Financing Activities
In January 2016,February 2017, Alabama Power issued $400 million aggregate principal amount of Series 2016A 4.30% Senior Notes due January 2, 2046. The proceeds were used to repayrepaid at maturity $200 million aggregate principal amount of Series 2007A 5.55% Senior Notes.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In March 2017, Alabama Power'sPower issued $550 million aggregate principal amount of Series FF 5.20%2017A 2.45% Senior Notes due January 15, 2016March 30, 2022. The proceeds were used to repay Alabama Power's short-term indebtedness and for general corporate purposes, including Alabama Power's continuous construction program.
In March 2016,Subsequent to June 30, 2017, Alabama Power entered into three bank term loan agreements withrepaid at maturity dates of March 2021, in an$36.1 million aggregate principal amount of $45 million, oneSeries 1993-A, 1993-B, and 1993-C Industrial Development Board of which bears interest at 2.38% per annum and twothe City of which bear interest based on three-month LIBOR.Mobile, Alabama Pollution Control Revenue Refunding Bonds (Alabama Power Company Project).
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 COMPANYIncome Taxes
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $11 | | 7.9 | | $35 | | 14.5 |
In the second quarter 2017, income taxes were $151 million compared to $140 million for the corresponding period in 2016. The increase was primarily due to higher pre-tax earnings.
For year-to-date 2017, income taxes were $277 million compared to $242 million for the corresponding period in 2016. The increase was primarily due to higher pre-tax earnings and unrecognized tax benefits related to certain state deductions for federal income taxes.
GEORGIA POWER COMPANY
CONDENSED 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: | | | | | | | |
| Retail revenues | $ | 2,540 |
| | $ | 2,537 |
| | $ | 6,164 |
| | $ | 6,223 |
|
| Wholesale revenues, non-affiliates | 49 |
| | 55 |
| | 131 |
| | 173 |
|
| Wholesale revenues, affiliates | 9 |
| | 5 |
| | 24 |
| | 18 |
|
| Other revenues | 100 |
| | 94 |
| | 302 |
| | 271 |
|
| Total operating revenues | 2,698 |
| | 2,691 |
| | 6,621 |
| | 6,685 |
|
| Operating Expenses: | | | | | | | |
| Fuel | 575 |
| | 706 |
| | 1,390 |
| | 1,735 |
|
| Purchased power, non-affiliates | 102 |
| | 90 |
| | 277 |
| | 227 |
|
| Purchased power, affiliates | 142 |
| | 148 |
| | 392 |
| | 411 |
|
| Other operations and maintenance | 496 |
| | 462 |
| | 1,393 |
| | 1,405 |
|
| Depreciation and amortization | 215 |
| | 214 |
| | 639 |
| | 633 |
|
| Taxes other than income taxes | 114 |
| | 107 |
| | 311 |
| | 302 |
|
| Total operating expenses | 1,644 |
| | 1,727 |
| | 4,402 |
| | 4,713 |
|
| Operating Income | 1,054 |
| | 964 |
| | 2,219 |
| | 1,972 |
|
| Other Income and (Expense): | | | | | | | |
| Interest expense, net of amounts capitalized | (98 | ) | | (90 | ) | | (290 | ) | | (272 | ) |
| Other income (expense), net | 11 |
| | 18 |
| | 35 |
| | 34 |
|
| Total other income and (expense) | (87 | ) | | (72 | ) | | (255 | ) | | (238 | ) |
| Earnings Before Income Taxes | 967 |
| | 892 |
| | 1,964 |
| | 1,734 |
|
| Income taxes | 365 |
| | 337 |
| | 737 |
| | 657 |
|
| Net Income | 602 |
| | 555 |
| | 1,227 |
| | 1,077 |
|
| Dividends on Preferred and Preference Stock | 4 |
| | 4 |
| | 13 |
| | 13 |
|
| Net Income After Dividends on Preferred and Preference Stock | $ | 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, |
| | 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 STATEMENTS OF CASH FLOWS (UNAUDITED) |
| | | | | | | |
| | 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.
GEORGIAALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRD QUARTER 2016 vs. THIRD QUARTER 2015FUTURE EARNINGS POTENTIAL
AND
YEAR-TO-DATE 2016 vs. YEAR-TO-DATE 2015
OVERVIEW
Georgia Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service territory located within the StateThe results of Georgia and to wholesale customers in the Southeast.
Manyoperations 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 GeorgiaAlabama Power's primary business of selling electricity.providing electric service. These factors include theAlabama Power's ability to maintain a constructive regulatory environment that continues to maintain and grow energy sales, and to effectively manage and secureallow for the timely recovery of costs.prudently-incurred costs during a time of increasing costs and limited projected demand growth over the next several years. Future earnings will be driven primarily by customer growth. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions. Earnings are subject to a variety of other factors. These costsfactors include thoseweather, 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 is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, which may impact future earnings. Current proposals related to projected long-term demand growth, increasingly stringent environmental standards, reliability, and fuel. In addition, construction continuespotential federal tax reform legislation are primarily focused on Plant Vogtle Units 3 and 4. Georgia Power will own a 45.7% interest in these two nuclear generating units to increase its generation diversity and meet future supply needs. Georgia Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms andappropriately balancing required costs andreducing the corporate income tax rate, allowing 100% of capital expenditures with customer prices will continue to challenge Georgia Power forbe deducted, and eliminating the foreseeable future.
On October 20, 2016, Georgia Powerinterest deduction. The ultimate impact of any tax reform proposals is dependent on the final form of any legislation enacted and the Georgia PSC Staff entered intorelated transition rules and cannot be determined at this time, but could have 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 informationmaterial impact 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, GeorgiaAlabama 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.financial statements. For additional information onrelating to these indicators,issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators"FUTURE EARNINGS POTENTIAL of GeorgiaAlabama Power in Item 7 of the Form 10-K.
RESULTS OF OPERATIONSCompliance 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, as compliance plans are revised or updated, and as legal challenges to rules are completed. Environmental compliance costs are recovered through Rate CNP Compliance. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate CNP Compliance" in Item 8 of the Form 10-K for additional information. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Net IncomeEnvironmental Statutes and Regulations
|
| | | | | | |
| 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 preferredOn April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. On June 6, 2017, the EPA proposed a rule establishing a stay of the compliance deadlines for certain effluent limitations and preference stock was $598 millionpretreatment standards under the rule.
On June 27, 2017, the EPA and the U.S. Army Corps of Engineers proposed to rescind the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the third quarter 2016 compared to $551 million for the corresponding period in 2015. The increase was primarily due to an increase in retail base revenues effective January 1, 2016, as authorized by the Georgia PSC, and higher retail revenues due to warmer weather as compared to the corresponding period in 2015, partially offset by higher non-fuel operating expenses.
For year-to-date 2016, net income after dividends on preferred and preference stock was $1.21 billion compared to $1.06 billion for the corresponding period in 2015. The increase was primarily due to an increase in retail base revenues effective January 1, 2016, as authorized by the Georgia PSC, the 2015 correction of an error affecting billings to a small number of large commercial and industrial customers, higher retail revenues in the third quarterSixth Circuit.
GEORGIAALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
2016 dueThe ultimate outcome of these matters cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Alabama Power in Item 7 of the Form 10-K for additional information.
On March 28, 2017, the U.S. President signed an executive order directing agencies to warmer weather as comparedreview actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules.
On June 1, 2017, the U.S. President announced that the United States will withdraw from the non-binding Paris Agreement and begin renegotiation of its terms.
The ultimate outcome of these matters cannot be determined at this time.
FERC Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the traditional electric operating companies' and Southern Power's market power proceeding and amendment to their market-rate tariff.
On May 17, 2017, the FERC accepted the traditional electric operating companies' (including Alabama Power's) and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies (including Alabama Power) and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' (including Alabama Power's) and Southern Power's market power proceeding, it remains a separate, ongoing matter.
Retail Regulatory Matters
Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject 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 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) |
Retail revenues increased slightly in the third quarter 2016 compared to the corresponding period in 2015. For year-to-date 2016, retail revenues were $6.16 billion compared to $6.22 billion for the corresponding period in 2015.
Detailsoversight of the changes inAlabama PSC. Alabama Power currently recovers its costs from the regulated retail revenues were as follows:
|
| | | | | | | | | | | | | |
| | Third Quarter 2016 | | Year-to-Date 2016 |
| | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | $ | 2,537 |
| | | | $ | 6,223 |
| | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 22 |
| | 0.9 |
| | 167 |
| | 2.7 |
|
| Sales growth | 1 |
| | — |
| | 3 |
| | — |
|
| Weather | 105 |
| | 4.1 |
| | 75 |
| | 1.2 |
|
| Fuel cost recovery | (125 | ) | | (4.9 | ) | | (304 | ) | | (4.9 | ) |
| Retail – current year | $ | 2,540 |
| | 0.1 | % | | $ | 6,164 |
| | (1.0 | )% |
Revenues associated with changes in ratesbusiness primarily through Rate RSE, Rate CNP, Rate ECR, and pricing increased inRate NDR. In addition, the third quarterAlabama PSC issues accounting orders to address current events impacting Alabama Power. See Notes 1 and year-to-date 2016 when compared to the corresponding periods in 2015 primarily due to increases in base tariffs approved under the 2013 ARP and the NCCR tariff, all effective January 1, 2016. Also contributing to the increase for year-to-date 2016 was the 2015 correction of an error affecting billings since 2013 to a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing. See Note 3 to the financial statements of GeorgiaAlabama Power under "Nuclear Outage Accounting Order" and "Retail Regulatory Matters, – Rate Plans" and " – Nuclear Construction"respectively, in Item 8 of the Form 10-K for additional information.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.
Revenues attributableOther 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 changes in sales were essentially flatcertain claims and legal actions arising in the third quarterordinary course of business. Alabama Power's business activities are subject to extensive governmental regulation related to public health and year-to-date 2016 when comparedthe environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
TheultimateoutcomeofsuchpendingorpotentiallitigationagainstAlabama Powercannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatementsherein,management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Alabama Power's financial statements. See Note (B) to the corresponding periods in 2015. Weather-adjusted residential KWH sales increased 1.7%, weather-adjusted commercial KWH sales decreased 0.7%, and weather-adjusted industrial KWH sales decreased 3.4% in the third quarter 2016 when compared to the corresponding period in 2015. For year-to-date 2016, weather-adjusted residential KWH sales increased 1.0%, weather-adjusted commercial KWH sales decreased 0.6%, and weather-adjusted industrial KWH sales decreased 0.5% when compared to the corresponding period in 2015. An increase of approximately 29,000 residential customers since September 30, 2015 contributed to the increase in weather-adjusted residential KWH sales, partially offset by a decline in average customer usage primarily resulting from an increase in multi-family housing and efficiency improvements in residential appliances and lighting. 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, 2015. Decreased demand in the pipeline, textiles, and stone, clay, and glass sectors was the main contributor to the decrease in weather-adjusted industrial KWH sales, partially offset by increased demand in the non-manufacturing sector.
Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues decreased $125 million and $304 million in the third quarter and year-to-date 2016, respectively, when compared to the corresponding periods in 2015 primarily due to lower fuel prices. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuelCondensed Financial
GEORGIAALABAMA POWER COMPANY
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.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Alabama Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Alabama Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Alabama Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Alabama Power in Item 7 of the Form 10-K for a complete discussion of Alabama Power's critical accounting policies and estimates related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, and Contingent Obligations.
Recently Issued Accounting Standards
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
While Alabama Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Alabama Power's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs. Alabama Power expects that the revenue from contracts with these customers will not result in a significant shift in the timing of revenue recognition for such sales.
Alabama Power's ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements, such as alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Alabama Power's financial statements, if material. In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Alabama Power expects CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Alabama Power intends to use the modified retrospective method of adoption effective January 1, 2018. Alabama Power has also elected to utilize practical expedients which allow it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Alabama Power's financial statements, Alabama Power will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost recovery provisions, fuel revenues generally equal fuel expensescomponent in the same line item or items
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
as other compensation costs and dorequires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. Alabama Power is currently evaluating the new standard. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Alabama Power's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not affect net income. expected to have a material impact on Alabama Power's financial statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See FUTURE EARNINGS POTENTIALMANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Alabama Power in Item 7 of the Form 10-K for additional information. Alabama Power's financial condition remained stable at June 30, 2017. Alabama Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See "Retail Regulatory MattersCapital Requirements and Contractual Obligations – ," "Fuel Cost RecoverySources of Capital," and "Financing Activities" herein for additional information.
Wholesale Revenues – Non-Affiliates
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(6) | | (10.9) | | $(42) | | (24.3) |
Wholesale revenuesNet cash provided from sales to non-affiliates consistoperating activities totaled $672 million for the first six months 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 on2017, a levelized basis over the appropriate contract period or the amounts billable under the contract terms and provide for recoverydecrease 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$135 million as compared to the costfirst six months 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 or2016. The 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 costcash provided from operating activities was primarily due to produce the energy.
In the third quarterreceipt of income tax refunds in 2016 wholesale revenues from sales to non-affiliates were $49 million compared to $55 million for the corresponding period in 2015 related to a $7 million decrease in capacity revenues, partially offset by a $1 million increase in energy revenues. For year-to-date 2016, wholesale revenues from sales to non-affiliates were $131 million compared to $173 million for the corresponding period in 2015 related to a $28 million decrease in capacity revenues and a $14 million decrease in energy revenues. The decreases in capacity revenues reflect the expiration of wholesale contracts in the second quarter 2016. In addition, the decrease in capacity revenues for year-to-date 2016 reflects the retirement of 14 coal-fired generating units since March 31, 2015 as a result of Georgia Power's environmental compliance strategy. The decrease in energy revenuesbonus depreciation. Net cash used for year-to-date 2016 wasinvesting activities totaled $759 million for the first six months of 2017 primarily due to lower fuel prices. gross property additions related to distribution, environmental, transmission, and steam generation. Net cash provided from financing activities totaled $306 million for the first six months of 2017 primarily due to an issuance of long-term debt and additional capital contributions from Southern Company, partially offset by common stock dividend payments and a redemption of long-term debt. Fluctuations in cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first six months of 2017 include increases of $547 million in long-term debt, primarily due to the issuance of additional senior notes, $367 million in property, plant, and equipment, primarily due to additions to distribution, steam generation, and transmission, $337 million in additional paid-in capital due to capital contributions from Southern Company, and $219 million in cash and cash equivalents, as well as a decrease of $200 million in securities due within one year.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Alabama Power in Item 7 of the Form 10-K for a description of Alabama Power's capital requirements for its construction program, including estimated capital expenditures to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. Approximately $361 million will be required through June 30, 2018 to fund maturities of long-term debt.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality"General" and "Retail Regulatory Matters" – Integrated Resource Plan"Global Climate Issues" of GeorgiaAlabama Power in Item 7 of the Form 10-K for additional information related to Georgiaon Alabama Power's environmental compliance strategy.
Other Revenues
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $6 | | 6.4 | | $31 | | 11.4 |
For year-to-date 2016, other revenues were $302 million compared to $271 million for the corresponding period in 2015. The increase was primarily due to a $14 million increase related to customer temporary facilities services revenues, a $9 million increase in outdoor lighting revenues, and a $3 million increase in solar application fee revenues. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Renewables" herein for additional information on Georgia Power's solar renewable energy program.
GEORGIAALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FuelThe construction program is subject to periodic review and Purchasedrevision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating units, to meet regulatory requirements; changes in the expected environmental compliance program; changes in FERC rules and regulations; Alabama PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Sources of Capital
Alabama Power Expensesplans to obtain the funds to meet its future capital needs from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, term loans, external security issuances, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Alabama Power in Item 7 of the Form 10-K for additional information.
Alabama Power's current liabilities sometimes exceed current assets because of long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs.
At June 30, 2017, Alabama Power had approximately $639 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2017 were as follows:
|
| | | | | | | | | | | | | | |
| | | 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 | | $ | (131 | ) | | (18.6 | ) | | $ | (345 | ) | | (19.9 | ) |
| Purchased power – non-affiliates | | 12 |
| | 13.3 |
| | 50 |
| | 22.0 |
|
| Purchased power – affiliates | | (6 | ) | | (4.1 | ) | | (19 | ) | | (4.6 | ) |
| Total fuel and purchased power expenses | | $ | (125 | ) | | | | $ | (314 | ) | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Expires | | | | | | Expires Within One Year |
| 2017 | | 2018 | | 2022 | | Total | | Unused | | Term Out | | No Term Out |
| (in millions) |
| $ | 3 |
| | $ | 532 |
| | $ | 800 |
| | $ | 1,335 |
| | $ | 1,335 |
| | $ | — |
| | $ | 35 |
|
In the third quarter 2016, total fuel and purchased power expenses were $819 million compared to $944 million in the corresponding period in 2015. The decrease in the third quarter 2016 was due to a net decrease of $189 million in the average cost of fuel and purchased power related to lower coal prices, partially offset by a $64 million increase relatedSee Note 6 to the volumefinancial statements of KWHs generatedAlabama Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and purchased as a result of warmer weather as comparedNote (E) 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 primarily as a result of warmer weather in the third quarter 2016 as compared to the corresponding period in 2015 resulting in higher customer demand.
Fuel and purchased power energy transactions do not have a significant impact on earnings since these fuel expenses are generally offset by fuel revenues through Georgia Power's fuel cost recovery mechanism. See FUTURE EARNINGS POTENTIAL –Condensed Financial Statements under "Retail Regulatory Matters – Fuel Cost RecoveryBank Credit Arrangements" herein for additional information.
DetailsAs reflected in the table above, in May 2017, Alabama Power amended its $800 million multi-year credit arrangement, which, among other things, extended the maturity date from 2020 to 2022.
Most of Georgiathese bank credit arrangements, as well as Alabama Power's generationterm loan arrangements, contain covenants that limit debt levels and purchased powercontain cross-acceleration provisions to other indebtedness (including guarantee obligations) of Alabama Power. Such cross-acceleration provisions to other indebtedness would trigger an event of default if Alabama Power defaulted on indebtedness, the payment of which was then accelerated. At June 30, 2017, Alabama Power was in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, Alabama Power expects to renew or replace its bank credit arrangements as needed, prior to expiration. In connection therewith, Alabama Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the unused credit with banks is allocated to provide liquidity support to Alabama Power's pollution control revenue bonds and commercial paper programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support was approximately $890 million as of June 30, 2017. At June 30, 2017, Alabama Power had no fixed rate pollution control revenue bonds outstanding that were as follows:required to be reoffered within the next 12 months.
|
| | | | | | | |
| | Third Quarter 2016 | | Third Quarter 2015 | | Year-to-Date 2016 | | Year-to-Date 2015 |
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 | 44 | | 41 | | 37 | | 38 |
| Nuclear | 22 | | 22 | | 23 | | 23 |
| Gas | 34 | | 36 | | 38 | | 37 |
| Hydro | — | | 1 | | 2 | | 2 |
Cost of fuel, generated (in cents per net KWH) — | | | | | | | |
| Coal | 3.16 | | 5.42 | | 3.32 | | 4.65 |
| Nuclear | 0.85 | | 0.86 | | 0.85 | | 0.76 |
| Gas | 2.61 | | 2.57 | | 2.27 | | 2.62 |
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. |
GEORGIAALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel
In the third quarter 2016, fuel expense was $575 million comparedAlabama Power also has substantial cash flow from operating activities and access to $706 million in the corresponding period in 2015. The decrease was primarily duecapital markets, including a commercial paper program, to a 26.7% decrease in the average cost of fuel per KWH generated primarily resulting from lower coal prices, partially offset by a 6.6% increase in the volume of KWHs generated due to warmer weather as compared to the corresponding period in 2015.
For year-to-date 2016, fuel expense was $1.39 billion compared to $1.74 billion in the corresponding period in 2015. The decrease was primarily due to a 21.5% decrease in the average cost of fuel per KWH generated primarily resulting from lower coal and natural gas prices and a 3.0% decrease in the volume of KWHs generated by coal.
Purchasedmeet liquidity needs. Alabama Power – Non-Affiliates
In the third quarter 2016, purchased power expense from non-affiliates was $102 million compared to $90 million in the corresponding period in 2015. The increase was primarily due to an 18.3% increase in the volume of KWHs purchased due to warmer weather as compared to the corresponding period in 2015, partially offset bymay meet short-term cash needs through its commercial paper program. Alabama Power may also meet short-term cash needs through a 5.6% decrease in the average cost per KWH purchased primarily resulting from lower natural gas prices.
For year-to-date 2016, purchased power expense from non-affiliates was $277 million compared to $227 million in the corresponding period in 2015. The increase was primarily due to a 29.8% increase in the volume of KWHs purchased, partially offset by a 10.4% decrease in the average cost per KWH purchased primarily resulting from lower natural gas prices.
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, demandsubsidiary organized to issue and sell commercial paper at the request and for energy within the Southern Company system's electric service territory,benefit of Alabama Power and the availabilityother traditional electric operating companies. Proceeds from such issuances for the benefit of Alabama Power are loaned directly to Alabama Power. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support.
Details of commercial paper borrowings were as follows:
|
| | | | | | | | | | | |
| | | Short-term Debt During the Period(*) |
| | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) |
| Commercial paper | | $ | 28 |
| | 1.1 | % | | $ | 200 |
|
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2017. No short-term debt was outstanding at June 30, 2017. |
Alabama Power believes the Southern Company system's generation.need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and operating cash flows.
PurchasedCredit Rating Risk
At June 30, 2017, Alabama Power – Affiliates
In the third quarter 2016, purchased power expense from affiliates was $142 million compared to $148 milliondid not have any credit arrangements that would require material changes in the corresponding period in 2015. The decrease was thepayment schedules or terminations as a result of a 2.4% decreasecredit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, 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 2016, purchased power expense from affiliates was $392 million compared to $411 million in the corresponding period in 2015. The decrease was primarily the resultevent of a 2.7% decrease in the volume of KWHs purchased duecredit rating change to the lower market cost of availableBBB 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 June 30, 2017 were 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 Expensesfollows:
|
| | | | | | |
| 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) |
|
| | | |
| Credit Ratings | Maximum Potential Collateral Requirements |
| | (in millions) |
| At BBB and/or Baa2 | $ | 1 |
|
| At BBB- and/or Baa3 | $ | 2 |
|
| Below BBB- and/or Baa3 | $ | 326 |
|
Included in these amounts are certain agreements that could require collateral in the event that either Alabama Power or Georgia Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Alabama Power to access capital markets and would be likely to impact the cost at which it does so.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including Alabama Power) from stable to negative.
Financing Activities
In the third quarter 2016, other operations and maintenance expenses were $496February 2017, Alabama Power repaid at maturity $200 million compared to $462 million in the corresponding period in 2015. The increase was primarily due to a $26 million charge in connection with an employee attrition plan associated with cost containment activities, an $11 million increase in scheduled generation outage and maintenance costs, and an $11 million increase in transmission and distribution overhead line maintenance, partially offset by a $9 million decrease in pension costs.
For year-to-date 2016, other operations and maintenance expenses were $1.39 billion compared to $1.41 billion in the corresponding period in 2015. The decrease was primarily due to decreasesaggregate principal amount of $31 million in scheduled generation outage and maintenance costs and $28 million in pension costs, partially offset by a $26 million chargeSeries 2007A 5.55% Senior Notes.
GEORGIAALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
in 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 the employee attrition plan and pension costs, respectively.
Depreciation and Amortization
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1 | | 0.5 | | $6 | | 0.9 |
For year-to-date 2016, depreciation and amortization was $639 million compared to $633 million in the corresponding period in 2015. The increase was primarily due to a $25 million increase related to additional plant in service and a $9 million increase in other cost of removal, partially offset by a decrease of $14 million related to amortization of nuclear construction financing costs that was completed in December 2015 and a decrease of $13 million related to unit retirements.
Taxes Other Than Income Taxes
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $7 | | 6.5 | | $9 | | 3.0 |
In the third quarter 2016, taxes other than income taxes were $114 million compared to $107 million in the corresponding period in 2015. For year-to-date 2016, taxes other than income taxes were $311 million compared to $302 million in the corresponding period in 2015. The increases were primarily due to increases in property taxes of $5 million and $8 million in the third quarter and year-to-date 2016, respectively, as a result of an increase in the assessed value of property.
Interest Expense, Net of Amounts Capitalized
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $8 | | 8.9 | | $18 | | 6.6 |
In the third quarter 2016, interest expense, net of amounts capitalized was $98 million compared to $90 million in the corresponding period in 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 2016, interest expense, net of amounts capitalized was $290 million compared to $272 million in the corresponding period in 2015. The increase was primarily due to a $27 million increase in interest due to additional long-term borrowings from the FFB and higher interest rates on obligations for pollution control revenue bonds remarketed in 2015, partially offset by an increase of $5 million in AFUDC debt and a decrease of $4 million in interest due to lower interest rates on obligations for senior notes.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In March 2017, Alabama Power issued $550 million aggregate principal amount of Series 2017A 2.45% Senior Notes due March 30, 2022. The proceeds were used to repay Alabama Power's short-term indebtedness and for general corporate purposes, including Alabama Power's continuous construction program.
Subsequent to June 30, 2017, Alabama Power repaid at maturity $36.1 million aggregate principal amount of Series 1993-A, 1993-B, and 1993-C Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Refunding Bonds (Alabama Power Company Project).
In 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.
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 |
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $11 | | 7.9 | | $35 | | 14.5 |
In the thirdsecond quarter 2016,2017, income taxes were $365$151 million compared to $140 million for the corresponding period in 2016. The increase was primarily due to higher pre-tax earnings.
For year-to-date 2017, income taxes were $277 million compared to $242 million for the corresponding period in 2016. The increase was primarily due to higher pre-tax earnings and unrecognized tax benefits related to certain state deductions for federal income taxes.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Alabama Power's future earnings potential. The level of Alabama Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Alabama Power's primary business of providing electric service. These factors include Alabama Power's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs during a time of increasing costs and limited projected demand growth over the next several years. Future earnings will be driven primarily by customer growth. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions. Earnings are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Alabama Power's service territory. Demand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, which may impact future earnings. Current proposals related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Alabama Power's financial statements. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of 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, as compliance plans are revised or updated, and as legal challenges to rules are completed. Environmental compliance costs are recovered through Rate CNP Compliance. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate CNP Compliance" in Item 8 of the Form 10-K for additional information. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Statutes and Regulations
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the final effluent guidelines rule and the final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs.
On April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. On June 6, 2017, the EPA proposed a rule establishing a stay of the compliance deadlines for certain effluent limitations and pretreatment standards under the rule.
On June 27, 2017, the EPA and the U.S. Army Corps of Engineers proposed to rescind the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The ultimate outcome of these matters cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Alabama Power in Item 7 of the Form 10-K for additional information.
On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules.
On June 1, 2017, the U.S. President announced that the United States will withdraw from the non-binding Paris Agreement and begin renegotiation of its terms.
The ultimate outcome of these matters cannot be determined at this time.
FERC Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the traditional electric operating companies' and Southern Power's market power proceeding and amendment to their market-rate tariff.
On May 17, 2017, the FERC accepted the traditional electric operating companies' (including Alabama Power's) and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies (including Alabama Power) and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' (including Alabama Power's) and Southern Power's market power proceeding, it remains a separate, ongoing matter.
Retail Regulatory Matters
Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See Notes 1 and 3 to the financial statements of Alabama Power under "Nuclear Outage Accounting Order" and "Retail Regulatory Matters," respectively, in Item 8 of the Form 10-K for additional information regarding Alabama Power's rate mechanisms and accounting orders. The recovery balance of each regulatory clause for Alabama Power is reported in Note (B) to the Condensed Financial Statements herein.
Other Matters
Alabama Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Alabama Power is subject to certain claims and legal actions arising in the ordinary course of business. Alabama Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
TheultimateoutcomeofsuchpendingorpotentiallitigationagainstAlabama Powercannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatementsherein,management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Alabama Power's financial statements. See Note (B) to the Condensed Financial
ALABAMA POWER COMPANY
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.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Alabama Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Alabama Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Alabama Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Alabama Power in Item 7 of the Form 10-K for a complete discussion of Alabama Power's critical accounting policies and estimates related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, and Contingent Obligations.
Recently Issued Accounting Standards
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
While Alabama Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Alabama Power's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs. Alabama Power expects that the revenue from contracts with these customers will not result in a significant shift in the timing of revenue recognition for such sales.
Alabama Power's ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements, such as alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Alabama Power's financial statements, if material. In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Alabama Power expects CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Alabama Power intends to use the modified retrospective method of adoption effective January 1, 2018. Alabama Power has also elected to utilize practical expedients which allow it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Alabama Power's financial statements, Alabama Power will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. Alabama Power is currently evaluating the new standard. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Alabama Power's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Alabama Power's financial statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Alabama Power in Item 7 of the Form 10-K for additional information. Alabama Power's financial condition remained stable at June 30, 2017. Alabama Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $672 million for the first six months of 2017, a decrease of $135 million as compared to the first six months of 2016. The decrease in net cash provided from operating activities was primarily due to the receipt of income tax refunds in 2016 as a result of bonus depreciation. Net cash used for investing activities totaled $759 million for the first six months of 2017 primarily due to gross property additions related to distribution, environmental, transmission, and steam generation. Net cash provided from financing activities totaled $306 million for the first six months of 2017 primarily due to an issuance of long-term debt and additional capital contributions from Southern Company, partially offset by common stock dividend payments and a redemption of long-term debt. Fluctuations in cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first six months of 2017 include increases of $547 million in long-term debt, primarily due to the issuance of additional senior notes, $367 million in property, plant, and equipment, primarily due to additions to distribution, steam generation, and transmission, $337 million in additional paid-in capital due to capital contributions from Southern Company, and $219 million in cash and cash equivalents, as well as a decrease of $200 million in securities due within one year.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Alabama Power in Item 7 of the Form 10-K for a description of Alabama Power's capital requirements for its construction program, including estimated capital expenditures to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. Approximately $361 million will be required through June 30, 2018 to fund maturities of long-term debt.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – General" and " – Global Climate Issues" of Alabama Power in Item 7 of the Form 10-K for additional information on Alabama Power's environmental compliance strategy.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating units, to meet regulatory requirements; changes in the expected environmental compliance program; changes in FERC rules and regulations; Alabama PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Sources of Capital
Alabama Power plans to obtain the funds to meet its future capital needs from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, term loans, external security issuances, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Alabama Power in Item 7 of the Form 10-K for additional information.
Alabama Power's current liabilities sometimes exceed current assets because of long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs.
At June 30, 2017, Alabama Power had approximately $639 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2017 were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Expires | | | | | | Expires Within One Year |
| 2017 | | 2018 | | 2022 | | Total | | Unused | | Term Out | | No Term Out |
| (in millions) |
| $ | 3 |
| | $ | 532 |
| | $ | 800 |
| | $ | 1,335 |
| | $ | 1,335 |
| | $ | — |
| | $ | 35 |
|
See Note 6 to the financial statements of Alabama Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
As reflected in the table above, in May 2017, Alabama Power amended its $800 million multi-year credit arrangement, which, among other things, extended the maturity date from 2020 to 2022.
Most of these bank credit arrangements, as well as Alabama Power's term loan arrangements, contain covenants that limit debt levels and contain cross-acceleration provisions to other indebtedness (including guarantee obligations) of Alabama Power. Such cross-acceleration provisions to other indebtedness would trigger an event of default if Alabama Power defaulted on indebtedness, the payment of which was then accelerated. At June 30, 2017, Alabama Power was in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, Alabama Power expects to renew or replace its bank credit arrangements as needed, prior to expiration. In connection therewith, Alabama Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the unused credit with banks is allocated to provide liquidity support to Alabama Power's pollution control revenue bonds and commercial paper programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support was approximately $890 million as of June 30, 2017. At June 30, 2017, Alabama Power had no fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Alabama Power also has substantial cash flow from operating activities and access to capital markets, including a commercial paper program, to meet liquidity needs. Alabama Power may meet short-term cash needs through its commercial paper program. Alabama Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Alabama Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Alabama Power are loaned directly to Alabama Power. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support.
Details of commercial paper borrowings were as follows:
|
| | | | | | | | | | | |
| | | Short-term Debt During the Period(*) |
| | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) |
| Commercial paper | | $ | 28 |
| | 1.1 | % | | $ | 200 |
|
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2017. No short-term debt was outstanding at June 30, 2017. |
Alabama Power believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and operating cash flows.
Credit Rating Risk
At June 30, 2017, Alabama Power did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2 or below. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, energy price risk management, and transmission.
The maximum potential collateral requirements under these contracts at June 30, 2017 were as follows:
|
| | | |
| Credit Ratings | Maximum Potential Collateral Requirements |
| | (in millions) |
| At BBB and/or Baa2 | $ | 1 |
|
| At BBB- and/or Baa3 | $ | 2 |
|
| Below BBB- and/or Baa3 | $ | 326 |
|
Included in these amounts are certain agreements that could require collateral in the event that either Alabama Power or Georgia Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Alabama Power to access capital markets and would be likely to impact the cost at which it does so.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including Alabama Power) from stable to negative.
Financing Activities
In February 2017, Alabama Power repaid at maturity $200 million aggregate principal amount of Series 2007A 5.55% Senior Notes.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In March 2017, Alabama Power issued $550 million aggregate principal amount of Series 2017A 2.45% Senior Notes due March 30, 2022. The proceeds were used to repay Alabama Power's short-term indebtedness and for general corporate purposes, including Alabama Power's continuous construction program.
Subsequent to June 30, 2017, Alabama Power repaid at maturity $36.1 million aggregate principal amount of Series 1993-A, 1993-B, and 1993-C Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Refunding Bonds (Alabama Power Company Project).
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Alabama Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
GEORGIA POWER COMPANY
GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | |
| Retail revenues | $ | 1,904 |
| | $ | 1,907 |
| | $ | 3,593 |
| | $ | 3,624 |
|
| Wholesale revenues, non-affiliates | 40 |
| | 40 |
| | 79 |
| | 82 |
|
| Wholesale revenues, affiliates | 9 |
| | 10 |
| | 17 |
| | 15 |
|
| Other revenues | 95 |
| | 94 |
| | 191 |
| | 202 |
|
| Total operating revenues | 2,048 |
| | 2,051 |
| | 3,880 |
| | 3,923 |
|
| Operating Expenses: | | | | | | | |
| Fuel | 445 |
| | 439 |
| | 815 |
| | 815 |
|
| Purchased power, non-affiliates | 103 |
| | 92 |
| | 191 |
| | 175 |
|
| Purchased power, affiliates | 138 |
| | 111 |
| | 310 |
| | 250 |
|
| Other operations and maintenance | 399 |
| | 439 |
| | 781 |
| | 896 |
|
| Depreciation and amortization | 223 |
| | 214 |
| | 444 |
| | 425 |
|
| Taxes other than income taxes | 101 |
| | 100 |
| | 199 |
| | 197 |
|
| Total operating expenses | 1,409 |
| | 1,395 |
| | 2,740 |
| | 2,758 |
|
| Operating Income | 639 |
| | 656 |
| | 1,140 |
| | 1,165 |
|
| Other Income and (Expense): | | | | | | | |
| Interest expense, net of amounts capitalized | (104 | ) | | (99 | ) | | (205 | ) | | (193 | ) |
| Other income (expense), net | 16 |
| | 8 |
| | 36 |
| | 26 |
|
| Total other income and (expense) | (88 | ) | | (91 | ) | | (169 | ) | | (167 | ) |
| Earnings Before Income Taxes | 551 |
| | 565 |
| | 971 |
| | 998 |
|
| Income taxes | 199 |
| | 211 |
| | 355 |
| | 371 |
|
| Net Income | 352 |
| | 354 |
| | 616 |
| | 627 |
|
| Dividends on Preferred and Preference Stock | 5 |
| | 5 |
| | 9 |
| | 9 |
|
| Net Income After Dividends on Preferred and Preference Stock | $ | 347 |
| | $ | 349 |
| | $ | 607 |
| | $ | 618 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) |
| Net Income | $ | 352 |
| | $ | 354 |
| | $ | 616 |
| | $ | 627 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
Reclassification adjustment for amounts included in net income,
net of tax of $-, $-, $1, and $1, respectively | 1 |
| | 1 |
| | 2 |
| | 1 |
|
| Total other comprehensive income (loss) | 1 |
| | 1 |
| | 2 |
| | 1 |
|
| Comprehensive Income | $ | 353 |
| | $ | 355 |
| | $ | 618 |
| | $ | 628 |
|
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED) |
| | | | | | | |
| | For the Six Months Ended June 30, |
| | 2017 | | 2016 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 616 |
| | $ | 627 |
|
| Adjustments to reconcile net income to net cash provided from operating activities -- | | | |
| Depreciation and amortization, total | 543 |
| | 530 |
|
| Deferred income taxes | 159 |
| | 157 |
|
| Allowance for equity funds used during construction | (25 | ) | | (24 | ) |
| Deferred expenses | 41 |
| | 39 |
|
| Pension, postretirement, and other employee benefits | (45 | ) | | (28 | ) |
| Settlement of asset retirement obligations | (62 | ) | | (52 | ) |
| Other, net | (39 | ) | | 36 |
|
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (150 | ) | | (25 | ) |
| -Fossil fuel stock | (32 | ) | | 61 |
|
| -Other current assets | (22 | ) | | 10 |
|
| -Accounts payable | (153 | ) | | 6 |
|
| -Accrued taxes | (194 | ) | | (137 | ) |
| -Accrued compensation | (65 | ) | | (44 | ) |
| -Retail fuel cost over recovery | (84 | ) | | 1 |
|
| -Other current liabilities | (6 | ) | | 16 |
|
| Net cash provided from operating activities | 482 |
| | 1,173 |
|
| Investing Activities: | | | |
| Property additions | (1,284 | ) | | (1,058 | ) |
| Nuclear decommissioning trust fund purchases | (271 | ) | | (386 | ) |
| Nuclear decommissioning trust fund sales | 266 |
| | 380 |
|
| Cost of removal, net of salvage | (32 | ) | | (34 | ) |
| Change in construction payables, net of joint owner portion | 1 |
| | (75 | ) |
| Payments pursuant to LTSAs | (56 | ) | | (14 | ) |
| Sale of property | 63 |
| | — |
|
| Other investing activities | (12 | ) | | 17 |
|
| Net cash used for investing activities | (1,325 | ) | | (1,170 | ) |
| Financing Activities: | | | |
| Increase in notes payable, net | 37 |
| | 39 |
|
| Proceeds — | | | |
| Capital contributions from parent company | 380 |
| | 239 |
|
| Senior notes | 850 |
| | 650 |
|
| FFB loan | — |
| | 300 |
|
| Short-term borrowings | 800 |
| | — |
|
| Redemptions and repurchases — | | | |
| Pollution control revenue bonds | (27 | ) | | (4 | ) |
| Senior notes | (450 | ) | | (500 | ) |
| Payment of common stock dividends | (640 | ) | | (653 | ) |
| Other financing activities | (19 | ) | | (20 | ) |
| Net cash provided from financing activities | 931 |
| | 51 |
|
| Net Change in Cash and Cash Equivalents | 88 |
| | 54 |
|
| Cash and Cash Equivalents at Beginning of Period | 3 |
| | 67 |
|
| Cash and Cash Equivalents at End of Period | $ | 91 |
| | $ | 121 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid during the period for — | | | |
| Interest (net of $11 and $10 capitalized for 2017 and 2016, respectively) | $ | 186 |
| | $ | 174 |
|
| Income taxes, net | 213 |
| | 78 |
|
| Noncash transactions — Accrued property additions at end of period | 348 |
| | 288 |
|
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At June 30, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 91 |
| | $ | 3 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 565 |
| | 523 |
|
| Unbilled revenues | | 251 |
| | 224 |
|
| Joint owner accounts receivable | | 199 |
| | 57 |
|
| Other accounts and notes receivable | | 62 |
| | 81 |
|
| Affiliated | | 22 |
| | 18 |
|
| Accumulated provision for uncollectible accounts | | (3 | ) | | (3 | ) |
| Fossil fuel stock | | 330 |
| | 298 |
|
| Materials and supplies | | 477 |
| | 479 |
|
| Prepaid expenses | | 55 |
| | 105 |
|
| Other regulatory assets, current | | 193 |
| | 193 |
|
| Other current assets | | 22 |
| | 38 |
|
| Total current assets | | 2,264 |
| | 2,016 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 34,410 |
| | 33,841 |
|
| Less: Accumulated provision for depreciation | | 11,502 |
| | 11,317 |
|
| Plant in service, net of depreciation | | 22,908 |
| | 22,524 |
|
| Nuclear fuel, at amortized cost | | 559 |
| | 569 |
|
| Construction work in progress | | 5,422 |
| | 4,939 |
|
| Total property, plant, and equipment | | 28,889 |
| | 28,032 |
|
| Other Property and Investments: | | | | |
| Equity investments in unconsolidated subsidiaries | | 56 |
| | 60 |
|
| Nuclear decommissioning trusts, at fair value | | 874 |
| | 814 |
|
| Miscellaneous property and investments | | 51 |
| | 46 |
|
| Total other property and investments | | 981 |
| | 920 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 675 |
| | 676 |
|
| Other regulatory assets, deferred | | 2,790 |
| | 2,774 |
|
| Other deferred charges and assets | | 589 |
| | 417 |
|
| Total deferred charges and other assets | | 4,054 |
| | 3,867 |
|
| Total Assets | | $ | 36,188 |
| | $ | 34,835 |
|
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholder's Equity | | At June 30, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 261 |
| | $ | 460 |
|
| Notes payable | | 1,228 |
| | 391 |
|
| Accounts payable — | | | | |
| Affiliated | | 367 |
| | 438 |
|
| Other | | 657 |
| | 589 |
|
| Customer deposits | | 269 |
| | 265 |
|
| Accrued taxes | | 212 |
| | 407 |
|
| Accrued interest | | 115 |
| | 106 |
|
| Accrued compensation | | 141 |
| | 224 |
|
| Asset retirement obligations, current | | 251 |
| | 299 |
|
| Other current liabilities | | 185 |
| | 297 |
|
| Total current liabilities | | 3,686 |
| | 3,476 |
|
| Long-term Debt | | 10,793 |
| | 10,225 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 6,163 |
| | 6,000 |
|
| Deferred credits related to income taxes | | 118 |
| | 121 |
|
| Accumulated deferred ITCs | | 251 |
| | 256 |
|
| Employee benefit obligations | | 652 |
| | 703 |
|
| Asset retirement obligations, deferred | | 2,340 |
| | 2,233 |
|
| Other deferred credits and liabilities | | 206 |
| | 199 |
|
| Total deferred credits and other liabilities | | 9,730 |
| | 9,512 |
|
| Total Liabilities | | 24,209 |
| | 23,213 |
|
| Preferred Stock | | 45 |
| | 45 |
|
| Preference Stock | | 221 |
| | 221 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, without par value — | | | | |
| Authorized — 20,000,000 shares | | | | |
| Outstanding — 9,261,500 shares | | 398 |
| | 398 |
|
| Paid-in capital | | 7,274 |
| | 6,885 |
|
| Retained earnings | | 4,052 |
| | 4,086 |
|
| Accumulated other comprehensive loss | | (11 | ) | | (13 | ) |
| Total common stockholder's equity | | 11,713 |
| | 11,356 |
|
| Total Liabilities and Stockholder's Equity | | $ | 36,188 |
| | $ | 34,835 |
|
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
SECOND QUARTER 2017 vs. SECOND QUARTER 2016
AND
YEAR-TO-DATE 2017 vs. YEAR-TO-DATE 2016
OVERVIEW
Georgia Power operates as a vertically integrated utility providing electric service to retail customers within its traditional service territory located within the State of Georgia and to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of Georgia Power's business of providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, reliability, fuel, capital expenditures, and restoration following major storms. Georgia Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms andappropriately balancing required costs and capital expenditures with customer prices will continue to challenge Georgia Power for the foreseeable future.
On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. To provide for a continuation of work at Plant Vogtle Units 3 and 4, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an interim assessment agreement with the EPC Contractor (Interim Assessment Agreement), which the bankruptcy court approved on March 30, 2017. On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion (Guarantee Obligations), of which Georgia Power's proportionate share is approximately $1.7 billion, and that the Guarantee Obligations exist regardless of whether Plant Vogtle Units 3 and 4 are completed. Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into a services agreement (Services Agreement), which was amended and restated on July 20, 2017, for the EPC Contractor to transition construction management of Plant Vogtle Units 3 and 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear. On July 27, 2017, the Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE and the Interim Assessment Agreement expired pursuant to its terms. The Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.
Georgia Power and the other Vogtle Owners are continuing to conduct comprehensive schedule and cost-to-complete assessments, as well as cancellation cost assessments, to determine the impact of the EPC Contractor's bankruptcy filing on the construction cost and schedule for Plant Vogtle Units 3 and 4. Georgia Power will continue working with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4, including, but not limited to, the status of construction and rate recovery, and currently expects to include its recommendation in its seventeenth Vogtle Construction Monitoring (VCM) report to be filed with the Georgia PSC in late August 2017.
An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Georgia Power's financial statements. The ultimate outcome of these matters also is dependent on the completion of the assessments described above, as well as the related regulatory treatment, and cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4, including Georgia Power's preliminary cost-to-complete and cancellation cost assessments for Plant Vogtle Units 3 and 4.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Georgia Power continues to focus on several key performance indicators including, but not limited to, customer satisfaction, plant availability, system reliability, the execution of major construction projects, and net income after dividends on preferred and preference stock.
RESULTS OF OPERATIONS
Net Income
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(2) | | (0.6) | | $(11) | | (1.8) |
Georgia Power's net income after dividends on preferred and preference stock for the second quarter 2017 was $347 million compared to $349 million for the corresponding period in 2016. For year-to-date 2017, net income after dividends on preferred and preference stock was $607 million compared to $618 million for the corresponding period in 2016. The decreases were primarily due to milder weather as compared to the corresponding periods in 2016, partially offset by lower non-fuel operations and maintenance expenses.
Retail Revenues
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(3) | | (0.2) | | $(31) | | (0.9) |
In the second quarter 2017, retail revenues were $1.90 billion compared to $1.91 billion for the corresponding period in 2016. For year-to-date 2017, retail revenues were $3.59 billion compared to $3.62 billion for the corresponding period in 2016.
Details of the changes in retail revenues were as follows:
|
| | | | | | | | | | | | | |
| | Second Quarter 2017 | | Year-to-Date 2017 |
| | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | $ | 1,907 |
| | | | $ | 3,624 |
| | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | (7 | ) | | (0.4 | ) | | 19 |
| | 0.5 |
|
| Sales growth (decline) | 1 |
| | 0.1 |
| | (11 | ) | | (0.3 | ) |
| Weather | (38 | ) | | (2.0 | ) | | (110 | ) | | (3.1 | ) |
| Fuel cost recovery | 41 |
| | 2.1 |
| | 71 |
| | 2.0 |
|
| Retail – current year | $ | 1,904 |
| | (0.2 | )% | | $ | 3,593 |
| | (0.9 | )% |
Revenues associated with changes in rates and pricing decreased in the second quarter and increased year-to-date 2017 when compared to the corresponding periods in 2016. An increase in revenues related to the recovery of Plant Vogtle Units 3 and 4 construction financing costs under the NCCR tariff was more than offset in the second quarter 2017 by the rate pricing effect of decreased customer usage and lower contributions from commercial and industrial customers under a rate plan for variable demand-driven pricing. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Constructions" of Georgia Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction – Regulatory Matters" herein for additional information related to the NCCR tariff.
Revenues attributable to changes in sales were essentially flat in the second quarter and decreased year-to-date 2017 when compared to the corresponding periods in 2016. Weather-adjusted residential KWH sales increased 0.3%, weather-adjusted commercial KWH sales increased 0.4%, and weather-adjusted industrial KWH sales decreased
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
1.3% in the second quarter 2017 when compared to the corresponding period in 2016. For year-to-date 2017, weather-adjusted residential KWH sales increased 0.8%, weather-adjusted commercial KWH sales decreased 1.0%, and weather-adjusted industrial KWH sales decreased 2.2% when compared to the corresponding period in 2016. An increase of approximately 29,000 residential customers since June 30, 2016 contributed to the increase in weather-adjusted residential KWH sales. A decline in average customer usage resulting from an increase in energy saving initiatives and electronic commerce transactions contributed to the decrease in weather-adjusted commercial KWH sales, partially offset by an increase of approximately 2,000 commercial customers since June 30, 2016. Decreased demand in the chemicals, paper, and transportation sectors was the main contributor to the decrease in weather-adjusted industrial KWH sales, partially offset by increased demand in the non-manufacturing and rubber sectors. Despite a more stable dollar and improving global economy, the industrial sector remains constrained by economic policy uncertainty.
Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues increased $41 million and $71 million in the second quarter and year-to-date 2017, respectively, when compared to the corresponding periods in 2016 primarily due to higher natural gas prices, partially offset by lower energy sales resulting from milder weather as compared to the corresponding periods in 2016. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" of Georgia Power in Item 7 of the Form 10-K for additional information.
Other Revenues
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1 | | 1.1 | | $(11) | | (5.4) |
For year-to-date 2017, other revenues were $191 million compared to $202 million for the corresponding period in 2016. The decrease was primarily due to a $14 million adjustment in 2016 for customer temporary facilities services revenues and an $8 million decrease in open access transmission tariff revenues, partially offset by a $7 million increase in outdoor lighting sales revenues primarily attributable to LED conversions and a $3 million increase in solar application fee revenue.
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | |
| | Second Quarter 2017
vs.
Second Quarter 2016 | | Year-to-Date 2017
vs.
Year-to-Date 2016 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | 6 |
| | 1.4 | | $ | — |
| | — |
| Purchased power – non-affiliates | 11 |
| | 12.0 | | 16 |
| | 9.1 |
| Purchased power – affiliates | 27 |
| | 24.3 | | 60 |
| | 24.0 |
| Total fuel and purchased power expenses | $ | 44 |
| | | | $ | 76 |
| | |
In the second quarter 2017, total fuel and purchased power expenses were $686 million compared to $642 million in the corresponding period in 2015. 2016. The increase was primarily due to a $45 million increase in the average cost of fuel and purchased power primarily related to higher natural gas prices, slightly offset by a decrease related to the volume of KWHs generated and purchased due to milder weather, resulting in lower customer demand.
For year-to-date 2016, income taxes2017, total fuel and purchased power expenses were $737$1.32 billion compared to $1.24 billion in the corresponding period in 2016. The increase was primarily due to an $89 million increase in the average cost of fuel and purchased power primarily related to higher natural gas prices, partially offset by a net decrease of $13 million
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
related to the volume of KWHs generated and purchased due to milder weather, resulting in lower customer demand.
Fuel and purchased power energy transactions do not have a significant impact on earnings since these fuel expenses are generally offset by fuel revenues through Georgia Power's fuel cost recovery mechanism. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" of Georgia Power in Item 7 of the Form 10-K for additional information.
Details of Georgia Power's generation and purchased power were as follows:
|
| | | | | | | |
| | Second Quarter 2017 | | Second Quarter 2016 | | Year-to-Date 2017 | | Year-to-Date 2016 |
Total generation (in billions of KWHs) | 16 | | 17 | | 30 | | 33 |
Total purchased power (in billions of KWHs) | 6 | | 6 | | 13 | | 12 |
Sources of generation (percent) — | | | | | | | |
| Coal | 36 | | 36 | | 32 | | 33 |
| Nuclear | 25 | | 24 | | 25 | | 24 |
| Gas | 37 | | 38 | | 41 | | 40 |
| Hydro | 2 | | 2 | | 2 | | 3 |
Cost of fuel, generated (in cents per net KWH) — | | | | | | | |
| Coal | 3.20 | | 3.37 | | 3.23 | | 3.45 |
| Nuclear | 0.84 | | 0.84 | | 0.84 | | 0.85 |
| Gas | 2.75 | | 2.18 | | 2.76 | | 2.10 |
Average cost of fuel, generated (in cents per net KWH) | 2.43 | | 2.29 | | 2.41 | | 2.26 |
Average cost of purchased power (in cents per net KWH)(*) | 4.76 | | 4.45 | | 4.61 | | 4.38 |
| |
| (*) | Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider. |
Fuel
In the second quarter 2017, fuel expense was $445 million compared to $657$439 million in the corresponding period in 2015.2016. The increase was primarily due to a 26.2% increase in the average cost of natural gas per KWH generated, partially offset by a 6.1% decrease in the volume of KWHs generated by coal and natural gas. For year-to-date 2017, fuel expense remained flat compared to the corresponding period in 2016 primarily resulting from a 31.4% increase in the average cost of natural gas per KWH generated, offset by a 9.5% decrease in the volume of KWHs generated by coal and natural gas.
Purchased Power – Non-Affiliates
In the second quarter 2017, purchased power expense from non-affiliates was $103 million compared to $92 million in the corresponding period in 2016. For year-to-date 2017, purchased power expense from non-affiliates was $191 million compared to $175 million in the corresponding period in 2016. The increases were primarily due to increases in the volume of KWHs purchased of 13.4% and 11.6% in the second quarter and year-to-date 2017, respectively, due to unplanned outages at Georgia Power-owned generating units.
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.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Purchased Power – Affiliates
In the second quarter 2017, purchased power expense from affiliates was $138 million compared to $111 million in the corresponding period in 2016. The increase was primarily the result of an 11.1% increase in the average cost per KWH purchased primarily resulting from higher natural gas prices and a 5.9% increase in the volume of KWHs purchased due to unplanned outages at Georgia Power-owned generating units and to support Southern Company system transmission reliability.
For year-to-date 2017, purchased power expense from affiliates was $310 million compared to $250 million in the corresponding period in 2016. The increase was primarily the result of a 10.1% increase in the volume of KWHs purchased due to unplanned outages at Georgia Power-owned generating units and to support Southern Company system transmission reliability and an 8.8% increase in the average cost per KWH purchased primarily resulting from higher natural gas prices.
Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(40) | | (9.1) | | $(115) | | (12.8) |
In the second quarter 2017, other operations and maintenance expenses were $399 million compared to $439 million in the corresponding period in 2016. The decrease was primarily due to cost containment activities implemented in the third quarter 2016 that contributed to decreases of $14 million in generation maintenance costs and $9 million in transmission and distribution overhead line maintenance. Other factors include decreases of $9 million in customer accounts, service, and sales costs, $5 million in transmission station expenses, and $5 million in billing adjustments with integrated transmission system owners, partially offset by a $7 million increase in scheduled generation outage costs.
For year-to-date 2017, other operations and maintenance expenses were $781 million compared to $896 million in the corresponding period in 2016. The decrease was primarily due to cost containment activities implemented in the third quarter 2016 that contributed to decreases of $28 million in generation maintenance costs, $18 million in transmission and distribution maintenance costs, and $13 million in employee benefit costs. Other factors include a $19 million increase in gains from sales of integrated transmission system assets and a $14 million decrease in customer assistance expenses primarily in demand-side management costs related to the timing of new programs.
Depreciation and Amortization
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $9 | | 4.2 | | $19 | | 4.5 |
In the second quarter 2017, depreciation and amortization was $223 million compared to $214 million in the corresponding period in 2016. The increase was primarily due to a $7 million increase related to additional plant in service and a $4 million decrease in amortization of regulatory liabilities related to other cost of removal obligations that expired in December 2016.
For year-to-date 2017, depreciation and amortization was $444 million compared to $425 million in the corresponding period in 2016. The increase was primarily due to a $17 million increase related to additional plant in service and a $7 million decrease in amortization of regulatory liabilities related to other cost of removal obligations
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
that expired in December 2016, partially offset by a $5 million decrease in depreciation related to generating unit retirements in 2016.
Interest Expense, Net of Amounts Capitalized
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $5 | | 5.1 | | $12 | | 6.2 |
In the second quarter 2017, interest expense, net of amounts capitalized was $104 million compared to $99 million in the corresponding period in 2016. For year-to-date 2017, interest expense, net of amounts capitalized was $205 million compared to $193 million in the corresponding period in 2016. The increases were primarily due to senior notes issuances and additional long-term borrowings from the FFB.
See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" herein for additional information on borrowings from the FFB.
Other Income (Expense), Net
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $8 | | 100.0 | | $10 | | 38.5 |
In the second quarter 2017, other income (expense), net was $16 million compared to $8 million in the corresponding period in 2016. For year-to-date 2017, other income (expense), net was $36 million compared to $26 million in the corresponding period in 2016. The increases were primarily due to increases in gains on purchases of state tax credits.
Income Taxes
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(12) | | (5.7) | | $(16) | | (4.3) |
In the second quarter 2017, income taxes were $199 million compared to $211 million in the corresponding period in 2016. For year-to-date 2017, income taxes were $355 million compared to $371 million in the corresponding period in 2016. The decreases were primarily due to increased state ITCs and lower pre-tax earnings.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Georgia Power's future earnings potential. The level of Georgia Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Georgia Power's business of selling electricity.providing electric service. These factors include Georgia Power's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs during a time of increasing costs and limited projected demand growth over the completionnext several years. Completing the cost assessments and subsequent operation of ongoing construction projects, primarilydetermining future actions related to Plant Vogtle Units 3 and 4.4 construction and rate recovery are also major factors. Future earnings in the near term will be driven primarily by customer growth. Earnings will also depend in part, upon maintaining and growing sales, whichconsidering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies, increasing volumes of electronic commerce transactions, and higher multi-family home construction. Earnings are subject to a numbervariety of other factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Georgia Power's service territory. Demand for electricity is primarily
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, which may impact future earnings.
Current proposals related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals, including any potential changes to the availability of nuclear PTCs, is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Georgia Power's financial statements.
For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Georgia Power in Item 7 of the Form 10-K.10-K and RISK FACTORS in Item 1A herein.
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Georgia Power's Environmental Compliance Cost Recovery (ECCR) tariff allows for the recovery of capital and operations and maintenance costs related to environmental controls mandated by state and federal regulations. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Statutes and Regulations
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 final MATS rule, regional haze regulations, fine particulate mattereight-hour ozone National Ambient Air Quality StandardsStandard (NAAQS), and the Cross State Air Pollution Rule (CSAPR).
On April 25, 2016, in response to a June 2015 U.S. Supreme Court opinion,2, 2017, the EPA published its supplemental finding regarding consideration of costs in support ofa final rule redesignating a 15-county area within metropolitan Atlanta to attainment for the MATS rule. This finding does not impact MATS rule2008 eight-hour ozone NAAQS.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
compliance requirements, costs, or deadlines, and all Georgia Power units that are subject to the MATS rule completed the measures necessary to achieve compliance with the MATS rule by the applicable deadlines.
Also on April 25, 2016,On June 18, 2017, the EPA issued proposed revisions topublished a notice delaying attainment designations for the regional haze regulations.2015 eight-hour ozone NAAQS by one year, setting a revised deadline of October 1, 2018. The ultimate impactoutcome of the proposed revisions will depend on their ultimate adoption, implementation, and any legal challenges andthis matter cannot be determined at this time.
On September 6, 2016, the EPA designated all remaining areas within Georgia Power's service territory as attainment for the 2012 annual fine particulate matter NAAQS.
On October 26, 2016, the EPA published a final rule that updates the CSAPR ozone season nitrogen oxide program, including revising ozone-season emissions budgets in Alabama and certain other states. The State of Georgia's emission budget was not affected by the revisions but interstate emissions trading is restricted unless the state decides to voluntarily adopt a reduced budget. The ultimate impact of this rule will depend on the outcome of any legal challenges and implementation at the state level and cannot be determined at this time.
Coal Combustion ResidualsWater Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Residuals"Water Quality" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA's regulationfinal effluent guidelines rule and the final rule revising the regulatory definition of CCR.waters of the U.S. for all Clean Water Act (CWA) programs.
On April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. On June 6, 2017, the EPA proposed a rule establishing a stay of the compliance deadlines for certain effluent limitations and pretreatment standards under the rule.
On June 13, 2016,27, 2017, the EPA and the U.S. Army Corps of Engineers proposed to rescind the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The ultimate outcome of these matters cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Georgia Power in Item 7 of the Form 10-K for additional information.
On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules.
On June 1, 2017, the U.S. President announced that allthe United States will withdraw from the non-binding Paris Agreement and begin renegotiation of its 29 ash ponds will cease operations and stop receiving coal ashterms.
The ultimate outcome of these matters cannot be determined at this time.
FERC Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Georgia Power 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 requirementsItem 7 of the EPA's Disposal of Coal Combustion Residuals from Electric Utilities Rule (CCR Rule)Form 10-K for additional information regarding the traditional electric operating companies' and establish additional requirements for all ofSouthern Power's market power proceeding and amendment to their market-rate tariff.
On May 17, 2017, the FERC accepted the traditional electric operating companies' (including Georgia Power's onsite storage units consisting of landfillsPower's) and surface impoundments. The final State of Georgia regulations are not anticipated to have a material impact on GeorgiaSouthern Power's compliance obligations underfiling accepting the CCR Rule. See Note (A)terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies (including Georgia Power) and Southern Power to their market-based rate tariff. While the Condensed Financial Statements herein for information regardingFERC's order references the traditional electric operating companies' (including Georgia Power's) and Southern Power's asset retirement obligations (ARO) as of September 30, 2016.market power proceeding, it remains a separate, ongoing matter.
Retail Regulatory Matters
Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, ECCR tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to the construction of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a separate fuel cost recovery tariffs.tariff. See "Nuclear Construction" herein and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the NCCR tariff. Also see "MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" hereinRecovery" of Georgia Power in Item 7 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; 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. Renewables
See Note 3 to the financial statementsMANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Integrated Resource Plan" of Georgia Power under "Retail Regulatory Matters" in Item 87 of the Form 10-K for additional information regarding renewable energy projects.
On May 16, 2017, the 2013 ARP.Georgia PSC approved Georgia Power's request to build, own, and operate a 139-MW solar generation facility at a U.S. Air Force base that is expected to be placed in service by the end of 2019.
During the six months ended June 30, 2017, Georgia Power continued construction of a 31-MW solar generation facility at a U.S. Marine Corps base that is expected to be placed in service in the fourth quarter 2017.
The ultimate outcome of these matters cannot be determined at this time.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Renewables
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Renewables" of Georgia Power in Item 7 of the Form 10-K for information regarding renewable energy projects.
As part of the Georgia Power Advanced Solar Initiative (ASI), four PPAs totaling 149 MWs of solar contracted capacity from Southern Power began in the first quarter 2016. During the second quarter 2016, Georgia Power executed PPAs to purchase an additional 41 MWs of solar capacity under the ASI. Ownership of any associated renewable energy credits (REC) is specified in each respective PPA. The party that owns the RECs retains the right to use them.
On October 4, 2016, two 30-MW solar generating facilities at Fort Gordon and Fort Stewart Army bases began commercial operation. These solar generating facilities were approved by the Georgia PSC in 2014.
Integrated Resource Plan
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Integrated Resource Plan" of Georgia Power in Item 7 of the Form 10-K for additional information regarding Georgia Power's triennial Integrated Resource Plan (2016 IRP).Plan.
On July 28, 2016, the Georgia PSC voted to approve the 2016 IRP including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 combustion turbine (17 MWs), as well as the decertification of the Intercession City unit (143 MWs total capacity). On August 2, 2016, the Plant Mitchell and Plant Kraft units were retired. On August 31, 2016, Georgia Power sold its 33% ownership interest in the Intercession City unit to Duke Energy Florida, Inc.
Additionally,March 7, 2017, the Georgia PSC approved Georgia Power's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures takendecision to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4.
The Georgia PSC approved the reclassification of the remaining net book value of Plant Mitchell Unit 3 and costs associated with materials and supplies remaining at the unit retirement date to a regulatory asset. Recovery of the unit's net book value will continue through December 31, 2019, as provided in the 2013 ARP. The timing of the recovery of the remaining balance of the unit's net book value as of December 31, 2019 and costs associated with materials and supplies remaining at the unit retirement date will be deferred for consideration in Georgia Power's base rate case required to be filed by July 1, 2019.
The Georgia PSC also approved the Renewable Energy Development Initiative to procure an additional 1,200 MWs of renewable resources primarily utilizing market-based prices established through a competitive bidding process with expected in-service dates between 2018 and 2021. Additionally, 200 MWs of self-build capacity for use by Georgia Power was approved, as well as consideration for no more than 200 MWs of capacity as part of a renewable commercial and industrial program.
The Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve the nuclear optionsuspend work at a future generation site in Stewart County, Georgia.Georgia, due to changing economics, including load forecasts and lower fuel costs. The timing of cost recovery for costs incurred of approximately $50 million will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time.
Fuel Cost Recovery
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" of Georgia Power in Item 7 of the Form 10-K for information regarding fuel cost recovery.
Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. On May 17, 2016, the Georgia PSC approved Georgia Power's request to decrease fuel rates by 15% effective June 1, 2016, which will
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
reduce annual billings by approximately $313 million. Georgia Power is currently scheduled to file its next fuel case by February 28, 2017.
Storm Damage Recovery
As of September 30, 2016, the balance in Georgia Power's regulatory asset related to storm damage was $94 million. During October 2016, Hurricane Matthew caused significant damage to Georgia Power's transmission and distribution facilities. The total amount of restoration costs related to this hurricane is estimated to be between $130 million and $155 million, which will be charged to capital accounts or to the storm damage reserve. Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, to the storm damage reserve to cover the operating and maintenance costs of damages from major storms to its transmission and distribution facilities, which is recoverable through base rates. The rate of recovery of storm damage costs after December 31, 2019 is expected to be adjusted in Georgia Power's base rate case required to be filed by July 1, 2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Georgia Power's financial statements. See Note 1 to the financial statements of Georgia Power under "Storm Damage Recovery" in Item 8 of the Form 10-K for additional information regarding Georgia Power's storm damage reserve.
Nuclear Construction
See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the construction of Plant Vogtle Units 3 and 4, Vogtle Construction Monitoring (VCM)VCM reports, the NCCR tariff, the Vogtle Construction Litigation (as defined below), and the Contractor Settlement Agreement.
Vogtle 3 and 4 Agreement (as defined below).and EPC Contractor Bankruptcy
In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an agreement with the Contractor,Vogtle 3 and 4 Agreement, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4 (Vogtle 3 and 4 Agreement).
4. 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. Georgia Power's proportionate share of Plant Vogtle Units 3 and 4 is 45.7%.
The Vogtle 3 and 4 Agreement also providesprovided for liquidated damages upon the EPC Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to a cap. In addition,an aggregate cap of 10% of 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 (basedcontract price, or approximately $920 million (approximately $420 million based on Georgia Power's ownership interest). Under the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of approximately $114 million. Each Vogtle Owner is severally (and not jointly) liablethe EPC Contractor, including any liability of the EPC Contractor for its proportionate share, based on its ownership interest,abandonment of all amounts owedwork. In January 2016, Westinghouse delivered to the ContractorVogtle Owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020 and require 60 days' written notice to 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,Power 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 the Westinghouse Letters of certain credit rating downgrades of any Vogtle Owner, such Vogtle OwnerCredit will not 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,renewed.
Under the terms of the Vogtle 3 and 4 Agreement.
The Vogtle Owners mayAgreement, the EPC Contractor did not have the right to terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided thatconvenience. In the Vogtle Owners will be required to pay certain termination costs. Theevent of an abandonment of work by the EPC Contractor, may terminatethe maximum liability of the EPC Contractor under the Vogtle 3 and 4 Agreement was 40% of the contract price (approximately $1.7 billion based on Georgia Power's ownership interest).
On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. To provide for a continuation of work at Plant Vogtle Units 3 and 4, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Interim Assessment Agreement, which the bankruptcy court approved on March 30, 2017.
The Interim Assessment Agreement provided, among other items, that during the term of the Interim Assessment Agreement (i) Georgia Power was obligated to pay, on behalf of the Vogtle Owners, all costs accrued by the EPC Contractor for subcontractors and vendors for services performed or goods provided, with these amounts paid to the EPC Contractor, except that amounts accrued for Fluor Corporation (Fluor) were paid directly to Fluor; (ii) the EPC Contractor provided certain engineering, procurement, and management services for Plant Vogtle Units 3 and 4, to the same extent as contemplated by the Vogtle 3 and 4 Agreement, and Georgia Power, on behalf of the Vogtle Owners, made payments of $5.4 million per week for these services; (iii) Georgia Power had the right to make payments, on behalf of the Vogtle Owners, directly to subcontractors and vendors who had accounts past due with the EPC Contractor; (iv) the EPC Contractor used commercially reasonable efforts to provide information reasonably requested by Georgia Power as was necessary to continue construction and investigation of the
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Agreement under certain circumstances, including certaincompletion status of Plant Vogtle Owner suspensionUnits 3 and 4; (v) the EPC Contractor rejected or delays of work, action by a governmental authority to permanently stop work, certain breaches ofaccepted the Vogtle 3 and 4 Agreement by the termination of the Interim Assessment Agreement; and (vi) Georgia Power did not exercise any remedies against Toshiba under the Toshiba Guarantee. Under the Interim Assessment Agreement, all parties expressly reserved all rights and remedies under the Vogtle 3 and 4 Agreement and all related security and collateral under applicable law.
The Interim Assessment Agreement, as amended, expired on July 27, 2017. Georgia Power's aggregate liability for the Vogtle Owners Vogtle Owner insolvency, and certain other events.under the Interim Assessment Agreement totaled approximately $650 million, of which $552 million had been paid or accrued as of June 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $297 million.
In 2009,Subsequent to the Georgia PSC votedEPC Contractor bankruptcy filing, a number of subcontractors to certify constructionthe EPC Contractor, including Fluor Enterprises, Inc., a subsidiary of Fluor, alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, is requiredacting for itself and as agent for the Vogtle Owners, has taken, and continues to file semi-annual VCM reports withtake, actions to remove liens filed by these subcontractors through the Georgia PSC by February 28 and August 31 each year. If the projected construction capital costs to be borne byposting of surety bonds. Georgia Power increase by 5% aboveestimates the certified costaggregate liability, through July 31, 2017, of the Vogtle Owners for the removal of subcontractor liens and payment of other EPC Contractor pre-petition accounts payable to total approximately $400 million, of which $354 million had been paid or the projected in-service dates are significantly extended,accrued as of June 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $183 million.
On June 9, 2017, Georgia Power is required to seek an amendmentand the other Vogtle Owners and Toshiba entered the Guarantee Settlement Agreement. Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion, of which Georgia Power's proportionate share is approximately $1.7 billion, and that the Guarantee Obligations exist regardless of whether Plant Vogtle Units 3 and 4 certificateare completed. The Guarantee Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations, beginning in October 2017 and continuing through January 2021. In the event Toshiba receives certain payments, including sale proceeds, from or related to Westinghouse (or its subsidiaries) or Toshiba Nuclear Energy Holdings (UK) Limited (or its subsidiaries), it will hold a portion of such payments in trust for the Georgia PSC.Vogtle Owners and promptly pay them as offsets against any remaining Guarantee Obligations. Under the Guarantee Settlement Agreement, the Vogtle Owners will forbear from exercising certain remedies, including drawing on the Westinghouse Letters of Credit, until June 30, 2020, unless certain events of nonpayment, insolvency, or other material breach of the Guarantee Settlement Agreement by Toshiba occur. If such an event occurs, the balance of the Guarantee Obligations will become immediately due and payable, and the Vogtle Owners may exercise any and all rights and remedies, including drawing on the Westinghouse Letters of Credit without restriction. In February 2013, Georgia Power requested an amendmentaddition, the Guarantee Settlement Agreement does not restrict the Vogtle Owners from fully drawing on the Westinghouse Letters of Credit in the event they are not renewed or replaced prior to the certificateexpiration date.
On June 23, 2017, Toshiba released a revised outlook for fiscal year 2016, which reflected a negative shareholders' equity balance of approximately $5 billion as of March 31, 2017, and announced that its independent audit process was continuing. Toshiba has also announced the existence of material events and conditions that raise substantial doubt about Toshiba's ability to increasecontinue as a going concern. As a result, substantial risk regarding the estimated in-service capitalVogtle Owners' ability to fully collect the Guarantee Obligations continues to exist. An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction 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 quartertherefore, on Georgia Power's financial statements.
Additionally, on June 9, 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 EPC Contractor entered into an amendment to the Vogtle 3Services Agreement, which was amended 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, basedrestated 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 providesJuly 20, 2017, for the resolution of other open existing items relatingEPC Contractor 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 newtransition 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 constructionmanagement of Plant Vogtle Units 3 and 4 that occurred on or beforeto Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear. On July 20, 2017, the date ofbankruptcy court approved the Contractor Settlement Agreement. On January 5, 2016,EPC Contractor's motion seeking authorization to (i) enter into the Services Agreement, (ii) assume and assign to the Vogtle Construction Litigation was dismissed with prejudice.
The Georgia PSC has approved fourteen VCM reports coveringOwners certain project-related contracts, (iii) join 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 AgreementVogtle Owners as counterparties to certain assumed project-related contracts, and the related amendment to(iv) reject the Vogtle 3 and 4 AgreementAgreement.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
toThe Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE on July 27, 2017. The Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.
The ultimate outcome of these matters cannot be determined at this time.
Regulatory Matters
In 2009, the Georgia PSC for its review. In accordancevoted to certify construction of Plant Vogtle Units 3 and 4 with the Georgia PSC's subsequent order, on April 5, 2016, Georgia Power filed supplemental information in support of the Contractor Settlement Agreement and Georgia Power's position that all construction costs to date have been prudently incurred and that the current estimated in-servicea certified capital cost and schedule are reasonable.
On October 20, 2016, Georgia Power andof $4.418 billion. In addition, in 2009 the Georgia PSC Staff entered intoapproved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by including the related CWIP accounts in rate base during the construction period. As of June 30, 2017, Georgia Power had recovered approximately $1.4 billion of financing costs.
On December 20, 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving the following prudence matters: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report will be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement is reasonable and prudent and none of the amounts paid or to be paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) financing costs on verified and approved capital costs will be deemed prudent provided they are incurred prior to December 31, 2019 and December 31, 2020 for Plant Vogtle Units 3 and 4, respectively; and (iv) (a) the in-service capital cost forecast will be adjusted to $5.680$5.680 billion (Revised Forecast), which includes a contingency of $240 million above Georgia Power's then current forecast of $5.440 billion, (b) capital costs incurred up to the Revised Forecast will be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, and (c) Georgia Power would have the burden to show that any capital costs above the Revised Forecast are reasonable and prudent. Under the terms of the Vogtle Cost Settlement Agreement, the certified in-service capital cost for purposes of calculating the NCCR tariff will remain at $4.418 billion. Construction capital costs above $4.418 billion will accrue AFUDC through commercial operation.the date each unit is placed in service. The ROE used to calculate the NCCR tariff will bewas reduced from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016. For purposes of the AFUDC calculation, the ROE on costs between $4.418 billion and $5.440 billion will also be 10.00% and the ROE on any amounts above $5.440 billion would be Georgia Power's average cost of long-term debt. If the Georgia PSC adjusts Georgia Power's ROE rate setting point in a rate case prior to Plant Vogtle Units 3 and 4 being placed into retail rate base, then the ROE for purposes of calculating both the NCCR tariff and AFUDC will likewise be 95 basis points lower than the revised ROE rate setting point. If Plant Vogtle Units 3 and 4 are not commercially operationalplaced in service by December 31, 2020, then (i) the ROE for purposes of calculating the NCCR tariff will be reduced an additional 300 basis points, or $8 million per month, and may, at the Georgia PSC's discretion, be accrued to be used for the benefit of customers, until such time as the units reach commercial operationare placed in service and (ii) the ROE used to calculate AFUDC will be Georgia Power's average cost of long-term debt.
Under the terms of the Vogtle Cost Settlement Agreement, Plant Vogtle Units 3 and 4 will be placed into retail rate base on December 31, 2020 or upon reaching commercial operation, whichever is later. Thethe Georgia PSC will determine, for retail ratemaking purposes, the process of transitioning Plant Vogtle Units 3 and 4 from a construction project to an operating plant no later than Georgia Power's base rate case required to be filed by July 1, 2019.
The Vogtle Cost Settlement Agreement is subject to approval by the Georgia PSC has approved fifteen VCM reports covering the periods through June 30, 2016, including construction capital costs incurred, which is scheduled to vote on this matter on December 20, 2016. Accordingly, the terms of the Vogtle Cost Settlement Agreement are subject to change and the terms of any final agreement approved by the Georgia PSC may differ materially from the terms of the Vogtle Cost Settlement Agreement. If approved, the Vogtle Cost Settlement Agreement is expected to reduce Georgia Power's revenues for the years 2016 through 2020 by a total of approximately $325 million ($115 million reduction in net income).
On August 31, 2016,that date totaled $3.7 billion. Georgia Power filed the fifteenthits sixteenth VCM report, with the Georgia PSC covering the period from JanuaryJuly 1 through June 30,December 31, 2016, requesting approval of $141$222 million of construction capital costs incurred during that period. 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.
On November 1, 2016, Georgia Power submitted its 2017 NCCR tariff filing requesting that the current NCCR tariff rate remain effective for 2017 ifwith 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 increaseon February 27, 2017.
The ultimate outcome of approximately $70 million.these matters cannot be determined at this time.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Revised Cost and Schedule
Georgia Power and the other Vogtle Owners are continuing to conduct comprehensive schedule and cost-to-complete assessments, as well as cancellation cost assessments, to determine the impact of the EPC Contractor's bankruptcy filing on the construction cost and schedule for Plant Vogtle Units 3 and 4. Georgia Power's preliminary assessment results indicate that its proportionate share of the remaining estimated cost to complete Plant Vogtle Units 3 and 4 ranges as follows:
|
| | | | | | | |
| Preliminary in-service dates | | | |
| Unit 3 | February 2021 | – | March 2022 |
| Unit 4 | February 2022 | – | March 2023 |
| | (in billions) |
| Preliminary estimated cost to complete | $ | 3.9 |
| – | $ | 4.6 |
|
| CWIP as of June 30, 2017 | 4.5 |
| | 4.5 |
|
| Guarantee Obligations | (1.7 | ) | | (1.7 | ) |
| Estimated capital costs | $ | 6.7 |
| – | $ | 7.4 |
|
| Vogtle Cost Settlement Agreement Revised Forecast | (5.7 | ) | | (5.7 | ) |
| Estimated net additional capital costs | $ | 1.0 |
| – | $ | 1.7 |
|
Georgia Power's estimates for cost to complete and schedule are based on preliminary analysis and remain subject to further refinement of labor productivity and consumable and commodity quantities and costs.
Georgia Power's estimated financing costs during the construction period total approximately $3.1 billion to $3.5 billion, of which approximately $1.4 billion had been incurred through June 30, 2017.
Georgia Power's preliminary cancellation cost estimate results indicate that its proportionate share of the estimated cancellation costs is approximately $400 million. As a result, as of June 30, 2017, total estimated costs subject to evaluation by Georgia Power and the Georgia PSC in the event of a cancellation decision are as follows:
|
| | | |
| | Preliminary Cancellation Cost Estimate |
| | (in billions) |
| CWIP as of June 30, 2017 | $ | 4.5 |
|
| Financing costs collected, net of tax | 1.4 |
|
Cancellation costs(*) | 0.4 |
|
| Total | $ | 6.3 |
|
| |
| (*) | The estimate for cancellation costs includes, but is not limited to, costs to terminate contracts for construction and other services, as well as costs to secure the Plant Vogtle Units 3 and 4 construction site. |
The Guarantee Obligations continue to exist in the event of cancellation. In addition, under Georgia law, prudently incurred costs related to certificated projects cancelled by the Georgia PSC are allowed recovery, including carrying costs, in future retail rates. Georgia Power will continue working with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4, including, but not limited to, the status of construction and rate recovery, and currently expects to include its recommendation in its seventeenth VCM report to be filed with the Georgia PSC in late August 2017.
The ultimate outcome of these matters is dependent on the completion of the assessments described above, as well as the related regulatory treatment, and cannot be determined at this time.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Matters
As of June 30, 2017, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through a loan guarantee agreement between Georgia Power and the DOE and a multi-advance credit facility among Georgia Power, the DOE, and the FFB. See Note 6 to the financial statements of Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
The IRS has allocated PTCs to Plant Vogtle Units 3 and 4 which require that the applicable unit be placed in service prior to 2021. The net present value of Georgia Power's PTCs is estimated at approximately $400 million per unit.
There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise asif 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 asif construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Vogtle Owners or the Contractor or to both.costs.
AsIf 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
The ultimate outcome 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 3these matters cannot 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.determined at this time.
See RISK FACTORS of Georgia Power in Item 1A of the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world.
The ultimate outcome of these matters cannot be determined at this time. See additional risks in Item 1A herein regarding the EPC Contractor's bankruptcy.
Other Matters
Georgia Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Georgia Power is subject to certain claims and legal actions arising in the ordinary course of business. Georgia Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation against Georgia Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, orinNote3tothefinancialstatementsofGeorgia 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 of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
Georgia Power regularly evaluates its operations and costs. Primarily in response to changing customer expectations and payment patterns, including electronic payments and alternative payment locations, and on-going efforts to increase overall operating efficiencies, Georgia Power initiated cost containment activities throughout the enterprise in July 2016, including the announced closure of 104 local offices and an employee attrition plan affecting approximately 300 positions. Charges associated with the cost containment activities are not expected to have a material impact on Georgia Power's results of operations, financial position, or cash flows. The cost containment activities are expected to reduce operating costs in 2017.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Georgia Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Georgia Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Georgia Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Georgia Power in Item 7 of the Form 10-K for a complete discussion of Georgia Power's critical accounting policies and estimates related to Electric Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, and Contingent Obligations.
Recently Issued Accounting Standards
On February 25, 2016,In 2014, the FASB issued ASU No. 2016-02, Leases(Topic 842)ASC 606, (ASU 2016-02). ASU 2016-02 requires lesseesRevenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize onrevenue to depict the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02transfer of goods or services to customers at the amount expected to be collected. The new standard also changes the recognition, measurement, and presentation of expense associated with leases and provides clarificationrequires enhanced disclosures regarding the identificationnature, amount, timing, and uncertainty of certain componentsrevenue and the related cash flows arising from contracts with customers.
While Georgia Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Georgia Power's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs. Georgia Power expects that the revenue from contracts that would representwith these customers will not result in a lease. significant shift in the timing of revenue recognition for such sales.
Georgia Power's ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Georgia Power's financial statements, if material. In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Georgia Power expects CIAC to be out of the scope of ASC 606.
The accounting required by lessors is relatively unchanged. ASU 2016-02new standard is effective for fiscal yearsinterim and annual reporting periods beginning after December 15, 2018, with early adoption permitted. 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 and2017. Georgia Power intends to adoptuse the ASU inmodified retrospective method of adoption effective January 1, 2018. Georgia Power has also elected to utilize practical expedients which allow it to apply the fourth quarter 2016. Thestandard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the resultstiming or amount of operations,revenues recognized in Georgia Power's financial position,statements, Georgia Power will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or cash flowsitems as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. Georgia Power.Power is currently evaluating the new standard. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Georgia Power's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Georgia Power's financial statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Georgia Power in Item 7 of the Form 10-K for additional information. Georgia Power's financial condition remained stable at SeptemberJune 30, 2016.2017. Georgia Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
"Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $2.26 billion$482 million for the first ninesix months of 20162017 compared to $2.16$1.17 billion for the corresponding period in 2015.2016. The increasedecrease was primarily due to the timing of vendor payments.payments and an increase in under-recovered fuel costs. Net cash used for investing activities totaled $1.76$1.33 billion for the first ninesix months of 20162017 compared to $1.39$1.17 billion for the corresponding period in 20152016 primarily related to installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities. Net cash used forprovided from financing activities totaled $522$931 million for the first ninesix months of 20162017 compared to $711$51 million in the corresponding period in 2015.2016. The decreaseincrease in cash used forprovided from financing activities is primarily due to an increase in short-term borrowings, higher issuances of senior notes, and higher capital contributions received from Southern Company, and senior note issuances, partially offset by higher common stock dividends and lowera decrease in 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 ninesix months of 20162017 include an increase in property, plant, and equipment of $1.1 billion$857 million to comply with environmental standards and the construction of generation, transmission, and distribution facilities, and increasesan increase in current and deferred ARO liabilitiesnotes payable of $638 million and other regulatory assets, deferred of $378$837 million primarily relateddue to changesissuances of short-term bank debt, an increase in ash pond closure strategy. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutespaid-in capital of $389 million primarily due to capital contributions received from Southern Company, and Regulations – Coal Combustion Residuals" herein for additional information regarding changesan increase in ash pond closure strategy.long-term debt of $369 million primarily due to issuances of senior notes.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Georgia Power in Item 7 of the Form 10-K for a description of Georgia Power's capital requirements for its construction program, including estimated capital expenditures for Plant Vogtle Units 3 and 4 and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. Approximately $458$261 million will be required through SeptemberJune 30, 20172018 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.
Georgia Power's construction program is currently estimated to total $2.6 billion Also see FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" for 2017, $2.7 billion for 2018, $2.3 billion for 2019, $2.2 billion for 2020, and $1.8 billion for 2021. These amounts include expenditures of approximately $0.6 billion for 2017, $0.7 billion for 2018, $0.4 billion for 2019, and $0.1 billion for 2020 to continue and complete construction ofadditional information regarding Plant Vogtle Units 3 and 4. These estimated expenditures do not include potential compliance costs that may arise from the EPA's final rules and guidelines or subsequently approved state plans that would limit CO2 emissions from existing, new, modified, or reconstructed fossil-fuel-fired electric generating units.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating units, to meet regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" herein for information regarding additional factors that may impact construction expenditures.expenditures, including Georgia Power's preliminary cost-to-complete and cancellation cost assessments for Plant Vogtle Units 3 and 4.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Sources of Capital
Except as described below with respect to the DOE loan guarantees, Georgia Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, external security issuances, term loans, and equity contributions from Southern Company.Company, and, to the extent available, borrowings from the FFB. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Georgia Power in Item 7 of the Form 10-K for additional information.
In addition, Georgia Power may make borrowings throughhas entered into a loan guarantee agreement (Loan Guarantee Agreement) between Georgia Power andwith the DOE, under which the proceeds of whichborrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4. Under the Loan Guarantee Agreement, the DOE agreed to guarantee borrowings of up to $3.46 billion (not to exceed 70% of Eligible Project Costs) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. Eligible Project Costs incurred through SeptemberJune 30, 20162017 would allow for borrowings of up to $2.6$3.1 billion under the FFB Credit Facility, of which Georgia Power has borrowed $2.5 billion.$2.6 billion; however, on July 27, 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement (LGA Amendment) to clarify the operation of the Loan Guarantee Agreement pending Georgia Power's completion of its comprehensive schedule, cost-to-complete, and cancellation cost assessments (Cost Assessments) for Plant Vogtle Units 3 and 4. Under the terms of the LGA Amendment, Georgia Power will not request any advances under the Loan Guarantee Agreement unless and until such time as Georgia Power has completed the Cost Assessments and made a determination to continue construction of Plant Vogtle Units 3 and 4 and satisfied certain other conditions related to continuing construction. See Note 6 to the financial statements of Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information regarding the Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and additional conditions to borrowing. Also see Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
As of SeptemberAt June 30, 2016,2017, Georgia Power's current liabilities exceeded current assets by $656 million primarily due to$1.42 billion. Georgia Power's current liabilities frequently exceed current assets because of scheduled maturities of long-term debt.debt ($261 million at June 30, 2017) and the periodic use of short-term debt as a funding source ($1.2 billion at June 30, 2017), as well as significant seasonal fluctuations in cash needs. Georgia Power intends to utilize operating cash flows, as well as FFB borrowings, commercial paper, lines of credit, bank notes, andshort-term debt, external securitiessecurity issuances, as market conditions permit, andterm loans, equity contributions from Southern Company, and, to the extent available, borrowings from the FFB to fund its short-term capital needs. Georgia Power has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet liquidity needs.
At SeptemberJune 30, 2016,2017, Georgia Power had approximately $47$91 million of cash and cash equivalents. Georgia Power's committed credit arrangement with banks at SeptemberJune 30, 20162017 was $1.75 billion of which $1.73 billion was unused. ThisIn May 2017, Georgia Power amended its multi-year credit arrangement, expires in 2020.which, among other things, extended the maturity date from 2020 to 2022.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This bank credit arrangement, as well as Georgia Power's term loan arrangements, contains a covenant that limits debt levels and contains a cross accelerationcross-acceleration provision to other indebtedness (including guarantee obligations) of Georgia Power. Such cross accelerationcross-acceleration provision to other indebtedness would trigger an event of default if Georgia Power defaulted on indebtedness, the payment of which was then accelerated. At June 30, 2017, Georgia Power is currentlywas in compliance with this covenant. This bank credit arrangement does not contain a material adverse change clause at the time of borrowing.
Subject to applicable market conditions, Georgia Power expects to renew or replace this credit arrangement, as needed, prior to expiration. In connection therewith, Georgia Power may extend the maturity date and/or increase or decrease the lending commitments thereunder.
See Note 6 to the financial statements of Georgia Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
A portion of the unused credit with banks is allocated to provide liquidity support to Georgia Power's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of SeptemberJune 30, 20162017 was approximately $868$550 million. In June 2017, Georgia Power remarketed $318 million of variable rate pollution control bonds in index rate modes, reducing the liquidity support utilized under Georgia Power's bank credit arrangement. In addition, at SeptemberJune 30, 2016,2017, Georgia Power had $250$436 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 traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support. Commercial paper is included in notes payable in the balance sheets.
Details of short-term borrowings were as follows:
|
| | | | | | | | | | | | | | | | | | |
| | | Short-term Debt at September 30, 2016 | | Short-term Debt During the Period (*) |
| | |
Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) | | | | (in millions) |
| Commercial paper | | $ | 95 |
| | 0.8 | % | | $ | 59 |
| | 0.8 | % | | $ | 197 |
|
|
| | | | | | | | | | | | | | | | | | |
| | | Short-term Debt at June 30, 2017 | | Short-term Debt During the Period(*) |
| | | Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) | | | | (in millions) |
| Commercial paper | | $ | 428 |
| | 1.5 | % | | $ | 280 |
| | 1.4 | % | | $ | 760 |
|
| Short-term bank debt | | 800 |
| | 2.0 | % | | 227 |
| | 2.0 | % | | 800 |
|
| Total | | $ | 1,228 |
| | 1.8 | % | | $ | 507 |
| | 1.6 | % | | |
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended SeptemberJune 30, 2016.2017. |
Georgia Power believes the need for working capital can be adequately met by utilizing the commercial paper programs,program, lines of credit, short-term bank notes, and operating cash flows.
Credit Rating Risk
At June 30, 2017, Georgia Power doesdid not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, and transmission, and, at June 30, 2017, included contracts related to the construction of new generation at Plant Vogtle Units 3 and 4.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The maximum potential collateral requirements under these contracts at SeptemberJune 30, 20162017 were as follows:
| | | Credit Ratings | Maximum Potential
Collateral
Requirements | Maximum Potential
Collateral
Requirements |
| | (in millions) | (in millions) |
| At BBB- and/or Baa3 | $ | 93 |
| $ | 87 |
|
| Below BBB- and/or Baa3 | $ | 1,222 |
| $ | 1,210 |
|
Included in these amounts are certain agreements that could require collateral in the event that oneGeorgia Power or more Southern Company system power pool participantsAlabama Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Georgia Power to access capital markets and would be likely to impact the cost at which it does so.
On March 20, 2017, Moody's revised its rating outlook for Georgia Power from stable to negative.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including Georgia Power) from stable to negative.
On March 30, 2017, Fitch placed the ratings of Georgia Power on rating watch negative.
Financing Activities
In January 2016, $4.085 million aggregate principal amount of Savannah Economic Development Authority Pollution Control Revenue Bonds (Savannah Electric and Power Company Project), First Series 1993 matured.
In March 2016,2017, Georgia Power issued $325$450 million aggregate principal amount of Series 2016A 3.25%2017A 2.00% Senior Notes due April 1, 2026March 30, 2020 and $325$400 million aggregate principal amount of Series 2016B 2.40% Senior Notes due April 1, 2021. An amount equal to the proceeds from the Series 2016A2017B 3.25% Senior Notes due April 1, 2026 will be allocated to eligible green expenditures, including financing of or investments in solar generating facilities or electric vehicle charging infrastructure, or payments under PPAs served by solar or wind generating facilities.March 30, 2027. The proceeds from the Series 2016B 2.40% Senior Notes due April 1, 2021 were used to repay at maturity $250 million aggregate principal amount of 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 general corporate purposes, including Georgia Power's continuous construction program.
In April 2016,2017, Georgia Power's $250Power purchased and held $27 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1995. Georgia Power may reoffer these bonds to the public at a later date.
In June 2017, Georgia Power repaid at maturity $450 million aggregate principal amount of Series 2011B 3.00%2007B 5.70% Senior Notes matured.Notes.
In June 2016,2017, Georgia Power made additional borrowings under the FFB Credit Facilityentered into three floating rate bank loans in an aggregate principal amountamounts of $300$50 million, $150 million, and $100 million, which mature on December 1, 2017, May 31, 2018, and June 28, 2018, respectively, and bear interest based on one-month LIBOR. Also in June 2017, Georgia Power borrowed $500 million pursuant to an uncommitted bank credit arrangement, which bears interest at a 2.571% interest rate throughagreed upon by Georgia Power and the final maturity date of February 20, 2044.bank from time to time and is payable on no less than 30 days' demand by the bank. The proceeds from these bank loans were used to reimburse Georgia Power for Eligible Project Costs relating to the constructionrepay a portion of Plant Vogtle Units 3 and 4.
In August 2016, Georgia Power's $200 million aggregate principal amount of Series 2013C Floating Rate Senior Notes matured.existing indebtedness and for working capital and other general corporate purposes, including Georgia Power's continuous construction program.
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 June 30, | | For the Six Months Ended June 30, |
| | 2016 |
| 2015 | | 2016 | | 2015 | 2017 |
| 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | | | | | | | | |
| Retail revenues | $ | 377 |
| | $ | 363 |
| | $ | 978 |
| | $ | 983 |
| $ | 318 |
| | $ | 319 |
| | $ | 596 |
| | $ | 602 |
|
| Wholesale revenues, non-affiliates | 17 |
| | 30 |
| | 48 |
| | 82 |
| 12 |
| | 15 |
| | 30 |
| | 31 |
|
| Wholesale revenues, affiliates | 23 |
| | 17 |
| | 59 |
| | 52 |
| 10 |
| | 15 |
| | 47 |
| | 36 |
|
| Other revenues | 19 |
| | 19 |
| | 51 |
| | 53 |
| 17 |
| | 16 |
| | 34 |
| | 31 |
|
| Total operating revenues | 436 |
| | 429 |
| | 1,136 |
| | 1,170 |
| 357 |
| | 365 |
| | 707 |
| | 700 |
|
| Operating Expenses: | | | | | | | | | | | | | | |
| Fuel | 141 |
| | 143 |
| | 342 |
| | 375 |
| 88 |
| | 107 |
| | 196 |
| | 201 |
|
| Purchased power, non-affiliates | 33 |
| | 26 |
| | 95 |
| | 76 |
| 35 |
| | 32 |
| | 67 |
| | 62 |
|
| Purchased power, affiliates | 3 |
| | 4 |
| | 9 |
| | 22 |
| 9 |
| | 4 |
| | 11 |
| | 5 |
|
| Other operations and maintenance | 86 |
| | 90 |
| | 239 |
| | 274 |
| 87 |
| | 77 |
| | 171 |
| | 155 |
|
| Depreciation and amortization | 49 |
| | 40 |
| | 129 |
| | 100 |
| 35 |
| | 42 |
| | 53 |
| | 80 |
|
| Taxes other than income taxes | 34 |
| | 35 |
| | 93 |
| | 91 |
| 28 |
| | 29 |
| | 55 |
| | 58 |
|
| Loss on Plant Scherer Unit 3 | | — |
| | — |
| | 33 |
| | — |
|
| Total operating expenses | 346 |
| | 338 |
| | 907 |
| | 938 |
| 282 |
| | 291 |
| | 586 |
| | 561 |
|
| Operating Income | 90 |
| | 91 |
| | 229 |
| | 232 |
| 75 |
| | 74 |
| | 121 |
| | 139 |
|
| Other Income and (Expense): | | | | | | | | | | | | | | |
| Interest expense, net of amounts capitalized | (11 | ) | | (12 | ) | | (36 | ) | | (38 | ) | (13 | ) | | (12 | ) | | (24 | ) | | (25 | ) |
| Other income (expense), net | (2 | ) | | 2 |
| | (4 | ) | | 8 |
| (1 | ) | | (1 | ) | | (2 | ) | | (2 | ) |
| Total other income and (expense) | (13 | ) | | (10 | ) | | (40 | ) | | (30 | ) | (14 | ) | | (13 | ) | | (26 | ) | | (27 | ) |
| Earnings Before Income Taxes | 77 |
| | 81 |
| | 189 |
| | 202 |
| 61 |
| | 61 |
| | 95 |
| | 112 |
|
| Income taxes | 30 |
| | 31 |
| | 74 |
| | 75 |
| 24 |
| | 24 |
| | 38 |
| | 44 |
|
| Net Income | 47 |
| | 50 |
| | 115 |
| | 127 |
| 37 |
| | 37 |
| | 57 |
| | 68 |
|
| Dividends on Preference Stock | 2 |
| | 2 |
| | 7 |
| | 7 |
| 2 |
| | 3 |
| | 4 |
| | 5 |
|
| Net Income After Dividends on Preference Stock | $ | 45 |
| | $ | 48 |
| | $ | 108 |
| | $ | 120 |
| $ | 35 |
| | $ | 34 |
| | $ | 53 |
| | $ | 63 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
| | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2016 | | 2015 | | 2016 | | 2015 | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Net Income | $ | 47 |
| | $ | 50 |
| | $ | 115 |
| | $ | 127 |
| $ | 37 |
| | $ | 37 |
| | $ | 57 |
| | $ | 68 |
|
| Other comprehensive income (loss): | | | | | | | | | | | | | | |
| Qualifying hedges: | | | | | | | | | | | | | | |
| Changes in fair value, net of tax of $-, $-, $(3), and $-, respectively | — |
| | — |
| | (4 | ) | | — |
| |
Changes in fair value, net of tax of
$-, $(1), $(1), and $(3), respectively | | (1 | ) | | (1 | ) | | (1 | ) | | (4 | ) |
| Total other comprehensive income (loss) | — |
| | — |
| | (4 | ) | | — |
| (1 | ) | | (1 | ) | | (1 | ) | | (4 | ) |
| Comprehensive Income | $ | 47 |
| | $ | 50 |
| | $ | 111 |
| | $ | 127 |
| $ | 36 |
| | $ | 36 |
| | $ | 56 |
| | $ | 64 |
|
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.
GULF POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
| | | | For the Nine Months Ended September 30, | For the Six Months Ended June 30, |
| | 2016 | | 2015 | 2017 | | 2016 |
| | (in millions) | (in millions) |
| Operating Activities: | | | | | | |
| Net income | $ | 115 |
| | $ | 127 |
| $ | 57 |
| | $ | 68 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | | | | |
| Depreciation and amortization, total | 134 |
| | 105 |
| 56 |
| | 83 |
|
| Deferred income taxes | 15 |
| | 58 |
| 19 |
| | 16 |
|
| Loss on Plant Scherer Unit 3 | | 33 |
| | — |
|
| Other, net | (4 | ) | | 5 |
| (4 | ) | | (3 | ) |
| Changes in certain current assets and liabilities — | | | | | | |
| -Receivables | (9 | ) | | 18 |
| (25 | ) | | (6 | ) |
| -Fossil fuel stock | 49 |
| | 18 |
| 4 |
| | 34 |
|
| -Other current assets | 3 |
| | 32 |
| 10 |
| | 1 |
|
| -Accrued taxes | 40 |
| | 46 |
| 7 |
| | 17 |
|
| -Accrued compensation | | (17 | ) | | (12 | ) |
| -Over recovered regulatory clause revenues | | (19 | ) | | 5 |
|
| -Other current liabilities | 30 |
| | 2 |
| 3 |
| | (7 | ) |
| Net cash provided from operating activities | 373 |
| | 411 |
| 124 |
| | 196 |
|
| Investing Activities: | | | | | | |
| Property additions | (106 | ) | | (189 | ) | (97 | ) | | (68 | ) |
| Cost of removal, net of salvage | (8 | ) | | (9 | ) | (9 | ) | | (4 | ) |
| Change in construction payables | (7 | ) | | (29 | ) | (14 | ) | | (7 | ) |
| Other investing activities | (6 | ) | | (6 | ) | (3 | ) | | (5 | ) |
| Net cash used for investing activities | (127 | ) | | (233 | ) | (123 | ) | | (84 | ) |
| Financing Activities: | | | | | | |
| Decrease in notes payable, net | (42 | ) | | (34 | ) | |
| Increase (decrease) in notes payable, net | | (190 | ) | | 46 |
|
| Proceeds — | | | | | | |
| Common stock issued to parent | — |
| | 20 |
| 175 |
| | — |
|
| Pollution control revenue bonds | — |
| | 13 |
| |
| Redemptions and repurchases — | | | | |
| Pollution control revenue bonds | — |
| | (13 | ) | |
| Capital contributions from parent company | | 5 |
| | 5 |
|
| Senior notes | | 300 |
| | — |
|
| Redemptions — | | | | |
| Preference stock | | (150 | ) | | — |
|
| Senior notes | (125 | ) | | (60 | ) | (85 | ) | | (125 | ) |
| Payment of common stock dividends | (90 | ) | | (98 | ) | (63 | ) | | (60 | ) |
| Other financing activities | 6 |
| | (4 | ) | (4 | ) | | (6 | ) |
| Net cash used for financing activities | (251 | ) | | (176 | ) | (12 | ) | | (140 | ) |
| Net Change in Cash and Cash Equivalents | (5 | ) | | 2 |
| (11 | ) | | (28 | ) |
| Cash and Cash Equivalents at Beginning of Period | 74 |
| | 39 |
| 56 |
| | 74 |
|
| Cash and Cash Equivalents at End of Period | $ | 69 |
| | $ | 41 |
| $ | 45 |
| | $ | 46 |
|
| Supplemental Cash Flow Information: | | | | | | |
| Cash paid (received) during the period for — | | | | | | |
| Interest (net of $- and $5 capitalized for 2016 and 2015, respectively) | $ | 29 |
| | $ | 27 |
| |
| Interest (net of $- and $- capitalized for 2017 and 2016, respectively) | | $ | 22 |
| | $ | 28 |
|
| Income taxes, net | 14 |
| | (37 | ) | 7 |
| | (3 | ) |
| Noncash transactions — Accrued property additions at end of period | 13 |
| | 17 |
| 19 |
| | 13 |
|
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.
GULF POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
| | | Assets | | At September 30, 2016 | | At December 31, 2015 | | At June 30, 2017 | | At December 31, 2016 |
| | | (in millions) | | (in millions) |
| Current Assets: | | | | | | | | |
| Cash and cash equivalents | | $ | 69 |
| | $ | 74 |
| | $ | 45 |
| | $ | 56 |
|
| Receivables — | | | | | | | | |
| Customer accounts receivable | | 94 |
| | 76 |
| | 77 |
| | 72 |
|
| Unbilled revenues | | 74 |
| | 54 |
| | 70 |
| | 55 |
|
| Under recovered regulatory clause revenues | | 2 |
| | 20 |
| | 26 |
| | 17 |
|
| Income taxes receivable, current | | — |
| | 27 |
| |
| Other accounts and notes receivable | | 4 |
| | 9 |
| | 11 |
| | 6 |
|
| Affiliated | | 3 |
| | 1 |
| | 8 |
| | 17 |
|
| Accumulated provision for uncollectible accounts | | (1 | ) | | (1 | ) | | (1 | ) | | (1 | ) |
| Fossil fuel stock | | 59 |
| | 108 |
| | 67 |
| | 71 |
|
| Materials and supplies | | 56 |
| | 56 |
| | 57 |
| | 55 |
|
| Other regulatory assets, current | | 62 |
| | 90 |
| | 55 |
| | 44 |
|
| Other current assets | | 15 |
| | 22 |
| | 17 |
| | 30 |
|
| Total current assets | | 437 |
| | 536 |
| | 432 |
| | 422 |
|
| Property, Plant, and Equipment: | | | | | | | | |
| In service | | 5,073 |
| | 5,045 |
| | 5,156 |
| | 5,140 |
|
| Less accumulated provision for depreciation | | 1,387 |
| | 1,296 |
| |
| Less: Accumulated provision for depreciation | | | 1,427 |
| | 1,382 |
|
| Plant in service, net of depreciation | | 3,686 |
| | 3,749 |
| | 3,729 |
| | 3,758 |
|
| Other utility plant, net | | — |
| | 62 |
| |
| Construction work in progress | | 64 |
| | 48 |
| | 59 |
| | 51 |
|
| Total property, plant, and equipment | | 3,750 |
| | 3,859 |
| | 3,788 |
| | 3,809 |
|
| Other Property and Investments | | 4 |
| | 4 |
| |
| Deferred Charges and Other Assets: | | | | | | | | |
| Deferred charges related to income taxes | | 59 |
| | 61 |
| | 57 |
| | 58 |
|
| Other regulatory assets, deferred | | 507 |
| | 427 |
| | 510 |
| | 512 |
|
| Other deferred charges and assets | | 45 |
| | 33 |
| | 22 |
| | 21 |
|
| Total deferred charges and other assets | | 611 |
| | 521 |
| | 589 |
| | 591 |
|
| Total Assets | | $ | 4,802 |
| | $ | 4,920 |
| | $ | 4,809 |
| | $ | 4,822 |
|
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.
GULF POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
| | | Liabilities and Stockholder's Equity | | At September 30, 2016 | | At December 31, 2015 | | At June 30, 2017 | | At December 31, 2016 |
| | | (in millions) | | (in millions) |
| Current Liabilities: | | | | | | | | |
| Securities due within one year | | $ | 195 |
| | $ | 110 |
| | $ | 27 |
| | $ | 87 |
|
| Notes payable | | 100 |
| | 142 |
| | 78 |
| | 268 |
|
| Accounts payable — | | | | | | | | |
| Affiliated | | 50 |
| | 55 |
| | 52 |
| | 59 |
|
| Other | | 41 |
| | 44 |
| | 46 |
| | 54 |
|
| Customer deposits | | 35 |
| | 36 |
| | 35 |
| | 35 |
|
| Accrued taxes — | | | | | |
| Accrued income taxes | | 19 |
| | 4 |
| |
| Other accrued taxes | | 34 |
| | 9 |
| |
| Accrued taxes | | | 27 |
| | 20 |
|
| Accrued interest | | 19 |
| | 9 |
| | 9 |
| | 8 |
|
| Accrued compensation | | 20 |
| | 25 |
| | 23 |
| | 40 |
|
| Deferred capacity expense, current | | 22 |
| | 22 |
| | 22 |
| | 22 |
|
| Other regulatory liabilities, current | | 28 |
| | 22 |
| | — |
| | 16 |
|
| Liabilities from risk management activities | | 30 |
| | 49 |
| |
| Other current liabilities | | 41 |
| | 40 |
| | 43 |
| | 40 |
|
| Total current liabilities | | 634 |
| | 567 |
| | 362 |
| | 649 |
|
| Long-term Debt | | 989 |
| | 1,193 |
| | 1,265 |
| | 987 |
|
| Deferred Credits and Other Liabilities: | | | | | | | | |
| Accumulated deferred income taxes | | 904 |
| | 893 |
| | 966 |
| | 948 |
|
| Employee benefit obligations | | 125 |
| | 129 |
| | 92 |
| | 96 |
|
| Deferred capacity expense | | 125 |
| | 141 |
| | 108 |
| | 119 |
|
| Asset retirement obligations | | 119 |
| | 113 |
| |
| Accrued environmental remediation | | 41 |
| | 42 |
| |
| Asset retirement obligations, deferred | | | 125 |
| | 120 |
|
| Other cost of removal obligations | | 248 |
| | 233 |
| | 218 |
| | 249 |
|
| Other regulatory liabilities, deferred | | 48 |
| | 47 |
| | 46 |
| | 47 |
|
| Other deferred credits and liabilities | | 41 |
| | 60 |
| | 74 |
| | 71 |
|
| Total deferred credits and other liabilities | | 1,651 |
| | 1,658 |
| | 1,629 |
| | 1,650 |
|
| Total Liabilities | | 3,274 |
| | 3,418 |
| | 3,256 |
| | 3,286 |
|
| Preference Stock | | 147 |
| | 147 |
| | — |
| | 147 |
|
| Common Stockholder's Equity: | | | | | | | | |
| Common stock, without par value — | | | | | | | | |
| Authorized — 20,000,000 shares | | | | | | | | |
| Outstanding — 5,642,717 shares | | 503 |
| | 503 |
| |
| Outstanding — June 30, 2017: 7,392,717 shares | | | | | |
| — December 31, 2016: 5,642,717 shares | | | 678 |
| | 503 |
|
| Paid-in capital | | 579 |
| | 567 |
| | 596 |
| | 589 |
|
| Retained earnings | | 303 |
| | 285 |
| | 280 |
| | 296 |
|
| Accumulated other comprehensive loss | | (4 | ) | | — |
| |
| Accumulated other comprehensive income (loss) | | | (1 | ) | | 1 |
|
| Total common stockholder's equity | | 1,381 |
| | 1,355 |
| | 1,553 |
| | 1,389 |
|
| Total Liabilities and Stockholder's Equity | | $ | 4,802 |
| | $ | 4,920 |
| | $ | 4,809 |
| | $ | 4,822 |
|
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRDSECOND QUARTER 20162017 vs. THIRDSECOND QUARTER 20152016
AND
YEAR-TO-DATE 20162017 vs. YEAR-TO-DATE 20152016
OVERVIEW
Gulf Power operates as a vertically integrated utility providing electricityelectric service to retail customers within its traditional service territory located in northwest Florida and to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of Gulf Power's business of selling electricity.providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, reliability, restoration following major storms, fuel, and fuel.capital expenditures. Gulf Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Gulf Power for the foreseeable future.
Through 2015, long-term non-affiliateOn April 4, 2017, the Florida PSC approved a settlement agreement (2017 Rate Case Settlement Agreement) among Gulf Power and three intervenors with respect to Gulf Power's request to increase retail base rates. Under the terms of the 2017 Rate Case Settlement Agreement, Gulf Power increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consists of a $62.0 million increase in annual base revenues less an annual equivalent credit of approximately $7.7 million for 2017 for certain wholesale revenues to be provided through December 2019 through the purchased power capacity sales fromcost recovery clause. In addition, Gulf Power continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%), is deemed to have an equity ratio of 52.5% for all retail regulatory purposes, and implemented new dismantlement accruals effective July 1, 2017. Gulf Power will also begin amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 (357 MWs) over 15 years effective January 1, 2018 and will implement new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs) provided, which was recorded in the majorityfirst quarter 2017. The remaining issues related to the inclusion of Gulf Power's wholesale earnings. The revenues from wholesale contracts covering 100% of this capacity represented 82% of wholesale capacity revenues in 2015. Following contract expirations at the end of 2015 and the end of May 2016, Gulf Power's remaining contracted sales from the unit cover approximately 24% of Gulf Power's ownership of the unit through 2019. The expiration of these contracts has had a material negative impact on Gulf Power's earnings in 2016. On May 5, 2016, Gulf Power delivered a letter to the Florida PSC requesting recognition of Gulf Power's ownershipinvestment in Plant Scherer Unit 3 as being in service to retail customers when and as its existing wholesale contracts expire. As a result, on September 13, 2016, the Florida PSC instructed Gulf Power to file its monthly earnings surveillance reports both including and excluding its share of investment and expenses related to Plant Scherer Unit 3 that is not covered by contracts.
On October 12, 2016, Gulf Power filed a petition (2016 Rate Case) with the Florida PSC requesting an increase in retail rates and charges of $106.8 million based on the projected test year of January 1, 2017 through December 31, 2017 andhave been resolved as a retail ROE of 11% compared to the current retail ROE of 10.25%. The recoverabilityresult of the costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 will be decided in this matter. The Florida PSC is expected to make a decision on the 20162017 Rate Case in the second quarter 2017. Gulf Power has requested that the increase in base rates, if approved by the Florida PSC, become effective in July 2017.
On November 2, 2016, the Florida PSC approved Gulf Power's annual rate clause request for its cost recovery clause factors for 2017. The fuel and environmental factors includeSettlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Cost Recovery Clauses" herein for additional information.
The ultimate outcome of these matters cannot be determined at this time. However, if the recovery of Plant Scherer Unit 3 costs is not resolvedunit through the 2016 Rate Case, it could continue to have a material negative impact on Gulf Power's earningsenvironmental cost recovery clause rate approved by the Florida PSC in future years until Gulf Power is able to find a suitable alternative related to this asset.November 2016.
Gulf Power continues to focus on several key performance indicators. These indicators includeincluding, but not limited to, customer satisfaction, plant availability, system reliability, and net income after dividends on preference stock. For additional information
RESULTS OF OPERATIONS
Net Income
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1 | | 2.9 | | $(10) | | (15.9) |
Gulf Power's net income after dividends on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators"preference stock for the second quarter 2017 was $35 million compared to $34 million for the corresponding period in 2016. Gulf Power's net income after dividends on preference stock for year-to-date 2017 was $53 million compared to $63 million for the corresponding period in 2016. The decrease for year-to-date 2017 was primarily due to a write-down of $32.5 million ($20 million after tax) of Gulf Power in Item 7Power's ownership of Plant Scherer Unit 3 resulting from the Form 10-K.2017 Rate Case Settlement Agreement and higher operations and maintenance expenses, partially offset by lower depreciation and higher wholesale revenue. See Note (B) to the
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONSCondensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information regarding the 2017 Rate Case Settlement Agreement.
Net IncomeRetail Revenues
| | | Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) | | (% change) | | (change in millions) | | (% change) |
$(3)(1) | | (6.3) | | $(12) | | (10.0) | | (0.3) | | $(6) | | (1.0) |
Gulf Power's net income after dividends on preference stock forIn the thirdsecond quarter 2016 was $452017, retail revenues were $318 million compared to $48$319 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 in2016. For year-to-date 2017, 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 $108were $596 million compared to $120$602 million for the corresponding period in 2015. The decrease was primarily due to lower non-affiliated wholesale capacity revenues and an increase in depreciation, partially offset by lower operations and maintenance expenses.
Retail Revenues
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $14 | | 3.9 | | $(5) | | (0.5) |
In the third quarter 2016, retail revenues were $377 million compared to $363 million for the corresponding period in 2015. For year-to-date 2016, retail revenues were $978 million compared to $983 million for the corresponding period in 2015.2016.
Details of the changes in retail revenues were as follows:
| | | | Third Quarter 2016 | | Year-to-Date 2016 | Second Quarter 2017 | | Year-to-Date 2017 |
| | (in millions) | | (% change) | | (in millions) | | (% change) | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | $ | 363 |
| | | | $ | 983 |
| | | $ | 319 |
| | | | $ | 602 |
| | |
| Estimated change resulting from – | | | | | | | | | | | | | | |
| Rates and pricing | 11 |
| | 3.0 |
| | 28 |
| | 2.8 |
| 5 |
| | 1.6 |
| | 7 |
| | 1.2 |
|
| Sales growth (decline) | (1 | ) | | (0.3 | ) | | — |
| | — |
| |
| Sales decline | | (1 | ) | | (0.3 | ) | | (3 | ) | | (0.5 | ) |
| Weather | 5 |
| | 1.4 |
| | (3 | ) | | (0.3 | ) | — |
| | — |
| | (6 | ) | | (1.0 | ) |
| Fuel and other cost recovery | (1 | ) | | (0.3 | ) | | (30 | ) | | (3.1 | ) | (5 | ) | | (1.6 | ) | | (4 | ) | | (0.7 | ) |
| Retail – current year | $ | 377 |
| | 3.8 | % | | $ | 978 |
| | (0.6 | )% | $ | 318 |
| | (0.3 | )% | | $ | 596 |
| | (1.0 | )% |
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 thirdsecond quarter and year-to-date 20162017 when compared to the corresponding periods in 20152016 primarily due to an increase in theretail base revenues, as well as an increase in environmental cost recovery clause rate, partially offset by a decrease in the energy conservation cost recovery clause rate, both effective in January 2016. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Cost Recovery Clauses" herein for additional information.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Plant Scherer Unit 3 being rededicated to retail service.
Revenues attributable to changes in sales decreased slightly in the thirdsecond quarter 2016and year-to-date 2017 when compared to the corresponding periodperiods in 2015. For the third quarter 2016, weather-adjusted2016. Weather-adjusted KWH sales to residential and commercial customers decreased 1.9%1.2% and 0.5%1.3%, respectively, for the second quarter 2017 and 1.3% and 1.0%, respectively, for year-to-date 2017 due to lower customer usage primarily resulting from efficiency improvements in appliances and lighting, partially offset by customer growth. KWH sales to industrial customers increased 1.3%decreased 2.7% and 5.6% for the thirdsecond quarter 2016and year-to-date 2017, respectively, primarily due to decreased customer co-generation and changes in customers' operations.
Revenues attributable to changes in sales remained essentially flat The 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 lower2017 decrease also reflects increased 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, partially offset by changes in customers' operations.co-generation.
Fuel and other cost recovery revenues decreased in the thirdsecond quarter 2016and year-to-date 2017 when compared to the corresponding periodperiods in 2015,2016, primarily due to lower fuel, purchased power capacity, and energy conservation recoverable costs, under Gulf Power's environmental cost recovery clause, partially offset by higher environmental recoverable costs under Gulf Power's energy conservation cost recovery clause. 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 fuel costs as a result of decreased generation and lower purchased power energy costs. Lower recoverable costs under Gulf Power's environmental cost recovery clause, partially offset by higher recoverable costs under Gulf Power's energy conservation cost recovery clause, also contributed to this decrease. Fuel and other cost recovery provisions include fuel expenses, the energy component of purchased power costs, purchased power capacity costs, and the difference between projected and actual costs and revenues related to energy conservation and environmental compliance. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Retail Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.
Wholesale Revenues – Non-Affiliates
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(13) | | (43.3) | | $(34) | | (41.5) |
Wholesale revenues from sales to non-affiliates consist of long-term sales agreements to other utilities in Florida and Georgia and short-term opportunity sales. Capacity revenues from long-term sales agreements represent the greatest contribution to net income. The energy is generally sold at variable cost. Short-term opportunity sales are made at market-based rates that generally provide a margin above Gulf Power's variable cost of energy. Wholesale energy revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Gulf Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.
In the third quarter 2016, wholesale revenues from sales to non-affiliates were $17 million compared to $30 million for the corresponding period in 2015. For year-to-date 2016, wholesale revenues from sales to non-affiliates were $48 million compared to $82 million for the corresponding period in 2015. These decreases were primarily due to a 62.1% and 52.3% decrease in capacity revenues for the third quarter and year-to-date 2016, respectively, resulting from the expiration of Plant Scherer Unit 3 long-term sales agreements.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale Revenues – Affiliates
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $6 | | 35.3 | | $7 | | 13.5 |
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(5) | | (33.3) | | $11 | | 30.6 |
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 thirdsecond quarter 2016,2017, wholesale revenues from sales to affiliates were $23$10 million compared to $17$15 million for the corresponding period in 2015.2016. The decrease was primarily due to a 40.6% decrease in KWH sales due to decreased generation as a result of milder weather reducing Southern Company system loads.
For year-to-date 2017, wholesale revenues from sales to affiliates were $47 million compared to $36 million for the corresponding period in 2016. The increase was primarily due to a 42.8%17.2% increase in KWH sales as a result of higher sales to the power pool due to greatersupporting Southern Company system load. For year-to-date 2016, wholesale revenues from sales to affiliates were $59 million compared to $52 million fortransmission reliability and a 10.0% increase in the corresponding period in 2015. The increase was primarilyprice of energy due to a 33.7% increase in KWH sales resulting from lower planned unit outages for Gulf Power's generation resources.higher natural gas prices.
Fuel and Purchased Power Expenses
| | | | | Third Quarter 2016
vs.
Third Quarter 2015 | | Year-to-Date 2016
vs.
Year-to-Date 2015 | Second Quarter 2017
vs.
Second Quarter 2016 | | Year-to-Date 2017
vs.
Year-to-Date 2016 |
| | | (change in millions) | | (% change) | | (change in millions) | | (% change) | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | | $ | (2 | ) | | (1.4 | ) | | $ | (33 | ) | | (8.8 | ) | $ | (19 | ) | | (17.8 | ) | | $ | (5 | ) | | (2.5 | ) |
| Purchased power – non-affiliates | | 7 |
| | 26.9 |
| | 19 |
| | 25.0 |
| 3 |
| | 9.4 |
| | 5 |
| | 8.1 |
|
| Purchased power – affiliates | | (1 | ) | | (25.0 | ) | | (13 | ) | | (59.1 | ) | 5 |
| | 125.0 |
| | 6 |
| | 120.0 |
|
| Total fuel and purchased power expenses | | $ | 4 |
| | | | $ | (27 | ) | | | $ | (11 | ) | | | | $ | 6 |
| | |
In the thirdsecond quarter 2016,2017, total fuel and purchased power expenses were $177$132 million compared to $173$143 million for the corresponding period in 2015.2016. The increasedecrease was primarily due tothe result of a $7$21 million net increasedecrease related to the volume of KWHs generated and purchased as a result of higher customer loads on Gulf Power's system,due to milder weather in 2017 reducing demand, partially offset by a $3an $11 million decrease innet increase due to the higher average cost of fuel andassociated with purchased power.
For year-to-date 2016,2017, total fuel and purchased power expenses were $446$274 million compared to $473$268 million for the corresponding period in 2015.2016. The decreaseincrease was primarily the result of a $40$16 million decrease duenet increase related to the lowerhigher average cost of fuel and purchased power resulting from higher natural gas prices, partially offset by a $13$10 million net increasedecrease related to the volume of KWHs generated and purchased from Gulf Power's gas-fired PPA resource.due to milder weather in 2017 reducing demand.
Fuel and purchased power transactions do not have a significant impact on earnings since energy and capacity expenses are generally offset by energy and capacity revenues through Gulf Power's fuel and purchased power capacity cost recovery clauses and long-term wholesale contracts. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Retail Fuel Cost Recovery" and " – Purchased Power Capacity Recovery" in Item 8 of the Form 10-K for additional information.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of Gulf Power's generation and purchased power were as follows:
| | | | Third Quarter 2016 | | Third Quarter 2015 | | Year-to-Date 2016 | | Year-to-Date 2015 | Second Quarter 2017 | | Second Quarter 2016 | | Year-to-Date 2017 | | Year-to-Date 2016 |
Total generation (in millions of KWHs) | 2,775 | | 2,839 | | 6,654 | | 7,435 | 1,898 | | 2,064 | | 4,220 | | 3,880 |
Total purchased power (in millions of KWHs) | 1,906 | | 1,637 | | 5,295 | | 4,231 | 1,218 | | 1,629 | | 2,676 | | 3,389 |
Sources of generation (percent) – | | |
| Coal | 68 | | 64 | | 57 | | 61 | 50 | | 54 | | 52 | | 48 |
| Gas | 32 | | 36 | | 43 | | 39 | 50 | | 46 | | 48 | | 52 |
Cost of fuel, generated (in cents per net KWH) – | | |
| Coal | 3.55 | | 3.67 | | 3.80 | | 3.88 | 3.17 | | 4.14 | | 3.23 | | 4.05 |
| Gas | 4.38 | | 4.32 | | 4.06 | | 4.22 | 3.88 | | 4.11 | | 3.54 | | 3.92 |
Average cost of fuel, generated (in cents per net KWH) | 3.81 | | 3.90 | | 3.91 | | 4.01 | 3.53 | | 4.12 | | 3.38 | | 3.98 |
Average cost of purchased power (in cents per net KWH)(*) | 3.79 | | 3.83 | | 3.51 | | 4.12 | 5.37 | | 3.50 | | 4.93 | | 3.35 |
| |
| (*) | Average cost of purchased power includes fuel purchased by Gulf Power for tolling agreements where power is generated by the provider. |
Fuel
In the thirdsecond quarter 2016,2017, fuel expense was $141$88 million compared to $143$107 million for the corresponding period in 2015.2016. The decrease was primarily due to a 12.9% decrease in the volume of KWHs generated by Gulf Power's gas-fired generation resources due to higher planned maintenance and a 2.3%14.3% decrease in the average cost of fuel. The decreases were partially offset byfuel resulting from lower coal and natural gas prices and a 3.6% increase in the volume of KWHs generated by Gulf Power's coal-fired generation resources.
For year-to-date 2016, fuel expense was $342 million compared to $375 million for the corresponding period in 2015. The decrease was primarily due to a 17.4%15.3% decrease in the volume of KWHs generated by Gulf Power's coal-fired generation resources due to milder weather reducing demand.
For year-to-date 2017, fuel expense was $196 million compared to $201 million for the lower cost of gas-fired resources andcorresponding period in 2016. The decrease was primarily due to a 2.5%15.1% decrease in the average cost of fuel. The decreases werefuel resulting from lower coal and natural gas prices, partially offset by a 0.5%an 8.8% increase in the volume of KWHs generated by Gulf Power's coal-fired and gas-fired generation resources.resources due to Southern Company system reliability requirements.
Purchased Power – Non-Affiliates
In the thirdsecond quarter 2016,2017, purchased power expense from non-affiliates was $33$35 million compared to $26$32 million for the corresponding period in 2015.2016. The increase was primarily due to a 26.5%68.7% increase in the average cost per KWH purchased primarily resulting from higher natural gas prices, partially offset by a 37.9% decrease in the volume of KWHs purchased due to a planned outage of an external generation resource under a PPA.
For year-to-date 2017, purchased power expense from non-affiliates was $67 million compared to $62 million for the availability of lower cost energy, partially offset bycorresponding period in 2016. The increase was primarily due to a 6.6% decrease50.0% increase in the average cost per KWH purchased due to lower energy costsprimarily resulting from gas-fired resources.
For year-to-date 2016, purchased power expense from non-affiliates was $95 million compared to $76 million for the corresponding period in 2015. The increase was primarily due tohigher natural gas prices, partially offset by a 46.6% increase25.6% decrease in the volume of KWHs purchased due to the availabilitya planned outage of lower cost energy, partially offset byan external generation resource under a 21.0% decrease in the average cost per KWH purchased due to lower energy costs from gas-fired resources.PPA.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the thirdsecond quarter 2016,2017, purchased power expense from affiliates was $3$9 million compared to $4 million for the corresponding period in 2015.2016. The decreaseincrease was primarily due to a 54.9% decrease66.1% increase in the volume of KWHs purchased due to an increase in coal-firedavailability of power pool resources at lower cost compared to Gulf Power generation committedgeneration.
For year-to-date 2017, purchased power expense from affiliates was $11 million compared to serve territorial loads, partially offset by$5 million for the corresponding period in 2016. The increase was primarily due to a 67.4%22.9% increase in the average cost per KWH purchased due to higher power pool interchange rates.volume of KWHs
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2016, purchased power expense from affiliates was $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 due to availability of power pool resources at lower territorial loadscost compared to Gulf Power generation and a 10.8% decrease67.1% increase in the average cost per KWH purchased due to lower power pool interchange rates as a result of lower fuel prices and lower off-peak energy prices of renewable market resources.primarily resulting from increased 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, all as approved by the FERC.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(4) | | (4.4) | | $(35) | | (12.8) |
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $10 | | 13.0 | | $16 | | 10.3 |
In the thirdsecond quarter 2016,2017, other operations and maintenance expenses were $86$87 million compared to $90$77 million for the corresponding period in 2015.2016. For year-to-date 2016,2017, other operations and maintenance expenses were $239$171 million compared to $274$155 million for the corresponding period in 2015. These decreases2016. The increases were primarily due to decreases inhigher expenses at generation facilities associated with routine and planned maintenance expenses at generating facilities and lower expenses related to marketing programs.
Expenses from marketing programs do not have a significant impact on earnings since they are generally offset by energy conservation revenues through Gulf Power's energy conservation cost recovery clause.maintenance.
Depreciation and Amortization
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $9 | | 22.5 | | $29 | | 29.0 |
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(7) | | (16.7) | | $(27) | | (33.8) |
In the thirdsecond quarter 2016,2017, depreciation and amortization was $49$35 million compared to $40$42 million for the corresponding period in 2015.2016. For year-to-date 2016,2017, depreciation and amortization was $129$53 million compared to $100$80 million for the corresponding period in 2015.2016. The increasesdecreases were primarily due to $7$8 million and $20$28 million lessmore of a reduction in depreciation, as authorized in a settlement agreement approved by the Florida PSC in 2013 (2013 Rate Case Settlement Agreement), in the thirdsecond quarter and year-to-date 2016,2017, respectively, compared to the corresponding periods in 2015. In the third quarter 2016, and in accordance with the 2013 Rate Case Settlement Agreement, Gulf Power reversed reductions previously recorded to depreciation. As a result, for the first nine months of 2016, the net reduction in depreciation was zero. Also contributing to the increases were property additions at generation, transmission, and distribution facilities placed in service in 2015.
2016. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Case" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Income (Expense), 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) |
| $(4) | | N/M | | $(12) | | N/M |
N/M - Not meaningful
In the third quarter 2016, other income (expense), net was $(2) million compared to $2 million for the corresponding period in 2015. For year-to-date 2016, other income (expense), net was $(4) million compared to $8 million for the corresponding period in 2015. These changes were primarily due to lower AFUDC related to environmental control projects at 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.providing electric service. These factors include Gulf Power's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs during a time of increasing costs.costs and limited projected demand growth over the next several years. Future earnings in the near term will be driven primarily by customer growth. Earnings will also depend in part, upon maintaining and growing sales, whichconsidering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies due to changes in the minimum allowable equipment efficiencies along with the continuation of changes in customer behavior. Earnings are subject to a numbervariety of other factors. These factors include weather, competition, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Gulf Power's service territory, the successful remarketing of wholesale capacity as current contracts expire, and the outcome of the 2016 Rate Case related to Gulf Power's ownership of Plant Scherer Unit 3.territory. Demand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, which may impact future earnings. Current proposals related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Gulf Power's financial statements. For additional information relating to these issues, see RISK FACTORS in Item
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Gulf Power in Item 7 of the Form 10-K.
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in retail rates or through long-term wholesale agreements on a timely basis or through market-based contracts. The State of Florida has statutory provisions that allow a utility to petition the Florida PSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. Gulf Power's current long-term wholesale agreements contain provisions that permit charging the customer with costs incurred as a result of changes in environmental laws and regulations. The full impact of any such regulatorylegislative or legislativeregulatory changes cannot be determined at this time. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higher costs that are recovered through regulated rates or long-term wholesale agreements could contribute to reduced demand for electricity as well as impact the cost competitiveness of wholesale capacity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters," "Retail Regulatory Matters – Cost Recovery Clauses – Environmental Cost Recovery," and "Other Matters" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Environmental Statutes and Regulations
AirWater Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – AirWater Quality" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the EPA's final MATSeffluent guidelines rule regional haze regulations, fine particulate matter National Ambient Air Quality Standards (NAAQS), and the Cross State Air Pollution Rule (CSAPR).final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs.
On April 25, 2016, in response to a June 2015 U.S. Supreme Court opinion,2017, the EPA published its supplemental finding regarding consideration of costsa notice announcing it would reconsider the effluent guidelines rule, which had been finalized in supportNovember 2015. On June 6, 2017, the EPA proposed a rule establishing a stay of the MATScompliance deadlines for certain effluent limitations and pretreatment standards under the rule. This finding does not impact MATS
On June 27, 2017, the EPA and the U.S. Army Corps of Engineers proposed to rescind the final rule compliance requirements, costs, or deadlines, andthat revised the regulatory definition of waters of the U.S. for all Gulf Power units that are subject to the MATSCWA programs. The final rule completed the measures necessary to achieve compliance with the MATS rulehas been stayed since October 2015 by the applicable deadlines.U.S. Court of Appeals for the Sixth Circuit.
Also on April 25, 2016, the EPA issued proposed revisions to the regional haze regulations. The ultimate impactoutcome of the proposed revisions will depend on their ultimate adoption, implementation, and any legal challenges andthese matters cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Gulf Power in Item 7 of the Form 10-K for additional information.
On September 6, 2016,March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA designated all remaining areas within Gulf Power's service territory as attainmentto review the Clean Power Plan and final greenhouse gas emission standards for the 2012 annual fine particulate matter NAAQS.new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules.
On October 26, 2016,June 1, 2017, the EPA published a final ruleU.S. President announced that updates the CSAPR ozone season nitrogen oxide program, including revising ozone-season emissions budgets in Mississippi and removing FloridaUnited States will withdraw from the CSAPR program. non-binding Paris Agreement and begin renegotiation of its terms.
The ultimate impact of this rule will depend on the outcome of any legal challenges and implementation at the state level andthese matters cannot be determined at this time.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FERC Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the traditional electric operating companies' and Southern Power's market power proceeding and amendment to their market-rate tariff.
On May 17, 2017, the FERC accepted the traditional electric operating companies' (including Gulf Power's) and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies (including Gulf Power) and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' (including Gulf Power's) and Southern Power's market power proceeding, it remains a separate, ongoing matter.
Retail Regulatory Matters
Gulf Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Florida PSC. Gulf Power's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased energy costs, purchased power capacity costs, energy conservation and demand side management programs, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are recovered through base rates. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.
Gulf Power's wholesale business consists of two types of agreements. The first type, referred to as requirements service, provides that Gulf Power serves the customer's capacity and energy requirements from Gulf Power resources. The second type, referred to as a unit sale, is a wholesale customer purchase from a dedicated generating plant unit where a portion of that unit is reserved for the customer. These agreements are associated with Gulf Power's ownership of Plant Scherer Unit 3 and consist of both capacity and energy sales. Through 2015, long-term non-affiliate capacity sales from Gulf Power's ownership of the unit provided the majority of Gulf Power's wholesale earnings. The revenues from wholesale contracts covering 100% of this capacity represented 82% of wholesale capacity revenues in 2015. Following contract expirations at the end of 2015 and the end of May 2016, Gulf Power's remaining contracted sales from the unit cover approximately 24% of Gulf Power's ownership of the unit through 2019. The expiration of these contracts has had a material negative impact on Gulf Power's earnings in 2016. On May 5, 2016, Gulf Power delivered a letter to the Florida PSC requesting recognition of Gulf Power's ownership in Plant Scherer Unit 3 as being in service to retail customers when and as its existing wholesale contracts expire. As a result, on September 13, 2016, the Florida PSC instructed Gulf Power to file its monthly earnings surveillance reports both including and excluding its share of investment and expenses related to Plant Scherer Unit 3 that is not covered by contracts. See "Retail Base Rate Cases" and "Cost Recovery Clauses" herein for additional information.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The ultimate outcome of this matter cannot be determined at this time. However, if the recovery of Plant Scherer Unit 3 costs is not resolved through the 2016 Rate Case, it could continue to have a material negative impact on Gulf Power's earnings in future years until Gulf Power is able to find a suitable alternative related to this asset.
Retail Base Rate Cases
The 2013 Rate Case Settlement Agreement authorized Gulf Power to reduce depreciation and record a regulatory asset up to $62.5 million from January 2014 through June 2017. In any given month, such depreciation reduction maycould not exceed the amount necessary for the retail ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. For 2014 and 2015, Gulf Power recognized reductions in depreciation of $8.4 million and $20.1 million, respectively. No net reduction in depreciation was recorded in 2016. In the third quarter 2016first six months of 2017, Gulf Power recognized the remaining allowable reductions in depreciation totaling $34.0 million.
On April 4, 2017, the Florida PSC approved the 2017 Rate Case Settlement Agreement among Gulf Power and in accordancethree intervenors with respect to Gulf Power's request to increase retail base rates. Under the 2013terms of the 2017 Rate Case Settlement Agreement, Gulf Power reversed reductions previously recorded to depreciation. As a result, forincreased rates effective with the first nine monthsbilling cycle in July 2017 to provide an annual overall net customer impact of 2016,approximately $54.3 million. The net customer impact consists of a $62.0 million increase in annual base revenues less an annual equivalent credit of approximately $7.7 million for 2017 for certain wholesale revenues to be provided through December 2019 through the net reduction in depreciation was zero.
On October 12, 2016,purchased power capacity cost recovery clause. In addition, Gulf Power filedcontinued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%), is deemed to have an equity ratio of 52.5% for all retail regulatory purposes, and implemented new dismantlement accruals effective July 1, 2017. Gulf Power will also begin amortizing the 2016regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 over 15 years effective January 1, 2018 and will implement new depreciation rates effective January 1, 2018. The 2017 Rate Case withSettlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3, which was recorded in the Florida PSC requesting an increasefirst quarter 2017. The remaining issues related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates and chargeshave been resolved as a result of $106.8 million based on the projected test year of January 1, 2017 through December 31, 2017 and a retail ROE of 11% compared to the current retail ROE of 10.25%. TheRate Case Settlement Agreement, including recoverability of thecertain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 will be decided in this matter. The Florida PSC is expected to make a decision on the 2016 Rate Case inunit through the second quarter 2017. Gulf Power has requested that the increase in base rates, ifenvironmental cost recovery clause rate approved by the Florida PSC become effective in July 2017. The ultimate outcome of this matter cannot be determined at this time.November 2016.
Cost Recovery Clauses
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Cost Recovery Clauses" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K for additional information regarding Gulf Power's recovery of retail costs through various regulatory clauses and accounting
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
orders. Gulf Power has four regulatory clauses which are approved by the Florida PSC. See Note (B) to the Condensed Financial Statements herein for additional information.
On November 2, 2016,As discussed previously, the Florida PSC approved2017 Rate Case Settlement Agreement resolved the remaining issues related to Gulf Power's annual rate clause request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2017. The net effectinclusion of the approved changes is a $41 million decrease in annual revenues for 2017. In general, the decreased revenues will not have a significant impact on net income since most of the revenues will be offset by lower expenses. However, certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 were included in the environmental cost recovery clause and no adjustment to the environmental cost recovery clause rate which will have an impact of approximately $11 million and $14 million of additional revenue in 2016 and 2017, respectively. The final disposition of these costs, and the related impact on rates, is subject to the Florida PSC's ultimate ruling on whether costs associated with Plant Scherer Unit 3 are recoverable from retail customers, which is expected to be decidedapproved by the Florida PSC in theNovember 2016 Rate Case as discussed previously. The ultimate outcome of this matter cannot be determined at this time.
Renewables
The Florida PSC issued a final approval order on Gulf Power's Community Solar Pilot Program on April 15, 2016. The program will offer all Gulf Power customers an opportunity to voluntarily contribute to the construction and operation of a solar photovoltaic facility with electric generating capacity of up to 1 MW through annual subscriptions. The energy generated from the solar facility is expected to provide power to all of Gulf Power's customers.
On October 11, 2016, the Florida PSC preliminarily approved an energy purchase agreement for up to 94 MWs of wind generation in central Oklahoma. Purchases under this agreement will be for energy only and will be recovered through Gulf Power's fuel cost recovery clause.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
was made.
Other Matters
As a result of the cost to comply with environmental regulations imposed by the EPA, Gulf Power retired its coal-fired generation at Plant Smith Units 1 and 2 (357 MWs) on March 31, 2016. Gulf Power filed a petition with the Florida PSC requesting permission to recover the remaining net book value of Plant Smith Units 1 and 2 and the remaining materials and supplies associated with these units as of the retirement date. In connection with this request, Gulf Power reclassified approximately $63 million to a regulatory asset, including the remaining net book value of the units and the associated materials and supplies. On August 29, 2016, the Florida PSC approved Gulf Power's request to create a regulatory asset and defer the recovery over a period to be decided in the 2016 Rate Case.
Gulf Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Gulf Power is subject to certain claims and legal actions arising in the ordinary course of business. Gulf Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation against Gulf Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, orinNote3tothefinancialstatementsofGulf PowerinItem8ofthe Form 10-K,management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Gulf Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Gulf Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Gulf Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Gulf Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Gulf Power in Item 7 of the Form 10-K for a complete discussion of Gulf Power's critical accounting policies and estimates related to Electric Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, and Contingent Obligations.
Recently Issued Accounting Standards
On February 25, 2016,In 2014, the FASB issued ASU No. 2016-02, Leases(Topic 842)ASC 606, (ASU 2016-02). ASU 2016-02 requires lesseesRevenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize onrevenue to depict the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02transfer of goods or services to customers at the amount expected to be collected. The new standard also changes the recognition, measurement, and presentation of expense associated with leases and provides clarificationrequires enhanced disclosures regarding the identificationnature, amount, timing, and uncertainty of certain components ofrevenue and the related cash flows arising from 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.customers.
While Gulf Power is currently evaluatingexpects most of its revenue to be included in the new standard andscope of ASC 606, it has not yet determinedfully completed its ultimate impact; however, adoptionevaluation of ASU 2016-02all revenue arrangements. The majority of Gulf Power's revenue, including energy provided to customers, is expected to havefrom tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs. Gulf Power expects that the revenue from contracts with these customers will not result in a significant impact on Gulf Power's balance sheet.
On March 30, 2016,shift in 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 accountingtiming of revenue recognition for income taxes and the cash flow presentation for share-based payment award transactions. Mostsuch sales.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
significantly, entitiesGulf Power's ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements are requiredexcluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Gulf Power's financial statements, if material. In addition, the power and utilities industry continues to recognize all excess tax benefits and deficiencies relatedevaluate other specific industry issues, including the applicability of ASC 606 to the exercise or vestingcontributions in aid of stock compensation as income tax expense or benefit in the income statement.construction (CIAC). Although final implementation guidance has not been issued, Gulf Power currently recognizes any excess tax benefits and deficiencies relatedexpects CIAC to be out of the exercise and vestingscope of stock compensation as additional paid-in capital. ASU 2016-09ASC 606.
The new standard is effective for fiscal yearsinterim and annual reporting periods beginning after December 15, 2016. Early adoption is permitted and2017. Gulf Power intends to adoptuse the ASU inmodified retrospective method of adoption effective January 1, 2018. Gulf Power has also elected to utilize practical expedients which allow it to apply the fourth quarter 2016. Thestandard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the resultstiming or amount of operations,revenues recognized in Gulf Power's financial position,statements, Gulf Power will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or cash flowsitems as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. Gulf Power.Power is currently evaluating the new standard. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Gulf Power's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Gulf Power's financial statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Gulf Power in Item 7 of the Form 10-K for additional information. Gulf Power's financial condition remained stable at SeptemberJune 30, 2016.2017. Gulf Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $373$124 million for the first ninesix months of 20162017 compared to $411$196 million for the corresponding period in 2015.2016. The $38$72 million decrease in net cash was primarily due to a decrease in wholesale capacity revenue, partially offset bythe timing of fossil fuel stock purchases, a federal income tax refund.refund received in 2016, as well as decreases in cash flows associated with lower cost recovery clause rates. Net cash used for investing activities totaled $127$123 million in the first ninesix months of 20162017 primarily due to property additions to utility plant. Net cash used for financing activities totaled $251$12 million for the first ninesix months of 20162017 primarily due to the redemptionpayment of short-term debt, redemptions of preference stock and long-term debt, and common stock dividend payments, partially offset by proceeds from
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
issuances of long-term debt payment ofand common stock dividends, and a decrease in notes payable.stock. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first ninesix months of 20162017 primarily reflect the financing activities described above. Other significant changes include decreasesa decrease in other cost of $125 millionremoval obligations, as authorized in long-term debt due tothe 2013 Settlement Agreement, and a redemption and $109 milliondecrease in net property, plant, and equipment primarily due to the retirementwrite-down of Gulf Power's ownership of Plant Smith Units 1Scherer Unit 3. See "Financing Activities" herein and 2 and an increase in accumulated provisionNote (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for depreciation primarily due to environmental control projects at generating facilities and transmission projects placed in service in 2015.additional information.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Gulf Power in Item 7 of the Form 10-K for a description of Gulf Power's capital requirements for its construction program, including estimated capital expenditures to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, leases, derivative obligations, preference stock dividends, purchase commitments, and trust funding requirements. Approximately $195$7 million will be required through SeptemberJune 30, 20172018 to fund maturities of long-term debt. In addition, at June 30, 2017, $20 million of Gulf Power's total fixed rate pollution control revenue bonds required to be remarketed over the next 12 months are classified as securities due within one year. See "Financing Activities" herein for additional information.
Gulf Power's construction program is currently estimated to total $0.2 billion for 2017, $0.2 billion for 2018, $0.2 billion for 2019, $0.3 billion for 2020, and $0.3 billion for 2021. These estimated expenditures do not include potential compliance costs that may arise from the EPA's final rules and guidelines or subsequently approved state plans that would limit CO2 emissions from existing, new, modified, or reconstructed fossil-fuel-fired electric generating units.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating units, to meet regulatory requirements; changes in the expected environmental compliance programs; changes in FERC rules and regulations; Florida PSC approvals; changes in legislation; the
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 purposesto meet its future capital needs from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, external security issuances, term loans, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Gulf Power in Item 7 of the Form 10-K for additional information.
Gulf Power's current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt, as well as significant seasonal fluctuations in cash needs. Gulf Power has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet short-term liquidity needs, including its commercial paper program which is supported by bank credit facilities.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
At SeptemberJune 30, 2016,2017, Gulf Power had approximately $69$45 million of cash and cash equivalents. Committed credit arrangements with banks at SeptemberJune 30, 20162017 were as follows:
| | | Expires | Expires | | | | | | Executable Term Loans | | Due Within One Year | Expires | | | | | | Executable Term Loans | | Expires Within One Year |
| 2016 | | 2017 | | 2018 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out | |
| 2017 | | 2017 | | 2018 | | 2019 | | 2020 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out |
| (in millions) | (in millions) | | (in millions) | | (in millions) | | (in millions) | (in millions) |
| $ | 50 |
| | $ | 65 |
| | $ | 165 |
| | $ | 280 |
| | $ | 280 |
| | $ | 45 |
| | $ | — |
| | $ | 45 |
| | $ | 70 |
| 30 |
| | $ | 195 |
| | $ | 25 |
| | $ | 30 |
| | $ | 280 |
| | $ | 280 |
| | $ | 45 |
| | $ | — |
| | $ | — |
| | $ | 40 |
|
See Note 6 to the financial statements of Gulf Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
Most of these bank credit arrangements contain covenants that limit debt levels and contain cross accelerationcross-acceleration provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of Gulf Power. Such cross accelerationcross-acceleration provisions to other indebtedness would trigger an event of default if Gulf Power defaulted on indebtedness, the payment of which was then accelerated. At June 30, 2017, Gulf Power is currentlywas in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, Gulf Power expects to renew or replace its bank credit arrangements, as needed, prior to expiration. In connection therewith, Gulf Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
Most of the unused credit arrangements with banks are allocated to provide liquidity support to Gulf Power's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of SeptemberJune 30, 20162017 was approximately $82 million. In addition, at SeptemberJune 30, 2016,2017, Gulf Power had approximately $21$140 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months.
Gulf Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Gulf Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Gulf Power are loaned directly to Gulf Power. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Short-term borrowings are included in notes payable in the balance sheets.
Details of short-term borrowings were as follows:
| | | | | Short-term Debt at September 30, 2016 | | Short-term Debt During the Period(*) | | Short-term Debt at June 30, 2017 | | Short-term Debt During the Period(*) |
| | | Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding | | Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) | | | | (in millions) | | (in millions) | | | | (in millions) | | | | (in millions) |
| Commercial paper | | $ | — |
| | — | % | | $ | 35 |
| | 0.8 | % | | $ | 88 |
| | $ | 78 |
| | 1.5 | % | | $ | 20 |
| | 1.4 | % | | $ | 78 |
|
| Short-term bank debt | | 100 |
| | 1.3 | % | | 100 |
| | 1.2 | % | | 100 |
| | — |
| | — | % | | 53 |
| | 1.7 | % | | 100 |
|
| Total | | $ | 100 |
| | 1.3 | % | | $ | 135 |
| | 1.1 | % | | | | $ | 78 |
| | 1.5 | % | | $ | 73 |
| | 1.6 | % | | |
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended SeptemberJune 30, 2016.2017. |
Gulf Power believes the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, short-term bank loans, and operating cash flows.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Credit Rating Risk
At June 30, 2017, Gulf Power doesdid not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, transmission, and energy price risk management.
The maximum potential collateral requirements under these contracts at SeptemberJune 30, 20162017 were as follows:
| | | Credit Ratings | Maximum Potential Collateral Requirements | Maximum Potential Collateral Requirements |
| | (in millions) | (in millions) |
| At BBB- and/or Baa3 | $ | 192 |
| $ | 167 |
|
| Below BBB- and/or Baa3 | $ | 630 |
| $ | 570 |
|
Included in these amounts are certain agreements that could require collateral in the event that oneAlabama Power or more Southern Company system power pool participantsGeorgia Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Gulf Power to access capital markets and would be likely to impact the cost at which it does so.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including Gulf Power) from stable to negative.
Market Price Risk
Gulf Power's market risk exposure relative to interest rate changes for the thirdsecond quarter and year-to-date 20162017 has not changed materially compared to the December 31, 20152016 reporting period. Gulf Power's exposure to market volatility in commodity fuel prices and prices of electricity with respect to its wholesale generating capacity had beenis limited because its long-term sales agreements shiftedagreement shifts substantially all fuel cost responsibility to the purchaser. However,
In connection with the 2017 Rate Case Settlement Agreement, Gulf Power is exposedrecorded a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 in the first quarter 2017 to market volatilityresolve the inclusion of Gulf Power's investment in energy-related commodity pricesPlant Scherer Unit 3 in retail rates and no adjustment to the extent anyenvironmental cost recovery clause rate approved by the Florida PSC in November 2016 was made. The 2017 Rate Case Settlement Agreement provides that 100% of Gulf Power's ownership of Plant Scherer Unit 3 will be included in retail rates. This resolved the market price risk concern around Gulf Power's uncontracted wholesale generating capacity is uncontracted.related to Plant Scherer Unit 3. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" herein for additional information.
The Florida PSC extended the moratorium on Gulf Power's fuel-hedging program through January 1, 2021 in connection with the 2017 Rate Case Settlement Agreement. The moratorium does not have an impact on the recovery of existing hedges entered into under the previously-approved hedging program.
For an in-depthadditional discussion of Gulf Power's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Gulf Power in Item 7 of the Form 10-K. On May 5, 2016,
Financing Activities
In January 2017, Gulf Power delivered a letterissued 1,750,000 shares of common stock to the Florida PSC requesting recognitionSouthern Company and realized proceeds of $175 million. The proceeds were used for general corporate purposes, including 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 instructedcontinuous construction program.
In March 2017, Gulf Power extended the maturity of a $100 million short-term floating rate bank loan bearing interest based on one-month LIBOR from April 2017 to file its monthly earnings surveillanceOctober 2017 and subsequently repaid the loan in May 2017.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
reports both including and excluding its share of investment and expenses related to Plant Scherer Unit 3 that is not covered by contracts. The recoverability of the costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 is expected to be decided in the 2016 Rate Case. The ultimate outcome of this matter cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" herein for additional information.
Financing Activities
In May 2016,2017, Gulf Power redeemed $125issued $300 million aggregate principal amount of its Series 2011A 5.75%2017A 3.30% Senior Notes due May 30, 2027. The proceeds, together with other funds, were used to repay at maturity $85 million aggregate principal amount of Series 2007A 5.90% Senior Notes due June 1, 2051.
Also in May 2016, Gulf Power entered into an 11-month15, 2017; to repay outstanding commercial paper borrowings; to repay a $100 million short-term floating rate bank loan, bearing interest based on one-month LIBOR. This short-term loan was for $100as discussed above; and to redeem 550,000 shares ($55 million aggregate principal amountliquidation amount) of 6.00% Series Preference Stock, 450,000 shares ($45 million aggregate liquidation amount) of Series 2007A 6.45% Preference Stock, and the proceeds were used to repay existing indebtedness and for working capital and other general corporate purposes.500,000 shares ($50 million aggregate liquidation amount) of Series 2013A 5.60% Preference Stock.
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 INCOME (UNAUDITED)
| | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2016 | | 2015 | | 2016 | | 2015 | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | | | | | | | | |
| Retail revenues | $ | 263 |
| | $ | 244 |
| | $ | 652 |
| | $ | 601 |
| $ | 222 |
| | $ | 206 |
| | $ | 422 |
| | $ | 389 |
|
| Wholesale revenues, non-affiliates | 78 |
| | 76 |
| | 198 |
| | 216 |
| 62 |
| | 60 |
| | 124 |
| | 120 |
|
| Wholesale revenues, affiliates | 7 |
| | 18 |
| | 23 |
| | 63 |
| 15 |
| | 7 |
| | 20 |
| | 16 |
|
| Other revenues | 4 |
| | 3 |
| | 12 |
| | 13 |
| 4 |
| | 4 |
| | 9 |
| | 8 |
|
| Total operating revenues | 352 |
| | 341 |
| | 885 |
| | 893 |
| 303 |
| | 277 |
| | 575 |
| | 533 |
|
| Operating Expenses: | | | | | | | | | | | | | | |
| Fuel | 112 |
| | 130 |
| | 268 |
| | 359 |
| 102 |
| | 81 |
| | 180 |
| | 157 |
|
| Purchased power, non-affiliates | 3 |
| | 1 |
| | 4 |
| | 5 |
| 2 |
| | 1 |
| | 3 |
| | 1 |
|
| Purchased power, affiliates | 5 |
| | 1 |
| | 14 |
| | 6 |
| 4 |
| | 4 |
| | 11 |
| | 9 |
|
| Other operations and maintenance | 74 |
| | 63 |
| | 211 |
| | 206 |
| 70 |
| | 68 |
| | 144 |
| | 136 |
|
| Depreciation and amortization | 30 |
| | 38 |
| | 114 |
| | 95 |
| 41 |
| | 45 |
| | 81 |
| | 84 |
|
| Taxes other than income taxes | 31 |
| | 24 |
| | 81 |
| | 71 |
| 26 |
| | 25 |
| | 52 |
| | 50 |
|
| Estimated loss on Kemper IGCC | 88 |
| | 150 |
| | 222 |
| | 182 |
| 3,012 |
| | 81 |
| | 3,120 |
| | 134 |
|
| Total operating expenses | 343 |
| | 407 |
| | 914 |
| | 924 |
| 3,257 |
| | 305 |
| | 3,591 |
| | 571 |
|
| Operating Income (Loss) | 9 |
| | (66 | ) | | (29 | ) | | (31 | ) | |
| Operating Loss | | (2,954 | ) | | (28 | ) | | (3,016 | ) | | (38 | ) |
| Other Income and (Expense): | | | | | | | | | | | | | | |
| Allowance for equity funds used during construction | 31 |
| | 29 |
| | 90 |
| | 82 |
| 36 |
| | 30 |
| | 71 |
| | 59 |
|
| Interest expense, net of amounts capitalized | (15 | ) | | (13 | ) | | (46 | ) | | 6 |
| (17 | ) | | (15 | ) | | (37 | ) | | (31 | ) |
| Other income (expense), net | (1 | ) | | (2 | ) | | (4 | ) | | (5 | ) | 1 |
| | (1 | ) | | 1 |
| | (3 | ) |
| Total other income and (expense) | 15 |
| | 14 |
| | 40 |
| | 83 |
| 20 |
| | 14 |
| | 35 |
| | 25 |
|
| Earnings (Loss) Before Income Taxes | 24 |
| | (52 | ) | | 11 |
| | 52 |
| |
| Loss Before Income Taxes | | (2,934 | ) | | (14 | ) | | (2,981 | ) | | (13 | ) |
| Income taxes (benefit) | (2 | ) | | (31 | ) | | (29 | ) | | (11 | ) | (881 | ) | | (17 | ) | | (908 | ) | | (27 | ) |
| Net Income (Loss) | 26 |
| | (21 | ) | | 40 |
| | 63 |
| (2,053 | ) | | 3 |
| | (2,073 | ) | | 14 |
|
| Dividends on Preferred Stock | — |
| | — |
| | 1 |
| | 1 |
| 1 |
| | 1 |
| | 1 |
| | 1 |
|
| Net Income (Loss) After Dividends on Preferred Stock | $ | 26 |
| | $ | (21 | ) | | $ | 39 |
| | $ | 62 |
| $ | (2,054 | ) | | $ | 2 |
| | $ | (2,074 | ) | | $ | 13 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
| | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2016 | | 2015 | | 2016 | | 2015 | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Net Income (Loss) | $ | 26 |
| | $ | (21 | ) | | $ | 40 |
| | $ | 63 |
| $ | (2,053 | ) | | $ | 3 |
| | $ | (2,073 | ) | | $ | 14 |
|
| Other comprehensive income (loss) |
| |
| |
| |
|
| |
| |
| |
|
| Qualifying hedges: | | | | | | | | | | | | | | |
| Changes in fair value, net of tax of $-, $-, $-, and $-, respectively | — |
| | — |
| | (1 | ) | | — |
| — |
| | — |
| | 1 |
| | — |
|
Reclassification adjustment for amounts included in net
income, net of tax of $-, $-, $-, and $-, respectively | — |
| | — |
| | 1 |
| | 1 |
| |
| Total other comprehensive income (loss) | — |
| | — |
| | — |
| | 1 |
| — |
| | — |
| | 1 |
| | — |
|
| Comprehensive Income (Loss) | $ | 26 |
| | $ | (21 | ) | | $ | 40 |
| | $ | 64 |
| $ | (2,053 | ) | | $ | 3 |
| | $ | (2,072 | ) | | $ | 14 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED) | | | | For the Nine Months Ended September 30, | For the Six Months Ended June 30, |
| | 2016 | | 2015 | 2017 | | 2016 |
| | (in millions) | (in millions) |
| Operating Activities: | | | | | | |
| Net income | $ | 40 |
| | $ | 63 |
| |
| Adjustments to reconcile net income to net cash provided from operating activities — | | | | |
| Net income (loss) | | $ | (2,073 | ) | | $ | 14 |
|
| Adjustments to reconcile net income (loss) to net cash provided from operating activities — | | | | |
| Depreciation and amortization, total | 115 |
| | 94 |
| 94 |
| | 82 |
|
| Deferred income taxes | 34 |
| | 518 |
| (860 | ) | | (16 | ) |
| Investment tax credits | — |
| | 25 |
| |
| Allowance for equity funds used during construction | (90 | ) | | (82 | ) | (71 | ) | | (59 | ) |
| Regulatory assets associated with Kemper IGCC | (13 | ) | | (56 | ) | |
| Estimated loss on Kemper IGCC | 222 |
| | 182 |
| 3,120 |
| | 134 |
|
| Income taxes receivable, non-current | — |
| | (544 | ) | |
| Other, net | 12 |
| | 7 |
| (11 | ) | | (8 | ) |
| Changes in certain current assets and liabilities — | | | | | | |
| -Prepaid income taxes | 38 |
| | (1 | ) | |
| -Receivables | | (15 | ) | | 15 |
|
| -Fossil fuel stock | | 21 |
| | 6 |
|
| -Other current assets | 7 |
| | 4 |
| (10 | ) | | 31 |
|
| -Accounts payable | 5 |
| | (32 | ) | (20 | ) | | (12 | ) |
| -Accrued taxes | 95 |
| | 24 |
| — |
| | 20 |
|
| -Accrued compensation | | (17 | ) | | (12 | ) |
| -Over recovered regulatory clause revenues | (20 | ) | | 59 |
| (30 | ) | | 4 |
|
| -Mirror CWIP | — |
| | 99 |
| |
| -Customer liability associated with Kemper refunds | (73 | ) | | — |
| — |
| | (69 | ) |
| -Other current liabilities | — |
| | (11 | ) | 7 |
| | 7 |
|
| Net cash provided from operating activities | 372 |
| | 349 |
| 135 |
| | 137 |
|
| Investing Activities: | | | | | | |
| Property additions | (592 | ) | | (626 | ) | (337 | ) | | (403 | ) |
| Construction payables | (25 | ) | | (31 | ) | (19 | ) | | (11 | ) |
| Capital grant proceeds | 137 |
| | — |
| |
| Government grant proceeds | | — |
| | 137 |
|
| Other investing activities | (29 | ) | | (29 | ) | (5 | ) | | (19 | ) |
| Net cash used for investing activities | (509 | ) | | (686 | ) | (361 | ) | | (296 | ) |
| Financing Activities: | | | | | | |
| Increase in notes payable, net | — |
| | 475 |
| |
| Decrease in notes payable, net | | (10 | ) | | — |
|
| Proceeds — | | | | | | |
| Capital contributions from parent company | 227 |
| | 153 |
| 1,001 |
| | 226 |
|
| Long-term debt to parent company | 200 |
| | — |
| 40 |
| | 200 |
|
| Other long-term debt | 900 |
| | — |
| — |
| | 900 |
|
| Short-term borrowings | — |
| | 30 |
| 4 |
| | — |
|
| Redemptions — | | | | | | |
| Short-term borrowings | (475 | ) | | (5 | ) | — |
| | (475 | ) |
| Long-term debt to parent company | (225 | ) | | — |
| (591 | ) | | (225 | ) |
| Other long-term debt | (425 | ) | | (350 | ) | (300 | ) | | (425 | ) |
| Other financing activities | (4 | ) | | (3 | ) | (2 | ) | | (3 | ) |
| Net cash provided from financing activities | 198 |
| | 300 |
| 142 |
| | 198 |
|
| Net Change in Cash and Cash Equivalents | 61 |
| | (37 | ) | (84 | ) | | 39 |
|
| Cash and Cash Equivalents at Beginning of Period | 98 |
| | 133 |
| 224 |
| | 98 |
|
| Cash and Cash Equivalents at End of Period | $ | 159 |
| | $ | 96 |
| $ | 140 |
| | $ | 137 |
|
| Supplemental Cash Flow Information: | | | | | | |
| Cash paid (received) during the period for — | | | | | | |
Interest (paid $72 and $58, net of $36 and $52 capitalized for 2016
and 2015, respectively) | $ | 36 |
| | $ | 6 |
| |
Interest (paid $53 and $49, net of $27 and $23 capitalized for 2017
and 2016, respectively) | | $ | 26 |
| | $ | 26 |
|
| Income taxes, net | (231 | ) | | (55 | ) | (93 | ) | | (122 | ) |
| Noncash transactions — | | | | |
| Accrued property additions at end of period | 80 |
| | 83 |
| |
Issuance of promissory note to parent related to repayment of interest-bearing refundable deposits and accrued interest | — |
| | 301 |
| |
| Noncash transactions — Accrued property additions at end of period | | 59 |
| | 94 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
| | | Assets | | At September 30, 2016 | | At December 31, 2015 | | At June 30, 2017 | | At December 31, 2016 |
| | | (in millions) | | (in millions) |
| Current Assets: | | | | | | | | |
| Cash and cash equivalents | | $ | 159 |
| | $ | 98 |
| | $ | 140 |
| | $ | 224 |
|
| Receivables — | | | | | | | | |
| Customer accounts receivable | | 39 |
| | 26 |
| | 33 |
| | 29 |
|
| Unbilled revenues | | 47 |
| | 36 |
| | 42 |
| | 42 |
|
| Income taxes receivable, current | | — |
| | 20 |
| | 544 |
| | 544 |
|
| Other accounts and notes receivable | | 6 |
| | 10 |
| | 25 |
| | 14 |
|
| Affiliated | | 17 |
| | 20 |
| | 20 |
| | 15 |
|
| Fossil fuel stock | | 96 |
| | 104 |
| | 20 |
| | 100 |
|
| Materials and supplies | | 75 |
| | 75 |
| | 44 |
| | 76 |
|
| Other regulatory assets, current | | 118 |
| | 95 |
| | 114 |
| | 115 |
|
| Prepaid income taxes | | — |
| | 39 |
| |
| Other current assets | | 10 |
| | 8 |
| | 2 |
| | 8 |
|
| Total current assets | | 567 |
| | 531 |
| | 984 |
| | 1,167 |
|
| Property, Plant, and Equipment: | | | | | | | | |
| In service | | 4,835 |
| | 4,886 |
| | 4,826 |
| | 4,865 |
|
| Less accumulated provision for depreciation | | 1,259 |
| | 1,262 |
| |
| Less: Accumulated provision for depreciation | | | 1,283 |
| | 1,289 |
|
| Plant in service, net of depreciation | | 3,576 |
| | 3,624 |
| | 3,543 |
| | 3,576 |
|
| Construction work in progress | | 2,525 |
| | 2,254 |
| | 56 |
| | 2,545 |
|
| Total property, plant, and equipment | | 6,101 |
| | 5,878 |
| | 3,599 |
| | 6,121 |
|
| Other Property and Investments | | 12 |
| | 11 |
| | 22 |
| | 12 |
|
| Deferred Charges and Other Assets: | | | | | | | | |
| Deferred charges related to income taxes | | 330 |
| | 290 |
| | 61 |
| | 361 |
|
| Other regulatory assets, deferred | | 510 |
| | 525 |
| | 441 |
| | 518 |
|
| Income taxes receivable, non-current | | 544 |
| | 544 |
| |
| Accumulated deferred income taxes | | | 404 |
| | — |
|
| Other deferred charges and assets | | 101 |
| | 61 |
| | 20 |
| | 56 |
|
| Total deferred charges and other assets | | 1,485 |
| | 1,420 |
| | 926 |
| | 935 |
|
| Total Assets | | $ | 8,165 |
| | $ | 7,840 |
| | $ | 5,531 |
| | $ | 8,235 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
| | | Liabilities and Stockholder's Equity | | At September 30, 2016 | | At December 31, 2015 | | At June 30, 2017 | | At December 31, 2016 |
| | | (in millions) | | (in millions) |
| Current Liabilities: | | | | | | | | |
| Securities due within one year | | $ | 343 |
| | $ | 728 |
| |
| Securities due within one year — | | | | | |
| Parent | | | $ | — |
| | $ | 551 |
|
| Other | | | 1,028 |
| | 78 |
|
| Notes payable | | 25 |
| | 500 |
| | 17 |
| | 23 |
|
| Accounts payable — | | | | | | | | |
| Affiliated | | 92 |
| | 85 |
| | 54 |
| | 62 |
|
| Other | | 126 |
| | 135 |
| | 109 |
| | 135 |
|
| Customer deposits | | 16 |
| | 16 |
| | 16 |
| | 16 |
|
| Accrued taxes — | | | | | |
| Accrued income taxes | | 110 |
| | — |
| |
| Other accrued taxes | | 75 |
| | 85 |
| |
| Accrued taxes | | | 97 |
| | 99 |
|
| Unrecognized tax benefits | | | 385 |
| | 383 |
|
| Accrued interest | | 20 |
| | 18 |
| | 52 |
| | 46 |
|
| Accrued compensation | | 21 |
| | 26 |
| | 25 |
| | 42 |
|
| Asset retirement obligations, current | | 36 |
| | 22 |
| | 21 |
| | 32 |
|
| Over recovered regulatory clause liabilities | | 76 |
| | 96 |
| | 21 |
| | 51 |
|
| Customer liability associated with Kemper refunds | | 1 |
| | 73 |
| |
| Other current liabilities | | 37 |
| | 52 |
| | 89 |
| | 20 |
|
| Total current liabilities | | 978 |
| | 1,836 |
| | 1,914 |
| | 1,538 |
|
| 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 |
| |
| Long-term Debt | | | 1,169 |
| | 2,424 |
|
| Deferred Credits and Other Liabilities: | | | | | | | | |
| Accumulated deferred income taxes | | 823 |
| | 762 |
| | — |
| | 756 |
|
| Deferred credits related to income taxes | | 7 |
| | 8 |
| |
| Employee benefit obligations | | 146 |
| | 153 |
| | 111 |
| | 115 |
|
| Asset retirement obligations, deferred | | 154 |
| | 154 |
| | 149 |
| | 146 |
|
| Unrecognized tax benefits | | 382 |
| | 368 |
| |
| Other cost of removal obligations | | 172 |
| | 165 |
| | 173 |
| | 170 |
|
| Other regulatory liabilities, deferred | | 76 |
| | 71 |
| | 80 |
| | 84 |
|
| Other deferred credits and liabilities | | 54 |
| | 45 |
| | 29 |
| | 26 |
|
| Total deferred credits and other liabilities | | 1,814 |
| | 1,726 |
| | 542 |
| | 1,297 |
|
| Total Liabilities | | 5,504 |
| | 5,448 |
| | 3,625 |
| | 5,259 |
|
| Redeemable Preferred Stock | | 33 |
| | 33 |
| | 33 |
| | 33 |
|
| Common Stockholder's Equity: | | | | | | | | |
| Common stock, without par value — | | | | | | | | |
| Authorized — 1,130,000 shares | | | | | | | | |
| Outstanding — 1,121,000 shares | | 38 |
| | 38 |
| | 38 |
| | 38 |
|
| Paid-in capital | | 3,124 |
| | 2,893 |
| | 4,527 |
| | 3,525 |
|
| Accumulated deficit | | (528 | ) | | (566 | ) | | (2,689 | ) | | (616 | ) |
| Accumulated other comprehensive loss | | (6 | ) | | (6 | ) | | (3 | ) | | (4 | ) |
| Total common stockholder's equity | | 2,628 |
| | 2,359 |
| | 1,873 |
| | 2,943 |
|
| Total Liabilities and Stockholder's Equity | | $ | 8,165 |
| | $ | 7,840 |
| | $ | 5,531 |
| | $ | 8,235 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRDSECOND QUARTER 20162017 vs. THIRDSECOND QUARTER 20152016
AND
YEAR-TO-DATE 20162017 vs. YEAR-TO-DATE 20152016
OVERVIEW
Mississippi Power operates as a vertically integrated utility providing electricityelectric service to retail customers within its traditional service territory located within the State of Mississippi and to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of Mississippi Power's business of selling electricity.providing electric service. These factors include Mississippi Power's ability to maintain and grow energy sales and to operate in a constructive regulatory environment that provides timely recovery of prudently-incurred costs. These costs include those related to the completion and operation of major construction projects, primarily the Kemper IGCC and the Plant Daniel scrubber project,County energy facility, projected long-term demand growth, reliability, fuel, and increasingly stringent environmental standards, as well as ongoing capital expenditures required for maintenance.maintenance and restoration following major storms. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Mississippi Power for the foreseeable future.
In 2010, the Mississippi PSC issued a CPCN authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate of the Kemper IGCC establishedwas approved by the Mississippi PSC was $2.4 billion within the 2010 CPCN proceedings, subject to a construction cost cap of $2.88 billion, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (Initial DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions). On April 8, 2016, Mississippi Power received 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 theThe combined cycle and the associated common facilities portion of the Kemper IGCC were placed 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.2014.
Mississippi Power's current cost estimate for the Kemper IGCC in total is approximately $6.82 billion, which includes approximately $5.52 billion of costs subject to the construction cost cap and is net of the Additional DOE Grants. Mississippi Power does not intend to seek any rate recovery for any related costs that exceed the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate totaling $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.
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
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
completed, such improvement projects would be expected to enhance plant performance, safety, and/or operations. The related potential costs have yet to be fully evaluated, have not been included in the current cost estimate, and may be subject to the $2.88 billion cost cap. Any further changes in the estimated costs of the Kemper IGCC subject to the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Mississippi Power's statements of income and these changes could be material.
In December 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order), based on a stipulation (2015 Stipulation) between Mississippi Power and the Mississippi Public Utilities Staff (MPUS), authorizing rates that provide for the recovery of approximately $126 million annually related to the combined cycle and associated common facilities portion of Kemper IGCC assets previously placed in service. On July 27, 2016, the Mississippi Supreme Court (Court) dismissed Greenleaf CO2 Solutions, LLC’s (Greenleaf) motion for reconsideration of its previous decision to dismiss Greenleaf's appeal ofAs required by the In-Service Asset Rate Order.
Order, on June 5, 2017, Mississippi Power made a rate filing requesting to adjust the amortization schedules of the regulatory assets reviewed and determined prudent in a manner that would not change customer rates or annual revenues. On August 17, 2016,June 28, 2017, the Mississippi PSC suspended this filing. On July 6, 2017, the Mississippi PSC issued an order establishingrequiring Mississippi Power to establish a discovery docketregulatory liability account to manage all filingsmaintain current rates related to the prudenceKemper IGCC following the July 2017 completion of the amortization period for certain regulatory assets approved in the In-Service Asset Rate Order that would allow for subsequent refund if the Mississippi PSC deems the rates unjust and unreasonable.
The remainder of the plant includes 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." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO2, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. Most recently, in May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast has decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations increased significantly since certification.
On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC (Kemper Settlement Order). The Kemper Settlement Order established a new docket for the purposes of pursuing a global settlement of costs of the Kemper IGCC (Kemper IGCC Settlement Docket). The Mississippi PSC requested any such proposed settlement agreement reflect: (i) at a minimum, no rate increase to Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and related assets; and (iii) modification or amendment of the CPCN for the Kemper IGCC to allow only for ownership and operation of a natural gas facility. The Kemper Settlement Order provides that any related settlement agreement be filed within 45 days from the effective date of the Kemper Settlement Order. If a settlement agreement is filed, a hearing will be set 45 days from the date of the settlement's filing, and the appropriate scheduling order will be established.
Although the ability to achieve a negotiated settlement is uncertain, Mississippi Power intends to pursue any available settlement alternatives. In addition, the Kemper Settlement Order provides that, in the event a settlement agreement is not reached, the Mississippi PSC reserves its right to take any appropriate steps, including issuing an order to show cause as to why the CPCN for the Kemper IGCC should not be revoked.
On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future of the gasifier portion of the Kemper IGCC. On October 3, 2016, Mississippi Power madeexpects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014.
At the time of project suspension, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in additional grants from the DOE received on April 8, 2016 (Additional DOE Grants). Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate subject to the construction cost cap totaling $196 million ($121 million after tax) in the second quarter through May 31, 2017 and a required compliance filing,total of $305 million ($188 million after tax) for year-to-date through May 31, 2017. In the aggregate, Mississippi Power incurred charges of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017. The May 31, 2017 cost estimate included approximately $175 million of estimated costs to be incurred beyond the then-estimated in-service date of June 30, 2017 that were expected to be subject to the $2.88 billion cost cap.
At June 30, 2017, approximately $3.3 billion in actual Kemper IGCC costs were not reflected in Mississippi Power's retail and wholesale rates, of which included a review$0.5 billion was related to the combined cycle and explanationassociated facilities and $2.8 billion was related to the gasification portions of differences betweenthe Kemper IGCC.
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper Settlement Order, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs currently estimated at approximately $100 million to $200 million are expected to be incurred.
Total pre-tax charges to income for the estimated probable losses on the Kemper IGCC were $3.0 billion ($2.1 billion after tax) for the second quarter 2017 and $3.1 billion ($2.2 billion after tax) for the six months ended June 30, 2017. In the aggregate, since 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.started, Mississippi Power expects the Mississippi PSC to address these issues in connection with its next rate request.has incurred charges of $6.0 billion ($3.9 billion after tax) through June 30, 2017.
As of June 30, 2017, Mississippi Power anticipates that it will incur additional expenseshas recorded a total of approximately $1.3 billion in excess of current ratescosts associated with operatingthe combined cycle portion of the Kemper IGCC after itincluding transmission and related regulatory assets, of which $0.8 billion is placedincluded 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 PSCretail and the FERC to defer all Kemper IGCC costs incurred after the in-service date that cannot be capitalized, arewholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility, as well as the 15% that was
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
previously contracted to SMEPA. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and are not requiredexpects them to be charged against earnings as a result ofrecovered through rates consistent with the $2.88 billion cost cap until such time asMississippi PSC's requested settlement conditions. The ultimate outcome will be determined by 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 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.Settlement Docket proceedings.
For additional information on the Kemper IGCC, including information on the project economic viability analysis, pending lawsuits, and an ongoing SEC investigation, see Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and "Other Matters" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein.
AsIn June 2017, Southern Company made equity contributions totaling $1.0 billion to Mississippi Power. Mississippi Power used a portion of September 30, 2016, the proceeds to (i) prepay $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan; (ii) repay $591 million of the outstanding principal amount of promissory notes to Southern Company; and (iii) repay $10 million of the outstanding principal amount of bank loans.
Mississippi Power's current liabilities exceeded current assets by approximately $411 million primarily due to the $300 million in senior notes which matured on October 15, 2016, as well as $65 million in short-term debt. In addition, if the Kemper IGCC does not go into service by December 31, 2016,financial statement presentation contemplates continuation of Mississippi Power would have to repay approximately $250 million of tax benefits receivedas a going concern as a result of quarterly income tax estimates through September 30, 2016.Southern Company's anticipated ongoing financial support of Mississippi Power. For additional information, see Notes 1 and 6 to the financial statements of Mississippi Power under "Recently Issued Accounting Standards" and "Going Concern," respectively, in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Going Concern" herein.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
the Kemper County energy facility, Mississippi Power continues to focus on several key performance indicators, including the construction, start-up, and rate recovery of the Kemper IGCC.indicators. In recognition that Mississippi Power's long-term financial success is dependent upon how well it satisfies its customers' needs, Mississippi Power's retail base rate mechanism, PEP, includes performance indicators that directly tie customer service indicators to Mississippi Power's allowed return. In addition to the PEP performance indicators,ROE. Mississippi Power also focuses on other performance measures, including broader measures of customer satisfaction, plant availability, system reliability, and net income after dividends on preferred stock. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Mississippi Power in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income (Loss)
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $47 | | N/M | | $(23) | | (37.1) |
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(2,056) | | N/M | | $(2,087) | | N/M |
N/M - Not meaningful
In the second quarter and year-to-date 2017, Mississippi Power's net incomeloss after dividends on preferred stock for the third quarter 2016 was $26 million$2.05 billion and $2.07 billion, respectively, compared to a net lossincome of $21$2 million and $13 million, respectively, for the corresponding periodperiods in 2015. The increase2016. In the second quarter and year-to-date 2017, the decrease in net income was primarily related to lowerhigher pre-tax charges associated with the Kemper IGCC of $88 million$3.0 billion ($54 million2.1 billion after tax) in the third quarter 2016and $3.1 billion ($2.2 billion after tax), respectively, compared to pre-tax charges of $150$81 million ($9350 million after tax) and $134 million ($83 million after tax), respectively, for the corresponding periods in the third quarter 2015 for revisions of the estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC above the $2.88 billion cost cap established by the Mississippi PSC, net of the Initial DOE Grants and excluding the Cost Cap Exceptions.2016. The increasechanges in net income was also due to an increase in retail revenues andwere partially offset by a decrease in depreciation and amortization partially offset by an increase in other operations and maintenance expenses.
For year-to-date 2016, net income after dividends on preferred stock was $39 million compared to $62 million for the corresponding period in 2015. The decrease was primarily related to a decrease in interest on deposits in 2015 resulting from the termination of an asset purchase agreement between Mississippi Power and SMEPA in May 2015, higher depreciation and amortization, and higher pre-tax charges of $222 million ($137 million after tax) in 2016 compared to pre-tax charges of $182 million ($112 million after tax) in 2015 for revisions of the estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC above the $2.88 billion cost cap established by the Mississippi PSC, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. The decrease in net income was partially offset by an increaseincreases in retail revenues.revenues, AFUDC equity, and income tax benefits.
See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Retail Revenues
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $19 | | 7.8 | | $51 | | 8.5 |
In the third quarter 2016, retail revenues were $263 million compared to $244 million for the corresponding period in 2015. For year-to-date 2016, retail revenues were $652 million compared to $601 million for the corresponding period in 2015.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Retail Revenues
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $16 | | 7.8 | | $33 | | 8.5 |
In the second quarter 2017, retail revenues were $222 million compared to $206 million for the corresponding period in 2016. For year-to-date 2017, retail revenues were $422 million compared to $389 million for the corresponding period in 2016.
Details of the changes in retail revenues were as follows:
| | | | Third Quarter 2016 | | Year-to-Date 2016 | Second Quarter 2017 | | Year-to-Date 2017 |
| | (in millions) | | (% change) | | (in millions) | | (% change) | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | $ | 244 |
| | | | $ | 601 |
| | | $ | 206 |
| | | | $ | 389 |
| | |
| Estimated change resulting from – | | | | | | | | | | | | | | |
| Rates and pricing | 8 |
| | 3.3 |
| | 66 |
| | 11.0 |
| 8 |
| | 3.9 |
| | 19 |
| | 4.9 |
|
| Sales growth (decline) | (3 | ) | | (1.3 | ) | | (2 | ) | | (0.3 | ) | (2 | ) | | (0.9 | ) | | 3 |
| | 0.8 |
|
| Weather | 7 |
| | 2.9 |
| | 5 |
| | 0.8 |
| (2 | ) | | (1.0 | ) | | (7 | ) | | (1.8 | ) |
| Fuel and other cost recovery | 7 |
| | 2.9 |
| | (18 | ) | | (3.0 | ) | 12 |
| | 5.8 |
| | 18 |
| | 4.6 |
|
| Retail – current year | $ | 263 |
| | 7.8 | % | | $ | 652 |
| | 8.5 | % | $ | 222 |
| | 7.8 | % | | $ | 422 |
| | 8.5 | % |
Revenues associated with changes in rates and pricing increased in the thirdsecond quarter and year-to-date 20162017 when compared to the corresponding periods in 2015,2016 primarily due to an ECO Plan rate increase implemented in the implementation of rates for certain Kemper IGCC in-service assets. See Note 3 tothird quarter 2016, partially offset by an ECO Plan rate decrease implemented in the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.second quarter 2017.
Revenues attributable to changes in sales decreased infor the thirdsecond quarter 20162017 when compared to the corresponding period in 2015.2016. Weather-adjusted KWH sales to residential andcustomers decreased 2.7% due to lower customer usage. Weather-adjusted KWH sales to commercial customers decreased 6.7% and 0.9%, respectively, in the third quarter 20160.8% due to decreasedlower customer usage, primarily resulting from efficiency improvements in residential appliances and lighting, partially offset by customer growth. KWH sales to industrial customers decreased 1.7% in the third quarter 20161.3% primarily due to an unplanned outage by a large customer.customer in 2017 and a decrease in the number of mid-size customers.
Revenues attributable to changes in sales decreasedincreased for year-to-date 20162017 when compared to the corresponding period in 2015.2016. Weather-adjusted KWH sales to residential and commercial customers decreased 2.6%0.7% and 1.5%0.5%, respectively, due to decreasedlower customer usage primarily resulting from efficiency improvements in residential appliances and lighting, partially offset by customer growth.usage. KWH sales to industrial customers decreased 0.7%0.4% primarily due to an unplanned outage by a large customer.
Inlarger customer in 2017 and a decrease 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 allocationnumber of Mississippi Power's unbilled first quarter 2015 KWH sales among customer classes that is consistent with the actual allocation in 2016. Without this adjustment, year-to-date 2016 weather-adjusted residential KWH sales decreased 0.8%, weather-adjusted KWH sales to commercial customers increased 0.6%, and KWH sales to industrial customers were relatively flat as compared to the corresponding period in 2015.mid-size customers.
Fuel and other cost recovery revenues increased in the thirdsecond quarter 2016and year-to-date 2017 when compared to the corresponding periodperiods in 2015,2016, primarily as a result of revised ECO Plan rates which became effective with the first billing cycle for September 2016, partially offset by lowerhigher recoverable fuel costs. Fuel and other cost recovery revenues decreased for year-to-date 2016 when compared to the corresponding period in 2015, primarily as a result of lower recoverable fuel costs, partially offset by revised ECO Plan rates which became effective with the first billing cycle for September 2016. See "Fuel and Purchased Power Expenses" herein for additional information. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power's service territory. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale Revenues – Non-Affiliates
| | | Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) | | (% change) | | (change in millions) | | (% change) |
| $2 | | 2.6 | | $(18) | | (8.3) | | 3.3 | | $4 | | 3.3 |
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
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. In addition, Mississippi Power provides service under long-term contracts with rural electric cooperative associations and municipalities located in southeastern Mississippi under cost-based electric tariffs which are subject to regulation by the FERC. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Mississippi Power in Item 7 of the Form 10-K and – FUTURE EARNINGS POTENTIAL – "FERC Matters""FERC Matters" herein for additional information.
ForIn the second quarter and year-to-date 2016,2017, wholesale revenues from sales to non-affiliates were $198$62 million and $124 million, respectively, compared to $216$60 million and $120 million for the corresponding periodperiods in 2015.2016. The decrease wasincreases were due to increases in energy revenues of $4 million and $5 million in the second quarter and year-to-date 2017, respectively, primarily resulting from higher fuel prices, partially offset by decreases in base and capacity revenues of $2 million and $1 million, respectively, primarily due to a $16 million decreasemilder weather resulting in energy revenues primarily resulting from lower natural gas prices and decreased usage primarily resulting from milder weather.sales.
Wholesale Revenues – Affiliates
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(11) | | (61.1) | | $(40) | | (63.5) |
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $8 | | N/M | | $4 | | 25.0 |
N/M - Not meaningful
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 thirdsecond quarter 2016,2017, wholesale revenues from sales to affiliates were $7$15 million compared to $18$7 million for the corresponding period in 2015.2016. The decreaseincrease was due to a decrease$6 million increase in KWH sales and a $2 million increase primarily due to availability of lower cost alternatives.higher natural gas prices.
For year-to-date 2016,2017, wholesale revenues from sales to affiliates were $23$20 million compared to $63$16 million for the corresponding period in 2015.2016. The decreaseincrease was primarily due to higher natural gas prices.
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | |
| | Second Quarter 2017
vs.
Second Quarter 2016 | | Year-to-Date 2017
vs.
Year-to-Date 2016 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | 21 |
| | 25.9 | | $ | 23 |
| | 14.6 |
| Purchased power – non-affiliates | 1 |
| | 100.0 | | 2 |
| | 200.0 |
| Purchased power – affiliates | — |
| | — | | 2 |
| | 22.2 |
| Total fuel and purchased power expenses | $ | 22 |
| | | | $ | 27 |
| | |
In the second quarter 2017, total fuel and purchased power expenses were $108 million compared to $86 million for the corresponding period in 2016. The increase was due to a $35$17 million decreaseincrease in KWH sales primarily due to availability of lower cost alternativesnatural gas prices and a $5 million decrease associated with lowerincrease in the volume of KWHs generated and purchased.
For year-to-date 2017, total fuel and purchased power expenses were $194 million compared to $167 million for the corresponding period in 2016. The increase was due to a $34 million increase in natural gas prices.prices, partially offset by a $7 million decrease in the volume of KWHs generated and purchased.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | | |
| | | Third Quarter 2016
vs.
Third Quarter 2015 | | Year-to-Date 2016
vs.
Year-to-Date 2015 |
| | | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | | $ | (18 | ) | | (13.8) | | $ | (91 | ) | | (25.3) |
| Purchased power – non-affiliates | | 2 |
| | N/M | | (1 | ) | | (20.0) |
| Purchased power – affiliates | | 4 |
| | N/M | | 8 |
| | N/M |
| Total fuel and purchased power expenses | | $ | (12 | ) | | | | $ | (84 | ) | | |
N/M - Not meaningful
In the third quarter 2016, total fuel and purchased power expenses were $120 million compared to $132 million for the corresponding period in 2015. The decrease was primarily due to a net decrease in the volume of KWHs generated and purchased primarily due to a decrease in non-territorial sales.
For year-to-date 2016, total fuel and purchased power expenses were $286 million compared to $370 million for the corresponding period in 2015. The decrease was due to a $49 million net decrease in the volume of KWHs generated and purchased primarily due to a decrease in non-territorial sales and milder weather and a $35 million decrease due to lower natural gas prices.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Mississippi Power's fuel cost recovery clause.
Details of Mississippi Power's generation and purchased power were as follows:
| | | | Third Quarter 2016 | | Third Quarter 2015 | | Year-to-Date 2016 | | Year-to-Date 2015 | Second Quarter 2017 | | Second Quarter 2016 | | Year-to-Date 2017 | | Year-to-Date 2016 |
Total generation (in millions of KWHs) | 4,255 | | 4,681 | | 11,570 | | 13,136 | 3,927 | | 3,728 | | 7,088 | | 7,315 |
Total purchased power (in millions of KWHs) | 288 | | 121 | | 877 | | 427 | |
Total purchased power (in millions of KWHs)(*) | | 121 | | 188 | | 362 | | 449 |
Sources of generation (percent) – | | | | |
| Coal | 10 | | 19 | | 9 | | 20 | 7 | | 5 | | 8 | | 8 |
| Gas | 90 | | 81 | | 91 | | 80 | 93 | | 95 | | 92 | | 92 |
Cost of fuel, generated (in cents per net KWH) – | | |
| Coal | 4.02 | | 3.81 | | 4.09 | | 3.70 | 3.61 | | 5.49 | | 3.46 | | 4.16 |
| Gas | 2.64 | | 2.72 | | 2.34 | | 2.70 | 2.73 | | 2.17 | | 2.69 | | 2.16 |
Average cost of fuel, generated (in cents per net KWH) | 2.79 | | 2.93 | | 2.50 | | 2.91 | 2.79 | | 2.33 | | 2.76 | | 2.32 |
Average cost of purchased power (in cents per net KWH) | 2.59 | | 2.21 | | 2.04 | | 2.42 | |
Average cost of purchased power (in cents per net KWH)(*) | | 4.74 | | 2.55 | | 3.80 | | 2.33 |
| |
| (*) | Includes energy produced during the test period for the Kemper IGCC, which is accounted for in accordance with FERC guidance. |
Fuel
In the thirdsecond quarter 2016,2017, total fuel expense was $112$102 million compared to $130$81 million for the corresponding period in 2015.2016. The decreaseincrease was due to a 10.2% decrease in the volume of KWHs generated primarily as a result of lower wholesale sales and a 4.8% decrease20% increase in the average cost of fuel per KWH generated, primarily due to a 2.7% lower26% higher cost of natural gas.gas, and a 6% increase in the volume of KWHs generated.
For year-to-date 2016,2017, total fuel expense was $268$180 million compared to $359$157 million for the corresponding period in 2015.2016. The decreaseincrease 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% decrease19% increase in the average cost of fuel per KWH generated primarily due to a 13.6% lower25% higher cost of natural gas.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Purchased Power - Non-Affiliates
For year-to-date 2016, purchased power expense from non-affiliates was $4 million compared to $5 million for the corresponding period in 2015. The decrease was primarily due to a 43.1% decrease in the average cost per KWH purchased due to lower energy costs from available gas-fired resources,gas, partially offset by a 49.0% increase3% decrease in the volume of KWHs purchased due to the availability of lower cost energy.generated.
Purchased Power
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 $5 million compared to $1 million for the corresponding period in 2015. The increase was primarily due to a 234.7% increase in the volume of KWHs purchased due to the availability of lower cost energy as compared to self-generation fuel cost and a 9.9% increase in the average cost per KWH purchased due to higher power pool interchange rates associated with higher natural gas prices.
For year-to-date 2016, purchased power expense from affiliates was $14 million compared to $6 million for the corresponding period in 2015. The increase was primarily due to a 163.8% 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 fuel prices.
Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC, or other contractual agreements, as approved by the FERC.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $11 | | 17.5 | | $5 | | 2.4 |
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $2 | | 2.9 | | $8 | | 5.9 |
In the third quarter 2016,For year-to-date 2017, other operations and maintenance expenses were $74$144 million compared to $63$136 million for the corresponding period in 2015.2016. The increase was primarily due to a $7 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 and a $4 million increase in transmission and distribution overhead line maintenance and vegetation 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.assets.
See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Rate Case" and " – Regulatory Assets and Liabilities" herein for additional information. See Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Depreciation and Amortization
| | | Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) | | (% change) | | (change in millions) | | (% change) |
$(8)(4) | | (21.1) | | $19 | | 20.0 | | (8.9) | | $(3) | | (3.6) |
In the thirdsecond quarter 2016,2017, depreciation and amortization was $30$41 million compared to $38$45 million for the corresponding period in 2015. The decrease was primarily due to a $17 million deferral associated with the implementation of revised ECO Plan rates with the first billing cycle for September 2016, partially offset by an increase in depreciation and amortization of $9 million primarily related to the In-Service Asset Rate Order, ECO Plan, MATS rule compliance, and additional plant in service assets.
2016. For year-to-date 2016,2017, depreciation and amortization was $114$81 million compared to $95$84 million for the corresponding period in 2015.2016. The increase wasdecreases were primarily due to additional regulatory asset amortization of $16 million related to the In-Service Asset Rate Order, ECO Plan,changes in amortization and MATS rule compliance, $12 million primarily due to Kemper IGCC deferrals and $8 million of depreciation for additional plant in service assets, primarily the Plant Daniel scrubbers. These increases were partially offset by a $17 million deferral associated with the implementation of revised ECO Plan rates with the first billing cycle for September 2016.regulatory assets.
See Note 1 to the financial statements of Mississippi Power under "Depreciation, Depletion, and Amortization" in Item 8 of the Form 10-K10-K.
Estimated Loss on Kemper IGCC
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $2,931 | | N/M | | $2,986 | | N/M |
N/M - Not meaningful
Prior to the project suspension on June 28, 2017, estimated probable losses on the Kemper IGCC totaled $196 million and $305 million in the second quarter and year-to-date 2017, respectively, compared to $81 million and $134 million in the second quarter and year-to-date 2016, respectively. These losses reflected revisions of estimated costs expected to be incurred on the construction of the Kemper IGCC prior to project suspension 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.
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper Settlement Order, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional information. Also, seecharge to income in June 2017 of $2.8 billion, which includes estimated costs associated with the gasification portions of the plant and lignite mine.
See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Mississippi Power – Environmental Compliance Overview Plan" and "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Rate Case" and " – Regulatory Assets and Liabilities" herein for additional information.
Taxes Other Than Income TaxesAllowance 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 | | 29.2 | | $10 | | 14.1 |
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $6 | | 20.0 | | $12 | | 20.3 |
In the thirdsecond quarter 2016, taxes other than income taxes were $312017, AFUDC equity was $36 million compared to $24$30 million for the corresponding period in 2015.2016. For year-to-date 2016, taxes other than income taxes were $812017, AFUDC equity was $71 million compared to $71$59 million for the corresponding period in 2015.2016. The increases were primarily due to increases in ad valorem taxes of $4 millionresulted from a higher AFUDC rate and $6 million for the third quarter and year-to-date 2016, respectively, due to an increase in the assessed value of property as well as increases in franchise taxes of $3 million and $4 million for the third quarter and year-to-date 2016, respectively.
The retail portion of ad valorem taxes is recoverable under Mississippi Power's ad valorem tax cost recovery clause and, therefore, does not affect net income.
Estimated Loss on Kemper IGCC
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(62) | | (41.3) | | $40 | | 22.0 |
In the third quarters of 2016 and 2015, estimated probable losses on the Kemper IGCC CWIP subject to AFUDC prior to project suspension.
See Note 3 to the financial statements of $88 millionMississippi Power under "FERC Matters" and $150 million, respectively, were recorded at Mississippi Power. For year-to-date 2016 and year-to-date 2015, estimated probable losses on the Kemper IGCC of $222 million and $182 million, respectively, were recorded at Mississippi Power. These losses reflect revisions of estimated costs expected to be incurred on the construction"Integrated Coal Gasification Combined Cycle" in Item 8 of the KemperForm 10-K and FUTURE EARNINGS POTENTIAL – "Integrated
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
IGCC in excessCoal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "FERC Matters" and "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the Kemper IGCC.
Interest Expense, Net of Amounts Capitalized
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $2 | | 13.3 | | $6 | | 19.4 |
In the $2.88 billion cost cap established by the Mississippi PSC,second quarter 2017, interest expense, net of amounts capitalized was $17 million compared to $15 million, for the Initial DOE Grants and excludingcorresponding period in 2016. For year-to-date 2017, interest expense, net of amounts capitalized was $37 million compared to $31 million for the Cost Cap Exceptions.corresponding period in 2016. The increases were primarily associated with the Kemper IGCC in-service assets.
See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Allowance for Equity Funds Used During ConstructionIncome 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) |
| $2 | | 6.9 | | $8 | | 9.8 |
In the third quarter of 2016, AFUDC equity was $31 million compared to $29 million for the corresponding period in 2015. For year-to-date 2016, AFUDC equity was $90 million compared to $82 million for the corresponding period in 2015. The increases were driven by a higher AFUDC rate and an increase in Kemper IGCC CWIP subject to AFUDC, partially offset by placing the Plant Daniel scrubbers in service in November 2015. 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 |
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(864) | | N/M | | $(881) | | N/M |
N/M - Not meaningful
In the thirdsecond quarter 2016, interest expense, net of amounts capitalized2017, income tax benefit was $15$881 million compared to $13$17 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.
2016. For year-to-date 2016, interest expense, net of amounts capitalized2017, income tax benefit was $46$908 million compared to $(6)$27 million for the corresponding period in 2015.2016. The increase waschanges were 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 Coal Gasification Combined Cycle" herein for additional information on the Mirror CWIP refund.
Income Taxes (Benefit)
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $29 | | 93.5 | | $(18) | | N/M |
N/M - Not meaningful
In the third quarter 2016, income tax benefit was $(2) million compared to $(31) million for the corresponding period in 2015. The change was primarily due to the reduction in the estimated probable losses on constructionthe Kemper IGCC, net of the Kemper IGCC.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2016, income tax benefit was $(29) million compared to $(11) million fornon-deductible AFUDC equity portion and the corresponding period in 2015. The change was primarily due to the increase in the estimated probable losses on construction of the Kemper IGCC.related state valuation allowances.
See Note (G) to the Condensed Financial Statements herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Mississippi Power's future earnings potential. The level of Mississippi Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Mississippi Power's business of selling electricity.providing electric service. These factors include Mississippi Power's ability to recover its prudently-incurred costs, including those related to the remainder of the Kemper County energy facility not included in current rates, in a timely manner during a time of increasing costs and its ability to prevail against legal challenges associated with the Kemper IGCC, and the completion and subsequent operation of the Kemper IGCC in accordance with any operational parameters that may be adopted by the Mississippi PSC, as well as other ongoing construction projects.County energy facility. Future earnings in the near term will be driven primarily by customer growth. Earnings will also depend in part, upon maintaining and growing sales, whichconsidering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions. Earnings are subject to a numbervariety of other factors. These factors include weather, competition, developing new and maintaining existing energy contracts and associated load requirements with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Mississippi Power's service territory. Demand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, which may impact future earnings.
Current proposals related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals is dependent on the final form of any legislation enacted and the related
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
transition rules and cannot be determined at this time, but could have a material impact on Mississippi Power's financial statements.
For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Mississippi Power in Item 7 of the Form 10-K.10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis or through market-based contracts.long-term wholesale agreements. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Statutes and Regulations
AirWater Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – AirWater Quality" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the EPA's final MATSeffluent guidelines rule regional haze regulations, and the Cross State Air Pollution Rule (CSAPR).final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs.
On April 25, 2016, in response to a June 2015 U.S. Supreme Court opinion,2017, the EPA published its supplemental finding regarding consideration of costsa notice announcing it would reconsider the effluent guidelines rule, which had been finalized in supportNovember 2015. On June 6, 2017, the EPA proposed a rule establishing a stay of the MATScompliance deadlines for certain effluent limitations and pretreatment standards under the rule. This finding does not impact MATS
On June 27, 2017, the EPA and the U.S. Army Corps of Engineers proposed to rescind the final rule compliance requirements, costs, or deadlines, andthat revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.
The ultimate outcome of these matters cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Mississippi Power unitsin Item 7 of the Form 10-K for additional information.
On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that are subject topotentially burden the MATS rule completed the measures necessary to achieve compliance with the MATS rule by the applicable deadlines.
Also on April 25, 2016,development or use of domestically produced energy resources. The executive order specifically directs the EPA issued proposed revisions to review the regional haze regulations. Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules.
On June 1, 2017, the U.S. President announced that the United States will withdraw from the non-binding Paris Agreement and begin renegotiation of its terms.
The ultimate impactoutcome of the proposed revisions will depend on their ultimate adoption, implementation, and any legal challenges andthese matters cannot be determined at this time.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 Mississippi. The ultimate impact of this rule will depend on the outcome of any legal challenges and implementation at the state level and cannot be determined at this time.
FERC Matters
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 Coal Gasification Combined Cycle" herein for information regarding Mississippi Power's construction of the Kemper IGCC.
OnIn March 31, 2016, Mississippi Power reached a settlement agreement with its wholesale customers, and filed a request withwhich was subsequently approved by the FERC, for an increase in wholesale base revenues under the Municipal and Rural Associations (MRA)MRA cost-based electric tariff, primarily as a result of placing scrubbers for Plant Daniel Units 1 and 2 in service in November 2015. The settlement agreement accepted by the FERC,became effective for services rendered beginning May 1, 2016, provides that base ratesresulting in an estimated annual revenue increase of $7 million under the MRA cost-based electric tariff will produce additional annual base revenues of $7 million.tariff. Additionally, under the settlement agreement, the tariff customers agreed to similar regulatory treatment for MRA tariff ratemaking as the treatment approved for retail ratemaking under the In-Service Asset Rate Order. This regulatory treatment primarily includes (i) recovery of the Kemper IGCC assets currently operational and providing service to customers and other related costs, (ii) amortization of the Kemper IGCC-related regulatory assets included in rates under the settlement agreement over the 36 months ending April 30, 2019, (iii) Kemper IGCC-related expenses included in rates under the settlement agreement no longer being deferred and charged to expense, and (iv) removing all of the Kemper IGCC CWIP from rate base with a corresponding increase in accrual of AFUDC. The additional resulting AFUDC is estimated to betotaled approximately $11$22 million through the suspension of Kemper IGCC's projected in-service date of December 31, 2016.IGCC start-up activities.
See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Fuel Cost Recovery
Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. Effective withAt June 30, 2017, the first billing cycle for September 2016, fuel rates decreased $11 million annually foramount of over-recovered wholesale MRA customers and $1fuel costs included in the balance sheets was $7 million annually forcompared to $13 million at December 31, 2016. Over-recovered wholesale MB customers.fuel costs included in the balance sheets were immaterial at June 30, 2017 and December 31, 2016.
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
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters – Market-Based Rate Authority" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the traditional electric operating companies' and Southern Power's market power proceeding and amendment to their market-rate tariff.
On May 17, 2017, the FERC accepted the traditional electric operating companies' (including Mississippi Power's) and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies (including Mississippi Power) and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' (including Mississippi Power's) and Southern Power's market power proceeding, it remains a separate, ongoing matter.
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
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased power, energy efficiency programs, ad valorem taxes, property damage, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are recovered through Mississippi Power's base rates. See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Mississippi Power" and "Integrated Coal Gasification Combined Cycle" herein for additional information.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Renewables
In November 2015, 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 theplaced in service two solar facilities for the 25-year term under each of the three PPAs. The projects arein January 2017 and June 2017. A third solar project is expected to be placed in service byin the secondthird quarter 2017 and the resulting energy purchases are expected to be recovered through Mississippi Power's fuel cost recovery mechanism.2017. Mississippi Power may retire the renewable energy credits (REC) generated on behalf of its customers or sell the RECs, separately or bundled with energy, to third parties.
On June 9, 2017, Mississippi Power submitted a CPCN to the Mississippi PSC for the approval of construction, operation, and maintenance of a 52.5-MW solar energy generating facility, which, if approved, is expected to be placed in service by January 2020. The ultimate outcome of this matter cannot be determined at this time.
Performance Evaluation Plan
On March 15, 2017, Mississippi Power submitted its annual PEP lookback filing for 2016, which reflected the need for a $5 million surcharge to be recovered from customers. The filing has been suspended for review by the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time.
Energy Efficiency
On May 3, 2016,July 6, 2017, the Mississippi PSC issued an order approving the annualMississippi Power's Energy Efficiency Cost Rider Compliancecompliance filing, which included an anticipated reduction ofincreased annual retail revenues by approximately $2 million in retail revenueseffective with the first billing cycle for the year ending December 31, 2016.
Performance Evaluation Plan
On April 1, 2016, Mississippi Power submitted its annual PEP lookback filing for 2015, which reflected the need for a $5 million surcharge to be recovered from customers. The filing has been suspended for review by the Mississippi PSC.
On July 12, 2016, Mississippi Power submitted its annual projected PEP filing for 2016 which indicated no change in rates. The filing has been suspended for review by the Mississippi PSC.
The ultimate outcome of these matters cannot be determined at this time.August 2017.
Environmental Compliance Overview Plan
On August 17, 2016,May 4, 2017, the Mississippi PSC approved Mississippi Power's revised ECO Plan filing for 2016,2017, which requested the maximum 2% annual increase in revenues, approximately $18 million, primarily related to the 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.June 2017. Approximately $22$26 million of related revenue requirements in excess of the 2% maximum was deferred for inclusion in the 20172018 filing.
Fuel Cost Recovery
At SeptemberJune 30, 2016,2017, the amount of over-recovered retail fuel costs included on the condensed balance sheet was $58$14 million compared to $71$37 million at December 31, 2015.2016.
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. Ad Valorem Tax Adjustment
On August 17, 2016,July 6, 2017, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment factor filing for 2017, which included an additional decreaseannual rate increase of $510.85%, or $8 million annually in fuel cost recovery rates effective with the first billing cycle for September 2016.annual retail revenues, primarily due to increased assessments.
Integrated Coal Gasification Combined Cycle
See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding Mississippi Power's construction of the Kemper IGCC.
Kemper IGCC Overview
The Kemper IGCC willwas designed to utilize an IGCC technology with an expected output capacity of 582 MWs. The Kemper IGCC willMWs and to be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper IGCC, Mississippi Power constructed and plans to operate approximately 61 miles of CO2 pipeline infrastructure for the planned transport of captured CO2 for use in enhanced oil recovery.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Kemper IGCC Schedule and Cost Estimate
In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of Initial DOE Grants and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014 and continues to progress towards completing the2014. The remainder of the Kemper IGCC, includingplant includes 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 thatachieved integrated operation of both gasifiers will not occur by mid-Novemberon January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO2, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. Most recently, in May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast has reviseddecreased significantly and the expected in-service date forestimated cost of operating and maintaining the remainderfacility during the first five full years of operations increased significantly since certification.
On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC. On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, to December 31, 2016. The remaining schedule reflectsgiven the time expected to achieve production of electricity using gasifier "B," complete gasifier "A" outage activities, and resume electricity production using gasifier "A," as welluncertainty as to complete the integrationfuture of all systems necessary for both combustion turbinesthe gasifier portion of the Kemper IGCC. Mississippi Power expects to simultaneously generate electricity with syngas.continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014.
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 at the time of project suspension (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 SeptemberJune 30, 20162017, all of which include 100% of the costs for the Kemper IGCC, are as follows:
| | | Cost Category | 2010 Project Estimate(a) | | Current Cost Estimate(b) | | Actual Costs | 2010 Project Estimate(a) | | Cost Estimate at Suspension(b) | | June 30, 2017 Actual Costs |
| | (in billions) | (in billions) |
Plant Subject to Cost Cap(c)(e) | $ | 2.40 |
| | $ | 5.52 |
| | $ | 5.30 |
| $ | 2.40 |
| | $ | 5.95 |
| | $ | 5.68 |
|
| 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(d) | 0.17 |
| | 0.75 |
| | 0.71 |
| 0.17 |
| | 0.85 |
| | 0.85 |
|
Combined Cycle and Related Assets Placed in
Service – Incremental(e) | — |
| | 0.04 |
| | 0.03 |
| — |
| | 0.05 |
| | 0.05 |
|
| General Exceptions | 0.05 |
| | 0.10 |
| | 0.09 |
| 0.05 |
| | 0.10 |
| | 0.08 |
|
Deferred Costs(e) | — |
| | 0.21 |
| | 0.20 |
| — |
| | 0.23 |
| | 0.23 |
|
| Additional DOE Grants | — |
| | (0.14 | ) | | (0.14 | ) | — |
| | (0.14 | ) | | (0.14 | ) |
| Total Kemper IGCC | $ | 2.97 |
| | $ | 6.82 |
| | $ | 6.53 |
| $ | 2.97 |
| | $ | 7.38 |
| | $ | 7.09 |
|
| |
| (a) | The 2010 Project Estimate isRepresents 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 inRepresents actual costs through June 30, 2017 and projected costs at the Current Cost Estimate include certaintime of project suspension, including estimated post-in-service costs which arewere 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 at Suspension 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"Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order.Order." The Current Cost Estimate at Suspension 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 current rates and are being recognized through income; however, such costs continue to be includedremained in the Current Cost Estimate at Suspension and are reflected in the Actual Costs at SeptemberJune 30, 2016.2017. The equity return associated with assets placed in service and other non-CWIP accounts deferred for regulatory purposes, as well as the wholesale portion of debt carrying costs, whether deferred or recognized through income, iswas not included in the Current Cost Estimate andat Suspension or in the Actual Costs at SeptemberJune 30, 2016. See "Rate Recovery of Kemper IGCC Costs – Regulatory Assets2017. At June 30, 2017, such deferred amounts totaled $33 million and Liabilities" herein for additional information. $1 million, respectively. |
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$196 million ($54121 million after tax) in the thirdsecond quarter 2016through May 31, 2017 and a total of $222$305 million ($137188 million after tax) for the nine months ended September 30, 2016. Since 2012, inyear-to-date through May 31, 2017. In the aggregate, Mississippi Power has incurred charges of $2.63$3.07 billion ($1.631.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through SeptemberMay 31, 2017. The May 31, 2017 cost estimate included approximately $175 million of estimated costs to be incurred beyond the then-estimated in-service date of June 30, 2016. The increase2017 that were expected to be subject to the $2.88 billion cost estimate incap.
While the third quarterultimate disposition of 2016 primarily reflects $53 million for the extensiongasification portions of the Kemper IGCC's projected in-service date from October 31, 2016IGCC remains subject to December 31, 2016the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper Settlement Order, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the event the gasification portions of the project are
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
increased efforts relatedultimately canceled, additional pre-tax costs currently estimated at approximately $100 million 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$200 million are expected to be subjectincurred.
In the aggregate, Mississippi Power recorded total pre-tax charges to the cost cap. The year-to-date increase to the cost estimate also includes $78 millionincome for the extension ofestimated probable losses on the Kemper IGCC's projected in-service date from August 31, 2016 to October 31, 2016. In addition, duringIGCC totaling $3.0 billion for the start-upsecond quarter 2017 and commissioning process,$3.1 billion for the six months ended June 30, 2017.
As of June 30, 2017, Mississippi Power is identifying potential improvement projects that ultimately may be completed subsequent to placinghas recorded a total of approximately $1.3 billion in costs associated with the remaindercombined cycle portion 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 beenof which $1.2 billion is 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 resultplant in additional base costs of approximately $25service, $14 million to $35 million per month, which includes maintaining necessary levels of start-up labor,in materials and fuel, as well as operational resources required to execute start-upsupplies, $22 million in other regulatory assets, current, 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$95 million per month, as well as carrying costs and operating expenses on Kemper IGCCin other regulatory 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.deferred.
Rate Recovery of Kemper IGCC Costs
See "FERC Matters" herein for additional information regarding Mississippi Power's MRA cost based tariff relating to recoveryGiven the variety of a portionpotential scenarios and the uncertainty of the Kemper IGCC costs from Mississippi Power's wholesale customers. Rate recoveryoutcome of the retail portion of the Kemper IGCC is subject to the jurisdiction offuture regulatory proceedings with the Mississippi PSC. See Note (G) toPSC (and any subsequent related legal challenges), the Condensed Financial Statements under "Unrecognized Tax Benefits – Section 174 Research and Experimental Deduction" herein for additional tax information related to the Kemper IGCC.
The ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, determinations of prudency, and the specific manner of recovery of prudently-incurred costs, cannot now be determined at this time, but could result in further material charges that could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity.
2012 MPSCKemper IGCC Settlement Docket
On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC. The Kemper Settlement Order established the Kemper IGCC Settlement Docket. The Mississippi PSC requested any such proposed settlement agreement reflect: (i) at a minimum, no rate increase to Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and related assets; and (iii) modification or amendment of the CPCN for the Kemper IGCC to allow only for ownership and operation of a natural gas facility. The Kemper Settlement Order provides that any related settlement agreement be filed within 45 days from the effective date of the Kemper Settlement Order. If a settlement agreement is filed, a hearing will be set 45 days from the date of the settlement's filing, and the appropriate scheduling order will be established.
The 2012 MPSCAlthough the ability to achieve a negotiated settlement is uncertain, Mississippi Power intends to pursue any available settlement alternatives. In addition, the Kemper Settlement Order provides that, in the event a settlement agreement is not reached, the Mississippi PSC reserves its right to take any appropriate steps, including issuing an order to show cause as to why the CPCN Order included provisions relatingfor the Kemper IGCC should not be revoked.
On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to both Mississippi Power's recovery of financing costs duringsuspend operations and start-up activities on the course of constructiongasifier portion of the Kemper IGCC, and Mississippi Power's recoverygiven the uncertainty as to the future of costs following the dategasifier portion of the Kemper IGCC is placed in service. With respectIGCC. Mississippi Power expects to recovery of costs followingcontinue to operate the in-service datecombined cycle portion of the Kemper IGCC as it has done since August 2014.
At June 30, 2017, approximately $3.3 billion in actual Kemper IGCC costs were not reflected in Mississippi Power's retail and wholesale rates, of which $0.5 billion was related to the 2012 MPSC CPCNcombined cycle and associated facilities and $2.8 billion was related to the gasification portions of the Kemper IGCC.
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper Settlement Order, providedgiven the Mississippi PSC's stated intent regarding no further rate increase for the establishmentKemper County energy facility, cost recovery of operational costthe gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and revenue parameterslignite mine. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs currently estimated at approximately $100 million to $200 million are expected to be incurred.
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based upon assumptionsAs of June 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in Mississippi Power's petitioncosts associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which $0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the CPCN.combined cycle portion of the facility, as well as the 15% that was previously contracted to SMEPA. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.
Prudence
On August 17, 2016, the Mississippi PSC issued an order establishing a discovery docket to manage all filings related to the prudence of the Kemper IGCC. On October 3, 2016, Mississippi Power made a required compliance filing, which included a review and explanation of differences between the Kemper IGCC project estimate set forth in the 2010 CPCN proceedings and the most recent Kemper IGCC project estimate, as well as comparisons of current cost estimates and current expected plant operational parameters to the estimates presented in the 2010 CPCN proceedings for the first five years after the Kemper IGCC is placed in service. Compared to amounts presented in the 2010 CPCN proceedings, operations and maintenance expenses have increased an average of $105 million annually and maintenance capital has increased an average of $44 million annually for the first full five years of operations for the Kemper IGCC. Additionally, while the current estimated operational availability estimates reflect ultimate results similar to those presented in the 2010 CPCN proceedings, the ramp up period for the current estimates reflects a lower starting point and a slower escalation rate. On November 17, 2016, Mississippi Power submitted a supplemental filing to the October 3, 2016 compliance filing to present revised non-fuel operations and maintenance expense projections for the first year after the Kemper IGCC is placed in service. This supplemental filing included approximately $68 million in additional estimated operations and maintenance costs expected to be required to support the operations of the Kemper IGCC during that period.
Mississippi Power responded to numerous requests for information from interested parties in the discovery docket, which is now complete. Mississippi Power expects the Mississippi PSC to apply operational parametersutilize this information in connection with future proceedings related to the operationultimate resolution of Kemper IGCC cost recovery.
Economic Viability Analysis
In the fourth quarter 2016, as a part of its Integrated Resource Plan process, the Southern Company system completed its regular annual updated fuel forecast, the 2017 Annual Fuel Forecast. This updated fuel forecast reflected significantly lower long-term estimated costs for natural gas than were previously projected. As a result of the updated long-term natural gas forecast, as well as the revised operating expense projections reflected in the discovery docket filings discussed above, on February 21, 2017, Mississippi Power filed an updated project economic viability analysis of the Kemper IGCC as required under the 2012 MPSC CPCN Order confirming authorization of the Kemper IGCC. ToThe project economic viability analysis measures the life cycle economics of the Kemper IGCC compared to feasible alternatives, natural gas combined cycle generating units, under a variety of scenarios and considering fuel, operating and capital costs, and operating characteristics, as well as federal and state taxes and incentives. The reduction in the projected long-term natural gas prices in the 2017 Annual Fuel Forecast and, to a lesser extent, the increase in the estimated Kemper IGCC operating costs, negatively impact the updated project economic viability analysis.
Mississippi Power expects the Mississippi PSC determinesto address this matter in connection with the Kemper IGCC does not meet the operational parameters ultimately adopted bySettlement Docket.
2015 Rate Case
On August 13, 2015, the Mississippi PSC orapproved 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
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transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The interim rates were designed to collect approximately $159 million annually and became effective in September 2015, subject to refund and certain other conditions.
On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order adopting in full the 2015 Stipulation entered into between Mississippi Power incurs additional costs to satisfy such parameters, there could be a material adverse impactand 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 financial statements.actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The In-Service Asset Rate Order also included a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets. The stipulated revenue requirement excluded the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by SMEPA but reserved Mississippi Power's right to seek recovery in a future proceeding. See "Prudence""Termination of Proposed Sale of Undivided Interest" herein for additional information. 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.
In 2011, the Mississippi PSC authorized Mississippi Power to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date. In connection with the implementation of the In-Service Asset Order and wholesale rates, Mississippi Power began expensing certain ongoing project costs and certain retail debt carrying costs that previously were deferred and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees. The amortization periods for these regulatory assets vary from two years to 10 years as set forth in the In-Service Asset Rate Order and the settlement agreement with wholesale customers. As of June 30, 2017, the balance associated with these regulatory assets was $117 million, of which $22 million is included in current assets. See "FERC Matters" herein for additional information related to the 2016 settlement agreement with wholesale customers.
The In-Service Asset Rate Order requires Mississippi Power to submit an annual true-up calculation of its actual cost of capital, compared to the stipulated total cost of capital, with the first occurring as of May 31, 2016. At June 30, 2017, Mississippi Power's related regulatory liability included in its balance sheet totaled approximately $10 million.
As required by the In-Service Asset Rate Order, on June 5, 2017, Mississippi Power made a rate filing requesting to adjust the amortization schedules of the regulatory assets reviewed and determined prudent in the In-Service Asset Order in a manner that would not change customer rates or annual revenues. On June 28, 2017, the Mississippi PSC suspended this filing. On July 6, 2017, the Mississippi PSC issued an order requiring Mississippi Power to establish a regulatory liability account to maintain current rates related to the Kemper IGCC following the July 2017 completion of the amortization period for certain regulatory assets approved in the In-Service Asset Rate Order that would allow for subsequent refund if the Mississippi PSC deems the rates unjust and unreasonable.
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 iswas placed in service, based on a mirror CWIP methodology (Mirror CWIP rate).
Because the 2013 MPSC Rate Order did not provide for the inclusion
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On February 12, 2015, the Court reversed the 2013 MPSC Rate Order basedand, 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 previously 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.
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With implementation of the new rates on December 17, 2015, the interim rates were terminated and, in March 2016, Mississippi Power completed customer refunds of approximately $11 million for the difference between the interim rates collected and the permanent rates.
On July 27, 2016, the Court dismissed Greenleaf's motion for reconsideration of its previous decision to dismiss Greenleaf's appeal of the In-Service Asset Rate Order.
In addition to current estimated costs at September 30, 2016 of $6.82 billion, Mississippi Power anticipates that it will incur additional expenses in excess of current rates associated with operating the Kemper IGCC after it is placed in service until the Kemper IGCC cost recovery approach is finalized, which are expected to be material. These costs include, but are not limited to, regulatory costs, operational costs in excess of current rates, taxes, and additional carrying costs. Mississippi Power expects to request authority from the Mississippi PSC and the FERC to defer all Kemper IGCC costs incurred after the in-service date that cannot be capitalized, are not included in current rates, and are not required to be charged against earnings as a result of the $2.88 billion cost cap until such time as the Mississippi PSC completes its review and includes the resulting allowable costs in rates. Mississippi Power is required to file its next rate request with the Mississippi PSC related to cost recovery for the Kemper IGCC by June 3, 2017. See "Regulatory Assets and Liabilities" below for additional information. As part of that filing, Mississippi Power expects to request recovery of certain costs that the Mississippi PSC had excluded from the revenue requirement calculation for the in-service assets.
Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law in 2013. Mississippi Power expects to securitize prudently-incurred qualifying facility costs in excess of the certificated cost estimate of $2.4 billion. Qualifying facility costs include, but are not limited to, pre-construction costs, construction costs, regulatory costs, and accrued AFUDC. The Court's decision regardingBecause the 2013 MPSC Rate Order did not impactprovide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power's abilityPower continued to utilize alternate financing through securitization orrecord AFUDC on the February 2013 legislation.
Prudence
On August 17, 2016,Kemper IGCC. Between the original May 2014 estimated in-service date and the June 2017 project suspension date, Mississippi PSC issued an order establishing a discovery docketPower recorded $493 million of AFUDC on the Kemper IGCC subject to manage all filingsthe $2.88 billion cost cap and Cost Cap Exception amounts, of which $459 million related to the prudencegasification portions 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,this matter 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 Mississippi Power under "Regulatory Assets and Liabilities" in Item 8 of the Form 10-K for additional information.Settlement Docket.
Lignite Mine and CO2 Pipeline Facilities
In conjunction with the Kemper IGCC, Mississippi Power will ownowns the lignite mine and equipment and has acquired and will continue to acquire mineral reserves located around the Kemper IGCC site. The mine started commercial operation in June 2013.
In 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is operating and managingresponsible for the mining operations. The contract with Liberty Fuels is effectiveoperations through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. 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 and an initial contract term of 16 years, and termination rights ifyears. Denbury has the right to terminate the contract at any time because Mississippi Power hasdid not satisfied its contractual obligation to deliver captured CO2place the Kemper IGCC in service 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.2017.
The ultimate outcome of these matters cannot be determined at this time.
Termination of Proposed Sale of Undivided Interest
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its termination of the agreement. Mississippi Power previously received a total of $275 million of deposits from SMEPA that were required to be returned to SMEPA with interest. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to SMEPA. Subsequently, Mississippi Power issued a promissory note in the aggregate principal amount of approximately $301 million to Southern Company, which was repaid in June 2017.
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
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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 23, 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the plaintiffs filed notice to appeal to the Court.
On June 9, 2016, Treetop, Greenleaf CO2 Solutions, LLC (Greenleaf), Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint relates to the cancelled CO2 contract with Treetop and alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and seeks compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS have moved to compel arbitration pursuant to the terms of the CO2 contract.contract, which the court granted on May 4, 2017. On June 28, 2017, Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a claim for arbitration requesting $500 million in damages.
Mississippi Power believes these legal challenges have no merit; however, an adverse outcome in these proceedings could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity. Mississippi Power will vigorously defend itself in these matters, and the ultimate outcome of these matters cannot be determined at this time.
Baseload Act
In 2008, the Baseload Act was signed by the Governor of Mississippi. The Baseload Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism that includes in retail base rates, prior to and during construction, all or a portion of the prudently-incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passage of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews by the Mississippi PSC and prohibits the cancellation of any such generating plant without the approval of the Mississippi PSC. In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery for costs incurred in connection with such cancelled generating plant.
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.information on bonus depreciation, investment tax credits, and the Section 174 research and experimental deduction.
Bonus Depreciation
The extension of 50% bonus depreciation included in the PATH Act is expected to result in approximately $400Approximately $370 million of positive cash flows is expected to result from bonus depreciation for the 20162017 tax year, whichbut may not all be realized in 20162017 due to a projected consolidated net operating loss projections for Southern Company. Approximately $370 million of the benefit2017 tax year, and is dependent upon placing the remainder of the Kemper IGCC in service by December 31, 2016,2017. If the suspension of which $250the Kemper IGCC start-up activities results in an abandonment, any amount previously estimated as bonus depreciation would be claimed as a deduction under IRC Section 165. As of June 30, 2017, $82 million has been received as of September 30, 2016 through quarterly income tax refunds.refunds for bonus depreciation related to the Kemper IGCC, which may be subject to repayment. See Note (B) to the Condensed Financial Statements under "Integrated"Integrated Coal Gasification Combined Cycle"
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Cycle" herein 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.
Section 174 Research and Experimental Deduction
Southern Company, on behalf of Mississippi Power, has reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, subject to approval of the U.S. Congress Joint Committee on Taxation, resolving a methodology for these deductions. Due to the uncertainty related to this tax position, Mississippi Power had unrecognized tax benefits associated with these R&E deductions totaling approximately $464 million as of June 30, 2017. If the suspension of the Kemper IGCC start-up activities results in an abandonment, any amount not allowed under IRC Section 174 would be claimed as a deduction under IRC Section 165, and would result in a reversal of the related unrecognized tax benefits, excluding interest. See Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Section 174 Research and Experimental Deduction," respectively, herein for additional information. This matter is expected to be resolved in the next 12 months; however, the ultimate outcome of this matter cannot be determined at this time.
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.
TheultimateoutcomeofsuchpendingorpotentiallitigationagainstMississippi Powercannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatementsherein, 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.IGCC. 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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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
incurredMississippi Power in Item 7 of the Form 10-K for a complete discussion of Mississippi Power's critical accounting policies and estimates related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, AFUDC, Unbilled Revenues, and Contingent Obligations.
Kemper IGCC Rate Recovery
For periods prior to the second quarter 2017, significant accounting estimates included Kemper IGCC estimated construction costs, project completion date, and rate recovery. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Kemper IGCC Estimated Construction Costs, Project Completion Date, and Rate Recovery" of Mississippi Power in Item 7 of the Form 10-K for additional information. Mississippi Power recorded total pre-tax charges to income related to the Kemper IGCC of $2.63$428 million ($264 million after tax) in 2016, $365 million ($226 million after tax) in 2015, $868 million ($536 million after tax) in 2014, and $1.2 billion ($1.63729 million after tax) in prior years.
As a result of the Mississippi PSC's June 21, 2017 stated intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant rather than an IGCC plant, as well as Mississippi Power's June 28, 2017 suspension of the operation and start-up of the gasifier portion of the Kemper IGCC, the estimated construction costs and project completion date are no longer considered significant accounting estimates. Significant accounting estimates for the June 30, 2017 financial statements presented herein include the overall assessment of rate recovery for the Kemper County energy facility and the estimated costs for the potential cancellation of the Kemper IGCC.
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper Settlement Order, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax) as a result, which includes estimated costs associated with the gasification portions of changes in the cost estimate aboveplant and lignite mine. In the cost cap forevent the Kemper IGCC through September 30, 2016.
Mississippi Power's revised cost estimate reflects an expected in-service dategasification portions of December 31, 2016 and includes certain post-in-servicethe project are ultimately canceled, additional pre-tax costs whichcurrently estimated at approximately $100 million to $200 million are expected to be subject to the cost cap.incurred.
As of June 30, 2017, Mississippi Power has experienced, and may continue to experience, material changesrecorded a total of approximately $1.3 billion in costs associated with 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 remaindercombined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which $0.8 billion is included in service. If completed, such improvement projects would be expectedretail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility, as well as the 15% that was previously contracted to enhance plant performance, safety, and/or operations. The related potentialSMEPA. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, have yetusing reasonable assumptions for amortization periods, and expects them to be fully evaluated, have not been includedrecovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC 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 toSettlement Docket proceedings.
In 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 toaggregate, since the Kemper IGCC beyond December 31, 2016 would also increase costsproject started, Mississippi Power has incurred charges of $5.96 billion ($3.94 billion after tax) through June 30, 2017. Mississippi Power recorded total pre-tax charges to income for the Cost Cap Exceptions, which are not subject toestimated probable losses on 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 placedof $3.0 billion ($2.1 billion after tax) and $81 million ($50 million after tax) in servicethe second quarter 2017 and consultingthe second quarter 2016, respectively, and legal feestotal pre-tax charges of approximately $3$3.1 billion ($2.2 billion after tax) and $134 million per month.($83 million after tax) year-to-date in 2017 and 2016, respectively.
Given the significant judgment involved in estimating the future costs to complete construction and start-up,cancel the project completion date,gasifier portion of the Kemper IGCC, the ultimate rate recovery for the Kemper IGCC, including the $0.5 billion of combined cycle-related costs not yet in rates, 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.
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 adoptionRecently Issued Accounting Standards
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is permittedto recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
While Mississippi Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Mississippi Power's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs. Mississippi Power expects that the revenue from contracts with these customers will not result in a significant shift in the timing of revenue recognition for such sales.
Mississippi Power's ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements, such as alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Mississippi Power's financial statements, if material. In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Mississippi Power expects CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Mississippi Power intends to adoptuse the ASU inmodified retrospective method of adoption effective January 1, 2018. Mississippi Power has also elected to utilize practical expedients which allow it to apply the fourth quarter 2016. Thestandard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the resultstiming or amount of operations,revenues recognized in Mississippi Power's financial position,statements, Mississippi Power will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or cash flowsitems as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. Mississippi Power.Power is currently evaluating the new standard. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Mississippi Power's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Mississippi Power's financial statements.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 ninesix months ended SeptemberJune 30, 20162017 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, projected2022. 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 DecemberIn the second quarter 2017, bearing interest based on one-month LIBOR. During the first nine months of 2016, Mississippi Power borrowed $100an additional $40 million under this promissory note and an additional $100 million under a separate promissory note issued to Southern Company. In June 2017, Southern Company in November 2015. On March 8, 2016,made equity contributions totaling $1.0 billion to Mississippi Power. 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 amountproceeds to prepay $901 million of outstanding promissory notes to Southern Company totaled $551 million.debt.
As of SeptemberJune 30, 2016,2017, Mississippi Power's current liabilities exceeded current assets by approximately $411$930 million primarily due to the $300$935 million in senior notes which matured on October 15, 2016, as well as $65long-term debt that matures within the next 12 months and $107 million inof short-term debt.
Mississippi Power intends to utilize operating cash flows, and lines of credit, (to the extent available)and bank term loans, as market conditions permit, as well as, loans and, under certain circumstances, commercial paper and/or equity contributions and/or loans from Southern Company to fund the remainder of itsMississippi Power's 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$135 million for the first ninesix months of 2016, an increase2017, a decrease of $23$2 million as compared to the corresponding period in 2015.2016. The increasedecrease in cash provided from operating activities is primarily due to incomelower taxes receivable associated with researchrelated to the Kemper IGCC, the timing of payments for ad valorem taxes and experimental (R&E) deductionsmaterials and accrued taxes,supplies, and the timing of payments received from affiliates and customers, partially offset by lower R&E tax deductions, the cessationcompletion of Mirror CWIP collections and subsequent refund payments, and higher recovery of regulatory fuel clause revenues.refunds in 2016. See Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" and "Unrecognized Tax Benefits – Section 174 Research and Experimental Deduction" herein for additional information. Net cash used for investing activities totaled $509$361 million for the first ninesix months of 20162017 primarily due to gross property additions related to the Kemper IGCC, partially offset by receipt of $137 million in Additional DOE Grants.IGCC. Net cash provided from financing activities totaled $198$142 million for the first ninesix months
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
of 20162017 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.debt. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first ninesix months of 20162017 include an increase in long-term debtpaid-in capital of $826 million. A$1.0 billion due to capital contributions from Southern Company, a portion of this debtwhich was used to repay securities and notes payable resulting in a $385$300 million decrease inof securities due within one year, $591 million of long-term debt, and a $475$10 million decrease in notes payable. Additionally, CWIP increased $271 millionof short-term debt. Long-term debt decreased primarily due to the Kemper IGCC and the customer liability associated with Kemper IGCC refunds decreased $72 million.reclassification of $1.2 billion in unsecured term loans to securities due within one year. Other significant changes include a $110decreases of $2.5 billion in construction work in progress, $1.1 billion in total common stockholder's equity, $352 million increase in accrued income taxes due to bonus depreciation, a $61 million increase in accumulated deferred income taxes, (ADIT) dueand $300 million in deferred charges related to transmission and distribution property-related ADITs and additional Section 174 R&E deduction, partially offset by ADITs associated with the estimated losses onincome taxes. All of these changes primarily result from the Kemper IGCC construction,estimated loss. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and a $39 million increase in prepaid income taxes. Total common stockholder's equity increased $269 million primarily dueNote (B) to the receipt of capital contributions from Southern Company and net incomeCondensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for the period.additional information.
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
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
obligations, preferred stock dividends, trust funding requirements, and unrecognized tax benefits. Approximately $300$935 million will be required through SeptemberJune 30, 20172018 to fund maturities of long-term debt and $25$17 million will be required to fund maturities of short-term debt. In addition, Mississippi Power has $40 million of tax-exempt variable rate demand obligations that are supported by short-term credit facilities and $50 million of fixed rate pollution control revenue bonds that are required to be remarketed over the next 12 months. See "Sources of Capital" herein for additional information. Subsequent to September 30, 2016, Mississippi Power repaid at maturity $300 million aggregate principal amount of its Series 2011A 2.35% Senior Notes due October 15, 2016. If the Kemper IGCC does not go into service by December 31, 2016, Mississippi Power also would have to repay approximately $250 million of tax benefits received as a result of quarterly income tax estimates through September 30, 2016. See "Income Tax Matters"and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" 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$561 million for 2017, $0.2 billion$192 million for 2018, $0.2 billion$182 million for 2019, $0.3 billion$235 million for 2020, and $0.3 billion$199 million for 2021, which includes revised estimatesand $245 million 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 2017.2022. These estimated expenditures do not include potential compliance costs that may arise from the EPA's final rules and guidelines or subsequently approvedfuture state plans that would limit CO2 emissions from existing, new, modified, or reconstructed fossil-fuel-fired electric generating units.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. 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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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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Sources of Capital
In December 2015,Mississippi Power plans to obtain the Mississippi PSC approved the In-Service Asset Rate Order, which amongfunds required for construction and other things, provided for retail rate recovery of an annual revenue requirement of approximately $126 million effective December 17, 2015.purposes from operating cash flows, external security issuances, term loans, and/or short-term debt, as well as, under certain circumstances, equity contributions and/or loans from Southern Company. The amount, type, and timing of future financings will depend upon regulatory approval, prevailing market conditions, and other factors, which includes resolution of the Kemper IGCCCounty energy facility cost recovery. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" and – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" and " – 2015 Rate Case" of Mississippi Power in Item 7 of the Form 10-K for additional information. Also see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Bonus Depreciation"Costs" of Mississippi Power in Item 7 of the Form 10-K for additional information.
Mississippi Power received $245 million of Initial DOE Grants in prior years that were usedOn February 28, 2017, the maturity dates 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$551 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 millionnotes to Southern Company which matures in Decemberwere extended to July 31, 2018. In the second quarter 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$40 million under a separate promissory note issued to Southern Company. In June 2017, Southern Company in November 2015. On March 8, 2016,made equity contributions totaling $1.0 billion to Mississippi Power. 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. Asproceeds to (i) prepay $300 million of September 30, 2016, the outstanding principal amount under its $1.2 billion unsecured term loan; (ii) repay all of the $591 million outstanding principal amount of outstanding promissory notes to Southern Company totaled $551 million.Company; and (iii) repay $10 million of the outstanding principal amount of bank loans.
As of June 30, 2017, Mississippi Power's current liabilities exceeded current assets by approximately $930 million primarily due to $935 million in long-term debt that matures within the next 12 months and $107 million of short-term debt. Mississippi Power intends to utilize operating cash flows, and lines of credit, (to the extent available)and bank term loans, as market conditions permit, as well as, loans and, under certain circumstances, commercial paper and/or equity contributions and/or loans from Southern Company to fund Mississippi Power's short-term capital needs. Specifically, Mississippi Power has been informed by Southern Company that in the event sufficient funds are not available from external sources, Southern Company intends to provide Mississippi Power with loans and/or equity contributions sufficient to fund the remaining indebtedness scheduled to mature and other cash needs over the next 12 months. Therefore, Mississippi Power's financial statement presentation contemplates continuation of Mississippi Power as a going concern as a result of Southern Company's anticipated ongoing financial support of Mississippi Power. For additional information, see Notes 1 and 6 to the financial statements of Mississippi Power under "Recently Issued
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Accounting Standards" and "Going Concern," respectively, in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Going Concern" herein.
At SeptemberJune 30, 2016,2017, Mississippi Power had approximately $159$140 million of cash and cash equivalents. Committed credit arrangements with banks at SeptemberJune 30, 20162017 were as follows:
| | | Expires | Expires | | | | Executable Term Loans | | Due Within One Year | Expires | | | | Executable Term Loans | | Expires Within One Year |
| 2016 | | 2017 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out | |
| 2017 | | 2017 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out |
| (in millions) | (in millions) | | (in millions) | | (in millions) | | (in millions) | (in millions) |
| $ | 100 |
| | $ | 75 |
| | $ | 175 |
| | $ | 150 |
| | $ | — |
| | $ | 15 |
| | $ | 15 |
| | $ | 160 |
| 113 |
| | $ | 113 |
| | $ | 100 |
| | $ | — |
| | $ | 13 |
| | $ | 13 |
| | $ | 100 |
|
See Note 6 to the financial statements of Mississippi Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
Most of these bank credit arrangements, as well as Mississippi Power's term loan arrangements,agreement, contain covenants that limit debt levels and typically contain cross acceleration or cross default provisions to other indebtedness
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(including (including guarantee obligations) of Mississippi Power. Such cross default provisions to other indebtedness would trigger an event of default if Mississippi Power defaulted on indebtedness or guarantee obligations over a specific threshold. Such cross accelerationcross-acceleration provisions to other indebtedness would trigger an event of default if Mississippi Power defaulted on indebtedness, the payment of which was then accelerated. At June 30, 2017, Mississippi Power iswas in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowing.
Subject to applicable market conditions, Mississippi Power expects to seek to renew or replace its credit arrangements as needed, prior to expiration. In connection therewith, Mississippi Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the $150$100 million unused credit arrangements with banks is allocated to provide liquidity support to Mississippi Power's pollution control revenue bonds and commercial paper borrowings.bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of SeptemberJune 30, 20162017 was approximately $40 million. In addition, at June 30, 2017, Mississippi Power had approximately $50 million of fixed rate pollution control bonds outstanding that were required to be remarketed within the next 12 months.
Short-term borrowings are included in notes payable in the balance sheets. Details of short-term borrowings were as follows:
|
| | | | | | | | | | | | | | | | |
| | | Short-term Debt at September 30, 2016 | | Short-term Debt During the Period(*) |
| | | Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) | | | | (in millions) |
| Short-term bank debt | | $ | 25 |
| | 2.2% | | $ | 25 |
| | 2.1% | | $ | 25 |
|
|
| | | | | | | | | | | | | | | | |
| | | Short-term Debt at June 30, 2017 | | Short-term Debt During the Period(*) |
| | | Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) | | | | (in millions) |
| Short-term bank debt | | $ | 17 |
| | 2.9% | | $ | 29 |
| | 3.1% | | $ | 36 |
|
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended SeptemberJune 30, 2016.2017. |
Credit Rating Risk
At June 30, 2017, Mississippi Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that have required or could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2 or below. These contracts are for physical electricity purchases and
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
sales, fuel transportation and storage, energy price risk management, and transmission. At SeptemberJune 30, 2016,2017, the maximum potential collateral requirements under these contracts at a rating of BBB and/or Baa2 or BBB- and/or Baa3 was not material. The maximum potential collateral requirements at a rating below BBB- and/or Baa3 equaled approximately $259$243 million.
Included in these amounts are certain agreements that could require collateral in the event that oneAlabama Power or more Southern Company system power pool participantsGeorgia Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Mississippi Power to access capital markets, and would be likely to impact the cost at which it does so.
On May 12, 2016, FitchMarch 1, 2017, Moody's downgraded the senior unsecured long-term debt rating of Mississippi Power to BBB+Ba1 from A-Baa3.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and revisedits subsidiaries (including Mississippi Power) from stable to negative.
On March 30, 2017, Fitch placed the ratings outlook from negative to stable.of Mississippi Power on rating watch negative.
On June 22, 2017, Moody's placed the ratings of Mississippi Power on review for downgrade.
Financing Activities
On January 28, 2016,In March 2017, Mississippi Power issued a $9 million short-term bank note bearing interest at 5% per annum, which was repaid in April 2017.
In February 2017, Mississippi Power amended $551 million in promissory note for up to $275 millionnotes to Southern Company which matures inextending the maturity dates of the notes from December 1, 2017 bearing interest based on one-month LIBOR. Duringto July 31, 2018. In the first nine months of 2016,second quarter 2017, Mississippi Power borrowed $100an additional $40 million under this promissory note and an additional $100 million under a separate promissory note issued to Southern Company.
In June 2017, Southern Company in November 2015. On March 8, 2016,made equity contributions totaling $1.0 billion to Mississippi Power. 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. Asproceeds to (i) prepay $300 million of Septemberthe outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2016,2018; (ii) repay all of the $591 million outstanding principal amount of outstanding promissory notes to Southern Company totaled $551 million.
In June 2016, Mississippi Power renewedCompany; and (iii) repay 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.bank loan.
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 June 30, | | For the Six Months Ended June 30, |
| | 2016 | | 2015 | | 2016 | | 2015 | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | | | | | | | | |
| Wholesale revenues, non-affiliates | $ | 387 |
| | $ | 295 |
| | $ | 866 |
| | $ | 776 |
| $ | 436 |
| | $ | 264 |
| | $ | 783 |
| | $ | 480 |
|
| Wholesale revenues, affiliates | 110 |
| | 104 |
| | 313 |
| | 303 |
| 90 |
| | 107 |
| | 190 |
| | 204 |
|
| Other revenues | 3 |
| | 2 |
| | 10 |
| | 7 |
| 3 |
| | 2 |
| | 6 |
| | 4 |
|
| Total operating revenues | 500 |
| | 401 |
| | 1,189 |
| | 1,086 |
| 529 |
| | 373 |
| | 979 |
| | 688 |
|
| Operating Expenses: | | | | | | | | | | | | | | |
| Fuel | 154 |
| | 118 |
| | 341 |
| | 361 |
| 139 |
| | 96 |
| | 271 |
| | 187 |
|
| Purchased power, non-affiliates | 25 |
| | 17 |
| | 60 |
| | 52 |
| 29 |
| | 21 |
| | 54 |
| | 35 |
|
| Purchased power, affiliates | 8 |
| | 5 |
| | 16 |
| | 18 |
| 11 |
| | 2 |
| | 16 |
| | 8 |
|
| Other operations and maintenance | 81 |
| | 62 |
| | 246 |
| | 184 |
| 97 |
| | 86 |
| | 190 |
| | 162 |
|
| Depreciation and amortization | 93 |
| | 64 |
| | 247 |
| | 183 |
| 129 |
| | 81 |
| | 247 |
| | 154 |
|
| Taxes other than income taxes | 5 |
| | 6 |
| | 17 |
| | 17 |
| 12 |
| | 6 |
| | 24 |
| | 13 |
|
| Total operating expenses | 366 |
|
| 272 |
| | 927 |
| | 815 |
| 417 |
|
| 292 |
| | 802 |
| | 559 |
|
| Operating Income | 134 |
| | 129 |
| | 262 |
| | 271 |
| 112 |
| | 81 |
| | 177 |
| | 129 |
|
| Other Income and (Expense): | | | | | | | | | | | | | | |
| Interest expense, net of amounts capitalized | (35 | ) | | (18 | ) | | (78 | ) | | (62 | ) | (48 | ) | | (22 | ) | | (97 | ) | | (43 | ) |
| Other income (expense), net | 2 |
| | 1 |
| | 3 |
| | 1 |
| 2 |
| | 1 |
| | (2 | ) | | 1 |
|
| Total other income and (expense) | (33 | ) | | (17 | ) | | (75 | ) | | (61 | ) | (46 | ) | | (21 | ) | | (99 | ) | | (42 | ) |
| Earnings Before Income Taxes | 101 |
| | 112 |
| | 187 |
| | 210 |
| 66 |
| | 60 |
| | 78 |
| | 87 |
|
| Income taxes (benefit) | (102 | ) | | 1 |
| | (167 | ) | | 14 |
| (38 | ) | | (41 | ) | | (90 | ) | | (65 | ) |
| Net Income | 203 |
| | 111 |
| | 354 |
| | 196 |
| 104 |
| | 101 |
| | 168 |
| | 152 |
|
| Less: Net income attributable to noncontrolling interests | 27 |
| | 9 |
| | 39 |
| | 15 |
| 22 |
| | 12 |
| | 17 |
| | 13 |
|
| Net Income Attributable to Southern Power | $ | 176 |
| | $ | 102 |
| | $ | 315 |
| | $ | 181 |
| $ | 82 |
| | $ | 89 |
| | $ | 151 |
| | $ | 139 |
|
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 June 30, | | For the Six Months Ended June 30, |
| | 2016 | | 2015 | | 2016 | | 2015 | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Net Income | $ | 203 |
| | $ | 111 |
| | $ | 354 |
| | $ | 196 |
| $ | 104 |
| | $ | 101 |
| | $ | 168 |
| | $ | 152 |
|
| Other comprehensive income (loss): | | | | | | | | | | | | | | |
| Qualifying hedges: | | | | | | | | | | | | | | |
| Changes in fair value, net of tax of $14, $-, $(1), and $-, respectively | 23 |
| | — |
| | (1 | ) | | — |
| |
Reclassification adjustment for amounts included in net
income, net of tax of $(1), $-, $7, and $-, respectively | (1 | ) | | — |
| | 13 |
| | — |
| |
Changes in fair value, net of tax of
$24, $(15), $20, and $(15), respectively | | 40 |
| | (24 | ) | | 32 |
| | (24 | ) |
Reclassification adjustment for amounts included in net income,
net of tax of $(27), $8, $(30), and $8, respectively | | (45 | ) | | 13 |
| | (48 | ) | | 14 |
|
| Total other comprehensive income (loss) | 22 |
| | — |
| | 12 |
| | — |
| (5 | ) | | (11 | ) | | (16 | ) | | (10 | ) |
| Comprehensive Income | | 99 |
| | 90 |
| | 152 |
| | 142 |
|
| Less: Comprehensive income attributable to noncontrolling interests | 27 |
| | 9 |
| | 39 |
| | 15 |
| 22 |
| | 12 |
| | 17 |
| | 13 |
|
| Comprehensive Income Attributable to Southern Power | $ | 198 |
| | $ | 102 |
| | $ | 327 |
| | $ | 181 |
| $ | 77 |
| | $ | 78 |
| | $ | 135 |
| | $ | 129 |
|
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 Six Months Ended June 30, |
| | 2017 | | 2016 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 168 |
| | $ | 152 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 264 |
| | 159 |
|
| Deferred income taxes | 91 |
| | (71 | ) |
| Amortization of investment tax credits | (28 | ) | | (15 | ) |
| Deferred revenues | (34 | ) | | (31 | ) |
| Income taxes receivable, non-current | (58 | ) | | — |
|
| Other, net | (1 | ) | | 9 |
|
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (58 | ) | | (76 | ) |
| -Prepaid income taxes | 33 |
| | (147 | ) |
| -Other current assets | 20 |
| | 5 |
|
| -Accounts payable | (45 | ) | | 4 |
|
| -Accrued taxes | 4 |
| | 62 |
|
| -Other current liabilities | (8 | ) | | — |
|
| Net cash provided from operating activities | 348 |
| | 51 |
|
| Investing Activities: | | | |
| Business acquisitions | (1,020 | ) | | (502 | ) |
| Property additions | (145 | ) | | (1,281 | ) |
| Change in construction payables | (167 | ) | | (137 | ) |
| Payments pursuant to LTSAs | (68 | ) | | (43 | ) |
| Investment in restricted cash | (16 | ) | | (646 | ) |
| Distribution of restricted cash | 27 |
| | 649 |
|
| Other investing activities | (2 | ) | | (25 | ) |
| Net cash used for investing activities | (1,391 | ) | | (1,985 | ) |
| Financing Activities: | | | |
| Increase in notes payable, net | 189 |
| | 695 |
|
| Proceeds — | | | |
| Senior notes | — |
| | 1,241 |
|
| Capital contributions from parent company | — |
| | 300 |
|
| Distributions to noncontrolling interests | (40 | ) | | (11 | ) |
| Capital contributions from noncontrolling interests | 73 |
| | 179 |
|
| Purchase of membership interests from noncontrolling interests | — |
| | (129 | ) |
| Payment of common stock dividends | (158 | ) | | (136 | ) |
| Other financing activities | (21 | ) | | (13 | ) |
| Net cash provided from financing activities | 43 |
| | 2,126 |
|
| Net Change in Cash and Cash Equivalents | (1,000 | ) | | 192 |
|
| Cash and Cash Equivalents at Beginning of Period | 1,099 |
| | 830 |
|
| Cash and Cash Equivalents at End of Period | $ | 99 |
| | $ | 1,022 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
| Interest (net of $4 and $21 capitalized for 2017 and 2016, respectively) | $ | 113 |
| | $ | 42 |
|
| Income taxes, net | (117 | ) | | 115 |
|
| Noncash transactions — Accrued property additions at end of period | 19 |
| | 108 |
|
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 June 30, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 99 |
| | $ | 1,099 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 158 |
| | 102 |
|
| Other accounts receivable | | 37 |
| | 34 |
|
| Affiliated | | 65 |
| | 57 |
|
| Fossil fuel stock | | 15 |
| | 15 |
|
| Materials and supplies | | 349 |
| | 337 |
|
| Prepaid income taxes | | 41 |
| | 74 |
|
| Other current assets | | 26 |
| | 39 |
|
| Total current assets | | 790 |
| | 1,757 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 13,731 |
| | 12,728 |
|
| Less: Accumulated provision for depreciation | | 1,689 |
| | 1,484 |
|
| Plant in service, net of depreciation | | 12,042 |
| | 11,244 |
|
| Construction work in progress | | 344 |
| | 398 |
|
| Total property, plant, and equipment | | 12,386 |
| | 11,642 |
|
| Other Property and Investments: | | | | |
Intangible assets, net of amortization of $35 and $22
at June 30, 2017 and December 31, 2016, respectively | | 423 |
| | 436 |
|
| Total other property and investments | | 423 |
| | 436 |
|
| Deferred Charges and Other Assets: | | | | |
| Prepaid LTSAs | | 61 |
| | 101 |
|
| Accumulated deferred income taxes | | 536 |
| | 594 |
|
| Income taxes receivable, non-current | | 69 |
| | 11 |
|
| Other deferred charges and assets — affiliated | | 28 |
| | 13 |
|
| Other deferred charges and assets — non-affiliated | | 410 |
| | 615 |
|
| Total deferred charges and other assets | | 1,104 |
| | 1,334 |
|
| Total Assets | | $ | 14,703 |
| | $ | 15,169 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholders' Equity | | At June 30, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 909 |
| | $ | 560 |
|
| Notes payable | | 398 |
| | 209 |
|
| Accounts payable — | | | | |
| Affiliated | | 68 |
| | 88 |
|
| Other | | 93 |
| | 278 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 35 |
| | 148 |
|
| Other accrued taxes | | 21 |
| | 7 |
|
| Accrued interest | | 25 |
| | 36 |
|
| Acquisitions payable | | — |
| | 461 |
|
| Contingent consideration | | 11 |
| | 46 |
|
| Other current liabilities | | 67 |
| | 70 |
|
| Total current liabilities | | 1,627 |
| | 1,903 |
|
| Long-term Debt | | 4,816 |
| | 5,068 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 174 |
| | 152 |
|
| Accumulated deferred ITCs | | 1,914 |
| | 1,839 |
|
| Asset retirement obligations | | 69 |
| | 64 |
|
| Other deferred credits and liabilities | | 238 |
| | 304 |
|
| Total deferred credits and other liabilities | | 2,395 |
| | 2,359 |
|
| Total Liabilities | | 8,838 |
| | 9,330 |
|
| Redeemable Noncontrolling Interests | | 51 |
| | 164 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, par value $.01 per share — | | | | |
| Authorized — 1,000,000 shares | | | | |
| Outstanding — 1,000 shares | | — |
| | — |
|
| Paid-in capital | | 3,671 |
| | 3,671 |
|
| Retained earnings | | 717 |
| | 724 |
|
| Accumulated other comprehensive income | | 19 |
| | 35 |
|
| Total common stockholder's equity | | 4,407 |
| | 4,430 |
|
| Noncontrolling interests | | 1,407 |
| | 1,245 |
|
| Total stockholders' equity | | 5,814 |
| | 5,675 |
|
| Total Liabilities and Stockholders' Equity | | $ | 14,703 |
| | $ | 15,169 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
|
| | | | | | | |
| | For the Nine Months Ended September 30, |
| | 2016 | | 2015 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 354 |
| | $ | 196 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 262 |
| | 187 |
|
| Deferred income taxes | (668 | ) | | 222 |
|
| Investment tax credits | — |
| | 294 |
|
| Amortization of investment tax credits | (25 | ) | | (14 | ) |
| Deferred revenues | 9 |
| | 15 |
|
| Collateral deposits | (80 | ) | | — |
|
| Accrued income taxes, non-current | — |
| | 100 |
|
| Other, net | 10 |
| | 10 |
|
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (82 | ) | | (28 | ) |
| -Prepaid income taxes | (16 | ) | | (116 | ) |
| -Other current assets | 1 |
| | 1 |
|
| -Accounts payable | 7 |
| | 1 |
|
| -Accrued taxes | 483 |
| | (247 | ) |
| -Other current liabilities | 14 |
| | (12 | ) |
| Net cash provided from operating activities | 269 |
| | 609 |
|
| Investing Activities: | | | |
| Business acquisitions | (1,134 | ) | | (1,128 | ) |
| Property additions | (1,702 | ) | | (348 | ) |
| Change in construction payables | (69 | ) | | 88 |
|
| Payments pursuant to long-term service agreements | (58 | ) | | (65 | ) |
| Investment in restricted cash | (750 | ) | | — |
|
| Distribution of restricted cash | 746 |
| | — |
|
| Other investing activities | (41 | ) | | (1 | ) |
| Net cash used for investing activities | (3,008 | ) | | (1,454 | ) |
| Financing Activities: | | | |
| Increase in notes payable, net | 692 |
| | 18 |
|
| Proceeds — | | | |
| Senior notes | 1,531 |
| | 650 |
|
| Capital contributions | 800 |
| | 226 |
|
| Other long-term debt | 63 |
| | 400 |
|
| Redemptions — | | | |
| Senior notes | — |
| | (525 | ) |
| Other long-term debt | (84 | ) | | (3 | ) |
| Distributions to noncontrolling interests | (22 | ) | | (6 | ) |
| Capital contributions from noncontrolling interests | 367 |
| | 274 |
|
| Purchase of membership interests from noncontrolling interests | (129 | ) | | — |
|
| Payment of common stock dividends | (204 | ) | | (98 | ) |
| Other financing activities | (14 | ) | | (5 | ) |
| Net cash provided from financing activities | 3,000 |
| | 931 |
|
| Net Change in Cash and Cash Equivalents | 261 |
| | 86 |
|
| Cash and Cash Equivalents at Beginning of Period | 830 |
| | 75 |
|
| Cash and Cash Equivalents at End of Period | $ | 1,091 |
| | $ | 161 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
| Interest (net of $32 and $4 capitalized for 2016 and 2015, respectively) | $ | 49 |
| | $ | 69 |
|
| Income taxes, net | 71 |
| | (215 | ) |
| Noncash transactions — Accrued property additions at end of period | 210 |
| | 120 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At September 30, 2016 | | At December 31, 2015 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 1,091 |
| | $ | 830 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 121 |
| | 75 |
|
| Other accounts receivable | | 25 |
| | 19 |
|
| Affiliated | | 67 |
| | 30 |
|
| Fossil fuel stock | | 14 |
| | 16 |
|
| Materials and supplies | | 163 |
| | 63 |
|
| Prepaid income taxes | | 61 |
| | 45 |
|
| Other current assets | | 32 |
| | 30 |
|
| Total current assets | | 1,574 |
| | 1,108 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 9,491 |
| | 7,275 |
|
| Less accumulated provision for depreciation | | 1,465 |
| | 1,248 |
|
| Plant in service, net of depreciation | | 8,026 |
| | 6,027 |
|
| Construction work in progress | | 1,652 |
| | 1,137 |
|
| Total property, plant, and equipment | | 9,678 |
| | 7,164 |
|
| Other Property and Investments: | | | | |
| Goodwill | | 2 |
| | 2 |
|
Other intangible assets, net of amortization of $16 and $12
at September 30, 2016 and December 31, 2015, respectively | | 389 |
| | 317 |
|
| Total other property and investments | | 391 |
| | 319 |
|
| Deferred Charges and Other Assets: | | | | |
| Prepaid long-term service agreements | | 151 |
| | 166 |
|
| Accumulated deferred income taxes | | 199 |
| | — |
|
| Other deferred charges and assets — affiliated | | 3 |
| | 9 |
|
| Other deferred charges and assets — non-affiliated | | 355 |
| | 139 |
|
| Total deferred charges and other assets | | 708 |
| | 314 |
|
| Total Assets | | $ | 12,351 |
| | $ | 8,905 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholders' Equity | | At September 30, 2016 | | At December 31, 2015 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 60 |
| | $ | 403 |
|
| Notes payable | | 828 |
| | 137 |
|
| Accounts payable — | | | | |
| Affiliated | | 91 |
| | 66 |
|
| Other | | 218 |
| | 327 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 147 |
| | 198 |
|
| Other accrued taxes | | 16 |
| | 5 |
|
| Accrued interest | | 30 |
| | 23 |
|
| Contingent consideration | | 30 |
| | 36 |
|
| Other current liabilities | | 97 |
| | 44 |
|
| Total current liabilities | | 1,517 |
| | 1,239 |
|
| Long-term Debt | | 4,548 |
| | 2,719 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 140 |
| | 601 |
|
| Accumulated deferred investment tax credits | | 1,385 |
| | 889 |
|
| Accrued income taxes, non-current | | 109 |
| | 109 |
|
| Asset retirement obligations | | 40 |
| | 21 |
|
| Deferred capacity revenues — affiliated | | 19 |
| | 17 |
|
| Other deferred credits and liabilities | | 115 |
| | 3 |
|
| Total deferred credits and other liabilities | | 1,808 |
| | 1,640 |
|
| Total Liabilities | | 7,873 |
| | 5,598 |
|
| Redeemable Noncontrolling Interests | | 49 |
| | 43 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, par value $.01 per share — | | | | |
| Authorized — 1,000,000 shares | | | | |
| Outstanding — 1,000 shares | | — |
| | — |
|
| Paid-in capital | | 2,620 |
| | 1,822 |
|
| Retained earnings | | 769 |
| | 657 |
|
| Accumulated other comprehensive income (loss) | | 16 |
| | 4 |
|
| Total common stockholder's equity | | 3,405 |
| | 2,483 |
|
| Noncontrolling interests | | 1,024 |
| | 781 |
|
| Total stockholders' equity | | 4,429 |
| | 3,264 |
|
| Total Liabilities and Stockholders' Equity | | $ | 12,351 |
| | $ | 8,905 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRDSECOND QUARTER 20162017 vs. THIRDSECOND QUARTER 20152016
AND
YEAR-TO-DATE 20162017 vs. YEAR-TO-DATE 20152016
OVERVIEW
Southern Power constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Power continually seeks opportunities to execute its strategy to create value through various transactions including acquisitions and sales of assets, construction and development of new generating facilities, and entry into PPAs primarily with investor-owned utilities, independent power producers, municipalities, electric cooperatives, and other load-serving entities. In general, Southern Power has constructed or acquired new generating capacity only after entering into or assuming long-term PPAs for the new facilities.
During the ninesix months ended SeptemberJune 30, 2016,2017, Southern Power acquired or commencedcompleted the construction of, and placed in service, approximately 758498 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 committedcontinued developing its portfolio of wind projects as well as the construction to acquire approximately 674expand the Mankato natural gas facility by 345 MWs of solarcapacity. Subsequent to June 30, 2017, Southern Power acquired and commenced construction of Cactus Flats, a 148-MW wind facilities over the next several months.facility. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information.
At SeptemberJune 30, 2016,2017, Southern Power had an average investment coverage ratio of 92% through 2020 and 91% through 2025,2021 and 90% through 2026, with an average remaining contract duration of approximately 1716 years. These ratios include the PPAs and capacity associated with facilities currently under construction and acquisitions discussed herein. See FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" herein for additional information.
Southern Power continues to focus on several key performance indicators. These indicators, includeincluding, but not limited to, peak season equivalent forced outage rate, contract availability, and net income.
RESULTS OF OPERATIONS
Net Income
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(7) | | (7.9) | | $12 | | 8.6 |
Net income attributable to Southern Power for the second quarter 2017 was $82 million compared to $89 million for the corresponding period in 2016. The decrease was primarily due to increased interest expense from debt issuances to fund acquisitions and construction and an increase in net income attributable to noncontrolling interests, significantly offset by additional operating income related to new generating facilities.
Net income attributable to Southern Power for year-to-date 2017 was $151 million compared to $139 million for the corresponding period in 2016. The increase was primarily due to additional operating income from new generating facilities, as well as increased federal income tax benefits from wind PTCs, partially offset by increased interest expense from debt issuances to fund acquisitions and construction. For additional information on these indicators,new generating facilities placed in service during 2016 and 2017, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "– OVERVIEW – Acquisitions"Key Performance Indicators" and "Construction Projects" 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 ITCs10-K and wind PTCsFUTURE EARNINGS POTENTIAL – "Acquisitions" 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."Construction Projects" herein.
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 |
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $156 | | 41.8 | | $291 | | 42.3 |
OperatingTotal operating revenues include PPA capacity revenues, which are derived primarily from long-term contracts involving natural gas and biomass generating facilities, and PPA energy revenues, which include sales from Southern Power's natural gas, biomass, solar, and wind facilities. To the extent Southern Power has unused capacity not contracted under a PPA, it may sell power into the wholesale market orand, to the extent the generation assets are part of the IIC, as approved by the FERC, it may sell power into the power pool.
Natural Gas and Biomass Capacity and Energy Revenue
Capacity revenues generally represent the greatest contribution to net income and are an integral componentdesigned to provide recovery of Southern Power's natural gas and biomass PPAs. fixed costs plus a return on investment.
Energy under these PPAs is generally sold at variable cost or is indexed to published gas indices. Energy revenues will vary depending on the energy demand of Southern Power's customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Power's energy. Energy revenues also include fees for support services, fuel storage, and unit start charges. Increases and decreases in energy revenues under PPAs that are driven by fuel or purchased power prices are accompanied by an increase or decrease in fuel and purchased power costs and do not have a significant impact on net income.
Solar and Wind Energy Revenue
Southern Power's electricity sales from solar and wind generating facilities are alsopredominantly through long-term PPAs; however, these solar and wind PPAs that do not have a capacity charge and customerscharge. Customers either purchase the energy output of a dedicated renewable facility through an energy charge.charge or pay a fixed price for electricity sold to the grid. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, and other factors.
See FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" herein for additional information regarding Southern Power's PPAs. |
| | | | | | | | | | | |
| | 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,Details of Southern Power's 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.follows:
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.
|
| | | | | | | | | | | | | | | |
| | Second Quarter 2017 | | Second Quarter 2016 | | Year-to-Date 2017 | | Year-to-Date 2016 |
| | (in millions) |
| PPA capacity revenues | $ | 149 |
| | $ | 133 |
| | $ | 298 |
| | $ | 258 |
|
| PPA energy revenues | 270 |
| | 168 |
| | 466 |
| | 285 |
|
| Total PPA revenues | 419 |
| | 301 |
| | 764 |
| | 543 |
|
| Non-PPA revenues | 107 |
| | 70 |
| | 209 |
| | 141 |
|
| Other revenues | 3 |
| | 2 |
| | 6 |
| | 4 |
|
| Total operating revenues | $ | 529 |
| | $ | 373 |
| | $ | 979 |
| | $ | 688 |
|
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Revenues not covered byIn the second quarter 2017, total operating revenues were $529 million, reflecting a $156 million, or 42%, increase from the corresponding period in 2016. The increase in operating revenues was primarily due to the following:
PPA capacity revenues increased $16 million, or 12%, primarily due to new PPAs related to natural gas facilities and additional customer load requirements.
PPA energy revenues increased $46$102 million, or 61%, primarily due to an $85 million increase in sales from new solar and wind facilities and a $20 million increase in sales from new natural gas PPAs and additional customer load requirements.
Non-PPA revenues increased $37 million, or 53%, due to a $70$23 million increase in the volume of KWHs sold primarily from uncovered natural gas capacity through short-term opportunity 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 a $14 million increase in the market pricesprice of wholesale energy comparedprimarily due to increased natural gas prices.
For year-to-date 2017, total operating revenues were $979 million, reflecting a $291 million, or 42%, increase from the corresponding period in 2016. The increase in operating revenues was primarily due to the costfollowing:
PPA capacity revenues increased $40 million, or 16%, primarily due to new PPAs related to natural gas facilities and additional customer load requirements.
PPA energy revenues increased $181 million, or 64%, primarily due to a $137 million increase in sales from new solar and wind facilities and a $37 million increase in sales from new natural gas PPAs and additional customer load requirements.
Non-PPA revenues increased $68 million, or 48%, due to a $48 million increase in the volume of Southern Power's energy. Increases and decreasesKWHs sold primarily from uncovered natural gas capacity through short-term opportunity sales, as well as a $20 million increase 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.the price of energy primarily due to increased natural gas prices.
Fuel and Purchased Power Expenses
Fuel costs constitute the single largest expense for Southern Power. In addition, Southern Power purchases a portion of its electricity needs from the wholesale market and the power pool.market. Details of Southern Power's generation and purchased power were as follows:
| | | | Third Quarter 2016 | Third Quarter 2015 | | Year-to-Date 2016 | Year-to-Date 2015 | Second Quarter 2017 | Second Quarter 2016 | | Year-to-Date 2017 | Year-to-Date 2016 |
| | (in billions of KWHs) | (in billions of KWHs) |
| Generation | 11.1 | 9.4 | | 27.9 | 24.8 | 10.9 | 9.1 | | 20.6 | 16.7 |
| Purchased power | 0.9 | 0.5 | | 2.5 | 1.5 | 1.2 | 0.9 | | 2.2 | 1.5 |
| Total generation and purchased power | 12.0 | 9.9 | | 30.4 | 26.3 | 12.1 | 10.0 | | 22.8 | 18.2 |
Total generation and purchased power excluding solar, wind, and tolling agreements | 6.7 | 5.2 | | 17.7 | 15.9 | |
| | | |
| Total generation and purchased power, excluding solar, wind, and tolling agreements | | 5.6 | 5.7 | | 10.5 | 11.0 |
Southern Power's PPAs for natural gas and biomass generation generally provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing Southern Power for substantially all of the cost of fuel relating to the energy delivered under such PPAs. Consequently, changes in such fuel costs are generally accompanied by a corresponding change in related fuel revenues and do not have a significant impact on net income. Southern Power is responsible for the cost of fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the wholesale market or into the power pool for capacity owned directly by Southern Power (excluding its subsidiaries).Power.
Purchased power expenses will vary depending on demand, availability, and the cost of generating resources throughout the Southern Company system and other contract resources. Load requirements are submitted to the power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power, an affiliate company, or external parties.
|
| | | | | | | | | | | | |
| | | 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 ofSouthern Power, an affiliate company, or external parties. Such purchased power costs are generally recovered through PPA revenues.
Details of Southern Power's fuel and a $4 million decrease associated with a PPA expiration.purchased power expenses were as follows:
|
| | | | | | | | | | | |
| | Second Quarter 2017
vs.
Second Quarter 2016 | | Year-to-Date 2017
vs.
Year-to-Date 2016 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | 43 |
| | 44.8 | | $ | 84 |
| | 44.9 |
| Purchased power | 17 |
| | 73.9 | | 27 |
| | 62.8 |
| Total fuel and purchased power expenses | $ | 60 |
| | | | $ | 111 |
| | |
In the second quarter 2017, total fuel and purchased power expenses were $417increased $60 million, or 50.4%, compared to $431 million for the corresponding period in 2015. The decrease was primarily due to the following:
2016. Fuel expense decreased $20increased $43 million primarily due to a $42$51 million increase in the average cost of natural gas per KWH generated, partially offset by an $8 million decrease in the volume of KWHs generated, excluding solar, wind, and tolling agreements. Purchased power expense increased $17 million primarily due to a $10 million increase in the volume of KWHs purchased and a $6 million increase associated with the average cost of purchased power.
For year-to-date 2017, total fuel and purchased power expenses increased $111 million, or 48.3%, compared to the corresponding period in 2016. Fuel expense increased $84 million primarily due to a $105 million increase in the average cost of natural gas per KWH generated, partially offset by a $22 million increase associated withdecrease in the volume of KWHs generated.
generated, excluding solar, wind, and tolling agreements. Purchased power expense increased $6$27 million due to a $48$19 million increase in the volume of KWHs purchased and an $8 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.power.
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 |
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $11 | | 12.8 | | $28 | | 17.3 |
In the thirdsecond quarter 2016,2017, other operations and maintenance expenses were $81$97 million compared to $62$86 million for the corresponding period in 2015.2016. The increase was primarily due to a $9$19 million increase in expenses associated with new solar, wind, and windgas facilities placed in service in 2015 and 2016, a $5 million increase associated with employee compensation and expenses in support of Southern Power's overall growth strategy, partially offset by a $9 million decrease in scheduled outage and maintenance expenses and a $3$5 million increasedecrease in general business expenses associated with Southern Power's overall growth strategy.non-outage operations and maintenance expenses.
For year-to-date 2016,2017, other operations and maintenance expenses were $246$190 million compared to $184$162 million for the corresponding period in 2015.2016. The increase was primarily due to a $24$35 million increase associated with scheduled outagenew solar, wind, and maintenance expenses,gas facilities and a $22$10 million increase in expenses associated with new solaremployee compensation and wind facilities placedexpenses in service in 2015 and 2016, and a $14 million increase in general business expenses associated withsupport of Southern Power's overall growth strategy.strategy, partially offset by a $16 million decrease in scheduled outage maintenance expenses and a $4 million decrease in non-outage operations and maintenance expenses.
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 |
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $48 | | 59.3 | | $93 | | 60.4 |
In the thirdsecond quarter 2016,2017, depreciation and amortization was $93$129 million compared to $64$81 million for the corresponding period in 2015.2016. For year-to-date 2016,2017, 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$154 million for the constructioncorresponding period in 2016. The increases were primarily due to new solar, wind, and gas facilities placed in service.
Interest Expense, net of solar facilities.Amounts Capitalized
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $26 | | 118.2 | | $54 | | 125.6 |
In the second quarter 2017, interest expense, net of amounts capitalized was $78$48 million compared to $62$22 million for the corresponding period in 2015.2016. The increase was primarily due to an increase of $43$16 million in interest expense related to additional debt issued since the third quarter of 2015in 2016, primarily to fund Southern Power's growth strategy and continuous construction program, largelyas well as a $9 million decrease in capitalized interest associated with completing construction of and placing in service solar facilities.
For year-to-date 2017, interest expense, net of amounts capitalized was $97 million compared to $43 million for the corresponding period in 2016. The increase was primarily due to an increase of $36 million in interest expense related to additional debt issued in 2016, primarily to fund Southern Power's growth strategy and continuous construction program, as well as a $17 million decrease in capitalized interest associated with completing construction of and placing in service solar facilities.
Other Income (Expense), Net
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1 | | 100.0 | | $(3) | | (300.0) |
In the second quarter 2017, other income (expense), net was $2 million compared to $1 million for the corresponding period in 2016. For year-to-date 2017, other income (expense), net was $(2) million compared to $1 million for the corresponding period in 2016. The changes include increases of $99 million and $116 million from currency losses arising from translation of €1.1 billion euro-denominated fixed-rate notes into U.S. dollars for the second quarter and year-to-date 2017, respectively, fully offset by an equal change in gains on the foreign currency hedges that were reclassified from accumulated OCI into earnings. See Note (H) to the Condensed Financial Statements herein for additional information.
Income Taxes (Benefit)
|
| | | | | | |
| Second Quarter 2017 vs. Second Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $3 | | 7.3 | | $(25) | | (38.5) |
In the second quarter 2017, income tax benefit was $38 million compared to $41 million for the corresponding period in 2016. The decrease was primarily due to a $29 million decrease in ITC benefits, partially offset by a $27 million increase in capitalized interest associated with the construction of solar facilities.wind PTC benefits.
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,For year-to-date 2017, income tax benefit was $(102)$90 million compared to an expense of $1$65 million for the corresponding period in 2015.2016. The changeincrease was primarily due to a $96$57 million increase in federal income taxwind PTC benefits, a $4 million increase resulting from solar ITCs and wind PTCs in 2016state apportionment rate changes, and a $10$4 million decrease in tax expenseincrease 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$41 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.ITC benefits.
See Note (G) to the Condensed Financial Statements herein for additional information.information on income taxes and Note 1 to the financial statements of Southern Power under "Income and Other Taxes" in Item 8 of the Form 10-K for additional information on ITCs.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern Power's future earnings potential. The level of Southern Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Power's competitive wholesale business. These factors include: Southern Power's ability to achieve sales growth while containing costs; regulatory matters; creditworthiness of customers; total generating capacity available in Southern Power's market areas; the successful remarketing of capacity as current contracts expire; Southern Power's ability to execute its growth strategy, including successful additional investments in renewable and other energy projects, and to develop and construct generating facilities;facilities. Current proposals related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals, including any potential changes to the availability or realizability of ITCs and PTCs, is dependent on the final form of any legislation enacted and the related transition rules, and cannot be determined at this time, but could have a material impact of federal ITCs and PTCs. on Southern Power's consolidated financial statements.
Demand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, as well as renewable portfolio standards, which may impact future earnings.
Other factors that could influence future earnings include weather, demand, cost of generation from unitsfacilities 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,June 30, 2017, Southern Power's generation contract coverage ratio, which compares contracted capacity (MW) to available demonstrated capacity (MW), was an average of 75% through 2020 and 70% through 2025, with an average remaining contract duration of approximately 10 years.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Power believes an investment coverage ratio best identifies the value offor its generating assets, covered since it representsbased on the ratio of investment under contract to total investment using the respective generation facilities' net book value (or expected in-service value for facilities under construction or being acquired)construction) as the investment amount. At September 30, 2016, the average investment coverage ratioamount, was 92% through 2020 and 91% through 2025,2021 and 90% through 2026, with an average remaining contract duration of approximately 1716 years. At December 31, 2015, the average investment coverage ratio would have been 91% through 2020 and 90% through 2025, with an average remaining contract duration of approximately 18 years.
Environmental Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Power in Item 7 of the Form 10-K for information on the development by federal and state environmental regulatory agencies of additional control strategies for emissions of air pollution from industrial sources, including electric generating facilities. Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, water quality, or other environmental and health concerns could also significantly affect Southern Power. While Southern Power's PPAs generally contain provisions that permit charging the counterparty with some of the new costs incurred as a result of changes in environmental laws and regulations, the full impact of any such legislative or regulatory changes cannot be determined at this time.
Environmental Statutes and Regulations
AirWater Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – AirWater Quality" of Southern Power in Item 7 of the Form 10-K for additional information regarding the EPA's Cross State Air Pollution Rule (CSAPR).final effluent guidelines rule.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
On October 26, 2016,April 25, 2017, the EPA published a finalnotice announcing it would reconsider the effluent guidelines rule, that updateswhich had been finalized in November 2015. On June 6, 2017, the CSAPR ozone season nitrogen oxide program, including revising ozone-season emissions budgets in AlabamaEPA proposed a rule establishing a stay of the compliance deadlines for certain effluent limitations and Texas and removing Florida and North Carolina frompretreatment standards under the CSAPR program. rule.
The ultimate impactoutcome of this rule will depend on the outcome of any legal challenges and implementation at the state level andmatter cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Southern Power in Item 7 of the Form 10-K for additional information.
On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules.
On June 1, 2017, the U.S. President announced that the United States will withdraw from the non-binding Paris Agreement and begin renegotiation of its terms.
The ultimate outcome of these matters cannot be determined at this time.
FERC Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Southern Power in Item 7 of the Form 10-K for additional information regarding the traditional electric operating companies' and Southern Power's market power proceeding and amendment to their market-rate tariff.
On May 17, 2017, the FERC accepted the traditional electric operating companies' and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' and Southern Power's market power proceeding, it remains a separate, ongoing matter.
Acquisitions
During 2016,the six months ended June 30, 2017, in accordance with itsSouthern Power's overall growth strategy, Southern Power or one of its wholly-owned subsidiaries, Southern Renewable Partnerships, LLC and(SRP), one of Southern Renewable Energy, Inc.,Power's wholly-owned subsidiaries, acquired or contracted to acquire the projects discussed below.Bethel wind facility. Acquisition-related costs were expensed as incurred and were not material. See Note (I) to the Condensed Financial Statements under "Southern Power" herein and MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Power in Item 7 of the Form 10-K for additional information.
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| | | | | | | | | |
| Project Facility | Resource | Approximate Nameplate Capacity (MW) | Location | Percentage Ownership | Actual COD | PPA Counterparties | PPA Contract Period |
| Bethel | Wind | 276 | Castro County, TX | 100 | % | | January 2017 | Google Energy, LLC | 12 years |
The aggregate amounts of revenue and net income, excluding impacts from PTCs, recognized by Southern Power related to the Bethel facility included in the condensed consolidated statements of income for year-to-date 2017 were immaterial. The Bethel facility did not have operating revenues or activities prior to completion of construction and the assets being placed in service; therefore, supplemental pro forma information for the comparable 2016 period is not meaningful and has been omitted.
Subsequent to June 30, 2017, Southern Power acquired a 100% ownership interest in and commenced construction of the Cactus Flats 148-MW wind facility, the majority of which is covered by two PPAs, which expire in 2030 and
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) | 2033. 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.placed in service in mid-2018. 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.
Construction Projects Completed and in Progress
During the ninesix months ended SeptemberJune 30, 2016,2017, in accordance with its overall growth strategy, Southern Power completed construction of and placed in service, or continued construction of, the projects set forth in the following table. Through SeptemberJune 30, 2016,2017, total costs of construction incurred for the followingthese projects were $3.0 billion,$421 million, of which $1.2 billion remains$49 million remained in CWIP. IncludingCWIP for the total construction costs incurred through September 30, 2016 and the acquisition prices allocated to CWIP, totalMankato facility acquired in 2016. Total aggregate construction costs, excluding the acquisition costs, are expected to be $170 million to $190 million for the following projects are estimated to be $3.1 billion to $3.2 billion.Mankato facility. The ultimate outcome of these mattersthis 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
|
| | | | | | |
SolarProject Facility | Resource | Approximate Nameplate Capacity (MW) | Location | Actual/Expected COD | PPA Counterparties | PPA Contract Period |
Projects Completed During the NineSix Months Ended SeptemberJune 30, 20162017 |
Butler Solar FarmEast Pecos | 22Solar | Taylor120 | Pecos County, GATX | February 2016March 2017 | 20Austin Energy | 15 years |
Desert Stateline(a)
Lamesa | 299(b)
Solar | San Bernardino102 | Dawson County, CATX | Through July 2016April 2017 | 20City of Garland, Texas | 15 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 |
ProjectsProject Under Construction as of SeptemberJune 30, 20162017 |
ButlerMankato | 103Natural Gas | Taylor County, GA345 | December 2016Mankato, MN | 30 years |
GarlandSecond quarter 2019 | 185 | Kern County, CA | October 2016 | 15 years |
Roserock | 160 | Pecos County, TX | November 2016Northern States Power Company | 20 years |
Sandhills | 146 | Taylor County, GA | October 2016 | 25 years |
| |
(a) | On March 29, 2016, Southern Power acquired an additional 15% interest in Desert Stateline. As a result, Southern Power and the class B member are entitled to 66% and 34%, respectively, of all cash distributions from Desert Stateline. In addition, Southern Power will continue to be entitled to substantially all of the federal tax benefits with respect to the transaction. |
| |
(b) | The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and 189 MWs were placed in service during the nine months ended September 30, 2016. |
Development Projects
In December 2016, as part of Southern Power's renewable development strategy, SRP entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct approximately 3,000 MWs of wind projects. Also in December 2016, Southern Power signed agreements and made payments to purchase wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. All of the wind turbine equipment was delivered by April 2017, which allows the projects to qualify for 100% PTCs for 10 years following their expected commercial operation dates between 2018 and 2020. The ultimate outcome of these matters cannot be determined at this time.
Income Tax Matters
Bonus Depreciation
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Bonus Depreciation"Matters" of Southern Power in Item 7 of the Form 10-K for additional information.
The extension of 50% bonus depreciation included in the PATH Act is expected to result in approximately $650 million of positive cash flows for the 2016 tax year, which may not all be realized in 2016 due to a projected consolidated net operating loss (NOL) for Southern Company. As a result, the NOL will increase deferred tax assets for federal ITC and PTC carryforwards. See Note (G) to the Condensed Financial Statements under "Current and Deferred Income Taxes – Net Operating Loss" and " – Tax Credit Carryforwards" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.
Other Matters
Southern Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Power is subject to certain claims and legal actions arising in the ordinary course of business. Southern Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation against Southern Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, orinNote3tothefinancialstatementsofSouthern PowerinItem8ofthe Form 10-K,management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Power's financial statements.
During 2015, Southern Power indirectly acquired a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock facility in Pecos County, Texas, which was under construction by Recurrent Energy, LLC and was subsequently placed in service in November 2016. Prior to placing the facility in service, certain solar panels were damaged during installation. While the facility currently is generating energy consistent with operational expectations and PPA obligations, Southern Power is pursuing remedies under its insurance policies and other contracts to repair or replace these solar panels. In connection therewith, Southern Power is withholding payments of approximately $26 million from the construction contractor, who has placed a lien on the Roserock facility for the same amount. The amounts withheld are included in other accounts payable and other current liabilities on Southern Power's consolidated balance sheets. On May 18, 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas, against X.L. America, Inc. (XL) and North American Elite Insurance Company (North American Elite) seeking recovery from an insurance policy for damages resulting from a hail storm and certain installation practices by the construction contractor, McCarthy Building Companies, Inc. (McCarthy). On May 19, 2017, Roserock filed a separate lawsuit against McCarthy in the state district court in Travis County, Texas alleging breach of contract and breach of warranty for the damages sustained at the Roserock facility, which has since been moved to the U.S. District Court for the Western District of Texas. On May 22, 2017, McCarthy filed a lawsuit against Roserock, Array Technologies, Inc., Canadian Solar (USA), Inc., XL, and North American Elite in the U.S. District Court for the Western District of Texas alleging, among other things, breach of contract, and requesting foreclosure of mechanic's liens against Roserock. On July 18, 2017, the U.S. District Court for the Western District of Texas consolidated the two pending lawsuits. Southern Power intends to vigorously pursue and defend these matters, the ultimate outcome of which cannot be determined at this time.
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,In 2014, the FASB issued ASU No. 2016-02, Leases(Topic 842)ASC 606, (ASU 2016-02). ASU 2016-02 requires lesseesRevenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize onrevenue to depict the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02transfer of goods or services to customers at the amount expected to be collected. The new standard also changes the recognition, measurement, and presentation of expense associated with leases and provides clarificationrequires enhanced disclosures regarding the identificationnature, amount, timing, and uncertainty of certain components ofrevenue and the related cash flows arising from 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.customers.
While Southern Power isexpects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. However, given Southern Power's core activities of selling
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
generation capacity and energy to high credit rated customers, Southern Power currently evaluatingdoes not expect the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact onto net income. Southern Power's balance sheet.ongoing evaluation of revenue streams and related contracts includes the evaluation of identified revenue streams tied to longer-term contractual arrangements, such as certain capacity and energy payments under PPAs that are expected to be excluded from the scope of ASC 606 and included in the scope of the current leasing guidance (ASC 840).
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Southern Power intends to use the modified retrospective method of adoption effective January 1, 2018. Southern Power has also elected to utilize practical expedients which allow it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Southern Power's financial statements, Southern Power will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Power in Item 7 of the Form 10-K for additional information. Southern Power's financial condition remained stable at SeptemberJune 30, 2016.2017. Southern Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements as needed to meet future capital and liquidity needs. See "Sources of Capital" herein for additional information on lines of credit.
Net cash provided from operating activities totaled $269$348 million for the first ninesix months of 20162017 compared to $609$51 million for the first ninesix months of 2015.2016. The decreaseincrease in net cash provided from operating activities was primarily due to an increase in unutilized ITCsenergy sales arising from new solar and PTCs.wind facilities and a decrease in income taxes paid, partially offset by an increase in interest paid. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Bonus Depreciation" hereinof Southern Power in Item 7 of the Form 10-K for additional information. Net cash used for investing activities totaled $3.0$1.4 billion for the first ninesix months of 20162017 primarily due to payments for renewable acquisitions and the construction of renewablegenerating facilities. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information. Net cash provided from financing activities totaled $3.0 billion$43 million for the first ninesix months of 20162017 primarily due to an increase in senior notes, notes payable and capital contributions from noncontrolling interests, partially offset by dividends to Southern Company.Company and distributions to noncontrolling interests. Cash flows from financing activities may vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first ninesix months of 20162017 include a $515 million increase in CWIP due to the acquisition and continued construction of new solar and wind facilities and a $2.2$1.0 billion increase in plant in service, primarily due to solar and wind facilities being placed in service. Other significant changes include a $261 million increasedecrease in cash and cash equivalents and a $2.5 billion$798 million increase in notes payableproperty, plant, and long-term debtequipment in-service primarily related to acquisitions, as well as a $54 million decrease in CWIP primarily due to additional borrowings to fund acquisitionsEast Pecos and Lamesa being placed in service, partially offset by equipment purchased for wind 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 description of Southern Power's capital requirements for its construction program, scheduled maturities of long-term debt, as well as the related interest, derivative obligations, leases, unrecognized tax benefits, and other purchase
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$909 million will be required to repay maturities of long-term debt through SeptemberJune 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.2018.
Southern Power's construction program includes estimates for potential plant acquisitions, new construction and development, capital improvements, and work to be performed under LTSAs and is subject to periodic review and revision. Planned expenditures for plant acquisitions may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. Capital expenditures for Southern Power are currently estimated to total approximately $4.5 billion for 2016, primarily for acquisitions and/or construction of new generating facilities. Capital expenditures for Southern Power are currently estimated to total approximately $1.6 billion annually for 2017 through 2021. Actual capital costs may vary from these estimates because of numerous factors such as: changes in business conditions; changes in the expected environmental compliance program; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in FERC rules and regulations; changes in load projections; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. See Note (I) to the Condensed Financial Statements herein for additional information.
Sources of Capital
Southern Power plans to obtain the funds required for acquisitions, construction, development, and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, securities issuances, term loans, tax equity partnership contributions, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Power in Item 7 of the Form 10-K for additional information.
As of June 30, 2017, Southern Power's current liabilities sometimes exceedexceeded current assets by $837 million due to long-term debt maturing in the next 12 months, the use of short-term debt as a funding source, and construction payables, as well as fluctuations in cash needs, due to both seasonality and the stage of acquisitions and construction projects. In 2017, Southern Power expects to utilize the debt capital markets, bank term loans, and commercial paper markets as the source of funds for the majority of its debt maturities.
As of SeptemberJune 30, 2016,2017, Southern Power had cash and cash equivalents of approximately $1.1 billion.$99 million.
Southern Power believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility (as defined below), bank term loans, and operating cash flows.
Southern Power's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities, for general corporate purposes, and to finance maturing debt. Commercial paper is included in notes payable on the condensed consolidated balance sheet at June 30, 2017.
Details of short-term borrowingscommercial paper were as follows:
|
| | | | | | | | | | |
| | Short-term Debt During the Period (*) |
| | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | (in millions) | | | | (in millions) |
| Commercial paper | $ | 10 |
| | 0.9 | % | | $ | 62 |
|
|
| | | | | | | | | | | | | | | | |
| | Short-term Debt at June 30, 2017 | | Short-term Debt During the Period (*) |
| | Amount Outstanding | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | (in millions) | | | (in millions) | | | | (in millions) |
| Commercial paper | $ | 398 |
| 1.5 | % | | $ | 328 |
| | 1.3 | % | | $ | 419 |
|
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended SeptemberJune 30, 2016. No short-term debt was outstanding at September 30, 2016.2017. |
Company Credit Facility
At SeptemberJune 30, 2016,2017, Southern Power had a committed credit facility (Facility) of $600$750 million, expiring in 2020, of which $68$75 million has been used for letters of credit and $532$675 million remains unused. In May 2017, Southern Power amended the Facility, which, among other things, extended the maturity date from 2020 to 2022 and increased Southern Power's subsidiaries are not borrowersborrowing ability under the Facility.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Thethis 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.
$750 million from $600 million. Proceeds from the Facility may be used for working capital and general corporate purposes as well as liquidity support for Southern Power's commercial paper program. Subject to applicable market conditions, Southern Power expects to renew or replace the Facility, as
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
needed, prior to expiration. In connection therewith, Southern Power may extend the maturity date and/or increase or decrease the lending commitment thereunder. See Note 6 to the financial statements of Southern Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
The Facility, as well as Southern Power's commercial paper programterm loan agreement, contains a covenant that limits the ratio of debt to capitalization (as defined in the Facility) to a maximum of 65% and contains a cross-default provision that is usedrestricted only to finance acquisitionindebtedness of Southern Power. For purposes of this definition, debt excludes any project debt incurred by certain subsidiaries of Southern Power to the extent such debt is non-recourse to Southern Power, and construction costs relatedcapitalization excludes the capital stock or other equity attributable to electric generating facilities andsuch subsidiary. Southern Power is currently in compliance with all covenants in the Facility.
In December 2016, Southern Power entered into an agreement for general corporate purposes, including maturing debt. a $120 million continuing letter of credit facility for standby letters of credit expiring in 2019. At June 30, 2017, the total amount available under this letter of credit facility was $62 million.
Southern Power's subsidiaries aredo not borrowersborrow under the commercial paper program.
Subsidiary Credit Facilities
In connection withprogram and are not parties to, and do not borrow under, 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 thanFacility or 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 securedcontinuing 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.facility.
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| | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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 SeptemberJune 30, 20162017 were as follows:
| | | Credit Ratings | Maximum Potential
Collateral
Requirements | Maximum Potential
Collateral
Requirements |
| | (in millions) | (in millions) |
| At BBB and/or Baa2 | $ | 30 |
| $ | 38 |
|
| At BBB- and/or Baa3 | $ | 385 |
| $ | 392 |
|
| Below BBB- and/or Baa3 | $ | 1,104 |
| |
At BB+ and/or Ba1(*) | | $ | 1,127 |
|
| |
| (*) | Any additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $38 million. |
Included in these amounts are certain agreements that could require collateral in the event that oneAlabama Power or more power pool participantsGeorgia Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Power to access capital markets and would be likely to impact the cost at which it does so.
In addition, Southern Power has a PPA that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power's credit. The PPA requires credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses resulting from a credit downgrade.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including Southern Power) from stable to negative.
Financing Activities
In June 2016, Southern Power issued €600 million aggregate principal amount of Series 2016A 1.00% Senior Notes due June 20, 2022 and €500 million aggregate principal amount of Series 2016B 1.85% Senior Notes due June 20, 2026. The proceeds are being allocated to renewable energy generation projects. Southern Power's obligations under its euro-denominated fixed-rate notes were effectively converted to fixed-rate U.S. dollars at issuance through cross-currency swaps, removing foreign currency exchange risk associated with the interest and principal payments. See Note (H) to the Condensed Financial Statements under "Foreign Currency Derivatives" herein for additional information.
In September 2016, Southern Power issued $290 million aggregate principal amount of Series 2016C 2.75% Senior Notes due September 20, 2023. The proceeds were used for general corporate purposes, including Southern Power's growth strategy and continuous construction program, as well as repayment of amounts outstanding under the Project Credit Facilities.
Also in September 2016, Southern Power repaid $80 million of an outstanding $400 million floating rate bank loan and extended the maturity date of the remaining $320 million from September 2016 to September 2018. In addition, Southern Power entered into a $60 million aggregate principal amount floating rate bank loan bearing interest based on one-month LIBOR due September 2017. The proceeds were used to repay existing indebtedness and for other general corporate purposes.
In addition, Southern Power issued $34 million in letters of creditdid not issue or redeem any securities during the ninesix months ended SeptemberJune 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 Southern2017.
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.
SOUTHERN COMPANY GAS
156AND SUBSIDIARY COMPANIES
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor | | Successor | | | Predecessor |
| | For the Three Months Ended June 30, | | | For the Three Months Ended June 30, | | For the Six Months Ended June 30, | | | For the Six Months Ended June 30, |
| | 2017 | | | 2016 | | 2017 | | | 2016 |
| | (in millions) | | | (in millions) | | (in millions) | | | (in millions) |
| Operating Revenues: | | | | | | | | | |
Natural gas revenues (includes revenue taxes of
$19, $17, $67, and $57 for the periods presented,
respectively) | $ | 684 |
| | | $ | 539 |
| | $ | 2,214 |
| | | $ | 1,841 |
|
| Other revenues | 32 |
| | | 32 |
| | 62 |
| | | 64 |
|
| Total operating revenues | 716 |
| | | 571 |
| | 2,276 |
| | | 1,905 |
|
| Operating Expenses: | | | | | | | | | |
| Cost of natural gas | 232 |
| | | 184 |
| | 951 |
| | | 755 |
|
| Cost of other sales | 6 |
| | | 7 |
| | 13 |
| | | 14 |
|
| Other operations and maintenance | 213 |
| | | 213 |
| | 467 |
| | | 454 |
|
| Depreciation and amortization | 125 |
| | | 104 |
| | 244 |
| | | 206 |
|
| Taxes other than income taxes | 44 |
| | | 37 |
| | 114 |
| | | 99 |
|
| Merger-related expenses | — |
| | | 53 |
| | — |
| | | 56 |
|
| Total operating expenses | 620 |
| | | 598 |
| | 1,789 |
| | | 1,584 |
|
| Operating Income (Loss) | 96 |
| | | (27 | ) | | 487 |
| | | 321 |
|
| Other Income and (Expense): | | | | | | | | | |
| Earnings from equity method investments | 29 |
| | | 1 |
| | 68 |
| | | 2 |
|
| Interest expense, net of amounts capitalized | (48 | ) | | | (48 | ) | | (94 | ) | | | (96 | ) |
| Other income (expense), net | 3 |
| | | 2 |
| | 7 |
| | | 5 |
|
| Total other income and (expense) | (16 | ) | | | (45 | ) | | (19 | ) | | | (89 | ) |
| Earnings (Loss) Before Income Taxes | 80 |
| | | (72 | ) | | 468 |
| | | 232 |
|
| Income taxes (benefit) | 31 |
| | | (24 | ) | | 180 |
| | | 87 |
|
| Net Income (Loss) | 49 |
| | | (48 | ) | | 288 |
| | | 145 |
|
| Less: Net income attributable to noncontrolling interest | — |
| | | 3 |
| | — |
| | | 14 |
|
| Net Income (Loss) Attributable to Southern Company Gas | $ | 49 |
| | | $ | (51 | ) | | $ | 288 |
| | | $ | 131 |
|
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor | | Successor | | | Predecessor |
| | For the Three Months Ended June 30, | | | For the Three Months Ended June 30, | | For the Six Months Ended June 30, | | | For the Six Months Ended June 30, |
| | 2017 | | | 2016 | | 2017 | | | 2016 |
| | (in millions) | | | (in millions) | | (in millions) | | | (in millions) |
| Net Income (Loss) | $ | 49 |
| | | $ | (48 | ) | | $ | 288 |
| | | $ | 145 |
|
| Other comprehensive income (loss): | | | | | | | | | |
| Qualifying hedges: | | | | | | | | | |
Changes in fair value, net of tax of
$(1), $(7), $(2), and $(23), respectively | (1 | ) | | | (12 | ) | | (2 | ) | | | (41 | ) |
Reclassification adjustment for amounts included in
net income, net of tax of $-, $-, $-, and $-,
respectively | — |
| | | 2 |
| | — |
| | | 1 |
|
| Pension and other postretirement benefit plans: | | | | | | | | | |
Reclassification adjustment for amounts included in
net income, net of tax of $-, $2, $-, and $4,
respectively | — |
| | | 2 |
| | (1 | ) | | | 5 |
|
| Total other comprehensive income (loss) | (1 | ) | | | (8 | ) | | (3 | ) | | | (35 | ) |
| Comprehensive Income (Loss) | 48 |
| | | (56 | ) | | 285 |
| | | 110 |
|
Less: Comprehensive income attributable to
noncontrolling interest | — |
| | | 3 |
| | — |
| | | 14 |
|
Comprehensive Income (Loss) Attributable to
Southern Company Gas | $ | 48 |
| | | $ | (59 | ) | | $ | 285 |
| | | $ | 96 |
|
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
|
| | | | | | | | |
| | Successor | | | Predecessor |
| | For the Six Months Ended June 30, | | | For the Six Months Ended June 30, |
| | 2017 | | | 2016 |
| | (in millions) | | | (in millions) |
| Operating Activities: | | | | |
| Net income | $ | 288 |
| | | $ | 145 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | | |
| Depreciation and amortization, total | 244 |
| | | 206 |
|
| Deferred income taxes | 144 |
| | | 8 |
|
| Stock based compensation expense | 19 |
| | | 20 |
|
| Hedge settlements | — |
| | | (26 | ) |
| Mark-to-market adjustments | (49 | ) | | | 162 |
|
| Other, net | (53 | ) | | | (77 | ) |
| Changes in certain current assets and liabilities — | | | | |
| -Receivables | 420 |
| | | 181 |
|
| -Natural gas for sale, net of temporary LIFO liquidation | 223 |
| | | 273 |
|
| -Prepaid income taxes | 24 |
| | | 151 |
|
| -Other current assets | (12 | ) | | | 37 |
|
| -Accounts payable | (102 | ) | | | 43 |
|
| -Accrued taxes | (8 | ) | | | 41 |
|
| -Accrued compensation | (12 | ) | | | (21 | ) |
| -Other current liabilities | 25 |
| | | (30 | ) |
| Net cash provided from operating activities | 1,151 |
| | | 1,113 |
|
| Investing Activities: | | | | |
| Property additions | (684 | ) | | | (509 | ) |
| Cost of removal, net of salvage | (25 | ) | | | (32 | ) |
| Change in construction payables, net | 23 |
| | | (7 | ) |
| Investment in unconsolidated subsidiaries | (111 | ) | | | (14 | ) |
| Other investing activities | 16 |
| | | 3 |
|
| Net cash used for investing activities | (781 | ) | | | (559 | ) |
| Financing Activities: | | | | |
| Decrease in notes payable, net | (631 | ) | | | (896 | ) |
| Proceeds — | | | | |
| First mortgage bonds | — |
| | | 250 |
|
| Capital contributions from parent company | 57 |
| | | — |
|
| Senior notes | 450 |
| | | 350 |
|
| Redemptions and repurchases — First mortgage bonds | — |
| | | (125 | ) |
| Distributions to noncontrolling interest | — |
| | | (19 | ) |
| Payment of common stock dividends | (221 | ) | | | (128 | ) |
| Other financing activities | (6 | ) | | | 10 |
|
| Net cash used for financing activities | (351 | ) | | | (558 | ) |
| Net Change in Cash and Cash Equivalents | 19 |
| | | (4 | ) |
| Cash and Cash Equivalents at Beginning of Period | 19 |
| | | 19 |
|
| Cash and Cash Equivalents at End of Period | $ | 38 |
| | | $ | 15 |
|
| Supplemental Cash Flow Information: | | | | |
| Cash paid (received) during the period for — | | | | |
| Interest (net of $7 and $3 capitalized for 2017 and 2016, respectively) | $ | 105 |
| | | $ | 119 |
|
| Income taxes, net | 20 |
| | | (100 | ) |
| Noncash transactions — Accrued property additions at end of period | 84 |
| | | 41 |
|
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At June 30, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 38 |
| | $ | 19 |
|
| Receivables — | | | | |
| Energy marketing receivables | | 482 |
| | 623 |
|
| Customer accounts receivable | | 270 |
| | 364 |
|
| Unbilled revenues | | 69 |
| | 239 |
|
| Other accounts and notes receivable | | 63 |
| | 76 |
|
| Accumulated provision for uncollectible accounts | | (35 | ) | | (27 | ) |
| Materials and supplies | | 24 |
| | 26 |
|
| Natural gas for sale | | 477 |
| | 631 |
|
| Prepaid expenses | | 69 |
| | 80 |
|
| Assets from risk management activities, net of collateral | | 114 |
| | 128 |
|
| Other regulatory assets, current | | 72 |
| | 81 |
|
| Other current assets | | 20 |
| | 10 |
|
| Total current assets | | 1,663 |
| | 2,250 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 14,850 |
| | 14,508 |
|
| Less: Accumulated depreciation | | 4,550 |
| | 4,439 |
|
| Plant in service, net of depreciation | | 10,300 |
| | 10,069 |
|
| Construction work in progress | | 779 |
| | 496 |
|
| Total property, plant, and equipment | | 11,079 |
| | 10,565 |
|
| Other Property and Investments: | | | | |
| Goodwill | | 5,967 |
| | 5,967 |
|
| Equity investments in unconsolidated subsidiaries | | 1,610 |
| | 1,541 |
|
Other intangible assets, net of amortization of $80 and $34
at June 30, 2017 and December 31, 2016, respectively | | 320 |
| | 366 |
|
| Miscellaneous property and investments | | 21 |
| | 21 |
|
| Total other property and investments | | 7,918 |
| | 7,895 |
|
| Deferred Charges and Other Assets: | | | | |
| Other regulatory assets, deferred | | 963 |
| | 973 |
|
| Other deferred charges and assets | | 186 |
| | 170 |
|
| Total deferred charges and other assets | | 1,149 |
| | 1,143 |
|
| Total Assets | | $ | 21,809 |
| | $ | 21,853 |
|
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholder's Equity | | At June 30, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 22 |
| | $ | 22 |
|
| Notes payable | | 626 |
| | 1,257 |
|
| Energy marketing trade payables | | 534 |
| | 597 |
|
| Accounts payable | | 327 |
| | 348 |
|
| Customer deposits | | 134 |
| | 153 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 23 |
| | 26 |
|
| Other accrued taxes | | 63 |
| | 68 |
|
| Accrued interest | | 50 |
| | 48 |
|
| Accrued compensation | | 45 |
| | 58 |
|
| Liabilities from risk management activities, net of collateral | | 20 |
| | 62 |
|
| Other regulatory liabilities, current | | 146 |
| | 102 |
|
| Accrued environmental remediation, current | | 63 |
| | 69 |
|
| Temporary LIFO liquidation | | 69 |
| | — |
|
| Other current liabilities | | 113 |
| | 108 |
|
| Total current liabilities | | 2,235 |
| | 2,918 |
|
| Long-term Debt | | 5,677 |
| | 5,259 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 2,091 |
| | 1,975 |
|
| Employee benefit obligations | | 432 |
| | 441 |
|
| Other cost of removal obligations | | 1,638 |
| | 1,616 |
|
| Accrued environmental remediation, deferred | | 353 |
| | 357 |
|
| Other regulatory liabilities, deferred | | 50 |
| | 51 |
|
| Other deferred credits and liabilities | | 91 |
| | 127 |
|
| Total deferred credits and other liabilities | | 4,655 |
| | 4,567 |
|
| Total Liabilities | | 12,567 |
| | 12,744 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, par value $0.01 per share — | | | | |
| Authorized — 100 million shares | | | | |
| Outstanding — 100 shares | | — |
| | — |
|
| Paid in capital | | 9,164 |
| | 9,095 |
|
| Retained earnings (accumulated deficit) | | 55 |
| | (12 | ) |
| Accumulated other comprehensive income | | 23 |
| | 26 |
|
| Total common stockholder's equity | | 9,242 |
| | 9,109 |
|
| Total Liabilities and Stockholder's Equity | | $ | 21,809 |
| | $ | 21,853 |
|
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through utilities in seven states – Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee, and Maryland. Southern Company Gas and its subsidiaries are also involved in several other complementary businesses.
Southern Company Gas has four reportable segments – gas distribution operations, gas marketing services, wholesale gas services, and gas midstream operations – and one non-reportable segment – all other. For additional information on these segments, see Note (K) to the Condensed Financial Statements herein and "BUSINESS – Southern Company Gas" in Item 1 of the Form 10-K.
Many factors affect the opportunities, challenges, and risks of Southern Company Gas' business. These factors include the ability to maintain constructive regulatory environments, to maintain and grow natural gas sales, and to effectively manage and secure timely recovery of costs. Southern Company Gas has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Southern Company Gas for the foreseeable future.
Merger and Acquisition Activities
On July 1, 2016, Southern Company Gas completed the Merger, which was accounted for by Southern Company using the acquisition method of accounting whereby the assets acquired and liabilities assumed were recognized at fair value as of the acquisition date. Pushdown accounting was applied to create a new cost basis for Southern Company Gas assets, liabilities, and equity as of the acquisition date. Accordingly, the successor financial statements reflect a new basis of accounting and successor and predecessor period financial results (separated by a heavy black line) are presented, but are not comparable. As a result of the application of acquisition accounting, certain discussions herein include disclosure of the predecessor and successor periods. See Note (I) to the Condensed Financial Statements herein for additional information relating to the Merger.
In September 2016, Southern Company Gas paid approximately $1.4 billion to acquire a 50% equity interest in SNG. On March 31, 2017, Southern Company Gas made an additional $50 million contribution to maintain its 50% equity interest in SNG. Southern Company Gas recorded equity investment income of $24 million and $58 million from this investment in the second quarter and year-to-date 2017, respectively. See Note (J) to the Condensed Financial Statements herein and Notes 4 and 11 to the financial statements of Southern Company Gas under "Equity Method Investments – SNG" and "Investment in SNG," respectively, in Item 8 of the Form 10-K for additional information.
In October 2016, Southern Company Gas completed its purchase of Piedmont's 15% interest in SouthStar, which eliminated the noncontrolling interest associated with SouthStar. See Note 4 to the financial statements of Southern Company Gas under "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.
Operating Metrics
Southern Company Gas continues to focus on several operating metrics, including Heating Degree Days, customer count, and volumes of natural gas sold. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – "Operating Metrics" of Southern Company Gas in Item 7 of the Form 10-K.
Southern Company Gas measures weather and the effect on its business using Heating Degree Days. Generally, increased Heating Degree Days result in higher demand for natural gas on Southern Company Gas' distribution system. With the exception of Southern Company Gas' utilities in Illinois and Florida, Southern Company Gas has various regulatory mechanisms, such as weather normalization mechanisms, which limit its exposure to weather changes within typical ranges in each of its utilities' respective service territory. However, the utility customers in Illinois and the gas marketing services customers primarily in Georgia can be impacted by warmer- or colder-than-normal weather. Southern Company Gas utilizes weather hedges at gas distribution operations and gas marketing services to reduce negative earnings impact in the event of warmer-than-normal weather, while retaining all of the
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
earnings upside in the event of colder-than-normal weather for gas distribution operations in Illinois and most of the earnings upside for gas marketing services.
The number of customers at gas distribution operations and energy customers at gas marketing services can be impacted by natural gas prices, economic conditions, and competition from alternative fuels. Gas marketing services' customers are primarily located in Georgia and Illinois.
Southern Company Gas' natural gas volume metrics for gas distribution operations and gas marketing services illustrate the effects of weather and customer demand for natural gas. Wholesale gas services' physical sales volumes represent the daily average natural gas volumes sold to its customers.
Seasonality of Results
During the months of November through March, natural gas usage and operating revenues are generally higher, as more customers are connected to the gas distribution systems and natural gas usage is higher in periods of colder weather. Occasionally in the summer, wholesale gas services' operating revenues are impacted due to peak usage by power generators in response to summer energy demands. Southern Company Gas' base operating expenses, excluding cost of natural gas, bad debt expense, and certain incentive compensation costs, are incurred relatively evenly during a year. Seasonality also affects the comparison of certain balance sheet items across quarters, including receivables, unbilled revenues, natural gas for sale, and notes payable. However, these items are comparable when reviewing Southern Company Gas' annual results. Operating results for the interim periods presented are not necessarily indicative of annual results and can vary significantly from quarter to quarter.
RESULTS OF OPERATIONS
Net Income
Net income attributable to Southern Company Gas for the successor second quarter 2017 and net loss attributable to Southern Company Gas for the predecessor second quarter 2016 were $49 million and $51 million, respectively. Net income attributable to Southern Company Gas for the successor year-to-date 2017 and the predecessor year-to-date 2016 was $288 million and $131 million, respectively.
As a result of purchasing the remaining interest in SouthStar in October 2016, all net income was attributable to Southern Company Gas in the successor period. Net income for the successor second quarter 2017 was negatively impacted by $5 million due to the pushdown of acquisition accounting related to the Merger and included $10 million in after-tax earnings from the SNG investment, net of related interest expense. Also reflected in net income was an increase of $12 million, after tax, from additional infrastructure replacement programs at gas distribution operations, net of increased depreciation and a base rate increase at Atlanta Gas Light effective March 1, 2017. The successor second quarter 2017 also included $11 million in after-tax losses from commercial activity and $8 million in after-tax mark-to-market gains at wholesale gas services.
Net loss attributable to Southern Company Gas for the predecessor second quarter 2016 included $39 million in after-tax Merger-related expenses, as well as $5 million in after-tax losses from commercial activity at wholesale gas services and $50 million in net after-tax mark-to-market losses at wholesale gas services and gas marketing services due to changes in natural gas price volatility in the period.
Net income attributable to Southern Company Gas for the successor year-to-date 2017 was negatively impacted by $2 million due to the pushdown of acquisition accounting related to the Merger and included $25 million in after-tax earnings from the SNG investment, net of related interest expense. The successor year-to-date 2017 included an increase of $19 million, after tax, from additional infrastructure replacement programs at gas distribution operations, net of increased depreciation and a base rate increase at Atlanta Gas Light effective March 1, 2017. The successor year-to-date 2017 also included $41 million in after-tax gains from commercial activity at wholesale gas services, $27 million in net after-tax mark-to-market gains at wholesale gas services and gas marketing services, and a reduction of $9 million, after tax, resulting from warmer-than-normal weather, net of hedging.
Net income attributable to Southern Company Gas for the predecessor year-to-date 2016 included $41 million in after-tax Merger-related expenses and $21 million in after-tax mark-to-market gains from commercial activity at
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
wholesale gas services. Also reflected in net income was $38 million in net after-tax mark-to-market losses at wholesale gas services and gas marketing services and a decrease of $5 million, after tax, resulting from warmer-than-normal weather, net of hedging.
Natural Gas Revenues
Natural gas revenues for the successor second quarter 2017 and the predecessor second quarter 2016 were $684 million and $539 million, respectively. Natural gas revenues for the successor year-to-date 2017 and the predecessor year-to-date 2016 were $2.2 billion and $1.8 billion, respectively.
Natural gas revenues for the successor second quarter 2017 included recovery of $232 million in cost of natural gas and $12 million in net losses from wholesale gas services. Also included in natural gas revenues were $26 million in additional revenues generated from gas distribution operations as a result of continued investment in infrastructure replacement programs and a $2 million decrease attributable to warmer-than-normal weather, net of hedging.
Natural gas revenues for the predecessor second quarter 2016 reflected recovery of $184 million in cost of natural gas and $95 million in net losses from wholesale gas services, primarily due to mark-to-market losses on storage, transportation, and forward commodity derivatives.
Natural gas revenues for the successor year-to-date 2017 included recovery of $951 million in cost of natural gas and $119 million in net revenues from wholesale gas services. Also included in natural gas revenues was $45 million in additional revenues generated from gas distribution operations as a result of continued investment in infrastructure replacement programs and a $15 million decrease attributable to warmer-than-normal weather, net of hedging.
Natural gas revenues for the predecessor year-to-date 2016 reflected recovery of $755 million in cost of natural gas and $32 million in net losses from wholesale gas services. Also included in natural gas revenues was a $7 million decrease attributable to warmer-than-normal weather, net of hedging.
See "Segment Information" herein for additional information on wholesale gas services' revenues and losses.
Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, recoverable natural gas revenues generally equal the cost of natural gas and do not affect net income from gas distribution operations. See "Cost of Natural Gas" herein for additional information. Revenue impacts from weather and customer growth are described further below.
Heating Season is the period from November through March when natural gas usage and operating revenues are generally higher. Weather typically does not have a significant net income impact during the non-Heating Season. The following table presents the Heating Degree Days information for Illinois and Georgia, the primary locations where Southern Company Gas' operations are impacted by weather.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Second Quarter | | 2017
vs.
2016 | | 2017
vs.
normal | | Year-to-Date | | 2017
vs.
2016 | | 2017
vs.
normal |
| | | Normal(a) | | 2017 | | 2016 | | (warmer) | | (warmer) | | Normal(a) | | 2017 | | 2016 | | (warmer) | | (warmer) |
Illinois(b) | | 639 |
| | 555 |
| | 639 |
| | (13 | )% | | (13 | )% | | 3,760 |
| | 3,110 |
| | 3,340 |
| | (7 | )% | | (17 | )% |
| Georgia | | 137 |
| | 75 |
| | 114 |
| | (34 | )% | | (45 | )% | | 1,636 |
| | 1,000 |
| | 1,448 |
| | (31 | )% | | (39 | )% |
| |
| (a) | Normal represents the 10-year average from January 1, 2007 through June 30, 2016 for Illinois at Chicago Midway International Airport and for Georgia at Atlanta Hartsfield-Jackson International Airport, based on information obtained from the National Oceanic and Atmospheric Administration, National Climatic Data Center. |
| |
| (b) | The 10-year average Heating Degree Days established by the Illinois Commission in Nicor Gas' 2009 rate case is 617 for the second quarter and 3,519 for the first six months from 1998 through 2007. |
For the successor second quarter 2017 and the predecessor second quarter 2016, the weather-related negative pre-tax income impact was limited to $2 million in each period.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Company Gas hedged its exposure to warmer-than-normal weather at Nicor Gas in Illinois; therefore, the weather-related negative pre-tax income impact on gas distribution operations was limited to $5 million ($3 million after tax) and $7 million ($5 million after tax) for the successor year-to-date 2017 and the predecessor year-to-date 2016, respectively. Southern Company Gas also hedged its exposure at gas marketing services to warmer-than-normal weather in Georgia; therefore, the weather-related negative pre-tax income impact on gas marketing services was limited to $10 million ($6 million after tax) for the successor year-to-date 2017 and there was no impact for the predecessor year-to-date 2016.
The following table provides the number of customers served by Southern Company Gas at June 30, 2017 and 2016:
|
| | | | | | | | |
| | June 30, | | |
| | 2017 | | 2016 | | 2017 vs. 2016 |
| | (in thousands, except market share %) | | (% change) |
| Gas distribution operations | 4,573 |
| | 4,544 |
| | 0.6 | % |
| Gas marketing services | | | | | |
Energy customers(*) | 768 |
| | 630 |
| | 21.9 | % |
| Market share of energy customers in Georgia | 29.1 | % | | 29.3 | % | | |
| Service contracts | 1,188 |
| | 1,197 |
| | (0.8 | )% |
| |
| (*) | Includes approximately 140,000 customers as of June 30, 2017 that were contracted to serve beginning April 1, 2017. |
Southern Company Gas anticipates overall customer growth trends at gas distribution operations to continue in 2017, as it expects continued improvement in the new housing market and low natural gas prices.
Gas marketing services' market share in Georgia decreased slightly at June 30, 2017 compared to June 30, 2016 as a result of a highly competitive marketing environment, which Southern Company Gas expects to continue for the foreseeable future. Southern Company Gas will continue efforts at gas marketing services to enter into targeted markets and expand its energy customers and service contracts.
Cost of Natural Gas
Cost of natural gas was $232 million for the successor second quarter 2017 and $184 million for the predecessor second quarter 2016, which primarily reflected an increase of 63% in natural gas prices during the successor second quarter 2017 compared to the corresponding period in 2016, partially offset by lower demand for natural gas driven by warmer-than-normal weather.
Cost of natural gas was $951 million for the successor year-to-date 2017 and $755 million for the predecessor year-to-date 2016, which primarily reflected an increase of 61% in natural gas prices during the successor year-to-date 2017 compared to the corresponding period in 2016, partially offset by lower demand for natural gas driven by warmer-than-normal weather.
Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, recoverable natural gas revenues generally equal the cost of natural gas and do not affect net income from gas distribution operations. For additional information, see MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – "Cost of Natural Gas" of Southern Company Gas in Item 7 of the Form 10-K and "Natural Gas Revenues" herein.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following table details the volumes of natural gas sold during all periods presented.
|
| | | | | | | | | | | | | | | | | |
| | Second Quarter | | 2017
vs.
2016 | | Year-to-Date | | 2017
vs.
2016 |
| | 2017 | | 2016 | | % Change | | 2017 | | 2016 | | % Change |
Gas distribution operations
(mmBtu in millions) | | | | | | | | | | | |
| Firm | 102 |
| | 107 |
| | (4.7 | )% | | 365 |
| | 396 |
| | (7.8 | )% |
| Interruptible | 23 |
| | 22 |
| | 4.5 | % | | 48 |
| | 49 |
| | (2.0 | )% |
| Total | 125 |
| | 129 |
| | (3.1 | )% | | 413 |
| | 445 |
| | (7.2 | )% |
Gas marketing services
(mmBtu in millions) | | | | | | | | | | | |
| Firm: | | | | | | | | | | | |
| Georgia | 4 |
| | 4 |
| | — | % | | 17 |
| | 21 |
| | (19.0 | )% |
| Illinois | 2 |
| | 2 |
| | — | % | | 7 |
| | 8 |
| | (12.5 | )% |
| Other emerging markets | 3 |
| | 2 |
| | 50.0 | % | | 8 |
| | 7 |
| | 14.3 | % |
| Interruptible: | | | | | | | | | | | |
| Large commercial and industrial | 3 |
| | 4 |
| | (25.0 | )% | | 7 |
| | 8 |
| | (12.5 | )% |
| Total | 12 |
| | 12 |
| | — | % | | 39 |
| | 44 |
| | (11.4 | )% |
Wholesale gas services
(mmBtu in millions/day) | | | | | | | | | | | |
| Daily physical sales | 6.2 |
| | 7.2 |
| | (13.9 | )% | | 6.4 |
| | 7.6 |
| | (15.8 | )% |
Other Operations and Maintenance Expenses
Other operations and maintenance expenses were $213 million for both the successor second quarter 2017 and the predecessor second quarter 2016.
Other operations and maintenance expenses were $467 million for the successor year-to-date 2017 and $454 million for the predecessor year-to-date 2016. Other operations and maintenance expense for the successor year-to-date period reflected increased compensation expenses and pipeline and maintenance expenses, partially offset by low bad debt expense.
Depreciation and Amortization
Depreciation and amortization was $125 million for the successor second quarter 2017 and $104 million for the predecessor second quarter 2016. The successor second quarter 2017 included $9 million of additional net amortization of intangible assets as a result of fair value adjustments in acquisition accounting at gas midstream operations and gas distribution operations, as well as $7 million in additional depreciation at gas distribution operations due to a $1.1 billion increase in gross property, plant, and equipment since June 30, 2016.
Depreciation and amortization was $244 million for the successor year-to-date 2017 and $206 million for the predecessor year-to-date 2016. The successor year-to-date 2017 included $19 million of additional net amortization of intangible assets as a result of fair value adjustments in acquisition accounting at gas midstream operations and gas distribution operations, as well as $13 million in additional depreciation at gas distribution operations due to additional assets placed in service.
Taxes Other Than Income Taxes
For the successor second quarter 2017 and the predecessor second quarter 2016, taxes other than income taxes were $44 million and $37 million, respectively. For the successor year-to-date 2017 and the predecessor year-to-date
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
2016, taxes other than income taxes were $114 million and $99 million, respectively. Taxes other than income taxes consist primarily of revenue tax expenses, property taxes, and payroll taxes. Taxes other than income taxes in the successor periods reflected increased revenue-based taxes due to higher revenues at gas distribution operations.
Earnings from Equity Method Investments
For the successor second quarter 2017, earnings from equity method investments were $29 million, which consisted of $24 million in earnings from SNG and $5 million in earnings from all other investments. For the predecessor second quarter 2016, earnings from equity method investments were not material.
For the successor year-to-date 2017, earnings from equity method investments were $68 million, which consisted of $58 million in earnings from SNG and $10 million in earnings from all other investments. For the predecessor year-to-date 2016, earnings from equity method investments were not material.
See Notes 4 and 11 to the financial statements of Southern Company Gas under "Equity Method Investments – SNG" and "Investment in SNG," respectively, in Item 8 of the Form 10-K and Note (J) to the Condensed Financial Statements under "Southern Company Gas – Equity Method Investments" herein for additional information.
Interest Expense, Net of Amounts Capitalized
For both the successor second quarter 2017 and the predecessor second quarter 2016, interest expense, net of amounts capitalized was $48 million. The successor second quarter 2017 reflects a $10 million reduction resulting from the fair value adjustment of long-term debt in acquisition accounting, partially offset by $6 million of additional interest expense on new debt issuances in 2017 and 2016.
For the successor year-to-date 2017 and the predecessor year-to-date 2016, interest expense, net of amounts capitalized was $94 million and $96 million, respectively. The successor year-to-date 2017 reflects a $19 million reduction resulting from the fair value adjustment of long-term debt in acquisition accounting, partially offset by $12 million of additional interest expense on new debt issuances in 2017 and 2016.
Income Taxes (Benefit)
For the successor second quarter 2017 and the predecessor second quarter 2016, income taxes (benefit) were $31 million and $(24) million, respectively, driven by pre-tax earnings.
For the successor year-to-date 2017 and the predecessor year-to-date 2016, income taxes were $180 million and $87 million, respectively, driven by pre-tax earnings and the non-deductibility of certain Merger-related expenses.
Performance and Non-GAAP Measures
Prior to the Merger, Southern Company Gas evaluated segment performance using earnings before interest and taxes (EBIT), which includes operating income, earnings from equity method investments, and other income (expense), net. EBIT excludes interest expense, net of amounts capitalized and income taxes (benefit), which were evaluated on a consolidated basis for those periods. EBIT is used herein to discuss the results of Southern Company Gas' segments for the predecessor period, as EBIT was the primary measure of segment profit or loss for that period. Subsequent to the Merger, Southern Company Gas changed its segment performance measure from EBIT to net income to better align with the performance measure utilized by Southern Company. EBIT for the successor second quarter and year-to-date 2017 presented herein is considered a non-GAAP measure. Southern Company Gas also discusses consolidated EBIT, which is considered a non-GAAP measure for all periods presented. The presentation of consolidated EBIT is believed to provide useful supplemental information regarding a consolidated measure of profit or loss. Southern Company Gas further believes that the presentation of segment EBIT for the successor second quarter and year-to-date 2017 is useful as it allows for a measure of comparability to the other companies with different capital and legal structures, which accordingly may be subject to different interest rates and effective tax rates. The applicable reconciliations of net income to consolidated EBIT and segment EBIT are provided herein.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Adjusted operating margin is a non-GAAP measure that is calculated as operating revenues minus cost of natural gas, cost of other sales, and revenue tax expense. Adjusted operating margin excludes other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, and Merger-related expenses, which are included in the calculation of operating income as calculated in accordance with GAAP and reflected in the consolidated statements of income. The presentation of adjusted operating margin is believed to provide useful information regarding the contribution resulting from customer growth at gas distribution operations since the cost of natural gas and revenue tax expense can vary significantly and are generally billed directly to customers. Southern Company Gas further believes that utilizing adjusted operating margin at gas marketing services, wholesale gas services, and gas midstream operations allows it to focus on a direct measure of adjusted operating margin before overhead costs. The applicable reconciliation of operating income to adjusted operating margin is provided herein.
EBIT and adjusted operating margin should not be considered alternatives to, or more meaningful indicators of, Southern Company Gas' operating performance than consolidated net income attributable to Southern Company Gas or operating income as determined in accordance with GAAP. In addition, Southern Company Gas' adjusted operating margin may not be comparable to similarly titled measures of other companies.
|
| | | | | | | | | | | | | | | | | |
| | Successor |
|
| Predecessor | | Successor | | | Predecessor |
| | Second Quarter 2017 | | | Second Quarter 2016 | | Year-to-Date 2017 | | | Year-to-Date 2016 |
| | (in millions) |
|
| (in millions) | | (in millions) | | | (in millions) |
| Operating Income | $ | 96 |
| | | $ | (27 | ) | | $ | 487 |
| | | $ | 321 |
|
Other operating expenses(a) | 382 |
| | | 407 |
| | 825 |
| | | 815 |
|
Revenue taxes(b) | (18 | ) | | | (17 | ) | | (65 | ) | | | (56 | ) |
| Adjusted Operating Margin | $ | 460 |
| | | $ | 363 |
| | $ | 1,247 |
| | | $ | 1,080 |
|
| |
| (a) | Includes other operations and maintenance, depreciation and amortization, taxes other than income taxes, and Merger-related expenses. |
| |
| (b) | Nicor Gas' revenue tax expenses, which are passed through directly to customers. |
|
| | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor | | Successor | | | Predecessor |
| | Second Quarter 2017 | | | Second Quarter 2016 | | Year-to-Date 2017 | | | Year-to-Date 2016 |
| | (in millions) | | | (in millions) | | (in millions) | | | (in millions) |
| Consolidated Net Income (Loss) Attributable to Southern Company Gas | $ | 49 |
| | | $ | (51 | ) | | $ | 288 |
| | | $ | 131 |
|
Net income attributable to noncontrolling interest (*) | — |
| | | 3 |
| | — |
| | | 14 |
|
| Income taxes | 31 |
| | | (24 | ) | | 180 |
| | | 87 |
|
| Interest expense, net of amounts capitalized | 48 |
| | | 48 |
| | 94 |
| | | 96 |
|
| EBIT | $ | 128 |
| | | $ | (24 | ) | | $ | 562 |
| | | $ | 328 |
|
| |
| (*) | See Note 4 to the financial statements of Southern Company Gas under "Variable Interest Entities" in Item 8 of the Form 10-K for additional information. |
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Segment Information
Adjusted operating margin, operating expenses, and Southern Company Gas' primary performance metric for each segment is illustrated in the tables below. See Note (K) to the Condensed Financial Statements herein for additional information.
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| Successor |
|
| Predecessor |
| | Second Quarter 2017 |
|
| Second Quarter 2016 |
| Adjusted Operating |
| Operating |
| Net |
|
| Adjusted Operating |
| Operating |
|
|
| Margin(*) |
| Expenses(*) |
| Income |
|
| Margin(*) |
| Expenses(*) |
| EBIT |
| (in millions) |
|
| (in millions) |
| Gas distribution operations | $ | 409 |
|
| $ | 283 |
|
| $ | 54 |
|
|
| $ | 386 |
|
| $ | 269 |
|
| $ | 118 |
|
| Gas marketing services | 57 |
|
| 48 |
|
| 4 |
|
|
| 66 |
|
| 37 |
|
| 29 |
|
| Wholesale gas services | (13 | ) |
| 14 |
|
| (17 | ) |
|
| (96 | ) |
| 16 |
|
| (112 | ) |
| Gas midstream operations | 7 |
|
| 13 |
|
| 9 |
|
|
| 6 |
|
| 12 |
|
| (5 | ) |
| All other | 3 |
|
| 9 |
|
| (1 | ) |
|
| 2 |
|
| 58 |
|
| (55 | ) |
| Intercompany eliminations | (3 | ) |
| (3 | ) |
| — |
|
|
| (1 | ) |
| (2 | ) |
| 1 |
|
| Consolidated | $ | 460 |
|
| $ | 364 |
|
| $ | 49 |
|
|
| $ | 363 |
|
| $ | 390 |
|
| $ | (24 | ) |
| |
| (*) | Operating margin and operating expenses are adjusted for Nicor Gas' revenue tax expenses, which are passed through directly to customers. |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Year-to-Date 2017 | | | Year-to-Date 2016 |
| | Adjusted Operating | | Operating | | Net | | | Adjusted Operating | | Operating | | |
| | Margin(*) | | Expenses(*) | | Income | | | Margin(*) | | Expenses(*) | | EBIT |
| | (in millions) | | | (in millions) |
| Gas distribution operations | $ | 951 |
| | $ | 596 |
| | $ | 171 |
| | | $ | 911 |
| | $ | 560 |
| | $ | 353 |
|
| Gas marketing services | 162 |
| | 101 |
| | 35 |
| | | 190 |
| | 81 |
| | 109 |
|
| Wholesale gas services | 118 |
| | 29 |
| | 51 |
| | | (36 | ) | | 33 |
| | (68 | ) |
| Gas midstream operations | 16 |
| | 25 |
| | 25 |
| | | 15 |
| | 24 |
| | (6 | ) |
| All other | 5 |
| | 14 |
| | 6 |
| | | 4 |
| | 65 |
| | (60 | ) |
| Intercompany eliminations | (5 | ) | | (5 | ) | | — |
| | | (4 | ) | | (4 | ) | | — |
|
| Consolidated | $ | 1,247 |
| | $ | 760 |
| | $ | 288 |
| | | $ | 1,080 |
| | $ | 759 |
| | $ | 328 |
|
| |
| (*) | Operating margin and operating expenses are adjusted for Nicor Gas' revenue tax expenses, which are passed through directly to customers. |
Gas Distribution Operations
Gas distribution operations is the largest component of Southern Company Gas' business and is subject to regulation and oversight by agencies in each of the states it serves. With the exception of Atlanta Gas Light, Southern Company Gas' second largest utility that operates in a deregulated natural gas market and has a straight-fixed-variable rate design that minimizes the variability of its revenues based on consumption, the earnings of the natural gas distribution utilities can be affected by customer consumption patterns that are a function of weather conditions, price levels for natural gas, and general economic conditions that may impact customers' ability to pay for natural gas consumed. Southern Company Gas has various weather mechanisms, such as weather normalization mechanisms and weather derivative instruments, that limit its exposure to weather changes within typical ranges in its natural gas utilities' service territories.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Successor Second Quarter 2017
Net income of $54 million includes $409 million in adjusted operating margin, $283 million in operating expenses, and $2 million in other income (expense), net, which resulted in EBIT of $128 million. Net income also includes $40 million in interest expense and $34 million in income tax expense. Adjusted operating margin reflects $26 million in additional revenue from the continued investment in infrastructure replacement programs, a base rate increase at Atlanta Gas Light effective March 1, 2017, and a $1 million positive impact of weather, net of hedging, despite warmer-than-normal weather. Operating expenses reflect additional depreciation due to continued investment in infrastructure programs and increased pipeline compliance and maintenance activities.
Predecessor Second Quarter 2016
EBIT of $118 million includes $386 million in adjusted operating margin, $269 million in operating expenses, and $1 million in other income (expense), net. Adjusted operating margin reflects revenue from continued investment in infrastructure replacement programs and increased usage and customer growth, partially offset by a $1 million negative impact of warmer-than-normal weather, net of hedging. Operating expenses reflect depreciation associated with additional assets placed in service.
Successor Year-to-Date 2017
Net income of $171 million includes $951 million in adjusted operating margin, $596 million in operating expenses, and $6 million in other income (expense), net, which resulted in EBIT of $361 million. Net income also includes $80 million in interest expense and $110 million in income tax expense. Adjusted operating margin reflects $45 million in additional revenue from continued investment in infrastructure replacement programs and a base rate increase at Atlanta Gas Light effective March 1, 2017. Also included in adjusted operating margin was increased customer growth, partially offset by a $5 million negative impact of warmer-than-normal weather, net of hedging. Operating expenses reflect a $13 million increase in depreciation associated with additional assets placed in service, as well as increased compensation expense, legal expenses, and pipeline compliance and maintenance activities.
Predecessor Year-to-Date 2016
EBIT of $353 million includes $911 million in adjusted operating margin, $560 million in operating expenses, and $2 million in other income (expense), net. Adjusted operating margin reflects revenue from continued investment in infrastructure replacement programs and increased usage and customer growth, partially offset by a $7 million negative impact of warmer-than-normal weather, net of hedging. Operating expenses reflect depreciation associated with additional assets placed in service.
Gas Marketing Services
Gas marketing services consists of several businesses that provide energy-related products and services to natural gas markets, including warranty sales. Gas marketing services is weather sensitive and uses a variety of hedging strategies, such as weather derivative instruments and other risk management tools, to partially mitigate potential weather impacts. Operating expenses primarily reflect employee costs, marketing, and bad debt expenses.
Successor Second Quarter 2017
Net income of $4 million includes $57 million in adjusted operating margin and $48 million in operating expenses, which resulted in EBIT of $9 million. Net income also includes $2 million in interest expense and $3 million in income tax expense. Adjusted operating margin reflects a $3 million negative impact of warmer-than-normal weather, net of hedging. Operating expenses reflect $10 million in additional amortization of intangible assets due to fair value adjustments to certain assets and liabilities in the application of acquisition accounting.
Predecessor Second Quarter 2016
EBIT of $29 million includes $66 million in adjusted operating margin and $37 million in operating expenses. Adjusted operating margin reflects $7 million in unrealized hedge gains and a $1 million negative impact of
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
weather, net of hedging. Earnings in the predecessor period include $3 million attributable to noncontrolling interest.
Successor Year-to-Date 2017
Net income of $35 million includes $162 million in adjusted operating margin and $101 million in operating expenses, which resulted in EBIT of $61 million. Net income also includes $3 million in interest expense and $23 million in income tax expense. Adjusted operating margin reflects $2 million of additional revenue as a result of fair value adjustments to certain assets and liabilities in the application of acquisition accounting, as well as a $10 million negative impact of warmer-than-normal weather, net of hedging and $7 million in unrealized hedge losses. Operating expenses also reflect $20 million in additional amortization of intangible assets due to fair value adjustments to certain assets and liabilities in the application of acquisition accounting.
Predecessor Year-to-Date 2016
EBIT of $109 million includes $190 million in adjusted operating margin and $81 million in operating expenses. Adjusted operating margin reflects $9 million in unrealized hedge gains. Earnings in the predecessor period include $14 million attributable to noncontrolling interest.
Wholesale Gas Services
Wholesale gas services is involved in asset management and optimization, storage, transportation, producer and peaking services, natural gas supply, natural gas services, and wholesale gas marketing. Southern Company Gas has positioned the business to generate positive economic earnings on an annual basis even under low volatility market conditions that can result from a number of factors. When market price volatility increases, wholesale gas services is well positioned to capture significant value and generate stronger results. Operating expenses primarily reflect employee compensation and benefits.
Successor Second Quarter 2017
Net loss of $17 million includes $(13) million in adjusted operating margin and $14 million in operating expenses, which resulted in a loss before interest and taxes of $27 million. Also included in net loss is $1 million in interest expense and $11 million in income tax benefit.
Predecessor Second Quarter 2016
Loss before interest and taxes of $112 million includes $(96) million in adjusted operating margin and $16 million in operating expenses.
Successor Year-to-Date 2017
Net income of $51 million includes $118 million in adjusted operating margin and $29 million in operating expenses, which resulted in EBIT of $89 million. Net income also includes $3 million in interest expense and $35 million in income tax expense.
Predecessor Year-to-Date 2016
Loss before interest and taxes of $68 million includes $(36) million in adjusted operating margin, $33 million in operating expenses, and $1 million in other income (expense), net.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following table illustrates the components of wholesale gas services' adjusted operating margin for the periods presented.
|
| | | | | | | | | | | | | | | | | | |
| | Successor |
|
| Predecessor | | | Successor | | | Predecessor |
| | Second Quarter 2017 | | | Second Quarter 2016 | | | Year-to-Date 2017 | | | Year-to-Date 2016 |
| | (in millions) |
|
| (in millions) | | | (in millions) | | | (in millions) |
| Commercial activity recognized | $ | (18 | ) | | | $ | (8 | ) | | | $ | 69 |
| | | $ | 34 |
|
| Gain (loss) on storage derivatives | 17 |
| | | (36 | ) | | | 18 |
| | | (38 | ) |
| Gain (loss) on transportation and forward commodity derivatives | (2 | ) | | | (52 | ) | | | 37 |
| | | (31 | ) |
| LOCOM adjustments, net of current period recoveries | (1 | ) | | | — |
| | | (1 | ) | | | (1 | ) |
| Impact of purchase accounting adjustments | (9 | ) | | | — |
| | | (5 | ) | | | — |
|
| Adjusted Operating Margin | $ | (13 | ) | | | $ | (96 | ) | | | $ | 118 |
| | | $ | (36 | ) |
Change in Commercial Activity
The commercial activity at wholesale gas services includes recognition of storage and transportation values that were generated in prior periods, which reflect the impact of prior period hedge gains and losses as associated physical transactions occur. Warmer-than-normal weather during the 2016/2017 Heating Season, lower power generation volumes, and build-out of new U.S. pipeline infrastructure, along with increases in natural gas supply, caused low volatility and a tightening of locational or transportation spreads in 2017, negatively impacting the amount of commercial activity revenues generated relative to demand fees for contracted pipeline transportation and storage capacity, and minimum sharing under asset management agreements. However, as natural gas prices and forward storage or time spreads increased, wholesale gas services was able to capture higher storage values that it expects to recognize as commercial activity revenues when natural gas is physically withdrawn from storage. Southern Company Gas anticipates continued low volatility in certain areas of wholesale gas services' portfolio.
Change in Storage and Transportation Derivatives
Volatility in the natural gas market arises from a number of factors, such as weather fluctuations or changes in supply or demand for natural gas in different regions of the U.S. The volatility of natural gas commodity prices has a significant impact on Southern Company Gas' customer rates, long-term competitive position against other energy sources, and the ability of wholesale gas services to capture value from locational and seasonal spreads. In 2017 and 2016, there was little price volatility; however, the potential exists for market fundamentals indicating some level of increased volatility that would benefit Southern Company Gas' portfolio of pipeline transportation capacity. Additionally, during the first six months of 2017, forward storage or time spreads applicable to the locations of wholesale gas services' specific storage positions resulted in storage derivative gains. Transportation and forward commodity derivative gains are primarily the result of narrowing transportation basis spreads due to some reduction in supply constraints resulting from new U.S. pipeline infrastructure and increases in natural gas supply and warmer-than-normal weather, which impacted forward prices at natural gas receipt and delivery points, primarily in the Northeast and Midwest regions.
Withdrawal Schedule and Physical Transportation Transactions
The expected natural gas withdrawals from storage and expected offset to prior hedge losses/gains associated with the transportation portfolio of wholesale gas services are presented in the following table, along with the net operating revenues expected at the time of withdrawal from storage and the physical flow of natural gas between contracted transportation receipt and delivery points. Wholesale gas services' expected net operating revenues exclude storage and transportation demand charges, as well as other variable fuel, withdrawal, receipt, and delivery charges, but are net of the estimated impact of profit sharing under its asset management agreements. Further, the amounts that are realizable in future periods are based on the inventory withdrawal schedule, planned physical flow of natural gas between the transportation receipt and delivery points, and forward natural gas prices at June 30,
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
2017. A portion of wholesale gas services' storage inventory and transportation capacity is economically hedged with futures contracts, which results in the realization of substantially fixed net operating revenues.
|
| | | | | | | | | | |
| | Storage withdrawal schedule | | |
| | Total storage
(WACOG $2.75) | | Expected net operating gains(a) | | Physical transportation transactions – expected net operating losses(b) |
| | (in mmBtu in millions) | | (in millions) | | (in millions) |
| 2017 | 36.5 |
| | $ | 5 |
| | $ | (10 | ) |
| 2018 and thereafter | 30.9 |
| | 12 |
| | (27 | ) |
| Total at June 30, 2017 | 67.4 |
| | $ | 17 |
| | $ | (37 | ) |
| |
| (a) | Represents expected operating gains from planned storage withdrawals associated with existing inventory positions and could change as wholesale gas services adjusts its daily injection and withdrawal plans in response to changes in future market conditions and forward NYMEX price fluctuations. |
| |
| (b) | Represents the periods associated with the transportation derivative gains during which the derivatives will be settled and the physical transportation transactions will occur that offset the derivative gains that were previously recognized. |
The unrealized storage and transportation derivative gains do not change the underlying economic value of wholesale gas services' storage and transportation positions and will be reversed when the related transactions occur and are recognized. For more information on wholesale gas services' energy marketing and risk management activities, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company Gas in Item 7 of the Form 10-K.
Gas Midstream Operations
Gas midstream operations consists primarily of gas pipeline investments, with storage and fuels also aggregated into this segment. Gas pipeline investments consist of the SNG interest, Horizon Pipeline, Atlantic Coast Pipeline, PennEast Pipeline, Dalton Pipeline, and Magnolia Enterprise Holdings, Inc. See Note (J) to the Condensed
Financial Statements herein and Notes 4 and 11 to the financial statements of Southern Company Gas under "Equity
Method Investments – SNG" and "Investment in SNG," respectively, in Item 8 of the Form 10-K for additional
information.
Successor Second Quarter 2017
Net income of $9 million includes $7 million in adjusted operating margin, $13 million in operating expenses, $28 million in earnings from equity method investments, which consists primarily of equity in earnings from the investment in SNG, and $1 million in other income (expense), net, which resulted in EBIT of $23 million. Also included in net income are $8 million in interest expense and $6 million in income tax expense.
Predecessor Second Quarter 2016
Loss before interest and taxes of $5 million includes $6 million in adjusted operating margin, $12 million in operating expenses, and $1 million of other income (expense), net.
Successor Year-to-Date 2017
Net income of $25 million includes $16 million in adjusted operating margin, $25 million in operating expenses, $66 million in earnings from equity method investments, which consists primarily of equity in earnings from the investment in SNG, and $2 million in other income (expense), net, which resulted in EBIT of $59 million. Also included in net income are $17 million in interest expense and $17 million in income tax expense.
Predecessor Year-to-Date 2016
Loss before interest and taxes of $6 million includes $15 million in adjusted operating margin, $24 million in operating expenses, and $3 million of other income (expense), net.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
All Other
All other includes Southern Company Gas' investment in Triton, AGL Services Company, and Southern Company Gas Capital, as well as various corporate operating expenses that are not allocated to the reportable segments and interest income (expense) associated with affiliate financing arrangements. There were no Merger-related expenses for the successor second quarter or year-to-date 2017. For the predecessor second quarter 2016 and year-to-date 2016, Merger-related expenses included in operating expenses were $53 million and $56 million, respectively.
Segment Reconciliations
Reconciliations of consolidated net income attributable to Southern Company Gas to EBIT for the successor second quarter and year-to-date 2017, and operating income to adjusted operating margin for all periods presented, are in the following tables. See Note (K) to the Condensed Financial Statements herein for additional information. |
| | | | | | | | | | | | | | | | | | | | | |
| Successor |
| Second Quarter 2017 |
| Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services | Gas Midstream Operations | All Other | Intercompany Elimination | Consolidated |
| (in millions) |
| Consolidated Net Income | $ | 54 |
| $ | 4 |
| $ | (17 | ) | $ | 9 |
| $ | (1 | ) | $ | — |
| $ | 49 |
|
| Income taxes | 34 |
| 3 |
| (11 | ) | 6 |
| (1 | ) | — |
| 31 |
|
Interest expense, net of
amounts capitalized | 40 |
| 2 |
| 1 |
| 8 |
| (3 | ) | — |
| 48 |
|
| EBIT | $ | 128 |
| $ | 9 |
| $ | (27 | ) | $ | 23 |
| $ | (5 | ) | $ | — |
| $ | 128 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| | Successor |
| | Year-to-Date 2017 |
| | Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services | Gas Midstream Operations | All Other | Intercompany Elimination | Consolidated |
| | (in millions) |
| Consolidated Net Income | $ | 171 |
| $ | 35 |
| $ | 51 |
| $ | 25 |
| $ | 6 |
| $ | — |
| $ | 288 |
|
| Income taxes | 110 |
| 23 |
| 35 |
| 17 |
| (5 | ) | — |
| 180 |
|
Interest expense, net of
amounts capitalized | 80 |
| 3 |
| 3 |
| 17 |
| (9 | ) | — |
| 94 |
|
| EBIT | $ | 361 |
| $ | 61 |
| $ | 89 |
| $ | 59 |
| $ | (8 | ) | $ | — |
| $ | 562 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| Successor |
| Second Quarter 2017 |
| Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services | Gas Midstream Operations | All Other | Intercompany Elimination | Consolidated |
| (in millions) |
| Operating Income (Loss) | $ | 126 |
| $ | 9 |
| $ | (27 | ) | $ | (6 | ) | $ | (6 | ) | $ | — |
| $ | 96 |
|
Other operating expenses(a) | 301 |
| 48 |
| 14 |
| 13 |
| 9 |
| (3 | ) | 382 |
|
Revenue tax expense(b) | (18 | ) | — |
| — |
| — |
| — |
| — |
| (18 | ) |
| Adjusted Operating Margin | $ | 409 |
| $ | 57 |
| $ | (13 | ) | $ | 7 |
| $ | 3 |
| $ | (3 | ) | $ | 460 |
|
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
| | | | | | | | | | | | | | | | | | | | | |
| | Successor |
| | Year-to-Date 2017 |
| | Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services | Gas Midstream Operations | All Other | Intercompany Elimination | Consolidated |
| | (in millions) |
| Operating Income (Loss) | $ | 355 |
| $ | 61 |
| $ | 89 |
| $ | (9 | ) | $ | (9 | ) | $ | — |
| $ | 487 |
|
Other operating expenses(a) | 661 |
| 101 |
| 29 |
| 25 |
| 14 |
| (5 | ) | 825 |
|
Revenue tax expense(b) | (65 | ) | — |
| — |
| — |
| — |
| — |
| (65 | ) |
| Adjusted Operating Margin | $ | 951 |
| $ | 162 |
| $ | 118 |
| $ | 16 |
| $ | 5 |
| $ | (5 | ) | $ | 1,247 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| Predecessor |
| Second Quarter 2016 |
| Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services | Gas Midstream Operations | All Other | Intercompany Elimination | Consolidated |
| (in millions) |
| Operating Income (Loss) | $ | 117 |
| $ | 29 |
| $ | (112 | ) | $ | (6 | ) | $ | (56 | ) | $ | 1 |
| $ | (27 | ) |
Other operating expenses(a) | 286 |
| 37 |
| 16 |
| 12 |
| 58 |
| (2 | ) | 407 |
|
Revenue tax expense(b) | (17 | ) | — |
| — |
| — |
| — |
| — |
| (17 | ) |
| Adjusted Operating Margin | $ | 386 |
| $ | 66 |
| $ | (96 | ) | $ | 6 |
| $ | 2 |
| $ | (1 | ) | $ | 363 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| | Predecessor |
| | Year-to-Date 2016 |
| | Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services | Gas Midstream Operations | All Other | Intercompany Elimination | Consolidated |
| | (in millions) |
| Operating Income (Loss) | $ | 351 |
| $ | 109 |
| $ | (69 | ) | $ | (9 | ) | $ | (61 | ) | $ | — |
| $ | 321 |
|
Other operating expenses(a) | 616 |
| 81 |
| 33 |
| 24 |
| 65 |
| (4 | ) | 815 |
|
Revenue tax expense(b) | (56 | ) | — |
| — |
| — |
| — |
| — |
| (56 | ) |
| Adjusted Operating Margin | $ | 911 |
| $ | 190 |
| $ | (36 | ) | $ | 15 |
| $ | 4 |
| $ | (4 | ) | $ | 1,080 |
|
| |
| (a) | Includes other operations and maintenance, depreciation and amortization, taxes other than income taxes, and Merger-related expenses. |
| |
| (b) | Nicor Gas' revenue tax expenses, which are passed through directly to customers. |
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern Company Gas' future earnings potential. The level of Southern Company Gas' future earnings depends on numerous factors that affect the opportunities, challenges, and risks of its primary business of natural gas distribution and complementary businesses in the gas marketing services, wholesale gas services, and gas midstream operations sectors. These factors include Southern Company Gas' ability to maintain a constructive regulatory environment that allows for the timely recovery of prudently-incurred costs, the completion and subsequent operation of ongoing infrastructure and other construction projects, creditworthiness of customers, Southern Company Gas' ability to optimize its transportation and storage positions, and its ability to re-contract storage rates at favorable prices. Future earnings in the near term will depend, in part, upon maintaining and growing sales and customers which are subject to a number of factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
by customers, the use of alternative energy sources by customers, the price of natural gas, the price elasticity of demand, and the rate of economic growth or decline in Southern Company Gas' service territories. Demand for natural gas is primarily driven by economic growth. The pace of economic growth and natural gas demand may be affected by changes in regional and global economic conditions, which may impact future earnings.
Current proposals related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Southern Company Gas' financial statements.
On July 6, 2017, the State of Illinois enacted tax legislation that increased the effective corporate income tax rate from 5.25% to 7.0% (making the total corporate tax rate 9.5% when combined with the 2.5% personal property replacement tax) effective July 1, 2017. In addition to increasing taxes on future earnings, this legislation will require Southern Company Gas to adjust existing accumulated deferred income tax liabilities to reflect an increased tax rate, and any portion not recoverable through rates will impact earnings. Southern Company Gas is currently evaluating these changes. The ultimate impact of this legislation cannot be determined at this time, but could have a material impact on Southern Company Gas' financial statements.
Volatility of natural gas prices has a significant impact on Southern Company Gas' customer rates, long-term competitive position against other energy sources, and the ability of its gas marketing services and wholesale gas services segments to capture value from locational and seasonal spreads. Additionally, changes in commodity prices subject a significant portion of Southern Company Gas' operations to earnings variability.
Over the longer-term, volatility is expected to be low to moderate and locational and/or transportation spreads are expected to decrease as new pipelines are built to reduce the existing supply constraints in the shale areas of the Northeast U.S. To the extent these pipelines are delayed or not built, volatility could increase. Additional economic factors may contribute to this environment, including a significant drop in oil and natural gas prices, which could lead to consolidation of natural gas producers or reduced levels of natural gas production. Further, if economic conditions continue to improve, including the new housing market, the demand for natural gas may increase, which may cause natural gas prices to rise and drive higher volatility in the natural gas markets on a longer-term basis.
For additional information relating to these issues, see "Risk Factors" of Southern Company Gas in Item 1A of the Form 10-K.
In September 2016, Southern Company Gas acquired a 50% equity interest in SNG. See OVERVIEW – "Merger and Acquisition Activities" and Note (J) to the Condensed Financial Statements herein and Notes 4 and 11 to the financial statements of Southern Company Gas under "Equity Method Investments – SNG" and "Investment in SNG," respectively, in Item 8 of the Form 10-K for additional information. As part of its business strategy, Southern Company Gas regularly considers and evaluates joint development arrangements as well as acquisitions and dispositions of businesses and assets.
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis or through market-based contracts. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for natural gas, which could negatively affect results of operations, cash flows, and financial condition. See Note (B) under "Environmental Remediation" to the Condensed Financial Statements herein and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company Gas in Item 7 and Note 3 to the financial statements of Southern Company Gas under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FERC Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Southern Company Gas in Item 7 and Note 4 to the financial statements of Southern Company Gas in Item 8 of the Form 10-K for additional information regarding the Dalton Pipeline project.
On August 1, 2017, the Dalton Pipeline was placed in service as authorized by the FERC and transportation service for customers commenced.
Regulatory Matters
See Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Southern Company Gas" herein for additional information regarding Southern Company Gas' regulatory matters.
Riders
Nicor Gas has established a variable tax cost adjustment rider, which was approved by the Illinois Commission effective July 16, 2017. This rider provides for recovery of the invested capital tax imposed on Nicor Gas through an annual true-up and reconciliation mechanism. Accordingly, this rider will not have a significant effect on Southern Company Gas' net income.
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. Changes in the billing factor will not have a significant effect on Southern Company Gas' revenues or net income, but will affect cash flows.
Base Rate Cases
Settled Base Rate Cases
On February 21, 2017, the Georgia PSC approved the Georgia Rate Adjustment Mechanism (GRAM) and a $20 million increase in annual base rate revenues for Atlanta Gas Light, effective March 1, 2017. GRAM adjusts base rates annually, up or down, based on the previously approved ROE of 10.75% and does not collect revenue through special riders and surcharges. Various infrastructure programs previously authorized by the Georgia PSC under Atlanta Gas Light's STRIDE program, which include the Integrated Vintage Plastic Replacement Program, Integrated System Reinforcement Program, and Integrated Customer Growth Program, will continue under GRAM and the recovery of and return on the infrastructure program investments will be included in annual base rate adjustments. The Georgia PSC will review Atlanta Gas Light's performance annually under GRAM.
Beginning with the next rate adjustment in June 2018, Atlanta Gas Light's recovery of the previously unrecovered Pipeline Replacement Program revenue through 2014, as well as the mitigation costs associated with the Pipeline Replacement Program that were not previously included in its rates, will also be included in GRAM. In connection with the GRAM approval, the last monthly Pipeline Replacement Program surcharge increase became effective March 1, 2017.
In September 2016, Elizabethtown Gas filed a general base rate case with the New Jersey BPU requesting a $19 million increase in annual base rate revenues. The requested increase was based on a projected 12-month test year ending March 31, 2017 and a ROE of 10.25%. On June 30, 2017, the New Jersey BPU approved a settlement that provides for a $13 million increase in annual base rate revenues, effective July 1, 2017, based on a ROE of 9.6%. Also included in the settlement was a new composite depreciation rate that is expected to result in a $3 million annual reduction of depreciation.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Pending Base Rate Cases
On March 10, 2017, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $208 million increase in annual base rate revenues. The requested increase is based on a 2018 projected test year and a ROE of 10.7%. The Illinois Commission is expected to rule on the requested increase within the 11-month statutory time limit, after which rate adjustments will be effective.
On March 31, 2017, Virginia Natural Gas filed a general base rate case with the Virginia Commission requesting a $44 million increase in annual base rate revenues. The requested increase is based on a projected 12-month test year beginning September 1, 2017 and a ROE of 10.25%. The requested increase includes $13 million related to the recovery of investments under the Steps to Advance Virginia's Energy (SAVE) program. The Virginia Commission is expected to rule on the requested increase in the first quarter 2018. Rate adjustments are expected to be effective September 1, 2017, subject to refund.
The ultimate outcome of these pending base rate cases cannot be determined at this time.
Regulatory Infrastructure Programs
Southern Company Gas is engaged in various infrastructure programs that update or expand its gas distribution systems to improve reliability and ensure the safety of its utility infrastructure, and recovers in rates its investment and a return associated with these infrastructure programs.
Nicor Gas
In 2014, the Illinois Commission approved Nicor Gas' nine-year regulatory infrastructure program, Investing in Illinois. Under this program, Nicor Gas placed into service $75 million of qualifying assets during the first six months of 2017.
Atlanta Gas Light
Atlanta Gas Light's STRIDE program, which started in 2009, consists of three individual programs that update and expand gas distribution systems and liquefied natural gas facilities as well as improve system reliability to meet operational flexibility and customer growth. Through the programs under STRIDE, Atlanta Gas Light invested $94 million during the first six months of 2017.
In August 2016, Atlanta Gas Light filed a petition with the Georgia PSC for approval of a four-year extension of its Integrated System Reinforcement Program (i-SRP) seeking approval to invest an additional $177 million to improve and upgrade its core gas distribution system in years 2017 through 2020.
The recovery of and return on current and future capital investments under the STRIDE program will be included in the annual base rate revenue adjustment under GRAM rather than a separate surcharge. The proposed capital investments associated with the extension of i-SRP were included in the 2017 annual base rate revenue under GRAM that was approved by the Georgia PSC on February 21, 2017. See "Base Rate Cases" herein for additional information.
Elizabethtown Gas
In 2013, the New Jersey BPU approved the extension of Elizabethtown Gas' Aging Infrastructure Replacement program, under which Elizabethtown Gas invested $12 million during the first six months of 2017.
Virginia Natural Gas
In March 2016, the Virginia Commission approved an extension to the SAVE program, under which Virginia Natural Gas invested $14 million during the first six months of 2017.
Florida City Gas
The Florida PSC approved Florida City Gas' Safety, Access, and Facility Enhancement program in 2015. Under the program, Florida City Gas invested $7 million during the first six months of 2017.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Matters
Southern Company Gas is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company Gas is subject to certain claims and legal actions arising in the ordinary course of business. The ultimate outcome of such pending or potential litigation against Southern Company Gas cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company Gas' financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies and regulatory matters, and other matters being litigated which may affect future earnings potential.
Nicor Gas and Nicor Energy Services Company, wholly-owned subsidiaries of Southern Company Gas, and Nicor Inc. were defendants in a putative class action initially filed in 2011 in the state court in Cook County, Illinois. The plaintiffs purported to represent a class of the customers who purchased the Gas Line Comfort Guard product from Nicor Energy Services Company and variously alleged that the marketing, sale, and billing of the Gas Line Comfort Guard product violated the Illinois Consumer Fraud and Deceptive Business Practices Act, constituting common law fraud and resulting in unjust enrichment of these entities. The plaintiffs sought, on behalf of the classes they purported to represent, actual and punitive damages, interest, costs, attorney fees, and injunctive relief. On February 8, 2017, the judge denied the plaintiffs' motion for class certification and Southern Company Gas' motion for summary judgment. On March 7, 2017, the parties reached a settlement, which was finalized and effective on April 3, 2017. The settlement did not have a material impact on Southern Company Gas' financial statements.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company Gas prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Company Gas in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Company Gas' results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Company Gas in Item 7 of the Form 10-K for a complete discussion of Southern Company Gas' critical accounting policies and estimates related to Utility Regulation, Pushdown of Acquisition Accounting, Assessment of Assets, Derivatives and Hedging Activities, Pension and Other Postretirement Benefits, and Contingent Obligations.
Recently Issued Accounting Standards
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
While Southern Company Gas expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Southern Company Gas' revenue, including energy provided to customers, is from tariff offerings that provide natural gas without a defined contractual term, as well as longer-term contractual agreements, including non-derivative natural gas asset management and optimization arrangements. Southern Company Gas expects that the revenue from contracts with these customers will not result in a significant shift in the timing of revenue recognition for such sales.
Southern Company Gas' ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements, such as energy-related derivatives and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Southern Company Gas' financial statements. In addition, the power
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Southern Company Gas expects CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Southern Company Gas intends to use the modified retrospective method of adoption effective January 1, 2018. Southern Company Gas has also elected to utilize practical expedients which allow it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Southern Company Gas' financial statements, Southern Company Gas will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.
On January 26, 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for annual and interim periods beginning on or after December 15, 2019, and early adoption is permitted on testing dates after January 1, 2017.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. Southern Company Gas is currently evaluating the new standard. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company Gas' operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Southern Company Gas' financial statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company Gas in Item 7 of the Form 10-K for additional information. As a result of the Merger that closed on July 1, 2016, the results reported herein include disclosure of the successor second quarter and year-to-date 2017 and the predecessor second quarter and year-to-date 2016. See OVERVIEW – "Merger and Acquisition Activities" and Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Company Gas' financial condition remained stable at June 30, 2017. Southern Company Gas intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. Due to the increased working capital requirements associated with Nicor Gas' Investing in Illinois infrastructure replacement program, since 2015, Nicor Gas has temporarily ceased distributing dividends to Southern Company Gas. Elizabethtown Gas is restricted by its dividend policy as established by the New Jersey BPU in the amount it can dividend to its parent company to the extent of 70% of its quarterly net income. Additionally, as stipulated in the New Jersey BPU's order approving the Merger, Southern Company Gas is prohibited from paying dividends to its parent company, Southern Company, if Southern Company Gas' senior unsecured debt rating falls below investment grade. As of June 30, 2017, the amount of subsidiary retained earnings and net income available to dividend totaled $739 million. These restrictions did not have any impact on Southern Company Gas' ability to meet its cash obligations, nor does management expect such restrictions to materially impact Southern Company Gas' ability to meet its currently anticipated cash obligations.
Net cash provided from operating activities totaled $1.2 billion for the successor first six months of 2017 and $1.1 billion for the predecessor first six months of 2016. These cash flows were primarily driven by the sale of natural gas inventory during the respective periods.
Net cash used for investing activities totaled $781 million for the successor first six months of 2017, primarily due to gross property additions related to capital expenditures for infrastructure replacement programs at gas distribution operations and capital contributed to equity method investments in pipelines. Net cash used for investing activities totaled $559 million for the predecessor first six months of 2016, primarily due to gross property additions related to capital expenditures for infrastructure replacement programs at gas distribution operations.
Net cash used for financing activities totaled $351 million for the successor first six months of 2017, primarily due to net repayments of commercial paper borrowings and common stock dividend payments to Southern Company, partially offset by proceeds from debt issuances and capital contributions from Southern Company. Net cash used for financing activities totaled $558 million for the predecessor first six months of 2016, primarily due to net repayments of commercial paper borrowings, the redemption of long-term debt, and common stock dividend payments to shareholders, partially offset by proceeds from debt issuances. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes at June 30, 2017 include an increase of $514 million in total property, plant, and equipment primarily due to capital expenditures for infrastructure replacement programs, an increase in long-term debt of $418 million primarily due to $450 million of senior notes issued in May 2017, and decreases of $223 million in natural gas for sale, including temporary LIFO liquidation due to the use of natural gas stored during the first six months of 2017, and $631 million in notes payable related primarily to net repayments of commercial paper borrowings at Nicor Gas. Other significant balance sheet changes include decreases of $141 million and $63 million in energy marketing receivables and payables, respectively, due to lower natural gas prices.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company Gas in Item 7 of the Form 10-K for a description of Southern Company Gas' capital requirements for its infrastructure programs, scheduled maturities of long-term debt and the related interest, as well as pipeline charges, storage capacity, and gas supply, operating leases, asset management agreements, standby letters of credit and performance/surety bonds, financial derivative obligations, pension and other postretirement benefit plans, and other purchase commitments, primarily related to environmental remediation liabilities. Approximately $22 million will be required through June 30, 2018 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The regulatory infrastructure programs and other construction programs are subject to periodic review and revision, and actual costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in FERC rules and regulations; state regulatory approvals; changes in legislation; the cost and efficiency of labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. See Note 3 to the consolidated financial statements of Southern Company Gas in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for information regarding additional factors that may impact infrastructure investment expenditures.
Sources of Capital
Southern Company Gas plans to obtain the funds to meet its future capital needs through operating cash flows, short-term debt borrowings under its commercial paper programs, external securities issuances, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Company Gas in Item 7 of the Form 10-K for additional information.
At June 30, 2017, Southern Company Gas' current liabilities exceeded current assets by $572 million primarily as a result of $626 million in notes payable. Southern Company Gas' current liabilities frequently exceed current assets because of commercial paper borrowings used to fund daily operations, scheduled maturities of long-term debt, and significant seasonal fluctuations in cash needs. Southern Company Gas intends to utilize operating cash flows, commercial paper, and debt securities issuances, as market conditions permit, as well as equity contributions from Southern Company to fund its short-term capital needs. Southern Company Gas has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet liquidity needs.
At June 30, 2017, Southern Company Gas had approximately $38 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2017 were as follows:
|
| | | | | | | |
| | Expires | | |
| Company | 2022 | | Unused |
| | (in millions) |
| Southern Company Gas Capital | $ | 1,200 |
| | $ | 1,149 |
|
| Nicor Gas | 700 |
| | 700 |
|
| Total | $ | 1,900 |
| | $ | 1,849 |
|
Additionally, Pivotal Utility Holdings is party to a series of loan agreements with the New Jersey Economic Development Authority and Brevard County, Florida under which five series of gas facility revenue bonds totaling $200 million have been issued.
See Note 6 to the consolidated financial statements of Southern Company Gas under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
As reflected in the table above, in May 2017, Southern Company Gas Capital and Nicor Gas terminated their existing credit arrangements for $1.3 billion and $700 million, respectively, which were to mature in 2017 and 2018, and entered into a new multi-year credit arrangement (Facility) currently allocated for $1.2 billion and $700 million, respectively, with a maturity date of 2022.
The Facility included in the table above contains a covenant that limits the ratio of debt to capitalization (as defined in each facility) to a maximum of 70% for each of Southern Company Gas and Nicor Gas and contains a cross-acceleration provision to other indebtedness (including guarantee obligations) of the applicable company. Such cross-acceleration provision to other indebtedness would trigger an event of default of the applicable company if Southern Company Gas or Nicor Gas defaulted on indebtedness, the payment of which was then accelerated. At
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
June 30, 2017, each of the applicable companies was in compliance with such covenant. The Facility does not contain a material adverse change clause at the time of borrowings.
Subject to applicable market conditions, the applicable company expects to renew or replace the Facility as needed, prior to expiration. In connection therewith, the applicable company may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
Southern Company Gas makes short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Commercial paper borrowings are included in notes payable in the balance sheets.
Details of short-term borrowings were as follows:
|
| | | | | | | | | | | | | | | | | |
| | Short-term Debt at June 30, 2017 | | Short-term Debt During the Period(*) |
| | Amount
Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| Commercial paper: | (in millions) | | | | (in millions) | | | | (in millions) |
| Southern Company Gas Capital | $ | 581 |
| | 1.5 | % | | $ | 558 |
| | 1.3 | % | | $ | 750 |
|
| Nicor Gas | 45 |
| | 1.4 |
| | 143 |
| | 1.2 |
| | 308 |
|
| Short-term loans: | | | | | | | | | |
| Southern Company Gas | — |
| | — |
| | — |
| | 4.0 |
| | 40 |
|
| Total | $ | 626 |
| | 1.5 | % | | $ | 701 |
| | 1.3 | % | | |
| |
| (*) | Average and maximum amounts are based upon daily balances during the successor three-month period ended June 30, 2017. |
Southern Company Gas believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and operating cash flows.
Credit Rating Risk
Southern Company Gas does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change below BBB- and/or Baa3. These contracts are for physical gas purchases and sales and energy price risk management. The maximum potential collateral requirements under these contracts at June 30, 2017 were $9 million.
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Company Gas to access capital markets, and would be likely to impact the cost at which it does so.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including Southern Company Gas, Southern Company Gas Capital, and Nicor Gas) from stable to negative.
Financing Activities
The long-term debt on Southern Company Gas' consolidated balance sheets includes both principal and non-principal components. As of June 30, 2017, the non-principal components totaled $537 million, which consisted of the unamortized portions of the fair value adjustment recorded in purchase accounting, debt premiums, debt discounts, and debt issuance costs.
In May 2017, Southern Company Gas Capital issued $450 million aggregate principal amount of Series 2017A 4.40% Senior Notes due May 30, 2047. The proceeds were used to repay Southern Company Gas' short-term indebtedness and for general corporate purposes.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Subsequent to June 30, 2017, Atlanta Gas Light Company repaid at maturity $22 million of Series C medium-term notes.
Subsequent to June 30, 2017, Nicor Gas agreed to issue $400 million aggregate principal amount of First Mortgage Bonds in a private placement, $200 million of which is expected to be issued in each of August 2017 and November 2017.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company Gas plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
Market Price Risk
Other than the items discussed below, there were no material changes to Southern Company Gas' disclosures about market price risk during the successor second quarter and year-to-date 2017. For an in-depth discussion of Southern Company Gas' market price risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company Gas in Item 7 of the Form 10-K. Also see Notes (C) and (H) to the Condensed Financial Statements herein for information relating to derivative instruments.
Southern Company Gas 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 end-use customers have limited exposure to market volatility of natural gas prices. Certain natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs implemented per the guidelines of their respective state regulatory agencies to hedge the impact of market fluctuations in natural gas prices for customers. For the weather risk associated with Nicor Gas, Southern Company Gas has a corporate weather hedging program that utilizes weather derivatives to reduce the risk of lower operating margins potentially resulting from significantly warmer-than-normal weather. In addition, certain non-regulated operations routinely utilize various types of derivative instruments to economically hedge certain commodity price and weather risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and over-the-counter energy contracts, such as forward contracts, futures contracts, options contracts, and swap agreements. Some of these economic hedge activities may not qualify, or are not designated, for hedge accounting treatment. The following table illustrates the change in the net fair value of Southern Company Gas' derivative instruments during all periods presented, and provides details of the net fair value of contracts outstanding as of the dates presented.
|
| | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor | | | Successor | | | Predecessor |
| | Second Quarter | | | Second Quarter | | | Year-to-Date | | | Year-to-Date |
| | 2017 | | | 2016 | | | 2017 | | | 2016 |
| | (in millions) | | | (in millions) | | | (in millions) | | | (in millions) |
| Contracts outstanding at beginning of period, assets (liabilities), net | $ | 64 |
| | | $ | (44 | ) | | | $ | 12 |
| | | $ | 75 |
|
| Contracts realized or otherwise settled | (20 | ) | | | 8 |
| | | (16 | ) | | | (77 | ) |
Current period changes(a) | 7 |
| | | (48 | ) | | | 55 |
| | | (82 | ) |
| Contracts outstanding at the end of period, assets (liabilities), net | 51 |
| | | (84 | ) | | | 51 |
| | | (84 | ) |
| Netting of cash collateral | 71 |
| | | 120 |
| | | 71 |
| | | 120 |
|
Cash collateral and net fair value of contracts outstanding at end of period(b) | $ | 122 |
| | | $ | 36 |
| | | $ | 122 |
| | | $ | 36 |
|
| |
| (a) | Current period changes also include the fair value of new contracts entered into during the period, if any. |
| |
| (b) | Net fair value of derivative instruments outstanding includes premiums and the intrinsic values associated with weather derivatives of $11 million at June 30, 2017 and $5 million at June 30, 2016. |
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The maturities of Southern Company Gas' energy-related derivative contracts at June 30, 2017 were as follows:
|
| | | | | | | | | | | | | | | |
| | | | Fair Value Measurements |
| | | | Successor – June 30, 2017 |
| | Total
Fair Value | | Maturity |
| | | Year 1 | | Years 2 & 3 | | Years 4 and thereafter |
| | (in millions) |
Level 1(a) | $ | (12 | ) | | $ | 5 |
| | $ | (14 | ) | | $ | (3 | ) |
Level 2(b) | 63 |
| | 27 |
| | 30 |
| | 6 |
|
Fair value of contracts outstanding at end of period(c) | $ | 51 |
| | $ | 32 |
| | $ | 16 |
| | $ | 3 |
|
| |
| (a) | Valued using NYMEX futures prices. |
| |
| (b) | Valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers. |
| |
| (c) | Excludes cash collateral of $71 million at June 30, 2017. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS
FOR
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA POWER COMPANY
GULF POWER COMPANY
MISSISSIPPI POWER COMPANY
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
(UNAUDITED)
INDEX TO THE NOTES TO THE CONDENSED FINANCIAL STATEMENTS
|
| | |
| Note | | Page Number |
| A | | |
| B | | |
| C | | |
| D | | |
| E | | |
| F | | |
| G | | |
| H | | |
| I | | |
| J | | |
| K | | |
INDEX TO APPLICABLE NOTES TO FINANCIAL STATEMENTS BY REGISTRANT
The following unaudited notes to the condensed financial statements are a combined presentation. The list below indicates the registrants to which each footnote applies.
|
| |
| Registrant | Applicable Notes |
| Southern Company | A, B, C, D, E, F, G, H, I, J, K |
| Alabama Power | A, B, C, E, F, G, H |
| Georgia Power | A, B, C, E, F, G, H |
| Gulf Power | A, B, C, E, F, G, H |
| Mississippi Power | A, B, C, E, F, G, H |
| Southern Power | A, B, C, D, E, G, H, I |
| Southern Company Gas | A, B, C, E, F, G, H, I, J, K |
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA POWER COMPANY
GULF POWER COMPANY
MISSISSIPPI POWER COMPANY
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
NOTES TO THE CONDENSED FINANCIAL STATEMENTS:
(UNAUDITED)
The condensed quarterly financial statements of each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 20152016 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended SeptemberJune 30, 20162017 and 2015.2016. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each registrant believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q unless specifically required by GAAP. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.
Southern Company's financial statements reflect its investments in its subsidiaries, including Southern Company Gas as a result of the Merger, on a consolidated basis. Southern Company Gas' results of operations and cash flows since July 1, 2016for the three and six months ended June 30, 2017 and financial condition as of SeptemberJune 30, 2017 and December 31, 2016 are reflected within Southern Company's consolidated amounts in these accompanying notes herein. Southern Company Gas continues to maintain reporting requirements as an SEC registrant and has filed its Quarterly Report on Form 10-Q with the SEC separately from this combined Form 10-Q. The equity method is used for entities in which Southern Company has significant influence but does not control, including Southern Company Gas' investment in Southern Natural Gas Company, L.L.C. (SNG),SNG, and for variable interest entities where Southern Company has an equity investment but is not the primary beneficiary. See Note (I) under "Southern Company – Merger with Southern Company Gas" and " – Investment in Southern Natural Gas" for additional information regarding the Merger.
Pursuant to the Merger, Southern Company pushed down the application of the acquisition method of accounting to the consolidated financial statements of Southern Company Gas such that the assets and liabilities are recorded at their respective fair values, and goodwill has been established for the excess of the purchase price over the fair value of net identifiable assets. Accordingly, the consolidated financial statements of Southern Company Gas for periods before and after July 1, 2016 (acquisition date) reflect different bases of accounting, and the financial positions and results of operations of those periods are not comparable. Throughout Southern Company Gas' investment in SNG, respectively.condensed consolidated financial statements and the accompanying notes herein, periods prior to July 1, 2016 are identified as "predecessor," while periods after the acquisition date are identified as "successor."
Certain prior year data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on the results of operations, financial position, or cash flows of any registrant.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Recently Issued Accounting Standards
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
While the registrants expect most of their revenue to be included in the scope of ASC 606, they have not fully completed the evaluation of all revenue arrangements. The majority of Southern Company's, the traditional electric operating companies', and Southern Company Gas' revenue, including energy provided to customers, is from tariff offerings that provide electricity or natural gas without a defined contractual term, as well as longer-term contractual commitments, including PPAs and non-derivative natural gas asset management and optimization arrangements. The majority of Southern Power's revenues includes longer-term PPAs for generation capacity and energy. The registrants expect the adoption of ASC 606 will not result in a significant shift from the current timing of revenue recognition for such transactions.
The registrants' ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements, such as certain PPAs, energy-related derivatives, and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on the registrants' financial statements. In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Southern Company, the traditional electric operating companies, and Southern Company Gas expect CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. The registrants intend to use the modified retrospective method of adoption effective January 1, 2018. The registrants have also elected to utilize practical expedients which allow them to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in the registrants' financial statements, the registrants will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.
On February 25, 2016,January 26, 2017, the FASB issued ASU No. 2016-02,2017-04, Leases(Topic 842)Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2016-02)2017-04). ASU 2016-02 requires lessees2017-04 removes the requirement to recognize oncompare the balance sheetimplied fair value of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a lease liability andreporting unit's carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a right-of-use asset for all leases.future goodwill impairment test does not pass the Step 1 evaluation. 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 2016-022017-04 is effective prospectively for fiscal yearsannual and interim periods beginning on or after December 15, 2018, with2019, and early adoption is permitted on testing dates after January 1, 2017.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
permitted.for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The registrantscapitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. Southern Company, the traditional electric operating companies, and Southern Company Gas are currently evaluating the new standardstandard. The presentation changes required for net periodic pension and have not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to havepostretirement benefit costs will result in a significant impact on the registrants' balance sheets.
On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation(Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions. Most significantly, entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefitdecrease in the income statement. Southern Company andCompany's, the traditional electric operating companies currently recognize any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016. Early adoption is permittedcompanies', and Southern Company Gas' operating income and the traditional electrican increase in other income for 2016 and 2017 and are expected to result in a decrease in operating companies intend to adopt the ASUincome and an increase in the fourth quarter 2016.other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on the results of operations, financial position, or cash flows of Southern Company andCompany's, the traditional electric operating companies.companies', or Southern Company Gas' financial statements.
Affiliate Transactions
In 2014, priorPrior to Southern Company's acquisitionthe completion of PowerSecure International, Inc. (PowerSecure) on May 9, 2016, Georgia Power entered into two agreements with PowerSecure to build solar power generation facilities at two U.S. Army bases, as approved by the Georgia PSC. Payments of approximately $108 million made by Georgia Power to PowerSecure under the two agreements since inception in 2014 are included in CWIP at September 30, 2016. PowerSecure construction service costs of approximately $0.2 million are included in accounts payable, affiliated in Georgia Power's balance sheet at September 30, 2016. On October 4, 2016, the two facilities began commercial operation.
Prior to Southern Company Gas' completionacquisition of its acquisition of a 50% equity interest in SNG, SCS (as agent for Alabama Power, Georgia Power, and Southern CompanyPower) and Southern Company Gas had entered into long-term interstate natural gas transportation agreements with SNG. The interstate transportation service provided to the traditional electric operating companies,Alabama Power, Georgia Power, Southern Power, and Southern Company Gas by SNG pursuant to these agreements is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. For the period subsequent to Southern Company Gas' investment in SNG,six months ended June 30, 2017, transportation costs paid to SNG by Southern Company were approximately $16 million, including $8 millionunder these agreements for Georgia Power, $2 million for Southern Power, and $1 million for Alabama Power.
See Note (I) under "Southern Company– Acquisition of PowerSecure International, Inc." and " – Investment in Southern Natural Gas" for additional information regarding Southern Company's acquisition of PowerSecure and Southern Company Gas' investment in SNG, respectively.
Asset Retirement Obligations
See Note 1 to the financial statements of Southern Company, Alabama Power, Georgia Power, GulfSouthern Power, and MississippiSouthern Company Gas were approximately $4 million, $51 million, $13 million, and $16 million, respectively.
SCS, as agent for Georgia Power under "Asset Retirement Obligationsand Southern Power, has agreements with certain subsidiaries of Southern Company Gas to purchase natural gas. For the six months ended June 30, 2017, natural gas purchases made by Georgia Power and Southern Power from Southern Company Gas' subsidiaries were approximately $9 million and $56 million, respectively.
Goodwill and Other CostsIntangible Assets
At June 30, 2017 and December 31, 2016, goodwill was as follows: |
| | | | | | |
| | Goodwill |
| | At June 30, 2017 | At December 31, 2016 |
| | (in millions) |
| Southern Company | $ | 6,271 |
| $ | 6,251 |
|
| Southern Power | $ | 2 |
| $ | 2 |
|
| Southern Company Gas | | |
| Gas distribution operations | $ | 4,702 |
| $ | 4,702 |
|
| Gas marketing services | 1,265 |
| 1,265 |
|
| Southern Company Gas total | $ | 5,967 |
| $ | 5,967 |
|
Goodwill is not amortized, but is subject to an annual impairment test during the fourth quarter 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 placeeach year, or by other methods. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, the traditional electric operating companies expect to continue to periodically update these estimates.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
As of September 30, 2016, details of the AROs included in the registrants' Condensed Balance SheetsOther intangible assets were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power | | Southern Power |
| | (in millions) |
| Balance at beginning of year | $ | 3,759 |
| | $ | 1,448 |
| | $ | 1,916 |
| | $ | 130 |
| | $ | 177 |
| | $ | 21 |
|
| Liabilities incurred | 41 |
| | 5 |
| | — |
| | — |
| | 15 |
| | 18 |
|
| Liabilities settled | (117 | ) | | (12 | ) | | (93 | ) | | — |
| | (12 | ) | | — |
|
| Accretion | 119 |
| | 55 |
| | 56 |
| | 2 |
| | 3 |
| | 1 |
|
| Cash flow revisions | 712 |
| | 31 |
| | 675 |
| | 2 |
| | 7 |
| | — |
|
| Balance at end of period | $ | 4,514 |
| | $ | 1,527 |
| | $ | 2,554 |
| | $ | 134 |
| | $ | 190 |
| | $ | 40 |
|
The traditional electric operating companies' increases in cash flow revisions for the nine months ended September 30, 2016 primarily relate to changes in ash pond closure strategy. The increase for Georgia Power reflects its decision in June 2016 to cease operating and stop receiving coal ash at all of its ash ponds within the next three years and to eventually close all of its ash ponds either by removal, consolidation, and/or recycling for the beneficial use of coal ash or through closure in place using advanced engineering methods.
Goodwill and Other Intangible Assets
As of September 30, 2016, goodwill was as follows: |
| | | |
| | As of September 30, 2016 |
| | (in millions) |
| Southern Company | $ | 6,223 |
|
| Southern Power | $ | 2 |
|
Table of Contents |
| | | | | | | | | | | | | | | | | | | |
| | At June 30, 2017 | | At December 31, 2016 |
| | Gross Carrying Amount | Accumulated Amortization | Other Intangible Assets, Net | | Gross Carrying Amount | Accumulated Amortization | Other
Intangible Assets, Net |
| | (in millions) | | (in millions) |
| Southern Company | | | | | | | |
| Other intangible assets subject to amortization: | | | | | | | |
| Customer relationships | $ | 288 |
| $ | (57 | ) | $ | 231 |
| | $ | 268 |
| $ | (32 | ) | $ | 236 |
|
| Trade names | 159 |
| (11 | ) | 148 |
| | 158 |
| (5 | ) | 153 |
|
| Patents | 4 |
| — |
| 4 |
| | 4 |
| — |
| 4 |
|
| Backlog | 5 |
| (1 | ) | 4 |
| | 5 |
| (1 | ) | 4 |
|
| Storage and transportation contracts | 64 |
| (21 | ) | 43 |
| | 64 |
| (2 | ) | 62 |
|
| Software and other | 4 |
| (1 | ) | 3 |
| | 2 |
| — |
| 2 |
|
| PPA fair value adjustments | 456 |
| (35 | ) | 421 |
| | 456 |
| (22 | ) | 434 |
|
| Total other intangible assets subject to amortization | $ | 980 |
| $ | (126 | ) | $ | 854 |
| | $ | 957 |
| $ | (62 | ) | $ | 895 |
|
| Other intangible assets not subject to amortization: | | | | | | | |
| Federal Communications Commission licenses | $ | 75 |
| $ | — |
| $ | 75 |
| | $ | 75 |
| $ | — |
| $ | 75 |
|
| Total other intangible assets | $ | 1,055 |
| $ | (126 | ) | $ | 929 |
| | $ | 1,032 |
| $ | (62 | ) | $ | 970 |
|
| | | | | | | | |
| Southern Power | | | | | | | |
| Other intangible assets subject to amortization: | | | | | | | |
| PPA fair value adjustments | $ | 456 |
| $ | (35 | ) | $ | 421 |
| | $ | 456 |
| $ | (22 | ) | $ | 434 |
|
| | | | | | | | |
| Southern Company Gas | | | | | | | |
| Other intangible assets subject to amortization: | | | | | | | |
| Gas marketing services | | | | | | | |
| Customer relationships | $ | 221 |
| $ | (53 | ) | $ | 168 |
| | $ | 221 |
| $ | (30 | ) | $ | 191 |
|
| Trade names | 115 |
| (6 | ) | 109 |
| | 115 |
| (2 | ) | 113 |
|
| Wholesale gas services | | | | | | | |
| Storage and transportation contracts | 64 |
| (21 | ) | 43 |
| | 64 |
| (2 | ) | 62 |
|
| Total other intangible assets subject to amortization | $ | 400 |
| $ | (80 | ) | $ | 320 |
| | $ | 400 |
| $ | (34 | ) | $ | 366 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
As of September 30, 2016, other intangible assets were as follows:
|
| | | | | | | | | | |
| | | As of September 30, 2016 |
| | Estimated Useful Life | Gross Carrying Amount | Accumulated Amortization | Other Intangible Assets, Net |
| | | (in millions) |
| Southern Company | | | | |
| Other intangible assets subject to amortization: | | | | |
| Customer relationships | 11-26 years | $ | 268 |
| $ | (16 | ) | $ | 252 |
|
| Trade names | 5-28 years | 158 |
| (3 | ) | 155 |
|
| Patents | 3-10 years | 4 |
| — |
| 4 |
|
| Backlog | 5 years | 5 |
| — |
| 5 |
|
| Storage and transportation contracts | 1-5 years | 64 |
| (4 | ) | 60 |
|
| Software and other | 1-12 years | 2 |
| — |
| 2 |
|
| PPA fair value adjustments | 19-20 years | 405 |
| (16 | ) | 389 |
|
| Total other intangible assets subject to amortization | | $ | 906 |
| $ | (39 | ) | $ | 867 |
|
| Other intangible assets not subject to amortization: | | | | |
| Federal Communications Commission licenses | | $ | 75 |
| $ | — |
| $ | 75 |
|
| Total other intangible assets | | $ | 981 |
| $ | (39 | ) | $ | 942 |
|
| | | | | |
| Southern Power | | | | |
| Other intangible assets subject to amortization: | | | | |
| PPA fair value adjustments | 19-20 years | $ | 405 |
| $ | (16 | ) | $ | 389 |
|
Amortization associated with other intangible assets was as follows:
|
| | | | | | |
| | Three Months Ended | Nine Months Ended |
| | September 30, 2016 |
| | (in millions) |
| Southern Company | $ | 25 |
| $ | 27 |
|
| Southern Power | $ | 2 |
| $ | 4 |
|
At December 31, 2015, other intangible assets consisted primarily of Southern Power's PPA fair value adjustments with a net carrying amount of $317 million. The increases in goodwill and other intangible assets primarily relate to Southern Company's acquisitions of PowerSecure on May 9, 2016 and Southern Company Gas on July 1, 2016. |
| | | | | | |
| | Three Months Ended | Six Months Ended |
| | June 30, 2017 |
| | (in millions) |
| Southern Company | $ | 29 |
| $ | 65 |
|
| Southern Power | $ | 6 |
| $ | 13 |
|
| Southern Company Gas | $ | 20 |
| $ | 46 |
|
See Note 12 to the financial statements of Southern Company under "Southern Power" and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information regarding Southern Power's PPA fair value adjustments.adjustments related to its business acquisitions. Also see Note (I) under "Southern Company – Acquisition of PowerSecure International, Inc." and " – Merger with Southern Company Gas" for additional information.
Property Damage Reserve
See Note 1 to the financial statements of Gulf Power under "Property Damage Reserve" in Item 8 of the Form 10-K for additional information.
Gulf Power's cost of repairing damages from major storms and other uninsured property damages, including uninsured damages to transmission and distribution facilities, generation facilities, and other property is charged to Gulf Power's property damage reserve. In accordance with a settlement agreement approved by the Florida PSC on April 4, 2017 (2017 Rate Case Settlement Agreement), Gulf Power suspended further property damage reserve accruals effective April 2017. Gulf Power may make discretionary accruals, but is required to resume accruals of $3.5 million annually if the reserve balance falls below zero. In addition, Gulf Power may initiate a storm surcharge to recover costs associated with any tropical systems named by the National Hurricane Center or other catastrophic storm events that reduce the property damage reserve in the aggregate by approximately $31 million (75% of the April 1, 2017 balance) or more. The storm surcharge would begin, on an interim basis, 60 days following the filing of a cost recovery petition, would be limited to $4.00/month for a 1,000 KWH residential customer unless Gulf Power incurs in excess of $100 million in qualified storm recovery costs in a calendar year, and would replenish the storm reserve to approximately $40 million. See Note (B) under "Regulatory Matters–Gulf Power– Retail Base Rate Cases" for additional details regarding the 2017 Rate Case Settlement Agreement.
Natural Gas for Sale
Southern Company Gas' natural gas distribution utilities, with the exception of Nicor Gas, carry natural gas inventory on a weighted average cost of gas (WACOG)WACOG basis.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Nicor Gas' natural gas inventory is carried at cost on a last-in, first-out (LIFO)LIFO basis. Inventory decrements occurring during the year that are restored prior to year-endyear end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year-endyear end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated. Southern Company Gas' inventory decrement at June 30, 2017 is expected to be restored prior to year end. The cost of natural gas, including inventory costs, is recovered from customers under a purchased gas recovery mechanism adjusted for differences between actual costs and amounts billed; therefore, LIFO liquidations have no impact on Southern Company's net income.
or Southern Company Gas' other naturalnet income.
Natural gas inventories for Southern Company Gas' non-utility businesses are carried at the lower of weighted average cost or current market price, with cost determined on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value. Southern Company Gas had no material LOCOM adjustment in any period presented.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| |
| (B) | CONTINGENCIES AND REGULATORY MATTERS |
See Note 3 to the financial statements of the registrants in Item 8 of the Form 10-K for information relating to various lawsuits, other contingencies, and regulatory matters.
General Litigation Matters
Nicor Gas and Nicor Energy Services Company, wholly-owned subsidiaries of Southern Company Gas, and Nicor Inc. are defendants in a putative class action initially filed in September 2011 in state court in Cook County, Illinois. The plaintiffs purport to represent a class of the customers who purchased the Gas Line Comfort Guard product from Nicor Energy Services Company and variously allege that the marketing, sale, and billing of the Gas Line Comfort Guard product violated the Illinois Consumer Fraud and Deceptive Business Practices Act, constituting common law fraud and resulting in unjust enrichment of these entities. The plaintiffs seek, on behalf of the classes they purport to represent, actual and punitive damages, interest, costs, attorney fees, and injunctive relief. On October 26, 2016, the court held a hearing on the plaintiffs' motion for class certification and the defendants' motion for summary judgment on all of the plaintiffs' claims. The ultimate outcome of this matter cannot be determined at this time.
Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation against each registrant and any subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, or in Note 3 to the financial statements of each registrant in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such registrant's financial statements.
Southern Company
On January 20, 2017, a purported securities class action complaint was filed against Southern Company, certain of its officers, and certain former Mississippi Power officers in the U.S. District Court for the Northern District of Georgia, Atlanta Division, by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint alleges that Southern Company, certain of its officers, and certain former Mississippi Power officers made materially false and misleading statements regarding the Kemper IGCC in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. On June 12, 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. On July 27, 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice.
On February 27, 2017, Jean Vineyard filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the defendants caused Southern Company to make false or misleading statements regarding the Kemper IGCC cost and schedule. Further, the complaint alleges that the defendants were unjustly enriched and caused the waste of corporate assets. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on her own behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. On March 27, 2017, the court deferred this lawsuit until 30 days after certain further action in the purported securities class action complaint discussed above.
On May 15, 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia, that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper IGCC. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper IGCC schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys'
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes.
On June 1, 2017, Judy Mesirov filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia, that names as defendants Southern Company, certain of its current and former directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper IGCC. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper IGCC schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages, disgorgement of profits, and equitable relief and, on her own behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes.
Southern Company believes these legal challenges have no merit; however, an adverse outcome in any of these proceedings could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, the ultimate outcome of which cannot be determined at this time.
Georgia Power
In 2011, plaintiffs filed a putative class action against Georgia Power in the Superior Court of Fulton County, Georgia alleging that Georgia Power's collection in rates of municipal franchise fees (all of which are remitted to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state tort law claims. In November 2016, the Georgia Court of Appeals reversed the trial court's previous dismissal of the case and remanded the case to the trial court for further proceedings. Georgia Power has filed a petition for writ of certiorari with the Georgia Supreme Court. Georgia Power believes the plaintiffs' claims have no merit and intends to vigorously defend itself in this matter. The ultimate outcome of this matter cannot be determined at this time.
Southern Power
During 2015, Southern Power indirectly acquired a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock facility in Pecos County, Texas, which was under construction by Recurrent Energy, LLC and was subsequently placed in service in November 2016. Prior to placing the facility in service, certain solar panels were damaged during installation. While the facility currently is generating energy consistent with operational expectations and PPA obligations, Southern Power is pursuing remedies under its insurance policies and other contracts to repair or replace these solar panels. In connection therewith, Southern Power is withholding payments of approximately $26 million from the construction contractor, who has placed a lien on the Roserock facility for the same amount. The amounts withheld are included in other accounts and notes payable and other current liabilities on Southern Company's consolidated balance sheets and other accounts payable and other current liabilities on Southern Power's consolidated balance sheets. On May 18, 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas, against X.L. America, Inc. (XL) and North American Elite Insurance Company (North American Elite) seeking recovery from an insurance policy for damages resulting from a hail storm and certain installation practices by the construction contractor, McCarthy Building Companies, Inc. (McCarthy). On May 19, 2017, Roserock filed a separate lawsuit against McCarthy in the state district court in Travis County, Texas alleging breach of contract and breach of warranty for the damages sustained at the Roserock facility, which has since been moved to the U.S. District Court for the Western District of Texas. On May 22, 2017, McCarthy filed a lawsuit against Roserock, Array Technologies, Inc., Canadian Solar (USA), Inc., XL, and North American Elite in the U.S. District Court for the Western District of Texas alleging, among other things, breach of contract, and requesting foreclosure of mechanic's liens against Roserock. On July 18, 2017, the U.S. District Court for the Western District of Texas consolidated the two pending lawsuits. Southern Power intends to vigorously pursue and defend these matters, the ultimate outcome of which cannot be determined at this time.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Southern Company Gas
Nicor Gas and Nicor Energy Services Company, wholly-owned subsidiaries of Southern Company Gas, and Nicor Inc. were defendants in a putative class action initially filed in 2011 in the state court in Cook County, Illinois. The plaintiffs purported to represent a class of the customers who purchased the Gas Line Comfort Guard product from Nicor Energy Services Company and variously alleged that the marketing, sale, and billing of the Gas Line Comfort Guard product violated the Illinois Consumer Fraud and Deceptive Business Practices Act, constituting common law fraud and resulting in unjust enrichment of these entities. The plaintiffs sought, on behalf of the classes they purported to represent, actual and punitive damages, interest, costs, attorney fees, and injunctive relief. On February 8, 2017, the judge denied the plaintiffs' motion for class certification and Southern Company Gas' motion for summary judgment. On March 7, 2017, the parties reached a settlement, which was finalized and effective on April 3, 2017. The settlement did not have a material impact on Southern Company's or Southern Company Gas' financial statements.
Environmental Remediation
The Southern Company system must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companies and Southern Company Gas'the natural gas distribution utilities in Illinois, New Jersey, Georgia, and Florida have each received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Georgia Power's environmental remediation liability was $12 million and $17 million as of SeptemberJune 30, 2017 and December 31, 2016, was $23 million.respectively. Georgia Power has been designated or identified as a potentially responsible party (PRP) at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, (CERCLA), including a site in Brunswick, Georgia on the CERCLA National Priorities List. The PRPs at the Brunswick site have completed a removal action as ordered by the EPA. On July 29, 2016, Honeywell International, Inc. and Georgia Power entered into a consent decree with the EPA to perform additional remediation at the site. Additional response actions at the site are anticipated. In September 2015, Georgia Power entered into an allocation agreement with another PRP, under which that PRP will be responsible (as between Georgia Power and that PRP) for paying and performing certain investigation, assessment remediation, and other incidental activities at the Brunswick site, including costs associated with implementation of the consent decree. Assessment and potential cleanup of othersuch sites are anticipated.
The ultimate outcome of these matters will depend upon the success of defenses asserted, the ultimate number of PRPs participating in the cleanup, and numerous other factors and cannot be determined at this time; however, as a result of Georgia Power's regulatory treatment for environmental remediation expenses, these matters are not expected to have a material impact on Southern Company's or Georgia Power's financial statements.is expected.
Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $46$51 million and $44 million as of SeptemberJune 30, 2016.2017 and December 31, 2016, respectively. These estimated costs primarily relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf PowerPower's substations. The schedule for completion of the remediation projects is subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power's environmental cost recovery clause; therefore, these liabilities have no impact on net income.
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 was $416 million and $426 million as of SeptemberJune 30, 2017 and December 31, 2016, was $433 millionrespectively, based on the estimated cost of environmental investigation and remediation associated with known current and former manufactured gas plant operating sites. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies of Southern Company Gas'the natural gas distribution utilities, with the exception of one site representing $5 million of the total accrued remediation costs.
The ultimatefinal outcome of these matters cannot be determined at this time; however, these matters are not expected to have a material impact on Southern Company's financial statements.
In September 2015, the EPA filed an administrative complaint and notice of opportunity for hearing against Nicor Gas. The complaint alleges violation of the regulatory requirements applicable to polychlorinated biphenyls in the Nicor Gas natural gas distribution system and the EPA seeks a total civil penalty of approximately $0.3 million. The ultimate resolution of this matter cannot be determined at this time; however,time. However, the final disposition of this matterthese matters is not expected to have a material impact on the financial statements of Southern Company's financial statements.Company, Georgia Power, Gulf Power, or Southern Company Gas.
FERC Matters
Municipal and Rural Associations Tariff
See Note 3 to the financial statements of Mississippi Power under "FERC Matters" in Item 8 of the Form 10-K for additional information regarding a settlement agreement entered into by Mississippi Power regarding the
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
establishment of a regulatory asset for Kemper IGCC-related costs. See "Integrated Coal Gasification Combined Cycle" herein for information regarding Mississippi Power's construction of the Kemper IGCC.
OnIn March 31, 2016, Mississippi Power reached a settlement agreement with its wholesale customers, and filed a request withwhich was subsequently approved by the FERC, for an increase in wholesale base revenues under the Municipal and Rural Associations (MRA)MRA cost-based electric tariff, primarily as a result of placing scrubbers for Plant Daniel Units 1 and 2 in service
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
in November 2015. The settlement agreement accepted by the FERC,became effective for services rendered beginning May 1, 2016, provides that base ratesresulting in an estimated annual revenue increase of $7 million under the MRA cost-based electric tariff will produce additional annual base revenues of $7 million.tariff. Additionally, under the settlement agreement, the tariff customers agreed to similar regulatory treatment for MRA tariff ratemaking as the treatment approved for retail ratemaking underthrough an order issued by the December 2015 Mississippi PSC order authorizing rates providing recovery of assets previously placed in serviceDecember 2015 (In-Service Asset Rate Order). This regulatory treatment primarily includes (i) recovery of the Kemper IGCC assets currently operational and providing service to customers and other related costs, (ii) amortization of the Kemper IGCC-related regulatory assets included in rates under the settlement agreement over the 36 months ending April 30, 2019, (iii) Kemper IGCC-related expenses included in rates under the settlement agreement no longer being deferred and charged to expense, and (iv) removing all of the Kemper IGCC CWIP from rate base with a corresponding increase in accrual of AFUDC. The additional resulting AFUDC is estimated to betotaled approximately $11$22 million through the suspension of Kemper IGCC's projected in-service date of December 31, 2016.IGCC start-up activities.
See "Integrated Coal Gasification Combined Cycle" herein for additional information.
Fuel Cost Recovery
Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At SeptemberJune 30, 2016,2017, the amount of over-recovered wholesale MRA fuel costs included in the balance sheets was $17$7 million compared to $24$13 million at December 31, 2015. At September 30, 2016 and December 31, 2015, the amount of over-recovered2016. 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 customerswere immaterial at June 30, 2017 and $1 million annually for wholesale MB customers.December 31, 2016.
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 companiesSee Note 3 to the financial statements of Southern Company and Mississippi Power under "FERC Matters – Market-Based Rate Authority" and Note 3 to the financial statements of Alabama Power, Georgia Power, Gulf Power, and Southern Power have authority fromunder "FERC Matters" in Item 8 of the FERC to sell electricity at market-based rates. Since 2008, that authority,Form 10-K 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 thatadditional information regarding 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 byproceeding and amendment to their market-rate tariff.
On May 17, 2017, the FERC accepted the traditional electric operating companiescompanies' and in some adjacent areas. The FERC directedSouthern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies and Southern Power to show whytheir market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. Thetariff. While the FERC's order references the traditional electric operating companiescompanies' and Southern Power filedPower's market power proceeding, it remains 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"Regulatory Matters – Alabama Power" and "Retail Regulatory Matters," respectively, in Item 8 of the Form 10-K for additional information regarding Alabama Power's recovery of retail costs through various regulatory clauses and accounting orders. The balance of each regulatory clause recovery on the balance sheet follows:
| | | Regulatory Clause | Balance Sheet Line Item | September 30,
2016 | December 31, 2015 | Balance Sheet Line Item | June 30,
2017 | December 31,
2016 |
|
| (in millions) |
| (in millions) |
| Rate CNP Compliance | Under recovered regulatory clause revenues | $ | — |
| $ | 43 |
| |
| | Deferred over recovered regulatory clause revenues | 23 |
| — |
| |
Rate CNP Compliance(*) | | Deferred under recovered regulatory clause revenues | $ | 6 |
| $ | 9 |
|
| Rate CNP PPA | Under recovered regulatory clause revenues | 52 |
| 99 |
| Over recovered regulatory clause revenues | 1 |
| — |
|
| | Deferred under recovered regulatory clause revenues | 87 |
| — |
| Deferred under recovered regulatory clause revenues | — |
| 142 |
|
| Retail Energy Cost Recovery | Other regulatory liabilities, current | — |
| 238 |
| Other regulatory liabilities, current | 11 |
| 76 |
|
| Deferred over recovered regulatory clause revenues | 134 |
| — |
| |
| Natural Disaster Reserve | Other regulatory liabilities, deferred | 71 |
| 75 |
| Other regulatory liabilities, deferred | 56 |
| 69 |
|
Environmental Accounting Order
In April 2016, as part of its environmental compliance strategy, Alabama Power ceased using coal at Plant Greene County Units 1 and 2 (300 MWs representing Alabama Power's ownership interest) and began operating Units 1 and 2 solely on natural gas in June 2016 and July 2016, respectively.
| |
| (*) | In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power reclassified $36 million of its under recovered balance for Rate CNP Compliance to a deferred regulatory asset account. |
Georgia Power
Rate Plans
See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory"Regulatory Matters – Georgia Power – Rate Plans" and "Retail Regulatory Matters – Rate Plans," respectively, in Item 8 of the Form 10-K for additional information.
Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, Environmental Compliance Cost Recovery tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to the construction of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a separate fuel cost recovery tariffs.tariff. See "Nuclear Construction" herein and Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Nuclear Construction" and Georgia Power under "Retail Regulatory Matters – Nuclear Construction" and Southern Company under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the NCCR tariff. Also see "Fuel Cost Recovery" herein and Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Fuel Cost Recovery" and Georgia Power under "Retail Regulatory Matters – Fuel Cost Recovery" and Southern Company under "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding fuel cost recovery.
Pursuant to the terms and conditions of a settlement agreement related to Southern Company's acquisition of Southern Company Gas approved by the Georgia PSC on April 14, 2016, Georgia Power's 2013 ARP will continue in effect until December 31, 2019, and Georgia Power will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, Georgia Power and Atlanta Gas Light Company (collectively, Utilities) each will retain their respective merger savings, net of transition costs, as defined in the settlement agreement;
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
through December 31, 2022, such net merger savings applicable to each utility will be shared on a 60/40 basis between their respective customers and the Utilities; thereafter, all merger savings will be retained by customers. See Note (I) under "Southern Company – Merger with Southern Company Gas" for additional information regarding the Merger.
Integrated Resource Plan
See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory"Regulatory Matters – Georgia Power – Integrated Resource Plan" and "Retail Regulatory Matters – Integrated Resource Plan," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's triennial Integrated Resource Plan (2016 IRP).Plan.
On July 28, 2016, the Georgia PSC voted to approve the 2016 IRP including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 combustion turbine (17 MWs), as well as the decertification of the Intercession City unit (143 MWs total capacity). On August 2, 2016, the Plant Mitchell and Plant Kraft units were retired. On August 31, 2016, Georgia Power sold its 33% ownership interest in the Intercession City unit to Duke Energy Florida, Inc.
Additionally,March 7, 2017, the Georgia PSC approved Georgia Power's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures takendecision to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4.
The Georgia PSC approved the reclassification of the remaining net book value of Plant Mitchell Unit 3 and costs associated with materials and supplies remaining at the unit retirement date to a regulatory asset. Recovery of the unit's net book value will continue through December 31, 2019, as provided in the 2013 ARP. The timing of the recovery of the remaining balance of the unit's net book value as of December 31, 2019 and costs associated with materials and supplies remaining at the unit retirement date will be deferred for consideration in Georgia Power's base rate case required to be filed by July 1, 2019.
The Georgia PSC also approved the Renewable Energy Development Initiative to procure an additional 1,200 MWs of renewable resources primarily utilizing market-based prices established through a competitive bidding process with expected in-service dates between 2018 and 2021. Additionally, 200 MWs of self-build capacity for use by Georgia Power was approved, as well as consideration for no more than 200 MWs of capacity as part of a renewable commercial and industrial program.
The Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve the nuclear optionsuspend work at a future generation site in Stewart County, Georgia.Georgia, due to changing economics, including load forecasts and lower fuel costs. The timing
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
of cost recovery for costs incurred of approximately $50 million will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time.
Fuel Cost Recovery
See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory"Regulatory Matters – Georgia Power – Fuel Cost Recovery" and "Retail Regulatory Matters – Fuel Cost Recovery," respectively, in Item 8 of the Form 10-K for additional information.
As of SeptemberJune 30, 20162017, Georgia Power's under recovered fuel balance totaled $61 million and is included in other deferred charges and assets on Southern Company's and Georgia Power's condensed balance sheets. As of December 31, 2015,2016, Georgia Power's over recovered fuel balance totaled $125$84 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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
condensed balance sheets.
Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's or Georgia Power's revenues or net income, but will affect cash flow.
Storm Damage Recovery
As of September 30, 2016, the balance in Georgia Power's regulatory asset related to storm damage was $94 million. During October 2016, Hurricane Matthew caused significant damage to Georgia Power's transmission and distribution facilities. The total amount of restoration costs related to this hurricane is estimated to be between $130 million and $155 million, which will be charged to capital accounts or to the storm damage reserve. Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, to the storm damage reserve to cover the operating and maintenance costs of damages from major storms to its transmission and distribution facilities, which is recoverable through base rates. The rate of recovery of storm damage costs after December 31, 2019 is expected to be adjusted in Georgia Power's base rate case required to be filed by July 1, 2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's or Georgia Power's financial statements. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Storm Damage Recovery" and Note 1 to the financial statements of Georgia Power under "Storm Damage Recovery" in Item 8 of the Form 10-K for additional information regarding Georgia Power's storm damage reserve.
Nuclear Construction
See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory"Regulatory Matters – Georgia Power – Nuclear Construction" and "Retail Regulatory Matters – Nuclear Construction," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's construction of Plant Vogtle Units 3 and 4, Vogtle Construction Monitoring (VCM) reports, the NCCR tariff, the Vogtle Construction Litigation (as defined below), and the Contractor Settlement Agreement.
Vogtle 3 and 4 Agreement (as defined below).and EPC Contractor Bankruptcy
In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an agreement with the Contractor,Vogtle 3 and 4 Agreement, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4 (Vogtle 3 and 4 Agreement).
4. 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. Georgia Power's proportionate share of Plant Vogtle Units 3 and 4 is 45.7%.
The Vogtle 3 and 4 Agreement also providesprovided for liquidated damages upon the EPC Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to a cap. In addition,an aggregate cap of 10% of 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 (basedcontract price, or approximately $920 million (approximately $420 million based on Georgia Power's ownership interest). Under the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of approximately $114 million. Each Vogtle Owner is severally (and not jointly) liablethe EPC Contractor, including any liability of the EPC Contractor for its proportionate share, based on its ownership interest,abandonment of all amounts owedwork. In January 2016, Westinghouse delivered to the ContractorVogtle Owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020 and require 60 days' written notice to 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,Power 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 the Westinghouse Letters of certain credit rating downgrades of any Vogtle Owner, such Vogtle OwnerCredit will not 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,renewed.
Under the terms of the Vogtle 3 and 4 Agreement.Agreement, the EPC Contractor did not have the right to terminate the Vogtle 3 and 4 Agreement for convenience. In the event of an abandonment of work by the EPC Contractor, the maximum liability of the EPC Contractor under the Vogtle 3 and 4 Agreement was 40% of the contract price (approximately $1.7 billion based on Georgia Power's ownership interest).
On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. To provide for a continuation of work at Plant Vogtle Units 3 and 4, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an interim assessment agreement with the EPC Contractor (Interim Assessment Agreement), which the bankruptcy court approved on March 30, 2017.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
TheContractor for subcontractors and vendors for services performed or goods provided, with these amounts paid to the EPC Contractor, except that amounts accrued for Fluor Corporation (Fluor) were paid directly to Fluor; (ii) the EPC Contractor provided certain engineering, procurement, and management services for Plant Vogtle Owners may terminateUnits 3 and 4, to the same extent as contemplated by the Vogtle 3 and 4 Agreement, at any time for their convenience, provided thatand Georgia Power, on behalf of the Vogtle Owners, will be requiredmade payments of $5.4 million per week for these services; (iii) Georgia Power had the right to pay certain termination costs. The Contractor may terminatemake payments, on behalf of the Vogtle Owners, directly to subcontractors and vendors who had accounts past due with the EPC Contractor; (iv) the EPC Contractor used commercially reasonable efforts to provide information reasonably requested by Georgia Power as was necessary to continue construction and investigation of the completion status of Plant Vogtle Units 3 and 4 Agreement under certain circumstances, including certain Vogtle Owner suspension4; (v) the EPC Contractor rejected or delays of work, action by a governmental authority to permanently stop work, certain breaches ofaccepted the Vogtle 3 and 4 Agreement by the termination of the Interim Assessment Agreement; and (vi) Georgia Power did not exercise any remedies against Toshiba under the Toshiba Guarantee. Under the Interim Assessment Agreement, all parties expressly reserved all rights and remedies under the Vogtle 3 and 4 Agreement and all related security and collateral under applicable law.
The Interim Assessment Agreement, as amended, expired on July 27, 2017. Georgia Power's aggregate liability for the Vogtle Owners under the Interim Assessment Agreement totaled approximately $650 million, of which $552 million had been paid or accrued as of June 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $297 million.
Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor, including Fluor Enterprises, Inc., a subsidiary of Fluor, alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle OwnerUnits 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken, and continues to take, actions to remove liens filed by these subcontractors through the posting of surety bonds. Georgia Power estimates the aggregate liability, through July 31, 2017, of the Vogtle Owners for the removal of subcontractor liens and payment of other EPC Contractor pre-petition accounts payable to total approximately $400 million, of which $354 million had been paid or accrued as of June 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $183 million.
On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion (Guarantee Obligations), of which Georgia Power's proportionate share is approximately $1.7 billion, and that the Guarantee Obligations exist regardless of whether Plant Vogtle Units 3 and 4 are completed. The Guarantee Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations, beginning in October 2017 and continuing through January 2021. In the event Toshiba receives certain payments, including sale proceeds, from or related to Westinghouse (or its subsidiaries) or Toshiba Nuclear Energy Holdings (UK) Limited (or its subsidiaries), it will hold a portion of such payments in trust for the Vogtle Owners and promptly pay them as offsets against any remaining Guarantee Obligations. Under the Guarantee Settlement Agreement, the Vogtle Owners will forbear from exercising certain remedies, including drawing on the Westinghouse Letters of Credit, until June 30, 2020, unless certain events of nonpayment, insolvency, or other material breach of the Guarantee Settlement Agreement by Toshiba occur. If such an event occurs, the balance of the Guarantee Obligations will become immediately due and payable, and the Vogtle Owners may exercise any and all rights and remedies, including drawing on the Westinghouse Letters of Credit without restriction. In addition, the Guarantee Settlement Agreement does not restrict the Vogtle Owners from fully drawing on the Westinghouse Letters of Credit in the event they are not renewed or replaced prior to the expiration date.
On June 23, 2017, Toshiba released a revised outlook for fiscal year 2016, which reflected a negative shareholders' equity balance of approximately $5 billion as of March 31, 2017, and announced that its independent audit process was continuing. Toshiba has also announced the existence of material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern. As a result, substantial risk regarding the Vogtle Owners' ability to fully collect the Guarantee Obligations continues to exist. An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Southern Company's and Georgia Power's financial statements.
Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into a services agreement (Services Agreement), which was amended and restated on July 20, 2017, for the EPC Contractor to transition construction management of Plant Vogtle Units 3 and 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Services Agreement, (ii) assume and assign to the Vogtle Owners certain other events.project-related contracts, (iii) join the Vogtle Owners as counterparties to certain assumed project-related contracts, and (iv) reject the Vogtle 3 and 4 Agreement. The Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE on July 27, 2017. The Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.
The ultimate outcome of these matters cannot be determined at this time.
Regulatory Matters
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 reports4 with a certified capital cost of $4.418 billion. In addition, in 2009 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 toapproved inclusion of the Plant Vogtle Units 3 and 4 certificate fromrelated CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for nuclear construction projects certified by the Georgia PSC. In February 2013,Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by including the related CWIP accounts in rate base during the construction period. As of June 30, 2017, Georgia Power requested an amendment to the certificate to increase the estimated in-service capital costhad recovered approximately $1.4 billion 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,financing costs.
On December 20, 2016, the Georgia PSC approved a stipulation (2013 Stipulation) between Georgia Power and the Georgia PSC Staffvoted 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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 intoapprove a settlement agreement (Vogtle Cost Settlement Agreement) resolving the following prudence matters: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report will be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement is reasonable and prudent and none of the amounts paid or to be paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) financing costs on verified and approved capital costs will be deemed prudent provided they are incurred prior to December 31, 2019 and December 31, 2020 for Plant Vogtle Units 3 and 4, respectively; and (iv) (a) the in-service capital cost forecast will be adjusted to $5.680 billion (Revised Forecast), which includes a contingency of $240 million above Georgia Power's then current forecast of $5.440 billion, (b) capital costs incurred up to the Revised Forecast will be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, and (c) Georgia Power would have the burden to show that any capital costs above the Revised Forecast are reasonable and prudent. Under the terms of the Vogtle Cost Settlement Agreement, the certified in-service capital cost for purposes of calculating the NCCR tariff will remain at $4.418 billion. Construction capital costs above $4.418 billion will accrue AFUDC through commercial operation.the date each unit is placed in service. The ROE used to calculate the NCCR tariff will bewas reduced from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016. For purposes of the AFUDC calculation, the ROE on costs between $4.418 billion and $5.440 billion will also be 10.00% and the ROE on any amounts above $5.440 billion would be Georgia Power's average cost of long-term debt. If the Georgia PSC adjusts Georgia Power's ROE rate setting point in a rate case prior to Plant Vogtle Units 3 and 4 being placed into retail rate base, then the ROE for purposes of calculating both the NCCR tariff and AFUDC will likewise be 95 basis points lower than the revised ROE rate setting point. If Plant Vogtle Units 3 and 4 are not commercially operationalplaced in service by December 31, 2020, then (i) the ROE for purposes of calculating the NCCR tariff will be reduced an additional 300 basis points, or $8 million per month, and may, at the Georgia PSC's discretion, be accrued to be used for the benefit of customers, until such time as the units reach commercial operationare placed in service and (ii) the ROE used to calculate AFUDC will be Georgia Power's average cost of long-term debt.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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. Thethe Georgia PSC will determine, for retail ratemaking purposes, the process of transitioning Plant Vogtle Units 3 and 4 from a construction project to an operating plant no later than Georgia Power's base rate case required to be filed by July 1, 2019.
The Vogtle Cost Settlement Agreement is subject to approval by the Georgia PSC has approved fifteen VCM reports covering the periods through June 30, 2016, including construction capital costs incurred, which is scheduled to vote on this matter on December 20, 2016. Accordingly, the terms of the Vogtle Cost Settlement Agreement are subject to change and the terms of any final agreement approved by the Georgia PSC may differ materially from the terms of the Vogtle Cost Settlement Agreement. If approved, the Vogtle Cost Settlement Agreement is expected to reduce Georgia Power's revenues for the years 2016 through 2020 by a total of approximately $325 million ($115 million reduction in net income).
On August 31, 2016,that date totaled $3.7 billion. Georgia Power filed the fifteenthits sixteenth VCM report, with the Georgia PSC covering the period from JanuaryJuly 1 through June 30,December 31, 2016, requesting approval of $141$222 million of construction capital costs incurred during that period.period, with the Georgia Power's CWIP balancePSC on February 27, 2017.
The ultimate outcome of these matters cannot be determined at this time.
Revised Cost and Schedule
Georgia Power and the other Vogtle Owners are continuing to conduct comprehensive schedule and cost-to-complete assessments, as well as cancellation cost assessments, to determine the impact of the EPC Contractor's bankruptcy filing on the construction cost and schedule for Plant Vogtle Units 3 and 4. Georgia Power's preliminary assessment results indicate that its proportionate share of the remaining estimated cost to complete Plant Vogtle Units 3 and 4 was $3.8 billionranges as follows:
|
| | | | | | | |
| Preliminary in-service dates | | | |
| Unit 3 | February 2021 | – | March 2022 |
| Unit 4 | February 2022 | – | March 2023 |
| | (in billions) |
| Preliminary estimated cost to complete | $ | 3.9 |
| – | $ | 4.6 |
|
| CWIP as of June 30, 2017 | 4.5 |
| | 4.5 |
|
| Guarantee Obligations | (1.7 | ) | | (1.7 | ) |
| Estimated capital costs | $ | 6.7 |
| – | $ | 7.4 |
|
| Vogtle Cost Settlement Agreement Revised Forecast | (5.7 | ) | | (5.7 | ) |
| Estimated net additional capital costs | $ | 1.0 |
| – | $ | 1.7 |
|
Georgia Power's estimates for cost to complete and schedule are based on preliminary analysis and remain subject to further refinement of September 30, 2016. Estimatedlabor productivity and consumable and commodity quantities and costs.
Georgia Power's estimated financing costs during the construction period total approximately $2.4$3.1 billion to $3.5 billion, of which $1.2approximately $1.4 billion had been incurred through SeptemberJune 30, 2016.2017.
Georgia Power's preliminary cancellation cost estimate results indicate that its proportionate share of the estimated cancellation costs is approximately $400 million. As a result, as of June 30, 2017, total estimated costs subject to evaluation by Georgia Power and the Georgia PSC in the event of a cancellation decision are as follows:
|
| | | |
| | Preliminary Cancellation Cost Estimate |
| | (in billions) |
| CWIP as of June 30, 2017 | $ | 4.5 |
|
| Financing costs collected, net of tax | 1.4 |
|
Cancellation costs(*) | 0.4 |
|
| Total | $ | 6.3 |
|
| |
| (*) | The estimate for cancellation costs includes, but is not limited to, costs to terminate contracts for construction and other services, as well as costs to secure the Plant Vogtle Units 3 and 4 construction site. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
On November 1, 2016,costs, in future retail rates. Georgia Power submitted its 2017 NCCR tariff filing requesting that the current NCCR tariff rate remain effective for 2017 ifwill continue working with the Georgia PSC approvesand the other Vogtle Cost Settlement Agreement. Owners to determine future actions related to Plant Vogtle Units 3 and 4, including, but not limited to, the status of construction and rate recovery, and currently expects to include its recommendation in its seventeenth VCM report to be filed with the Georgia PSC in late August 2017.
The ultimate outcome of these matters is dependent on the completion of the assessments described above, as well as the related regulatory treatment, and cannot be determined at this time.
Other Matters
As required under the current order,of June 30, 2017, Georgia Power concurrently submittedhad borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through a 2017 NCCR tariff rate calculated usingloan guarantee agreement between Georgia Power and the current authorized 10.95% ROE,DOE and a multi-advance credit facility among Georgia Power, the DOE, and the FFB. See Note 6 to the financial statements of Southern Company and Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (E) under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
The IRS has allocated PTCs to Plant Vogtle Units 3 and 4 which would resultrequire that the applicable unit be placed in an increaseservice prior to 2021. The net present value of Georgia Power's PTCs is estimated at approximately $70 million.$400 million per unit.
There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise asif 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 asif construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Vogtle Owners or the Contractor or to both.costs.
AsIf 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"Regulatory Matters – Gulf Power – Retail Base Rate Case"Cases" and "Retail Regulatory Matters – Retail Base Rate Case,Cases," respectively, in Item 8 of the Form 10-K for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
In 2013, the Florida PSC approved a settlement agreement (2013 Rate Case Settlement Agreement) that authorized Gulf Power to reduce depreciation and record a regulatory asset up to $62.5 million from January 2014 through June 2017. In any given month, such depreciation reduction maycould not exceed the amount necessary for the retail ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. For 2014 and 2015, Gulf Power recognized reductions in depreciation of $8.4 million and $20.1 million, respectively. No net reduction in depreciation was recorded in 2016. In the third quarter 2016first six months of 2017, Gulf Power recognized the remaining allowable reductions in depreciation totaling $34.0 million.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
On April 4, 2017, the Florida PSC approved the 2017 Rate Case Settlement Agreement among Gulf Power and in accordancethree intervenors with respect to Gulf Power's request to increase retail base rates. Under the 2013terms of the 2017 Rate Case Settlement Agreement, Gulf Power reversed reductions previously recorded to depreciation. As a result, forincreased rates effective with the first nine monthsbilling cycle in July 2017 to provide an annual overall net customer impact of 2016,approximately $54.3 million. The net customer impact consists of a $62.0 million increase in annual base revenues less an annual equivalent credit of approximately $7.7 million for 2017 for certain wholesale revenues to be provided through December 2019 through the net reduction in depreciation was zero.
On October 12, 2016,purchased power capacity cost recovery clause. In addition, Gulf Power filed a petition (2016 Rate Case)continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%), is deemed to have an equity ratio of 52.5% for all retail regulatory purposes, and implemented new dismantlement accruals effective July 1, 2017. Gulf Power will also begin amortizing the regulatory asset associated with the Florida PSC requesting an increaseinvestment balances remaining after the retirement of Plant Smith Units 1 and 2 (357 MWs) over 15 years effective January 1, 2018 and will implement new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs), which was recorded in the first quarter 2017. The remaining issues related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates and chargeshave been resolved as a result of $106.8 million based on the projected test year of January 1, 2017 through December 31, 2017 and a retail ROE of 11% compared to the current retail ROE of 10.25%. TheRate Case Settlement Agreement, including recoverability of thecertain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 will be decided in this matter. The Florida PSC is expected to make a decision on the 2016 Rate Case inunit through the second quarter 2017. Gulf Power has requested that the increase in base rates, ifenvironmental cost recovery clause rate approved by the Florida PSC become effective in July 2017. The ultimate outcome of this matter cannot be determined at this time.November 2016.
Cost Recovery Clauses
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K for additional information regarding Gulf Power's recovery of retail costs through various regulatory clauses and accounting orders. Gulf Power has four regulatory clauses which are approved by the Florida PSC. The balance of each regulatory clause recovery on the balance sheet follows:
| | | Regulatory Clause | Balance Sheet Line Item | September 30,
2016 | December 31, 2015 | Balance Sheet Line Item | June 30,
2017 | December 31,
2016 |
|
| (in millions) |
| (in millions) |
| Fuel Cost Recovery | Other regulatory liabilities, current | $ | 20 |
| $ | 18 |
| Under recovered regulatory clause revenues | $ | 7 |
| $ | — |
|
| Purchased Power Capacity Recovery | Other regulatory liabilities, current | 3 |
| — |
| |
| Fuel Cost Recovery | | Other regulatory liabilities, current | — |
| 15 |
|
| Purchased Power Capacity Recovery | Under recovered regulatory clause revenues | — |
| 1 |
| Under recovered regulatory clause revenues | 5 |
| — |
|
| Environmental Cost Recovery | Other regulatory liabilities, current | 5 |
| — |
| Under recovered regulatory clause revenues | 12 |
| 13 |
|
| Environmental Cost Recovery | Under recovered regulatory clause revenues | — |
| 19 |
| |
| Energy Conservation Cost Recovery | Other regulatory liabilities, current | — |
| 4 |
| Under recovered regulatory clause revenues | 2 |
| 4 |
|
| Energy Conservation Cost Recovery | Under recovered regulatory clause revenues | 2 |
| — |
| |
On November 2, 2016,As discussed previously, the Florida PSC approved2017 Rate Case Settlement Agreement resolved the remaining issues related to Gulf Power's annual rate clause request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2017. The net effectinclusion of the approved changes is a $41 million decrease in annual revenues for 2017. In general, the decreased revenues will not have a significant impact on net income since most of the revenues will be offset by lower expenses. However, certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 were included in the environmental cost recovery clause and no adjustment to the environmental cost recovery clause rate which will have an impact of approximately $11 million and $14 million of additional revenue in 2016 and 2017, respectively. The final disposition of these costs and the related impact on rates is expected to be decidedapproved by the Florida PSC in theNovember 2016 Rate Case as discussed previously. The ultimate outcome of this matter cannot be determined at this time.
Other Matters
As a result of the cost to comply with environmental regulations imposed by the EPA, Gulf Power retired its coal-fired generation at Plant Smith Units 1 and 2 (357 MWs) on March 31, 2016. Gulf Power filed a petition with the
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Florida PSC requesting permission to recover the remaining net book value of Plant Smith Units 1 and 2 and the remaining materials and supplies associated with these units as of the retirement date. In connection with this request, Gulf Power reclassified approximately $63 million to a regulatory asset, including the remaining net book value of the units and the associated materials and supplies. On August 29, 2016, the Florida PSC approved Gulf Power's request to create a regulatory asset and defer the recovery over a period to be decided in the 2016 Rate Case.was made.
Mississippi Power
Energy Efficiency
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Energy Efficiency" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's energy efficiency programs.
On May 3, 2016, the Mississippi PSC issued an order approving the annual Energy Efficiency Cost Rider Compliance filing, which included an anticipated reduction of $2 million in retail revenues for the year ending December 31, 2016.
Performance Evaluation Plan
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Performance Evaluation Plan" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's base rates.
On April 1, 2016,March 15, 2017, Mississippi Power submitted its annual PEP lookback filing for 2015,2016, which reflected the need for a $5 million surcharge to be recovered from customers. The filing has been suspended for review by the Mississippi PSC.
On July 12, 2016, Mississippi Power submitted its annual projected PEP filing for 2016 which indicated no change in rates. The filing has been suspended for review by the Mississippi PSC.
The ultimate outcome of these mattersthis matter cannot be determined at this time.
Environmental Compliance Overview Plan
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Energy Efficiency
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Environmental Compliance Overview Plan"Energy Efficiency" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's ECO Plan.energy efficiency programs.
On July 6, 2017, the Mississippi PSC issued an order approving Mississippi Power's Energy Efficiency Cost Rider compliance filing, which increased annual retail revenues by approximately $2 million effective with the first billing cycle for August 17, 2016,2017.
Environmental Compliance Overview Plan
On May 4, 2017, the Mississippi PSC approved Mississippi Power's revised ECO Plan filing for 2016,2017, which requested the maximum 2% annual increase in revenues, approximately $18 million, primarily related to the 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.June 2017. Approximately $22$26 million of related revenue requirements in excess of the 2% maximum was deferred for inclusion in the 20172018 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 additional information regarding Mississippi Power's retail fuel cost recovery.
At SeptemberJune 30, 2016,2017, the amount of over-recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheetcondensed balance sheet was $58$14 million compared to $71$37 million at December 31, 2015.2016.
TheAd Valorem Tax Adjustment
See Note 3 to the financial statements of Mississippi PSC conditionally approved a decreasePower under "Retail Regulatory Matters – Ad Valorem Tax Adjustment" in Item 8 of $120 million annually in fuel cost recovery rates on January 5, 2016, effective with the first billing cycleForm 10-K for February 2016. additional information regarding Mississippi Power's ad valorem tax adjustments.
On August 17, 2016,July 6, 2017, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment factor filing for 2017, which included an additional decreaseannual rate increase of $510.85%, or $8 million annually in fuel cost recovery rates effective with the first billing cycle for September 2016.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
annual retail revenues, primarily due to increased assessments.
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, changesChanges in the billing factor will not have a significant effect on Southern Company's or Southern Company Gas' revenues or net income, but will affect cash flow.flows.
Base Rate Cases
See Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters – Base Rate Cases" in Item 8 of the Form 10-K for additional information.
Settled Base Rate Cases
On February 21, 2017, the Georgia PSC approved the Georgia Rate Adjustment Mechanism (GRAM) and a $20 million increase in annual base rate revenues for Atlanta Gas Light, effective March 1, 2017. GRAM adjusts base rates annually, up or down, based on the previously approved ROE of 10.75% and does not collect revenue through special riders and surcharges. Various infrastructure programs previously authorized by the Georgia PSC under Atlanta Gas Light's STRIDE program, which include the Integrated Vintage Plastic Replacement Program,
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Integrated System Reinforcement Program, and Integrated Customer Growth Program, will continue under GRAM and the recovery of and return on the infrastructure program investments will be included in annual base rate adjustments. The Georgia PSC will review Atlanta Gas Light's performance annually under GRAM.
Beginning with the next rate adjustment in June 2018, Atlanta Gas Light's recovery of the previously unrecovered Pipeline Replacement Program revenue through 2014, as well as the mitigation costs associated with the Pipeline Replacement Program that were not previously included in its rates, will also be included in GRAM. In connection with the GRAM approval, the last monthly Pipeline Replacement Program surcharge increase became effective March 1, 2017.
In September 2016, Elizabethtown Gas filed a general base rate case with the New Jersey BPU requesting a $19 million increase in annual base rate revenues. The requested increase was based on a projected 12-month test year ending March 31, 2017 and a ROE of 10.25%. On June 30, 2017, the New Jersey BPU approved a settlement that provides for a $13 million increase in annual base rate revenues, effective July 1, 2017, based on a ROE of 9.6%. Also included in the settlement was a new composite depreciation rate that is expected to result in a $3 million annual reduction of depreciation.
Pending Base Rate Cases
On March 10, 2017, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $208 million increase in annual base rate revenues. The requested increase is based on a 2018 projected test year and a ROE of 10.7%. The Illinois Commission is expected to rule on the requested increase within the 11-month statutory time limit, after which rate adjustments will be effective.
On March 31, 2017, Virginia Natural Gas filed a general base rate case with the Virginia Commission requesting a $44 million increase in annual base rate revenues. The requested increase is based on a projected 12-month test year beginning September 1, 2017 and a ROE of 10.25%. The requested increase includes $13 million related to the recovery of investments under the Steps to Advance Virginia's Energy (SAVE) program. The Virginia Commission is expected to rule on the requested increase in the first quarter 2018. Rate adjustments are expected to be effective September 1, 2017, subject to refund.
The ultimate outcome of these pending base rate cases cannot be determined at this time.
Regulatory Infrastructure Programs
Southern Company Gas' natural gas distribution utilities are involvedGas is engaged in ongoing capital projects associated withvarious 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 naturalits gas distribution systems to improve reliability and ensure the safety of its utility infrastructure, and recovers in rates its investment and a return associated with these infrastructure programs. See Note 3 to the financial statements of Southern Company and Southern Company Gas under "Regulatory Matters – Southern Company Gas – Regulatory Infrastructure Programs" and "Regulatory Matters – Regulatory Infrastructure Programs," respectively, in Item 8 of the utilitiesForm 10-K for additional information.
Nicor Gas
In 2014, the Illinois Commission approved Nicor Gas' nine-year regulatory infrastructure program, Investing in Illinois. Under this program, Nicor Gas placed into service $75 million of qualifying assets during the first six months of 2017.
Atlanta Gas Light
Atlanta Gas Light's STRIDE program, which started in 2009, consists of three individual programs that update and expand gas distribution systems and liquefied natural gas facilities as well as improve system reliability to improve safety and reliability and meet operational flexibility and customer growth. Southern CompanyThrough the programs under STRIDE, Atlanta Gas currently has approved infrastructure improvement programs inLight invested $94 million during the first six different states with initial program lengths ranging from four to 10 years,months of 2017.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
In August 2016, Atlanta Gas Light filed a petition with the longest setGeorgia PSC for approval of a four-year extension of its Integrated System Reinforcement Program (i-SRP) seeking approval to expire in 2025. The average annual spend under these programs ranges from $10invest an additional $177 million to $250 million.improve and upgrade its core gas distribution system in years 2017 through 2020.
Southern Company Gas currently hasThe recovery of and return on current and future capital investments under the STRIDE program will be included in the annual base rate revenue adjustment under GRAM rather than a separate surcharge. The proposed infrastructure improvement programs pending approvalcapital investments associated with the extension of i-SRP were included in the 2017 annual base rate revenue under GRAM that was approved by the applicable state regulatory agencies in Georgia andPSC on February 21, 2017. See "Base Rate Cases" herein for additional information.
Elizabethtown Gas
In 2013, the New Jersey requesting average annual spendingBPU approved the extension of $44Elizabethtown Gas' Aging Infrastructure Replacement program, under which Elizabethtown Gas invested $12 million through 2020during the first six months of 2017.
Virginia Natural Gas
In March 2016, the Virginia Commission approved an extension to the SAVE program, under which Virginia Natural Gas invested $14 million during the first six months of 2017.
Florida City Gas
The Florida PSC approved Florida City Gas' Safety, Access, and $110Facility Enhancement program in 2015. Under the program, Florida City Gas invested $7 million through 2027, respectively. The ultimate outcomeduring the first six months of these matters cannot be determined at this time.2017.
Integrated Coal Gasification Combined Cycle
See Note 3 to the financial statements of Southern Company and Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding Mississippi Power's construction of the Kemper IGCC.
Kemper IGCC Overview
The Kemper IGCC willwas designed to utilize an IGCC technology with an expected output capacity of 582 MWs. The Kemper IGCC willMWs and to be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper IGCC, Mississippi Power constructed and plans to operate approximately 61 miles of CO2 pipeline infrastructure for the planned transport of captured CO2 for use in enhanced oil recovery.
Kemper IGCC Schedule and Cost Estimate
In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of grants awarded to the Kemper IGCC project by the DOE under the Clean Coal Power Initiative Round 2 (Initial DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014 and continues to progress towards completing the2014. The remainder of the Kemper IGCC, includingplant includes 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,Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the Kemper IGCC beganproduction of electricity from syngas in both combustion turbines. During testing, using clean syngas from gasifier "A"the plant produced and captured CO2, and produced sulfuric acid and ammonia, each of acceptable quality under 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,off-take agreements. However, Mississippi Power determined a maintenance outage on gasifier "A" is neededexperienced numerous challenges during the extended start-up process to make improvements toachieve integrated operation of the ash removal systems.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Therefore,gasifiers on a sustained basis. Most recently, in May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast has re-sequenced activities,decreased significantly and gasifier "B" is now expected to progress through testingthe estimated cost of operating and begin producing electricitymaintaining the facility during the gasifier "A" outage. In lightfirst five full years of these changes,operations increased significantly since certification.
On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power has determinedto pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC (Kemper Settlement Order). On June 28, 2017, Mississippi Power notified the Mississippi PSC that integrated operation of both gasifiers will not occur by mid-Novemberit would begin a process to suspend operations and has revisedstart-up activities on the expected in-service date for the remaindergasifier portion of the Kemper IGCC, to December 31, 2016. The remaining schedule reflectsgiven the time expected to achieve production of electricity using gasifier "B," complete gasifier "A" outage activities, and resume electricity production using gasifier "A," as welluncertainty as to complete the integration of all systems necessary for both combustion turbines to simultaneously generate electricity with syngas.
Recoveryfuture of the costs subject to the cost cap and the costgasifier portion of the lignite mine and equipment,Kemper IGCC. Mississippi Power expects to continue to operate the costcombined cycle portion 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. Kemper IGCC as it has done since August 2014.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Mississippi Power's Kemper IGCC 2010 project estimate, current cost estimate at the time of project suspension (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 SeptemberJune 30, 20162017, all of which include 100% of the costs for the Kemper IGCC, are as follows:
| | | Cost Category | 2010 Project Estimate(a) | | Current Cost Estimate(b) | | Actual Costs | 2010 Project Estimate(a) | | Cost Estimate at Suspension(b) | | June 30, 2017 Actual Costs |
| | (in billions) | (in billions) |
Plant Subject to Cost Cap(c)(e) | $ | 2.40 |
| | $ | 5.52 |
| | $ | 5.30 |
| $ | 2.40 |
| | $ | 5.95 |
| | $ | 5.68 |
|
| 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(d) | 0.17 |
| | 0.75 |
| | 0.71 |
| 0.17 |
| | 0.85 |
| | 0.85 |
|
Combined Cycle and Related Assets Placed in
Service – Incremental(e) | — |
| | 0.04 |
| | 0.03 |
| — |
| | 0.05 |
| | 0.05 |
|
| General Exceptions | 0.05 |
| | 0.10 |
| | 0.09 |
| 0.05 |
| | 0.10 |
| | 0.08 |
|
Deferred Costs(e) | — |
| | 0.21 |
| | 0.20 |
| — |
| | 0.23 |
| | 0.23 |
|
Additional DOE Grants(f) | — |
| | (0.14 | ) | | (0.14 | ) | — |
| | (0.14 | ) | | (0.14 | ) |
| Total Kemper IGCC | $ | 2.97 |
| | $ | 6.82 |
| | $ | 6.53 |
| $ | 2.97 |
| | $ | 7.38 |
| | $ | 7.09 |
|
| |
| (a) | The 2010 Project Estimate isRepresents 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 inRepresents actual costs through June 30, 2017 and projected costs at the Current Cost Estimate include certaintime of project suspension, including estimated post-in-service costs which arewere expected to be subject to the cost cap. |
| |
| (c) | The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the Initial DOE Grants and excluding the Costcost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions.Exceptions). The Current Cost Estimate at Suspension 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 at Suspension 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 current rates and are being recognized through income; however, such costs continue to be includedremained in the Current Cost Estimate at Suspension and are reflected in the Actual Costs at SeptemberJune 30, 2016.2017. The equity return associated with assets placed in service and other non-CWIP accounts deferred for regulatory purposes, as well as the wholesale portion of debt carrying costs, whether deferred or recognized through income, iswas not included in the Current Cost Estimate andat Suspension or in the Actual Costs at SeptemberJune 30, 2016. See "Rate Recovery of Kemper IGCC Costs – Regulatory Assets2017. At June 30, 2017, such deferred amounts totaled $33 million and Liabilities" herein for additional information. $1 million, respectively. |
| |
| (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$196 million ($54121 million after tax) in the thirdsecond quarter 2016through May 31, 2017 and a total of $222$305 million ($137188 million after tax) for the nine months ended September 30, 2016. Since 2012, inyear-to-date through May 31, 2017. In the aggregate, Mississippi Power has incurred charges of $2.63$3.07 billion ($1.631.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through September 30, 2016.May 31, 2017. The increase to theMay 31, 2017 cost estimate inincluded approximately $175 million of estimated costs to be incurred beyond the third quarter of 2016 primarily reflects $53 million for the extension of the Kemper IGCC's projectedthen-estimated 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 costsJune 30, 2017 that were 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)
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper Settlement Order, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs currently estimated at approximately $100 million to $200 million are expected to be incurred.
In the aggregate, Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC totaling $3.0 billion for the second quarter 2017 and $3.1 billion for the six months ended June 30, 2017.
As of June 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC, of which $1.2 billion is included in plant in service, $14 million in materials and supplies, $22 million in other regulatory assets, current, and $95 million in other regulatory assets, deferred.
Rate Recovery of Kemper IGCC Costs
See "FERC Matters" herein for additional information regarding Mississippi Power's MRA cost based tariff relating to recoveryGiven the variety of a portionpotential scenarios and the uncertainty of the Kemper IGCC costs from Mississippi Power's wholesale customers. Rate recoveryoutcome of the retail portion of the Kemper IGCC is subject to the jurisdiction offuture regulatory proceedings with the Mississippi PSC. See Note (G) under "Unrecognized Tax Benefits – Section 174 Research and Experimental Deduction" for additional tax informationPSC (and any subsequent related tolegal challenges), the Kemper IGCC.
The ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, determinations of prudency, and the specific manner of recovery of prudently-incurred costs, cannot now be determined at this time, but could result in further material charges that could have a material impact on Southern Company's and Mississippi Power's results of operations, financial condition, and liquidity.
2012 MPSC CPCNKemper IGCC Settlement Docket
On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC. The Kemper Settlement Order
The 2012 MPSC CPCN Order included provisions relating to both Mississippi Power's recovery established a new docket for the purposes of financingpursuing a global settlement of costs during the course of construction of the Kemper IGCC (Kemper IGCC Settlement Docket). The Mississippi PSC requested any such proposed settlement agreement reflect: (i) at a minimum, no rate increase to Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and related assets; and (iii) modification or amendment of the CPCN for the Kemper IGCC to allow only for ownership and operation of a natural gas facility. The Kemper Settlement Order provides that any related settlement agreement be filed within 45 days from the effective date of the Kemper Settlement Order. If a settlement agreement is filed, a hearing will be set 45 days from the date of the settlement's filing, and the appropriate scheduling order will be established.
Although the ability to achieve a negotiated settlement is uncertain, Mississippi Power intends to pursue any available settlement alternatives. In addition, the Kemper Settlement Order provides that, in the event a settlement agreement is not reached, the Mississippi PSC reserves its right to take any appropriate steps, including issuing an order to show cause as to why the CPCN for the Kemper IGCC should not be revoked.
On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014.
At June 30, 2017, approximately $3.3 billion in actual Kemper IGCC costs were not reflected in Mississippi Power's retail and wholesale rates, of which $0.5 billion was related to the combined cycle and associated facilities and $2.8 billion was related to the gasification portions of the Kemper IGCC.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper Settlement Order, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs followingassociated with the dategasification portions of the plant and lignite mine. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs currently estimated at approximately $100 million to $200 million are expected to be incurred.
As of June 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which $0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility, as well as the 15% that was previously contracted to SMEPA. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.
Prudence
On August 17, 2016, the Mississippi PSC issued an order establishing a discovery docket to manage all filings related to the prudence of the Kemper IGCC. On October 3, 2016, Mississippi Power made a required compliance filing, which included a review and explanation of differences between the Kemper IGCC project estimate set forth in the 2010 CPCN proceedings and the most recent Kemper IGCC project estimate, as well as comparisons of current cost estimates and current expected plant operational parameters to the estimates presented in the 2010 CPCN proceedings for the first five years after the Kemper IGCC is placed in service. With respectCompared to recoveryamounts presented in the 2010 CPCN proceedings, operations and maintenance expenses have increased an average of $105 million annually and maintenance capital has increased an average of $44 million annually for the first full five years of operations for the Kemper IGCC. Additionally, while the current estimated operational availability estimates reflect ultimate results similar to those presented in the 2010 CPCN proceedings, the ramp up period for the current estimates reflects a lower starting point and a slower escalation rate. On November 17, 2016, Mississippi Power submitted a supplemental filing to the October 3, 2016 compliance filing to present revised non-fuel operations and maintenance expense projections for the first year after the Kemper IGCC is placed in service. This supplemental filing included approximately $68 million in additional estimated operations and maintenance costs followingexpected to be required to support the in-service dateoperations of the Kemper IGCC during that period.
Mississippi Power responded to numerous requests for information from interested parties in 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.discovery docket, which is now complete. Mississippi Power expects the Mississippi PSC to apply operational parametersutilize this information in connection with future proceedings related to the operationultimate resolution of Kemper IGCC cost recovery.
Economic Viability Analysis
In the fourth quarter 2016, as a part of its Integrated Resource Plan process, the Southern Company system completed its regular annual updated fuel forecast, the 2017 Annual Fuel Forecast. This updated fuel forecast reflected significantly lower long-term estimated costs for natural gas than were previously projected. As a result of the updated long-term natural gas forecast, as well as the revised operating expense projections reflected in the discovery docket filings discussed above, on February 21, 2017, Mississippi Power filed an updated project economic viability analysis of the Kemper IGCC as required under the 2012 MPSC CPCN Order confirming authorization of the Kemper IGCC. ToThe project economic viability analysis measures the life cycle economics of the Kemper IGCC compared to feasible alternatives, natural gas combined cycle generating units, under a variety of scenarios and considering fuel, operating and capital costs, and operating characteristics, as well as federal and state taxes and incentives. The reduction in the projected long-term natural gas prices in the 2017 Annual Fuel Forecast
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
and, to a lesser extent, the increase in the estimated Kemper IGCC operating costs, negatively impact the updated project economic viability analysis.
Mississippi Power expects the Mississippi PSC determinesto address this matter in connection with the Kemper IGCC does not meet the operational parameters ultimately adopted bySettlement Docket.
2015 Rate Case
On August 13, 2015, the Mississippi PSC orapproved Mississippi Power's request for interim rates, which presented an alternative rate proposal (In-Service Asset Proposal) designed to recover Mississippi Power's costs associated with the Kemper IGCC assets that are commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The interim rates were designed to collect approximately $159 million annually and became effective in September 2015, subject to refund and certain other conditions.
On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order adopting in full a stipulation (2015 Stipulation) entered into between Mississippi Power incurs additional costs to satisfy such parameters, there could be a material adverse impactand 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 Southern Company's or Mississippi Power's financial statements.actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The In-Service Asset Rate Order also included a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets. The stipulated revenue requirement excluded the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by SMEPA but reserved Mississippi Power's right to seek recovery in a future proceeding. See "Prudence""Termination of Proposed Sale of Undivided Interest" herein for additional information. 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.
In 2011, the Mississippi PSC authorized Mississippi Power to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date. In connection with the implementation of the In-Service Asset Order and wholesale rates, Mississippi Power began expensing certain ongoing project costs and certain retail debt carrying costs that previously were deferred and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees. The amortization periods for these regulatory assets vary from two years to 10 years as set forth in the In-Service Asset Rate Order and the settlement agreement with wholesale customers. As of June 30, 2017, the balance associated with these regulatory assets was $117 million, of which $22 million is included in current assets. See "FERC Matters" herein for additional information related to the 2016 settlement agreement with wholesale customers.
The In-Service Asset Rate Order requires Mississippi Power to submit an annual true-up calculation of its actual cost of capital, compared to the stipulated total cost of capital, with the first occurring as of May 31, 2016. At June 30, 2017, Mississippi Power's related regulatory liability included in its balance sheet totaled approximately $10 million.
As required by the In-Service Asset Rate Order, on June 5, 2017, Mississippi Power made a rate filing requesting to adjust the amortization schedules of the regulatory assets reviewed and determined prudent in the In-Service Asset Order in a manner that would not change customer rates or annual revenues. On June 28, 2017, the Mississippi PSC suspended this filing. On July 6, 2017, the Mississippi PSC issued an order requiring Mississippi Power to establish a regulatory liability account to maintain current rates related to the Kemper IGCC following the July 2017 completion of the amortization period for certain regulatory assets approved in the In-Service Asset Rate Order that would allow for subsequent refund if the Mississippi PSC deems the rates unjust and unreasonable.
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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 iswas 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 basedand, 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 previously 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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
2015 Rate Case
On August 13, 2015, the Mississippi PSC approved Mississippi Power's request for interim rates, which presented an alternative rate proposal (In-Service Asset Proposal) designed to recover Mississippi Power's costs associated with the Kemper IGCC assets that are commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The interim rates were designed to collect approximately $159 million annually and became effective with the first billing cycle for September 2015, subject to refund and certain other conditions.
On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order adopting in full a stipulation entered into between Mississippi Power and the Mississippi Public Utilities Staff (MPUS) regarding the In-Service Asset Proposal. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The In-Service Asset Rate Order also included a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets. The stipulated revenue requirement excluded the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by SMEPA. Mississippi Power continues to evaluate its alternatives with respect to its investment and related costs associated with the 15% undivided interest.
With implementation of the new rates on December 17, 2015, the interim rates were terminated and, in March 2016, Mississippi Power completed customer refunds of approximately $11 million for the difference between the interim rates collected and the permanent rates.
On July 27, 2016, the Court dismissed Greenleaf CO2 Solutions, LLC (Greenleaf) motion for reconsideration of its previous decision to dismiss Greenleaf's appeal of the In-Service Asset Rate Order.
In addition to current estimated costs at September 30, 2016 of $6.82 billion, Mississippi Power anticipates that it will incur additional expenses in excess of current rates associated with operating the Kemper IGCC after it is placed in service until the Kemper IGCC cost recovery approach is finalized, which are expected to be material. These costs include, but are not limited to, regulatory costs, operational costs in excess of current rates, taxes, and additional carrying costs. Mississippi Power expects to request authority from the Mississippi PSC and the FERC to defer all Kemper IGCC costs incurred after the in-service date that cannot be capitalized, are not included in current rates, and are not required to be charged against earnings as a result of the $2.88 billion cost cap until such time as the Mississippi PSC completes its review and includes the resulting allowable costs in rates. Mississippi Power is required to file its next rate request with the Mississippi PSC related to cost recovery for the Kemper IGCC by June 3, 2017. See "Regulatory Assets and Liabilities" below for additional information. As part of that filing, Mississippi Power expects to request recovery of certain costs that the Mississippi PSC had excluded from the revenue requirement calculation for the in-service assets.
Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law in 2013. Mississippi Power expects to securitize prudently-incurred qualifying facility costs in excess of the certificated cost estimate of $2.4 billion. Qualifying facility costs include, but are not limited to, pre-construction costs, construction costs, regulatory costs, and accrued AFUDC. The Court's decision regardingBecause the 2013 MPSC Rate Order did not impactprovide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power's abilityPower continued to utilize alternate financing through securitization orrecord AFUDC on the February 2013 legislation.
Prudence
On August 17, 2016,Kemper IGCC. Between the original May 2014 estimated in-service date and the June 2017 project suspension date, Mississippi PSC issued an order establishing a discovery docketPower recorded $493 million of AFUDC on the Kemper IGCC subject to manage all filingsthe $2.88 billion cost cap and Cost Cap Exception amounts, of which $459 million related to the prudencegasification portions 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,this matter 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.Settlement Docket.
Lignite Mine and CO2 Pipeline Facilities
In conjunction with the Kemper IGCC, Mississippi Power will ownowns the lignite mine and equipment and has acquired and will continue to acquire mineral reserves located around the Kemper IGCC site. The mine started commercial operation in June 2013.
In 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is operating and managingresponsible for the mining operations. The contract with Liberty Fuels is effectiveoperations through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. In addition to the obligation to fund the reclamation activities, Mississippi Power currently provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. See
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Note 1 to the financial statements of Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" and "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.
In addition, Mississippi Power has constructed and will operate the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery. Mississippi Power entered into agreements with Denbury Onshore (Denbury) and Treetop Midstream Services, LLC (Treetop), pursuant to which Denbury would purchase 70% of the CO2 captured from the Kemper IGCC and Treetop would purchase 30% of the CO2 captured from the Kemper IGCC. On June 3, 2016, Mississippi Power cancelled its contract with Treetop and amended its contract with Denbury to reflect, among other things, Denbury's agreement to purchase 100% of the CO2 captured from the Kemper IGCC and an initial contract term of 16 years, and termination rights ifyears. Denbury has the right to terminate the contract at any time because Mississippi Power hasdid not satisfied its contractual obligation to deliver captured CO2place the Kemper IGCC in service 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.2017.
The ultimate outcome of these matters cannot be determined at this time.
Termination of Proposed Sale of Undivided Interest
In 2010 and as amended in 2012, Mississippi Power and SMEPA entered into an agreement whereby SMEPA agreed to purchase a 15% undivided interest in the Kemper IGCC (15% Undivided Interest). On May 20, 2015, SMEPA notified Mississippi Power of its termination of the agreement. Mississippi Power previously received a total of $275 million of deposits from SMEPA that were required to be returned to SMEPA with interest. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to SMEPA.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Subsequently, Mississippi Power issued a promissory note in the aggregate principal amount of approximately $301 million to Southern Company, which was repaid in June 2017.
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 23, 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the plaintiffs filed notice to appeal to the Court.
On June 9, 2016, Treetop, Greenleaf CO2 Solutions, LLC (Greenleaf), Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint relates to the cancelled CO2 contract with Treetop and alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and seeks compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS have moved to compel arbitration pursuant to the terms of the CO2 contract.contract, which the court granted on May 4, 2017. On June 28, 2017, Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a claim for arbitration requesting $500 million in damages.
Southern Company and Mississippi Power believe these legal challenges have no merit; however, an adverse outcome in these proceedings could impact Southern Company's results of operations, financial condition, and liquidity and could have a material impact on Southern Company's and Mississippi Power's results of operations, financial condition, and liquidity. Southern Company and Mississippi Power will vigorously defend themselves in these matters, and the ultimate outcome of these matters cannot be determined at this time.
Baseload Act
In 2008, the Baseload Act was signed by the Governor of Mississippi. The Baseload Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism that includes in retail base rates, prior to and during construction, all or a portion of the prudently-incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passage of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews by the Mississippi PSC and prohibits the cancellation of any such generating plant without the approval of the Mississippi PSC. In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery for costs incurred in connection with such cancelled generating plant.
Income Tax Matters
See Note 3 to the financial statements of Southern Company and Mississippi Power under "Integrated Coal Gasification Combined Cycle – Bonus Depreciation," " – Investment Tax Credits," and " – Section 174 Research and Experimental Deduction" in Item 8 of the Form 10-K and Note (G) under "Section 174 Research and
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
179(UNAUDITED)
Experimental Deduction" for additional information on bonus depreciation, investment tax credits, and the Section 174 research and experimental deduction.
Approximately $370 million of Contentspositive cash flows is expected to result from bonus depreciation for the 2017 tax year, but may not all be realized in 2017 due to net operating loss projections for the 2017 tax year, and is dependent upon placing the remainder of the Kemper IGCC in service by December 31, 2017. If the suspension of the Kemper IGCC start-up activities results in an abandonment, any amount previously estimated as bonus depreciation would be claimed as a deduction under IRC Section 165. As of June 30, 2017, $82 million has been received through quarterly income tax refunds for bonus depreciation related to the Kemper IGCC, which may be subject to repayment. See Note (G) for additional information. The ultimate outcome of this matter cannot be determined at this time.
Section 174 Research and Experimental Deduction
Southern Company, on behalf of Mississippi Power, has reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, subject to approval of the U.S. Congress Joint Committee on Taxation, resolving a methodology for these deductions. Due to the uncertainty related to this tax position, Southern Company and Mississippi Power had unrecognized tax benefits associated with these R&E deductions totaling approximately $464 million as of June 30, 2017. If the suspension of the Kemper IGCC start-up activities results in an abandonment, any amount not allowed under IRC Section 174 would be claimed as a deduction under IRC Section 165, and would result in a reversal of the related unrecognized tax benefits, excluding interest. See Note (G) for additional information. This matter is expected to be resolved in the next 12 months; however, the ultimate outcome of this matter cannot be determined at this time.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| |
| (C) | FAIR VALUE MEASUREMENTS |
As of SeptemberJune 30, 2016,2017, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
|
| | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using | | |
| As of September 30, 2016: | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Net Asset Value as a Practical Expedient (NAV) | | Total |
| | (in millions) |
| Southern Company | | | | | | | | | |
| Assets: | | | | | | | | | |
Energy-related derivatives(a) | $ | 203 |
| | $ | 190 |
| | $ | — |
| | $ | — |
| | $ | 393 |
|
| Interest rate derivatives | — |
| | 19 |
| | — |
| | — |
| | 19 |
|
| Foreign currency derivatives | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
Nuclear decommissioning trusts(b) | 660 |
| | 938 |
| | — |
| | 18 |
| | 1,616 |
|
| Cash equivalents | 1,680 |
| | — |
| | — |
| | — |
| | 1,680 |
|
| Other investments | 9 |
| | — |
| | 1 |
| | — |
| | 10 |
|
| Total | $ | 2,552 |
| | $ | 1,170 |
| | $ | 1 |
| | $ | 18 |
| | $ | 3,741 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | 267 |
| | $ | 274 |
| | $ | — |
| | $ | — |
| | $ | 541 |
|
| Interest rate derivatives | — |
| | 7 |
| | — |
| | — |
| | 7 |
|
| Foreign currency derivatives | — |
| | 24 |
| | — |
| | — |
| | 24 |
|
| Contingent consideration | — |
| | — |
| | 18 |
| | — |
| | 18 |
|
| Total | $ | 267 |
| | $ | 305 |
| | $ | 18 |
| | $ | — |
| | $ | 590 |
|
| | | | | | | | | | |
| Alabama Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | 8 |
|
Nuclear decommissioning trusts(c) | | | | | | | | |
|
|
| Domestic equity | 373 |
| | 72 |
| | — |
| | — |
| | 445 |
|
| Foreign equity | 49 |
| | 49 |
| | — |
| | — |
| | 98 |
|
| U.S. Treasury and government agency securities | — |
| | 22 |
| | — |
| | — |
| | 22 |
|
| Corporate bonds | 22 |
| | 148 |
| | — |
| | — |
| | 170 |
|
| Mortgage and asset backed securities | — |
| | 21 |
| | — |
| | — |
| | 21 |
|
| Private Equity | — |
| | — |
| | — |
| | 18 |
| | 18 |
|
| Other | — |
| | 7 |
| | — |
| | — |
| | 7 |
|
| Cash equivalents | 410 |
| | — |
| | — |
| | — |
| | 410 |
|
| Total | $ | 854 |
| | $ | 327 |
| | $ | — |
| | $ | 18 |
| | $ | 1,199 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 21 |
| | $ | — |
| | $ | — |
| | $ | 21 |
|
Table of Contents |
| | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using: | | |
| As of June 30, 2017: | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Net Asset Value as a Practical Expedient (NAV) | | Total |
| | (in millions) |
| Southern Company | | | | | | | | | |
| Assets: | | | | | | | | | |
Energy-related derivatives(a)(b) | $ | 193 |
| | $ | 179 |
| | $ | — |
| | $ | — |
| | $ | 372 |
|
| Interest rate derivatives | — |
| | 11 |
| | — |
| | — |
| | 11 |
|
| Foreign currency derivatives | — |
| | 56 |
| | — |
| | — |
| | 56 |
|
Nuclear decommissioning trusts(c) | 728 |
| | 966 |
| | — |
| | 25 |
| | 1,719 |
|
| Cash equivalents | 834 |
| | — |
| | — |
| | — |
| | 834 |
|
| Other investments | 9 |
| | — |
| | 1 |
| | — |
| | 10 |
|
| Total | $ | 1,764 |
| | $ | 1,212 |
| | $ | 1 |
| | $ | 25 |
| | $ | 3,002 |
|
| Liabilities: | | | | | | | | | |
Energy-related derivatives(a)(b) | $ | 205 |
| | $ | 161 |
| | $ | — |
| | $ | — |
| | $ | 366 |
|
| Interest rate derivatives | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
| Foreign currency derivatives | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
| Contingent consideration | — |
| | — |
| | 20 |
| | — |
| | 20 |
|
| Total | $ | 205 |
| | $ | 207 |
| | $ | 20 |
| | $ | — |
| | $ | 432 |
|
| | | | | | | | | | |
| Alabama Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 9 |
| | $ | — |
| | $ | — |
| | $ | 9 |
|
Nuclear decommissioning trusts:(d) | | | | | | | | |
|
|
| Domestic equity | 411 |
| | 79 |
| | — |
| | — |
| | 490 |
|
| Foreign equity | 56 |
| | 54 |
| | — |
| | — |
| | 110 |
|
| U.S. Treasury and government agency securities | — |
| | 29 |
| | — |
| | — |
| | 29 |
|
| Corporate bonds | 22 |
| | 145 |
| | — |
| | — |
| | 167 |
|
| Mortgage and asset backed securities | — |
| | 18 |
| | — |
| | — |
| | 18 |
|
| Private Equity | — |
| | — |
| | — |
| | 25 |
| | 25 |
|
| Other | — |
| | 6 |
| | — |
| | — |
| | 6 |
|
| Cash equivalents | 493 |
| | — |
| | — |
| | — |
| | 493 |
|
| Total | $ | 982 |
| | $ | 340 |
| | $ | — |
| | $ | 25 |
| | $ | 1,347 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 11 |
| | $ | — |
| | $ | — |
| | $ | 11 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using | | |
| As of September 30, 2016: | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Net Asset Value as a Practical Expedient (NAV) | | Total |
| | (in millions) |
| Georgia Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 15 |
| | $ | — |
| | $ | — |
| | $ | 15 |
|
| Interest rate derivatives | — |
| | 10 |
| | — |
| | — |
| | 10 |
|
Nuclear decommissioning trusts(c) (d) | | | | | | | | | |
| Domestic equity | 197 |
| | 1 |
| | — |
| | — |
| | 198 |
|
| Foreign equity | — |
| | 125 |
| | — |
| |
|
| | 125 |
|
| U.S. Treasury and government agency securities | — |
| | 59 |
| | — |
| | — |
| | 59 |
|
| Municipal bonds | — |
| | 70 |
| | — |
| | — |
| | 70 |
|
| Corporate bonds | — |
| | 172 |
| | — |
| | — |
| | 172 |
|
| Mortgage and asset backed securities | — |
| | 149 |
| | — |
| | — |
| | 149 |
|
| Other | 19 |
| | 43 |
| | — |
| | — |
| | 62 |
|
| Cash equivalents | 32 |
| | — |
| | — |
| | — |
| | 32 |
|
| Total | $ | 248 |
| | $ | 644 |
| | $ | — |
| | $ | — |
| | $ | 892 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 16 |
| | $ | — |
| | $ | — |
| | $ | 16 |
|
| | | | | | | | | | |
| Gulf Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
| Cash equivalents | 20 |
| | — |
| | — |
| | — |
| | 20 |
|
| Total | $ | 20 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 21 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 51 |
| | $ | — |
| | $ | — |
| | $ | 51 |
|
| Interest rate derivatives | — |
| | 6 |
| | — |
| | — |
| | 6 |
|
| Total | $ | — |
| | $ | 57 |
| | $ | — |
| | $ | — |
| | $ | 57 |
|
| | | | | | | | | | |
| Mississippi Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
| Cash equivalents | 137 |
| | — |
| | — |
| | — |
| | 137 |
|
| Total | $ | 137 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 138 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 21 |
| | $ | — |
| | $ | — |
| | $ | 21 |
|
| Interest rate derivatives | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
| Total | $ | — |
| | $ | 22 |
| | $ | — |
| | $ | — |
| | $ | 22 |
|
| | | | | | | | | | |
Table of Contents |
| | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using: | | |
| As of June 30, 2017: | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Net Asset Value as a Practical Expedient (NAV) | | Total |
| | (in millions) |
| Georgia Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 15 |
| | $ | — |
| | $ | — |
| | $ | 15 |
|
| Interest rate derivatives | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Nuclear decommissioning trusts:(d) (e) | | | | | | | | | |
| Domestic equity | 225 |
| | 1 |
| | — |
| | — |
| | 226 |
|
| Foreign equity | — |
| | 147 |
| | — |
| | — |
| | 147 |
|
| U.S. Treasury and government agency securities | — |
| | 198 |
| | — |
| | — |
| | 198 |
|
| Municipal bonds | — |
| | 72 |
| | — |
| | — |
| | 72 |
|
| Corporate bonds | — |
| | 169 |
| | — |
| | — |
| | 169 |
|
| Mortgage and asset backed securities | — |
| | 41 |
| | — |
| | — |
| | 41 |
|
| Other | 14 |
| | 7 |
| | — |
| | — |
| | 21 |
|
| Cash equivalents | 50 |
| | — |
| | — |
| | — |
| | 50 |
|
| Total | $ | 289 |
| | $ | 651 |
| | $ | — |
| | $ | — |
| | $ | 940 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 14 |
| | $ | — |
| | $ | — |
| | $ | 14 |
|
| Interest rate derivatives | — |
| | 3 |
| | — |
| | — |
| | 3 |
|
| Total | $ | — |
| | $ | 17 |
| | $ | — |
| | $ | — |
| | $ | 17 |
|
| | | | | | | | | | |
| Gulf Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
| Cash equivalents | 21 |
| | — |
| | — |
| | — |
| | 21 |
|
| Total | $ | 21 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 22 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 29 |
| | $ | — |
| | $ | — |
| | $ | 29 |
|
| | | | | | | | | | |
| Mississippi Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 2 |
|
| Interest rate derivatives | — |
| | 3 |
| | — |
| | — |
| | 3 |
|
| Cash equivalents | 100 |
| | — |
| | — |
| | — |
| | 100 |
|
| Total | $ | 100 |
| | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | 105 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 10 |
| | $ | — |
| | $ | — |
| | $ | 10 |
|
| | | | | | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| | | | Fair Value Measurements Using | | | Fair Value Measurements Using: | | |
| As of September 30, 2016: | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Net Asset Value as a Practical Expedient (NAV) | | Total | |
| As of June 30, 2017: | | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Net Asset Value as a Practical Expedient (NAV) | | Total |
| | (in millions) | (in millions) |
| Southern Power | | | | | | | | | | | | | | | | | | |
| Assets: | | | | | | | | | | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 3 |
| $ | — |
| | $ | 14 |
| | $ | — |
| | $ | — |
| | $ | 14 |
|
| Foreign currency derivatives | — |
| | 23 |
| | — |
| | — |
| | 23 |
| — |
| | 56 |
| | — |
| | — |
| | 56 |
|
| Cash equivalents | 647 |
| | — |
| | — |
| | — |
| | 647 |
| |
| Total | $ | 647 |
| | $ | 26 |
| | $ | — |
| | $ | — |
| | $ | 673 |
| $ | — |
| | $ | 70 |
| | $ | — |
| | $ | — |
| | $ | 70 |
|
| Liabilities: | | | | | | | | | | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 3 |
| $ | — |
| | $ | 9 |
| | $ | — |
| | $ | — |
| | $ | 9 |
|
| Foreign currency derivatives | — |
| | 24 |
| | — |
| | — |
| | 24 |
| — |
| | 23 |
| | — |
| | — |
| | 23 |
|
| Contingent consideration | — |
| | — |
| | 18 |
| | — |
| | 18 |
| — |
| | — |
| | 20 |
| | — |
| | 20 |
|
| Total | $ | — |
|
| $ | 27 |
|
| $ | 18 |
|
| $ | — |
|
| $ | 45 |
| $ | — |
|
| $ | 32 |
|
| $ | 20 |
|
| $ | — |
|
| $ | 52 |
|
| | | | | | | | | | | |
| Southern Company Gas | | | | | | | | | | |
| Assets: | | | | | | | | | | |
Energy-related derivatives(a)(b) | | $ | 193 |
| | $ | 138 |
| | $ | — |
| | $ | — |
| | $ | 331 |
|
| Liabilities: | | | | | | | | | | |
Energy-related derivatives(a)(b) | | $ | 205 |
| | $ | 86 |
| | $ | — |
| | $ | — |
| | $ | 291 |
|
| |
| (a) | Excludes $7$11 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value. |
| |
| (b) | Excludes cash collateral of $71 million. |
| |
| (c) | For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table. |
| |
(c)(d) | Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. |
| |
(d)(e) | Includes the investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of SeptemberJune 30, 2016,2017, approximately $42$38 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$55 million and $116$118 million, respectively, for the three and ninesix months ended SeptemberJune 30, 2016,2017, and decreased by $65$47 million and $33$67 million, respectively, for the three and ninesix months ended SeptemberJune 30, 2015.2016. Alabama Power recorded an increase in fair value of $26$28 million and $66$62 million, respectively, for the three and six months ended June 30, 2017 and $29 million and $40 million, respectively, for the three and ninesix months ended SeptemberJune 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 increaseincreases in fair value of $23$27 million and $50$56 million, respectively, for the three and ninesix months ended SeptemberJune 30, 20162017 and a decrease in fair value of $26$18 million and $14$27 million, respectively, for the three and ninesix months ended SeptemberJune 30, 20152016 as a change in its regulatory asset related to its AROs.
Valuation Methodologies
The energy-related derivatives primarily consist of exchange-traded and over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The fair value of cross-currency swaps reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputs to the net present
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
value calculation may include the contract terms, counterparty credit risk, and discount rates. The interest rate derivatives and cross-currency swaps are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note (H) for additional information on how these derivatives are used.
The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. For fair value measurements of the investments within the nuclear decommissioning trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgments, are also obtained when available. See Note 1 to the financial statements of Southern Company, Alabama Power, and Georgia Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.
Southern Power has contingent payment obligations related to certain acquisitions whereby Southern Power is obligated to paymake generation-based payments to the seller over a 10-year period ranging from 10 to 30 years, beginning at the commercial operation date. The obligation is measured atcategorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs such asfor the forecasted facility generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate, and is evaluated periodically. The fair value of contingent consideration reflects the net present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial.
"Other investments" include investments that are not traded in the open market. The fair value of these investments havehas been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan executions.
As of SeptemberJune 30, 2016,2017, the fair value measurements of private equity investments held in the nuclear decommissioning trust that are calculated at net asset value per share (or its equivalent) as a practical expedient, as well as the nature and risks of those investments, were as follows:
| | | As of September 30, 2016: | Fair Value | | Unfunded Commitments | | Redemption Frequency | | Redemption Notice Period | |
| As of June 30, 2017: | | Fair Value | | Unfunded Commitments | | Redemption Frequency | | Redemption Notice Period |
| | (in millions) | | (in millions) | |
| Southern Company | $ | 18 |
| | $ | 27 |
| | Not Applicable | | Not Applicable | $ | 25 |
| | $ | 22 |
| | Not Applicable | | Not Applicable |
| Alabama Power | $ | 18 |
| | $ | 27 |
| | Not Applicable | | Not Applicable | $ | 25 |
| | $ | 22 |
| | Not Applicable | | Not Applicable |
Private equity funds include a fund-of-funds that invests in high-quality private equity funds across several market sectors, a fundfunds that investsinvest in real estate assets, and a fund that acquires companies to create resale value. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated. Liquidations are expected to occur at various times over the next ten10 years.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
As of SeptemberJune 30, 2016,2017, other financial instruments for which the carrying amount did not equal fair value were as follows:
| | | | Carrying Amount | | Fair Value | Carrying Amount | | Fair Value |
| | (in millions) | (in millions) |
| Long-term debt, including securities due within one year: | | | | | | |
| Southern Company | $ | 43,668 |
| | $ | 47,227 |
| $ | 46,631 |
| | $ | 48,228 |
|
| Alabama Power | $ | 7,091 |
| | $ | 7,961 |
| $ | 7,440 |
| | $ | 8,041 |
|
| Georgia Power | $ | 10,398 |
| | $ | 11,582 |
| $ | 10,888 |
| | $ | 11,585 |
|
| Gulf Power | $ | 1,184 |
| | $ | 1,267 |
| $ | 1,292 |
| | $ | 1,336 |
|
| Mississippi Power | $ | 2,981 |
| | $ | 2,967 |
| $ | 2,125 |
| | $ | 2,071 |
|
| Southern Power | $ | 4,608 |
| | $ | 4,821 |
| $ | 5,725 |
| | $ | 5,878 |
|
| Southern Company Gas | | $ | 5,699 |
| | $ | 6,031 |
|
The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to the registrants.Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas.
Earnings per Share
For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under the stock option and performance share plans. See Note 8 to the financial statements of Southern Company in Item 8 of the Form 10-K for information on the stock option and performance share plans. The effect of both stock options and performance share award units was determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:
| | | | Three Months Ended September 30, 2016 |
| Three Months Ended September 30, 2015 | | Nine Months Ended September 30, 2016 | | Nine Months Ended September 30, 2015 | Three Months Ended June 30, 2017 | Three Months Ended June 30, 2016 | Six Months Ended June 30, 2017 | Six Months Ended June 30, 2016 |
| | (in millions) | (in millions) |
| As reported shares | 968 |
| | 910 |
| | 940 |
| | 910 |
| 998 |
| 934 |
| 996 |
| 925 |
|
| Effect of options and performance share award units | 7 |
| | 2 |
| | 5 |
| | 3 |
| 7 |
| 6 |
| 7 |
| 6 |
|
| Diluted shares | 975 |
| | 912 |
| | 945 |
| | 913 |
| 1,005 |
| 940 |
| 1,003 |
| 931 |
|
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 six months ended SeptemberJune 30, 20162017 and were 15 million and 1 million for the three and nine months ended September 30, 2015, respectively.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Changes in Stockholders' Equity
The following table presents year-to-date changes in stockholders' equity of Southern Company:
| | | | Number of Common Shares | | Common
Stockholders'
Equity | Preferred and Preference Stock of Subsidiaries | | | Total
Stockholders'
Equity | Number of Common Shares | | Common
Stockholders'
Equity | Preferred and Preference Stock of Subsidiaries | | Total
Stockholders'
Equity |
| | Issued | Treasury | | Noncontrolling Interests(*) | | Issued | Treasury | | Noncontrolling Interests(*) |
| | | (in thousands) | | (in millions) |
| Balance at December 31, 2016 | | 991,213 |
| (819 | ) | | $ | 24,758 |
| $ | 609 |
| $ | 1,245 |
| $ | 26,612 |
|
| Consolidated net income (loss) attributable to Southern Company | | — |
| — |
| | (723 | ) | — |
| — |
| (723 | ) |
| Other comprehensive income (loss) | | — |
| — |
| | (11 | ) | — |
| — |
| (11 | ) |
| Stock issued | | 9,129 |
| — |
| | 417 |
| — |
| — |
| 417 |
|
| Stock-based compensation | | — |
| — |
| | 72 |
| — |
| — |
| 72 |
|
| Cash dividends on common stock | | — |
| — |
| | (1,134 | ) | — |
| — |
| (1,134 | ) |
| Preference stock redemption | | — |
| — |
| | — |
| (150 | ) | — |
| (150 | ) |
| Contributions from noncontrolling interests | | — |
| — |
| | — |
|
|
| 71 |
| 71 |
|
| Distributions to noncontrolling interests | | — |
| — |
| | — |
| — |
| (40 | ) | (40 | ) |
| Net income attributable to noncontrolling interests | | — |
| — |
| | — |
| — |
| 16 |
| 16 |
|
| Reclassification from redeemable noncontrolling interests | | — |
| — |
| | — |
| — |
| 114 |
| 114 |
|
| Other | | — |
| (49 | ) | | (7 | ) | 3 |
| 1 |
| (3 | ) |
| Balance at June 30, 2017 | | 1,000,342 |
| (868 | ) | | $ | 23,372 |
| $ | 462 |
| $ | 1,407 |
| $ | 25,241 |
|
| | (in thousands) | | (in millions) | | | |
| Balance at December 31, 2015 | 915,073 |
| (3,352 | ) | | $ | 20,592 |
| $ | 609 |
| $ | 781 |
| | $ | 21,982 |
| 915,073 |
| (3,352 | ) | | $ | 20,592 |
| $ | 609 |
| $ | 781 |
| $ | 21,982 |
|
| Consolidated net income attributable to Southern Company | — |
| — |
| | 2,226 |
| — |
| — |
| | 2,226 |
| — |
| — |
| | 1,112 |
| — |
| — |
| 1,112 |
|
| Other comprehensive income (loss) | — |
| — |
| | (95 | ) | — |
| — |
| | (95 | ) | — |
| — |
| | (117 | ) | — |
| — |
| (117 | ) |
| Stock issued | 65,725 |
| 2,599 |
| | 3,265 |
| — |
| — |
| | 3,265 |
| 27,297 |
| 2,599 |
| | 1,383 |
| — |
| — |
| 1,383 |
|
| Stock-based compensation | — |
| — |
| | 119 |
| — |
| — |
| | 119 |
| — |
| — |
| | 67 |
| — |
| — |
| 67 |
|
| Cash dividends on common stock | — |
| — |
| | (1,553 | ) | — |
| — |
| | (1,553 | ) | — |
| — |
| | (1,023 | ) | — |
| — |
| (1,023 | ) |
| Contributions from noncontrolling interests | — |
| — |
| | — |
| — |
| 357 |
| | 357 |
| — |
| — |
| | — |
| — |
| 169 |
| 169 |
|
| Distributions to noncontrolling interests | — |
| — |
| | — |
| — |
| (21 | ) | | (21 | ) | — |
| — |
| | — |
| — |
| (10 | ) | (10 | ) |
| Purchase of membership interests from noncontrolling interests | — |
| — |
| | — |
| — |
| (129 | ) | | (129 | ) | — |
| — |
| | — |
| — |
| (129 | ) | (129 | ) |
| Net income attributable to noncontrolling interests | — |
| — |
| | — |
| — |
| 36 |
| | 36 |
| — |
| — |
| | — |
| — |
| 11 |
| 11 |
|
| Other | — |
| (46 | ) | | (7 | ) | — |
| — |
| | (7 | ) | — |
| (19 | ) | | 1 |
| — |
| — |
| 1 |
|
| Balance at September 30, 2016 | 980,798 |
| (799 | ) | | $ | 24,547 |
| $ | 609 |
| $ | 1,024 |
| | $ | 26,180 |
| |
| | | | | | | |
| Balance at December 31, 2014 | 908,502 |
| (725 | ) | | $ | 19,949 |
| $ | 756 |
| $ | 221 |
| | $ | 20,926 |
| |
| Consolidated net income attributable to Southern Company | — |
| — |
| | 2,096 |
| — |
| — |
| | 2,096 |
| |
| Other comprehensive income (loss) | — |
| — |
| | (7 | ) | — |
| — |
| | (7 | ) | |
| Stock issued | 3,769 |
| — |
| | 136 |
| — |
| — |
| | 136 |
| |
| Stock-based compensation | — |
| — |
| | 78 |
| — |
| — |
| | 78 |
| |
| Stock repurchased, at cost | — |
| (2,599 | ) | | (115 | ) | — |
| — |
| | (115 | ) | |
| Cash dividends on common stock | — |
| — |
| | (1,465 | ) | — |
| — |
| | (1,465 | ) | |
| Preference stock redemption | — |
| — |
| | — |
| (150 | ) | — |
| | (150 | ) | |
| Contributions from noncontrolling interests | — |
| — |
| | — |
| — |
| 429 |
| | 429 |
| |
| Distributions to noncontrolling interests | — |
| — |
| | — |
| — |
| (13 | ) | | (13 | ) | |
| Net income attributable to noncontrolling interests | — |
| — |
| | — |
| — |
| 13 |
| | 13 |
| |
| Other | — |
| (8 | ) | | (8 | ) | 3 |
| — |
| | (5 | ) | |
| Balance at September 30, 2015 | 912,271 |
| (3,332 | ) | | $ | 20,664 |
| $ | 609 |
| $ | 650 |
| | $ | 21,923 |
| |
| Balance at June 30, 2016 | | 942,370 |
| (772 | ) | | $ | 22,015 |
| $ | 609 |
| $ | 822 |
| $ | 23,446 |
|
| |
| (*) | Primarily relatedRelated to Southern Power Company and excludes redeemable noncontrolling interests. In April 2017, approximately $114 million was reclassified from redeemable noncontrolling interests to noncontrolling interests, included in stockholder's equity, due to the expiration of SunPower Corp's option to require Southern Power to purchase its membership interests in one of the solar partnerships. See Note 10 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Going Concern
As of June 30, 2017, Mississippi Power's current liabilities exceeded current assets by approximately $930 million primarily due to approximately $935 million that will be required through June 30, 2018 to fund maturities of long-term debt and $17 million that will be required to fund maturities of short-term debt. In addition, Mississippi Power has $40 million of tax-exempt variable rate demand obligations that are supported by short-term credit facilities and $50 million of fixed rate pollution control revenue bonds that are required to be remarketed over the next 12 months. Mississippi Power intends to utilize operating cash flows, lines of credit, and bank term loans, as market conditions permit, as well as, under certain circumstances, commercial paper and/or equity contributions and/or loans from Southern Company to fund Mississippi Power's short-term capital needs. Specifically, Mississippi Power has been informed by Southern Company that in the event sufficient funds are not available from external sources, Southern Company intends to provide Mississippi Power with loans and/or equity contributions sufficient to fund the remaining indebtedness scheduled to mature and other cash needs over the next 12 months. Therefore, Mississippi Power's financial statement presentation contemplates continuation of Mississippi Power as a going concern as a result of Southern Company's anticipated ongoing financial support of Mississippi Power. For additional information, see Notes 1 and 6 to the financial statements of Mississippi Power under "Recently Issued Accounting Standards" and "Going Concern," respectively, in Item 8 of the Form 10-K and Note (B) under "Integrated Coal Gasification Combined Cycle."
DOE Loan Guarantee Borrowings
See Note 6 to the financial statements of Southern Company and Georgia Power in Item 8 of the Form 10-K for additional information regarding Georgia Power's loan guarantee agreement (Loan Guarantee Agreement) with the DOE and related multi-advance term loan facility (FFB Credit Facility) with the FFB.
On July 27, 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement (LGA Amendment) in connection with the DOE's consent to Georgia Power's entry into the Services Agreement and the related intellectual property licenses (IP Licenses). The purpose of the amendment is to clarify the operation of the Loan Guarantee Agreement pending Georgia Power's completion of its comprehensive schedule, cost-to-complete, and cancellation cost assessments being prepared as a result of the bankruptcy of the EPC Contractor (Cost Assessments).
Under the terms of the Loan Guarantee Agreement, upon termination of the Vogtle 3 and 4 Agreement, further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement. Under the terms of the LGA Amendment, Georgia Power will not request any advances unless and until such time as Georgia Power has (i) completed the Cost Assessments and made a determination to continue construction of Plant Vogtle Units 3 and 4, (ii) delivered to the DOE an updated project schedule, construction budget, and other information, (iii) entered into one or more agreements with a construction contractor or contractors that will be primarily responsible for construction of Plant Vogtle Units 3 and 4 and such agreements have been approved by the DOE (together with the Services Agreement and the IP Licenses, the Replacement EPC Arrangements), and (iv) entered into a further amendment to the Loan Guarantee Agreement with the DOE to reflect the Replacement EPC Arrangements.
Upon satisfaction of the conditions described above, advances may be requested under the FFB Credit Facility on a quarterly basis through 2020. The final maturity date for each advance under the FFB Credit Facility is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20, 2020. Borrowings under the FFB Credit Facility will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375%.
In addition to the conditions described above, future advances are subject to satisfaction of customary conditions, as well as certification of compliance with the requirements of the Title XVII Loan Guarantee Program, accuracy of project-related representations and warranties, delivery of updated project-related information, absence of liens on Georgia Power's ownership interest in Plant Vogtle Units 3 and 4 other than permitted liens, evidence of compliance
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
with the prevailing wage requirements of the Davis-Bacon Act of 1931, as amended, and certification from the DOE's consulting engineer that proceeds of the advances are used to reimburse Eligible Project Costs.
Under the Loan Guarantee Agreement, Georgia Power is subject to customary borrower affirmative and negative covenants and events of default. In addition, Georgia Power is subject to project-related reporting requirements and other project-specific covenants and events of default.
In the event certain mandatory prepayment events occur, the FFB's commitment to make further advances under the FFB Credit Facility will terminate and Georgia Power will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facility over a period of five years (with level principal amortization). Among other things, these mandatory prepayment events include (i) the termination of the Services Agreement or rejection of the Services Agreement in bankruptcy if Georgia Power does not maintain access to intellectual property rights under the IP Licenses; (ii) a decision by Georgia Power not to continue construction of Plant Vogtle Units 3 and 4; (iii) a failure by Georgia Power to complete the Cost Assessments or enter into Replacement EPC Arrangements by December 31, 2017; (iv) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC, or by Georgia Power if authorized by the Georgia PSC; and (v) cost disallowances by the Georgia PSC that could have a material adverse effect on completion of Plant Vogtle Units 3 and 4 or Georgia Power's ability to repay the outstanding borrowings under the FFB Credit Facility. Under certain circumstances, insurance proceeds and any proceeds from an event of taking must be applied to immediately prepay outstanding borrowings under the FFB Credit Facility. In addition, under certain circumstances Georgia Power may be required to make additional prepayments in connection with its receipt of payments under the Guarantee Settlement Agreement or from the EPC Contractor under the Vogtle 3 and 4 Agreement. Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facility. Under the FFB Credit Facility, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable.
See Note (B) under "Regulatory Matters – Georgia Power – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.
Bank Credit Arrangements
Bank credit arrangements provide liquidity support to the registrants' commercial paper borrowings and the traditional electric operating companies' pollution control revenue bonds. The amount of variable rate pollution control revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of SeptemberJune 30, 20162017 was approximately $1.9$1.6 billion (comprised of approximately $890 million at Alabama Power, $868$550 million at Georgia Power, $82 million at Gulf Power, and $40 million at Mississippi Power). In June 2017, Georgia Power remarketed $318 million of variable rate pollution control bonds in index rate modes, reducing the liquidity support utilized under Georgia Power's bank credit arrangement. In addition, at SeptemberJune 30, 2016,2017, the traditional electric operating companies had approximately $358$626 million (comprised of approximately $87 million at Alabama Power, $250$436 million at Georgia Power, and $21$140 million at Gulf Power, and $50 million at Mississippi Power) of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months. See Note 6 to the financial statements of each registrant under "Bank Credit Arrangements" in Item 8 of the Form 10-K and "Financing Activities" herein for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
The following table outlines the committed credit arrangements by company as of SeptemberJune 30, 2016:2017:
| | | | Expires | | | | Executable Term Loans | | Due Within One Year | Expires | | | | Executable Term Loans | | Expires Within One Year |
| Company | 2016 |
| 2017 | 2018 | 2020 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out | 2017 | 2018 | 2019 | 2020 | 2022 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out |
| | (in millions) | | (in millions) | | (in millions) | | (in millions) | (in millions) |
Southern Company(a) | $ | — |
| $ | — |
| $ | 1,000 |
| $ | 1,250 |
| | $ | 2,250 |
| | $ | 2,250 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 2,000 |
| | $ | 2,000 |
| | $ | 2,000 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Alabama Power | — |
| 35 |
| 500 |
| 800 |
| | 1,335 |
| | 1,335 |
| | — |
| | — |
| | — |
| | 35 |
| 3 |
| 532 |
| — |
| — |
| 800 |
| | 1,335 |
| | 1,335 |
| | — |
| | — |
| | — |
| | 35 |
|
| Georgia Power | — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,732 |
| | — |
| | — |
| | — |
| | — |
| — |
| — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,732 |
| | — |
| | — |
| | — |
| | — |
|
| Gulf Power | 50 |
| 65 |
| 165 |
| — |
| | 280 |
| | 280 |
| | 45 |
| | — |
| | 45 |
| | 70 |
| 30 |
| 195 |
| 25 |
| 30 |
| — |
| | 280 |
| | 280 |
| | 45 |
| | — |
| | — |
| | 40 |
|
| Mississippi Power | 100 |
| 75 |
| — |
| — |
| | 175 |
| | 150 |
| | — |
| | 15 |
| | 15 |
| | 160 |
| 113 |
| — |
| — |
| — |
| — |
| | 113 |
| | 100 |
| | — |
| | 13 |
| | 13 |
| | 100 |
|
Southern Power Company(b) | — |
| — |
| — |
| 600 |
| | 600 |
| | 532 |
| | — |
| | — |
| | — |
| | — |
| — |
| — |
| — |
| — |
| 750 |
| | 750 |
| | 675 |
| | — |
| | — |
| | — |
| | — |
|
Southern Company Gas(c)(b) | — |
| 75 |
| 1,925 |
| — |
| | 2,000 |
| | 1,947 |
| | — |
| | — |
| | — |
| | — |
| — |
| — |
| — |
| — |
| 1,900 |
| | 1,900 |
| | 1,849 |
| | — |
| | — |
| | — |
| | — |
|
| Other | — |
| 55 |
| — |
| — |
| | 55 |
| | 55 |
| | 20 |
| | — |
| | 20 |
| | 35 |
| 10 |
| 30 |
| — |
| — |
| — |
| | 40 |
| | 40 |
| | 20 |
| | — |
| | 20 |
| | 20 |
|
| Southern Company Consolidated | $ | 150 |
| $ | 305 |
| $ | 3,590 |
| $ | 4,400 |
| | $ | 8,445 |
| | $ | 8,281 |
| | $ | 65 |
| | $ | 15 |
| | $ | 80 |
| | $ | 300 |
| $ | 156 |
| $ | 757 |
| $ | 25 |
| $ | 30 |
| $ | 7,200 |
| | $ | 8,168 |
| | $ | 8,011 |
| | $ | 65 |
| | $ | 13 |
| | $ | 33 |
| | $ | 195 |
|
| |
| (a) | Represents the Southern Company parent entity. |
| |
| (b) | Excluding its subsidiaries. See "Southern Power Project Credit Facilities" below and Note (I) under "Southern Power" for additional information.
|
| |
(c) | Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.3$1.2 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $700$700 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. |
OnAs reflected in the table above, in May 24, 2016,2017, Southern Company's $8.1Company, Alabama Power, Georgia Power, and Southern Power Company each amended certain of their multi-year credit arrangements, which, among other things, extended the maturity dates from 2020 to 2022. Southern Company and Southern Power Company increased their borrowing ability under these arrangements to $2.0 billion Bridge Agreementfrom $1.25 billion and to provide Merger financing,$750 million from $600 million, respectively. Southern Company also terminated its $1.0 billion facility maturing in 2018. Also in May 2017, Southern Company Gas Capital and Nicor Gas terminated their existing credit arrangements for $1.3 billion and $700 million, respectively, which were to the extent necessary, was terminated.mature in 2017 and 2018, and entered into a new multi-year credit arrangement currently allocated for $1.2 billion and $700 million, respectively, with a maturity date of 2022.
Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
Southern Power Project Credit Facilities
In connection with the construction of solar facilities by RE Garland Holdings LLC, RE Roserock LLC, and RE Tranquillity LLC, indirect subsidiaries of Southern Power, each subsidiary entered into separate credit agreements (Project Credit Facilities), which are non-recourse to Southern Power (other than the subsidiary party to the agreement). Each Project Credit Facility provides (a) a senior secured construction loan credit facility, (b) a senior secured bridge loan facility, and (c) a senior secured letter of credit facility that is secured by the membership interests of the respective project company, with proceeds directed to finance project costs related to the respective
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
solar facilities. Each Project Credit Facility is secured by the assets of the applicable project subsidiary and membership interests of the applicable project subsidiary. The table below summarizes each Project Credit Facility as of September 30, 2016.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Project | | Maturity Date | | Construction Loan Facility | | Bridge Loan Facility | | Total Loan Facility | | Loan Facility Undrawn | | Letter of Credit Facility | | Letter of Credit Facility Undrawn |
| | | | | (in millions) |
| Garland | | Earlier of PPA COD or November 30, 2016 | | $ | 86 |
| | $ | 308 |
| | $ | 394 |
| | $ | 21 |
| | $ | 49 |
| | $ | 23 |
|
| Roserock | | Earlier of PPA COD or November 30, 2016(*) | | 63 |
| | 180 |
| | 243 |
| | 34 |
| | 23 |
| | 16 |
|
| Tranquillity | | October 14, 2016 | | 86 |
| | 172 |
| | 258 |
| | 12 |
| | 77 |
| | 26 |
|
| Total | | | | $ | 235 |
| | $ | 660 |
| | $ | 895 |
| | $ | 67 |
| | $ | 149 |
| | $ | 65 |
|
| |
(*) | Subsequent to September 30, 2016, Roserock extended the maturity date of its Project Credit Facility to December 31, 2016. |
The Project Credit Facilities above had total amounts outstanding as of September 30, 2016 of $828 million at a weighted average interest rate of 2.05%. For the three-month period ended September 30, 2016, these credit agreements had a maximum amount outstanding of $828 million and an average amount outstanding of $805 million at a weighted average interest rate of 2.02%.
Furthermore, in connection with the acquisition of the Henrietta solar facility on July 1, 2016, a subsidiary of Southern Power assumed a $217 million construction loan, which was fully repaid prior to September 30, 2016. For the three-month period ended September 30, 2016, this credit agreement had a maximum amount outstanding of $217 million and an average amount outstanding of $137 million at a weighted average interest rate of 2.21%.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Financing Activities
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first ninesix months of 2016:2017:
| | | Company | Senior Note Issuances | | Senior Note Maturities and Redemptions | | Revenue
Bond
Maturities Redemptions and
Repurchases | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(a) | Senior Note Issuances | | Senior Note Maturities and Redemptions | | Revenue Bond
Maturities, Redemptions, and
Repurchases | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(a) |
| | (in millions) | (in millions) |
Southern Company(b) | $ | 8,500 |
| | $ | 500 |
| | $ | — |
| | $ | 800 |
| | $ | — |
| $ | 300 |
| | $ | — |
| | $ | — |
| | $ | 500 |
| | $ | 400 |
|
| Alabama Power | 400 |
| | 200 |
| | — |
| | 45 |
| | — |
| 550 |
| | 200 |
| | — |
| | — |
| | — |
|
| Georgia Power | 650 |
| | 700 |
| | 4 |
| | 300 |
| | 5 |
| 850 |
| | 450 |
| | 27 |
| | — |
| | 3 |
|
| Gulf Power | — |
| | 125 |
| | — |
| | 2 |
| | — |
| 300 |
| | 85 |
| | — |
| | 6 |
| | — |
|
| Mississippi Power | — |
| | — |
| | — |
| | 1,100 |
| | 652 |
| — |
| | — |
| | — |
| | 40 |
| | 893 |
|
| Southern Power | 1,531 |
| | — |
| | — |
| | 63 |
| | 84 |
| — |
| | — |
| | — |
| | 3 |
| | 3 |
|
Southern Company Gas(c) | 900 |
| | 300 |
| | — |
| | — |
| | — |
| 450 |
| | — |
| | — |
| | — |
| | — |
|
| Other | — |
| | — |
| | — |
| | — |
| | 60 |
| — |
| | — |
| | — |
| | — |
| | 8 |
|
Elimination(d) | — |
| | — |
| | — |
| | (200 | ) | | (225 | ) | — |
| | — |
| | — |
| | (40 | ) | | (591 | ) |
| Southern Company Consolidated | $ | 11,981 |
| | $ | 1,825 |
| | $ | 4 |
| | $ | 2,110 |
| | $ | 576 |
| $ | 2,450 |
| | $ | 735 |
| | $ | 27 |
| | $ | 509 |
| | $ | 716 |
|
| |
| (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 the Southern Company Gas.Gas parent entity. |
| |
| (d) | Intercompany loans from Southern Company to Mississippi Power eliminated in Southern Company's Consolidated Financial Statements. |
Southern Company
In May 2016,June 2017, Southern Company issued the following series of senior notes for an aggregate principal amount of $8.5 billion:
$0.5 billion of 1.55% Senior Notes due July 1, 2018;
$1.0 billion of 1.85% Senior Notes due July 1, 2019;
$1.5 billion of 2.35% Senior Notes due July 1, 2021;
$1.25 billion of 2.95% Senior Notes due July 1, 2023;
$1.75 billion of 3.25% Senior Notes due July 1, 2026;
$0.5 billion of 4.25% Senior Notes due July 1, 2036; and
$2.0 billion of 4.40% Senior Notes due July 1, 2046.
The net proceeds were used to fund a portion of the consideration for the Merger and related transaction costs and for other general corporate purposes.
In September 2016, Southern Company issued $800$500 million aggregate principal amount of Series 2016A 5.25%2017A 5.325% Junior Subordinated Notes due October 1, 2076.June 21, 2057. The proceeds were used to repay short-term indebtedness that was incurred to repay at maturity $500 million aggregate principal amount of Southern Company's Series 2011A 1.95% Senior Notes due September 1, 2016 and for other general corporate purposes.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Alabama Power
In January 2016, Alabama PowerAlso in June 2017, Southern Company issued $400$300 million aggregate principal amount of Series 2016A 4.30%2017A Floating Rate Senior Notes due January 2, 2046.September 30, 2020, which bear interest at a floating rate based on three-month LIBOR. The proceeds were used to repay at maturity $200short-term indebtedness and for other general corporate purposes.
Also in June 2017, Southern Company entered into two $100 million aggregate principal amount floating rate bank term loan agreements, which mature on June 21, 2018 and June 29, 2018 and bear interest based on one-month LIBOR. The proceeds were used for working capital and other general corporate purposes.
Alabama Power
In March 2017, Alabama Power issued $550 million aggregate principal amount of Alabama Power's Series FF 5.20%2017A 2.45% Senior Notes due January 15, 2016March 30, 2022. The proceeds were used to repay Alabama Power's short-term indebtedness and for general corporate purposes, including Alabama Power's continuous construction program.
In March 2016, Alabama Power entered into three bank term loan agreements with maturity dates of March 2021, in an aggregate principal amount of $45 million, one of which bears interest at 2.38% per annum and two of which bear interest based on three-month LIBOR.
Georgia Power
In March 2016,2017, Georgia Power issued $325$450 million aggregate principal amount of Series 2016A 3.25%2017A 2.00% Senior Notes due April 1, 2026March 30, 2020 and $325$400 million aggregate principal amount of Series 2016B 2.40% Senior Notes due April 1, 2021. An amount equal to the proceeds from the Series 2016A2017B 3.25% Senior Notes due April 1, 2026 will be allocated to eligible green expenditures, including financing of or investments in solar generating facilities or electric vehicle charging infrastructure, or payments under PPAs served by solar or wind generating facilities.March 30, 2027. The proceeds from the Series 2016B 2.40% Senior Notes due April 1, 2021 were used to repay at maturity $250 million aggregate principal amount of Georgia Power's Series 2013B Floating Rate Senior Notes due March 15, 2016, to repay a portion of Georgia Power's short-term indebtedness and for general corporate purposes, including Georgia Power's continuous construction program.
In June 2016, Georgia Power made additional borrowings under the FFB Credit Facility in an aggregate principal amount of $300 million at a 2.571% interest rate through the final maturity date of February 20, 2044. The proceeds were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4.
Gulf Power
In May 2016, Gulf Power redeemed $125 million aggregate principal amount of its Series 2011A 5.75% Senior Notes due June 1, 2051.
Also in May 2016, Gulf Power entered into an 11-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 2016, Mississippi Power borrowed $100 million under this promissory note and an additional $100 million under a separate promissory note issued to Southern Company in November 2015. On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicate of financial institutions for an aggregate amount of $1.2 billion. Mississippi Power borrowed $900 million on March 8, 2016 under the term loan agreement and the remaining $300 million on October 7, 2016. Mississippi Power used the initial proceeds to repay $900 million in maturing bank loans on March 8, 2016 and the remaining $300 million to repay at maturity Mississippi Power's Series 2011A 2.35% Senior Notes due October 15, 2016. The term loan pursuant to this agreement matures on April 1, 2018 and bears interest based on one-month LIBOR. On June 27, 2016, Mississippi Power received a capital contribution from Southern Company of $225 million, the proceeds of which were used to repay to Southern Company a portion of the promissory note issued in November 2015. As of September 30, 2016, the amount of outstanding promissory notes to Southern Company totaled $551 million.
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)
SouthernIn April 2017, Georgia Power
In June 2016, Southern Power issued €600 purchased and held $27 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 2016A 1.00% Senior Notes due1995. Georgia Power may reoffer these bonds to the public at a later date.
In June 20, 2022 and €500 million2017, Georgia Power entered into three floating rate bank loans in aggregate principal amountamounts of Series 2016B 1.85% Senior Notes due$50 million, $150 million, and $100 million, which mature on December 1, 2017, May 31, 2018, and June 20, 2026.28, 2018, respectively, and bear interest based on one-month LIBOR. Also in June 2017, Georgia Power borrowed $500 million pursuant to an uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Georgia Power and the bank from time to time and is payable on no less than 30 days' demand by the bank. 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 proceedsfrom these bank loans were used to repay a portion of Georgia Power's existing indebtedness and for working capital and other general corporate purposes, including SouthernGeorgia Power's growth strategy and continuous construction program, as well as repayment of amounts outstanding under the Project Credit Facilities.program.
Also in September 2016, SouthernGulf Power repaid $80 million of an outstanding $400 million floating rate bank loan and
In March 2017, Gulf Power extended the maturity date of the remaining $320a $100 million from September 2016 to September 2018. In addition, Southern Power entered into a $60 million aggregate principal amountshort-term floating rate bank loan bearing interest based on one-month LIBOR from April 2017 to October 2017 and subsequently repaid the loan in May 2017.
In May 2017, Gulf Power issued $300 million aggregate principal amount of Series 2017A 3.30% Senior Notes due SeptemberMay 30, 2027. The proceeds, together with other funds, were used to repay at maturity $85 million aggregate principal amount of Series 2007A 5.90% Senior Notes due June 15, 2017; to repay outstanding commercial paper borrowings; to repay a $100 million short-term floating rate bank loan, as discussed above; and to redeem 550,000 shares ($55 million aggregate liquidation amount) of Gulf Power's 6.00% Series Preference Stock, 450,000 shares ($45 million aggregate liquidation amount) of Gulf Power's Series 2007A 6.45% Preference Stock, and 500,000 shares ($50 million aggregate liquidation amount) of Gulf Power's Series 2013A 5.60% Preference Stock.
Mississippi Power
In March 2017, Mississippi Power issued a $9 million short-term bank note bearing interest at 5% per annum, which was repaid in April 2017.
In February 2017, Mississippi Power amended $551 million in promissory notes to Southern Company extending the maturity dates of the notes from December 1, 2017 to July 31, 2018. In the second quarter 2017, Mississippi Power borrowed an additional $40 million under a promissory note issued to Southern Company.
In June 2017, Southern Company made equity contributions totaling $1.0 billion to Mississippi Power. Mississippi Power used a portion of the proceeds to (i) prepay $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018; (ii) repay all of the $591 million outstanding principal amount of promissory notes to Southern Company; and (iii) repay a $10 million short-term bank loan.
Southern Company Gas
In May 2017, Southern Company Gas Capital issued $450 million aggregate principal amount of Series 2017A 4.40% Senior Notes due May 30, 2047. The proceeds were used to repay existing indebtedness and for other general corporate purposes.
In addition, Southern Power issued $34 million in letters of credit during the nine months ended September 30, 2016.
During the nine months ended September 30, 2016, Southern Power's subsidiaries incurred an additional $691 million of short-term borrowings pursuant to the Project Credit Facilities at a weighted average interest rate of 2.05%. Furthermore, in connection with the acquisition of the Henrietta solar facility, a subsidiary of Southern Power assumed a $217 million construction loan, which was fully repaid prior to September 30, 2016. In addition, Southern Power's subsidiaries issued $16 million in letters of credit.
Southern Company Gas
In September 2016, Southern Company Gas Capital issued $350 million aggregate principal amount of 2.45% Senior Notes due October 1, 2023 and $550 million aggregate principal amount of 3.95% Senior Notes due October 1, 2046, both of which are guaranteed by Southern Company Gas. The proceeds were used to repay a $360 million promissory note issued to Southern Company for the purpose of funding a portion of the purchase price for Southern Company Gas' 50% equity interest in SNG, to fund Southern Company Gas' purchase of Piedmont Natural Gas Company, Inc.'s (Piedmont) interest in SouthStar Energy Services, LLC (SouthStar), to make a voluntary pension contribution, to repay at maturity $120 million aggregate principal amount of Series A Floating Rate Senior Notes due October 27, 2016,short-term indebtedness and for general corporate purposes. See Note (I) under "Southern Company– Investment in Southern Natural Gas" and " – Acquisition of Remaining Interest in SouthStar" for additional information regarding Southern Company Gas' investment in SNG and purchase of Piedmont's interest in SouthStar, respectively.
Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees.employees, with the exception of employees at Southern Company Gas, as discussed below, and PowerSecure. The Southern Company qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended.amended (ERISA). No mandatory contributions to the Southern Company qualified pension plan are anticipated for the year ending December 31, 2016.2017. Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions.
See Note 2 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power in Item 8 of the Form 10-K for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
In addition, Southern Company Gas has a qualified defined benefit, trusteed, pension plan covering certain eligible employees, which was closed in 2012 to new employees. TheThis qualified pension plan is funded in accordance with requirements of ERISA. No mandatory contributions to the Employee Retirement Income Security Act of 1974, as amended. Southern Company Gas made a $125 million voluntary contribution to the qualified pension plan in September 2016.are anticipated for the year ending December 31, 2017. Southern Company Gas also provides certain non-qualified defined benefit and defined contribution pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are largely unfunded and benefits are primarily paid using corporate assets.funded on a cash basis. In addition, Southern Company Gas provides certain medical care and life insurance benefits for eligible retired employees through a postretirement benefit plan. Southern Company Gas also has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses.
See Note 2 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Company Gas in Item 8 of the Form 10-K for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Components of the net periodic benefit costs for the three and ninesix months ended SeptemberJune 30, 2017 and 2016 and 2015 were as follows:are presented in the following tables.
|
| | | | | | | | | | | | | | | | | | | |
| Pension Plans | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power |
| | (in millions) |
| Three Months Ended September 30, 2016 | | | | | | | | | |
| Service cost | $ | 68 |
| | $ | 14 |
| | $ | 17 |
| | $ | 3 |
| | $ | 3 |
|
| Interest cost | 110 |
| | 23 |
| | 34 |
| | 5 |
| | 4 |
|
| Expected return on plan assets | (203 | ) | | (46 | ) | | (64 | ) | | (9 | ) | | (9 | ) |
| Amortization: | | | | | | | | | |
| Prior service costs | 3 |
| | 1 |
| | 1 |
| | — |
| | 1 |
|
| Net (gain)/loss | 45 |
| | 10 |
| | 14 |
| | 2 |
| | 2 |
|
| Net periodic pension cost | $ | 23 |
| | $ | 2 |
| | $ | 2 |
| | $ | 1 |
| | $ | 1 |
|
| Nine Months Ended September 30, 2016 | | | | | | | | | |
| Service cost | $ | 192 |
| | $ | 43 |
| | $ | 52 |
| | $ | 9 |
| | $ | 9 |
|
| Interest cost | 311 |
| | 71 |
| | 102 |
| | 14 |
| | 14 |
|
| Expected return on plan assets | (577 | ) | | (138 | ) | | (193 | ) | | (26 | ) | | (26 | ) |
| Amortization: | | | | | | | | | |
| Prior service costs | 10 |
| | 2 |
| | 4 |
| | 1 |
| | 1 |
|
| Net (gain)/loss | 120 |
| | 30 |
| | 41 |
| | 5 |
| | 5 |
|
| Net periodic pension cost | $ | 56 |
| | $ | 8 |
| | $ | 6 |
| | $ | 3 |
| | $ | 3 |
|
| Three Months Ended September 30, 2015 | | | | | | | | | |
| Service cost | $ | 65 |
| | $ | 14 |
| | $ | 18 |
| | $ | 3 |
| | $ | 3 |
|
| Interest cost | 111 |
| | 26 |
| | 38 |
| | 5 |
| | 5 |
|
| Expected return on plan assets | (181 | ) | | (44 | ) | | (62 | ) | | (8 | ) | | (8 | ) |
| Amortization: | | | | | | | | | |
| Prior service costs | 6 |
| | 2 |
| | 2 |
| | 1 |
| | — |
|
| Net (gain)/loss | 53 |
| | 14 |
| | 19 |
| | 2 |
| | 3 |
|
| Net periodic pension cost | $ | 54 |
| | $ | 12 |
| | $ | 15 |
| | $ | 3 |
| | $ | 3 |
|
| Nine Months Ended September 30, 2015 | | | | | | | | | |
| Service cost | $ | 193 |
| | $ | 44 |
| | $ | 54 |
| | $ | 9 |
| | $ | 9 |
|
| Interest cost | 333 |
| | 79 |
| | 115 |
| | 15 |
| | 16 |
|
| Expected return on plan assets | (543 | ) | | (133 | ) | | (188 | ) | | (24 | ) | | (25 | ) |
| Amortization: | | | | | | | | | |
| Prior service costs | 19 |
| | 5 |
| | 7 |
| | 1 |
| | 1 |
|
| Net (gain)/loss | 161 |
| | 41 |
| | 57 |
| | 7 |
| | 8 |
|
| Net periodic pension cost | $ | 163 |
| | $ | 36 |
| | $ | 45 |
| | $ | 8 |
| | $ | 9 |
|
Table of Contents |
| | | | | | | | | | | | | | | | | | | |
| Pension Plans | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power |
| | (in millions) |
| Three Months Ended June 30, 2017 | | | | | | | | | |
| Service cost | $ | 74 |
| | $ | 16 |
| | $ | 18 |
| | $ | 4 |
| | $ | 3 |
|
| Interest cost | 113 |
| | 24 |
| | 35 |
| | 5 |
| | 5 |
|
| Expected return on plan assets | (225 | ) | | (49 | ) | | (70 | ) | | (9 | ) | | (10 | ) |
| Amortization: | | | | | | | | | |
| Prior service costs | 3 |
| | — |
| | 1 |
| | — |
| | 1 |
|
| Net (gain)/loss | 41 |
| | 11 |
| | 14 |
| | 1 |
| | 2 |
|
| Net periodic pension cost (income) | $ | 6 |
| | $ | 2 |
| | $ | (2 | ) | | $ | 1 |
| | $ | 1 |
|
| Six Months Ended June 30, 2017 | | | | | | | | | |
| Service cost | $ | 147 |
| | $ | 32 |
| | $ | 37 |
| | $ | 7 |
| | $ | 7 |
|
| Interest cost | 227 |
| | 48 |
| | 69 |
| | 10 |
| | 10 |
|
| Expected return on plan assets | (449 | ) | | (98 | ) | | (141 | ) | | (19 | ) | | (20 | ) |
| Amortization: | | | | | | | | | |
| Prior service costs | 6 |
| | 1 |
| | 2 |
| | — |
| | 1 |
|
| Net (gain)/loss | 81 |
| | 21 |
| | 28 |
| | 3 |
| | 4 |
|
| Net periodic pension cost (income) | $ | 12 |
| | $ | 4 |
| | $ | (5 | ) | | $ | 1 |
| | $ | 2 |
|
| Three Months Ended June 30, 2016 | | | | | | | | | |
| Service cost | $ | 62 |
| | $ | 15 |
| | $ | 18 |
| | $ | 3 |
| | $ | 3 |
|
| Interest cost | 101 |
| | 24 |
| | 34 |
| | 4 |
| | 5 |
|
| Expected return on plan assets | (187 | ) | | (46 | ) | | (65 | ) | | (8 | ) | | (8 | ) |
| Amortization: | | | | | | | | | |
| Prior service costs | 3 |
| | — |
| | 2 |
| | 1 |
| | — |
|
| Net (gain)/loss | 37 |
| | 10 |
| | 13 |
| | 1 |
| | 1 |
|
| Net periodic pension cost | $ | 16 |
| | $ | 3 |
| | $ | 2 |
| | $ | 1 |
| | $ | 1 |
|
| Six Months Ended June 30, 2016 | | | | | | | | | |
| Service cost | $ | 124 |
| | $ | 29 |
| | $ | 35 |
| | $ | 6 |
| | $ | 6 |
|
| Interest cost | 201 |
| | 48 |
| | 68 |
| | 9 |
| | 10 |
|
| Expected return on plan assets | (374 | ) | | (92 | ) | | (129 | ) | | (17 | ) | | (17 | ) |
| Amortization: | | | | | | | | | |
| Prior service costs | 7 |
| | 1 |
| | 3 |
| | 1 |
| | — |
|
| Net (gain)/loss | 75 |
| | 20 |
| | 27 |
| | 3 |
| | 3 |
|
| Net periodic pension cost | $ | 33 |
| | $ | 6 |
| | $ | 4 |
| | $ | 2 |
| | $ | 2 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| | | Postretirement Benefits | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power | |
| Pension Plans | | Southern Company Gas |
| | (in millions) | (in millions) |
| Three Months Ended September 30, 2016 | | | | | | | | | | |
| Successor – Three Months Ended June 30, 2017 | | |
| Service cost | $ | 6 |
| | $ | 1 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| $ | 5 |
|
| Interest cost | 20 |
| | 5 |
| | 7 |
| | 1 |
| | — |
| 10 |
|
| Expected return on plan assets | (16 | ) | | (6 | ) | | (6 | ) | | — |
| | — |
| (17 | ) |
| Amortization: | | | | | | | | | | |
| Prior service costs | 1 |
| | 1 |
| | — |
| | — |
| | — |
| (1 | ) |
| Net (gain)/loss | 5 |
| | — |
| | 3 |
| | — |
| | 1 |
| 5 |
|
| Net periodic postretirement benefit cost | $ | 16 |
| | $ | 1 |
| | $ | 6 |
| | $ | 1 |
| | $ | 1 |
| |
| Nine Months Ended September 30, 2016 | | | | | | | | | | |
| Net periodic pension cost | | $ | 2 |
|
| Successor – Six Months Ended June 30, 2017 | | |
| Service cost | $ | 17 |
| | $ | 4 |
| | $ | 5 |
| | $ | 1 |
| | $ | 1 |
| $ | 11 |
|
| Interest cost | 55 |
| | 14 |
| | 22 |
| | 2 |
| | 2 |
| 20 |
|
| Expected return on plan assets | (44 | ) | | (19 | ) | | (17 | ) | | (1 | ) | | (1 | ) | (35 | ) |
| Amortization: | | | | | | | | | | |
| Prior service costs | 4 |
| | 3 |
| | 1 |
| | — |
| | — |
| (1 | ) |
| Net (gain)/loss | 12 |
| | 1 |
| | 7 |
| | — |
| | 1 |
| 10 |
|
| Net periodic postretirement benefit cost | $ | 44 |
| | $ | 3 |
| | $ | 18 |
| | $ | 2 |
| | $ | 3 |
| |
| Three Months Ended September 30, 2015 | | | | | | | | | | |
| Net periodic pension cost | | $ | 5 |
|
| | | |
| | | |
| Predecessor – Three Months Ended June 30, 2016 | | |
| Service cost | $ | 6 |
| | $ | 1 |
| | $ | 2 |
| | $ | 1 |
| | $ | — |
| $ | 7 |
|
| Interest cost | 20 |
| | 5 |
| | 9 |
| | — |
| | 1 |
| 11 |
|
| Expected return on plan assets | (15 | ) | | (6 | ) | | (6 | ) | | — |
| | — |
| (17 | ) |
| Amortization: | | | | | | | | | | |
| Prior service costs | 1 |
| | 2 |
| | — |
| | — |
| | — |
| (1 | ) |
| Net (gain)/loss | 4 |
| | — |
| | 2 |
| | — |
| | — |
| 7 |
|
| Net periodic postretirement benefit cost | $ | 16 |
| | $ | 2 |
| | $ | 7 |
| | $ | 1 |
| | $ | 1 |
| |
| Nine Months Ended September 30, 2015 | | | | | | | | | | |
| Net periodic pension cost | | $ | 7 |
|
| Predecessor – Six Months Ended June 30, 2016 | | |
| Service cost | $ | 17 |
| | $ | 4 |
| | $ | 5 |
| | $ | 1 |
| | $ | 1 |
| $ | 13 |
|
| Interest cost | 59 |
| | 15 |
| | 26 |
| | 2 |
| | 3 |
| 21 |
|
| Expected return on plan assets | (44 | ) | | (19 | ) | | (18 | ) | | (1 | ) | | (1 | ) | (33 | ) |
| Amortization: | | | | | | | | | | |
| Prior service costs | 3 |
| | 3 |
| | — |
| | — |
| | — |
| (1 | ) |
| Net (gain)/loss | 13 |
| | 1 |
| | 8 |
| | — |
| | — |
| 13 |
|
| Net periodic postretirement benefit cost | $ | 48 |
| | $ | 4 |
| | $ | 21 |
| | $ | 2 |
| | $ | 3 |
| |
| Net periodic pension cost | | $ | 13 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | |
| Postretirement Benefits | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power |
| | (in millions) |
| Three Months Ended June 30, 2017 | | | | | | | | | |
| Service cost | $ | 6 |
| | $ | 2 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
|
| Interest cost | 20 |
| | 4 |
| | 8 |
| | — |
| | 1 |
|
| Expected return on plan assets | (17 | ) | | (8 | ) | | (6 | ) | | (1 | ) | | (1 | ) |
| Amortization: | | | | | | | | | |
| Prior service costs | 1 |
| | 1 |
| | 1 |
| | — |
| | — |
|
| Net (gain)/loss | 5 |
| | 1 |
| | 1 |
| | — |
| | — |
|
| Net periodic postretirement benefit cost | $ | 15 |
| | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | 1 |
|
| Six Months Ended June 30, 2017 | | | | | | | | | |
| Service cost | $ | 12 |
| | $ | 3 |
| | $ | 3 |
| | $ | 1 |
| | $ | 1 |
|
| Interest cost | 40 |
| | 9 |
| | 15 |
| | 1 |
| | 2 |
|
| Expected return on plan assets | (33 | ) | | (14 | ) | | (12 | ) | | (1 | ) | | (1 | ) |
| Amortization: | | | | | | | | | |
| Prior service costs | 3 |
| | 2 |
| | 1 |
| | — |
| | — |
|
| Net (gain)/loss | 7 |
| | 1 |
| | 3 |
| | — |
| | — |
|
| Net periodic postretirement benefit cost | $ | 29 |
| | $ | 1 |
| | $ | 10 |
| | $ | 1 |
| | $ | 2 |
|
| Three Months Ended June 30, 2016 | | | | | | | | | |
| Service cost | $ | 6 |
| | $ | 2 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
|
| Interest cost | 17 |
| | 4 |
| | 7 |
| | — |
| | 1 |
|
| Expected return on plan assets | (14 | ) | | (7 | ) | | (5 | ) | | (1 | ) | | (1 | ) |
| Amortization: | | | | | | | | | |
| Prior service costs | 1 |
| | 1 |
| | 1 |
| | — |
| | — |
|
| Net (gain)/loss | 4 |
| | 1 |
| | 2 |
| | — |
| | — |
|
| Net periodic postretirement benefit cost | $ | 14 |
| | $ | 1 |
| | $ | 6 |
| | $ | — |
| | $ | 1 |
|
| Six Months Ended June 30, 2016 | | | | | | | | | |
| Service cost | $ | 11 |
| | $ | 3 |
| | $ | 3 |
| | $ | 1 |
| | $ | 1 |
|
| Interest cost | 35 |
| | 9 |
| | 15 |
| | 1 |
| | 2 |
|
| Expected return on plan assets | (28 | ) | | (13 | ) | | (11 | ) | | (1 | ) | | (1 | ) |
| Amortization: | | | | | | | | | |
| Prior service costs | 3 |
| | 2 |
| | 1 |
| | — |
| | — |
|
| Net (gain)/loss | 7 |
| | 1 |
| | 4 |
| | — |
| | — |
|
| Net periodic postretirement benefit cost | $ | 28 |
| | $ | 2 |
| | $ | 12 |
| | $ | 1 |
| | $ | 2 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | |
| Postretirement Benefits | Southern Company Gas |
| | (in millions) |
| Successor – Three Months Ended June 30, 2017 | |
| Service cost | $ | — |
|
| Interest cost | 2 |
|
| Expected return on plan assets | (1 | ) |
| Amortization: | |
| Prior service costs | — |
|
| Net (gain)/loss | 1 |
|
| Net periodic postretirement benefit cost | $ | 2 |
|
| Successor – Six Months Ended June 30, 2017 | |
| Service cost | $ | 1 |
|
| Interest cost | 5 |
|
| Expected return on plan assets | (3 | ) |
| Amortization: | |
| Prior service costs | (1 | ) |
| Net (gain)/loss | 2 |
|
| Net periodic postretirement benefit cost | $ | 4 |
|
| | |
| | |
| Predecessor – Three Months Ended June 30, 2016 | |
| Service cost | $ | — |
|
| Interest cost | 2 |
|
| Expected return on plan assets | (1 | ) |
| Amortization: | |
| Prior service costs | — |
|
| Net (gain)/loss | 1 |
|
| Net periodic postretirement benefit cost | $ | 2 |
|
| Predecessor – Six Months Ended June 30, 2016 | |
| Service cost | $ | 1 |
|
| Interest cost | 5 |
|
| Expected return on plan assets | (3 | ) |
| Amortization: | |
| Prior service costs | (1 | ) |
| Net (gain)/loss | 2 |
|
| Net periodic postretirement benefit cost | $ | 4 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
See Note 5 to the financial statements of each registrant in Item 8 of the Form 10-K for additional tax information.
Current and Deferred Income Taxes
Net Operating Loss
Southern Company expects to be in a consolidated net operating loss (NOL) position for income tax purposes for the 2016 tax year. The NOL will limit the amount of positive cash flows resulting from bonus depreciation, ITCs, and PTCs for the tax year and will significantly increase deferred tax assets for the NOL and tax credit carryforwards. Portions of the NOL are expected to be carried back to prior tax years and forward to the 2017 tax year, which could further increase existing tax credit carryforwards. The ultimate outcome of this matter cannot be determined at this time.
Tax Credit Carryforwards
Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) totaling $1.2$1.9 billion and $26 million, respectively, as of SeptemberJune 30, 2016 and $554 million and $1 million, respectively,2017 compared to $1.8 billion as of December 31, 2015. Additionally, Southern Company had $165 million of state ITC carryforwards for the state of Georgia as of September 30, 2016 compared to $188 million as of December 31, 2015. See "Unrecognized Tax Benefits" herein for further information.2016.
The federal ITC carryforwards as of September 30, 2016 begin expiring in 2034 but are expected to be utilized by the end of 2021. The PTC carryforwards as of September 30, 2016 begin expiring in 2035 but are expected to be utilized by the end of 2021. The state ITC carryforwards for the state of Georgia as of September 30, 2016 expire between 2020 and 20262032 but are expected to be fully utilized by 2022. The PTC carryforwards begin expiring in 2036 but are expected to be utilized by 2022. The expected utilization of tax credit carryforwards could be further delayed by numerous factors. These factors include the endacquisition of 2022.additional renewable projects, increased generation at existing wind facilities, carrying back the federal net operating loss, and potential tax reform legislation, as well as additional deductions in the event of an asset abandonment. The ultimate outcome of these matters cannot be determined at this time.
Valuation Allowances
At June 30, 2017, valuation allowances were as follows:
|
| | | | | | | | | | | |
| | Mississippi Power | | Southern Company Gas | | Southern Company |
| | (in millions) |
| Federal | $ | — |
| | $ | 18 |
| | $ | 18 |
|
| State (net of federal benefit) | 46 |
| | 1 |
| | 63 |
|
| Balance at June 30, 2017 | $ | 46 |
| | $ | 19 |
| | $ | 81 |
|
Southern Company had valuation allowances, net of the federal benefit, of $81 million at June 30, 2017 compared to $21 million at December 31, 2016. The increase was primarily due to Mississippi Power's projected inability to utilize the State of Mississippi net operating loss.
Effective Tax Rate
Southern Company
Southern Company's effective tax rate is typically lower than the statutory rate due to employee stock plans' dividend deduction, non-taxable AFUDC equity, and federal income tax benefits from ITCs and PTCs.
Southern Company's effective tax (benefit) rate was 29.1%(28.6)% for the ninesix months ended SeptemberJune 30, 20162017 compared to 33.5%29.4% for the corresponding period in 2015.2016. The effective tax rate decrease was primarily due to increased federal incomethe estimated probable losses on the Kemper IGCC, net of the non-deductible AFUDC equity portion. Other factors include an increase in tax benefits from wind PTCs and state apportionment rate changes, partially offset by a decrease in tax benefits from ITCs and an increase in state valuation allowances.
Southern Company recognizes PTCs at Southern Power, partially offset bywhen wind energy is generated and sold (using the impact of additionalprescribed KWH rate in applicable federal and state statutes), which may differ significantly from amounts computed on a quarterly basis using an overall estimated annual effective income tax benefits recognized in 2015.rate. Southern Company uses this method of recognition since the amount of PTCs can be significantly impacted by wind generation. This method can significantly affect the effective income tax rate for the period depending on the amount of pretax income.
Mississippi Power
Mississippi Power's effective tax (benefit) rate was (276.2)(30.5)% for the ninesix months ended SeptemberJune 30, 20162017 compared to (20.9)(208.1)% for the corresponding period in 2015.2016. The effective tax rate decreaseincrease was primarily due to an increase in tax benefits related to the estimated
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
probable losses on construction of the Kemper IGCC, net of the non-deductible AFUDC equity portion and an increase in non-taxable AFUDC equity.the related state valuation allowances.
Southern Power
Southern Power's effective tax (benefit) rate was (88.9)(114.7)% for the ninesix months ended SeptemberJune 30, 20162017 compared to 6.9%(74.0)% for the corresponding period in 2015.2016. The effective tax rate decrease was primarily due to increased federal incomeadditional PTCs arising from Southern Power's wind facility acquisitions, state apportionment rate changes, and lower pre-tax earnings, partially offset by a decrease in tax benefits from ITCs related to solar projects expected toITCs.
Southern Power recognizes PTCs when wind energy is generated and sold (using the prescribed KWH rate in applicable federal and state statutes), which may differ significantly from amounts computed on a quarterly basis using an overall estimated annual effective income tax rate. Southern Power uses this method of recognition since the amount of PTCs can be placed in service in 2016 and additional PTCs related tosignificantly impacted by wind projects in 2016 compared to 2015.generation. This method can significantly affect the effective income tax rate for the period depending on the amount of pretax income.
Unrecognized Tax Benefits
See Note 5 to the financial statements of each registrant under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Changes during 2016the six months ended June 30, 2017 for unrecognized tax benefits were as follows:
| | | | Mississippi Power | | Southern Power | | Southern Company | Mississippi Power | | Southern Power | | Southern Company |
| | (in millions) | (in millions) |
| Unrecognized tax benefits as of December 31, 2015 | $ | 421 |
| | $ | 8 |
| | $ | 433 |
| |
| Unrecognized tax benefits as of December 31, 2016 | | $ | 465 |
| | $ | 17 |
| | $ | 484 |
|
| Tax positions from current periods | — |
| | 12 |
| | 12 |
| 3 |
| | 1 |
| | 10 |
|
| Tax positions from prior periods | 18 |
| | (1 | ) | | 13 |
| — |
| | 1 |
| | 7 |
|
| Balance as of September 30, 2016 | $ | 439 |
| | $ | 19 |
| | $ | 458 |
| |
| Balance as of June 30, 2017 | | $ | 468 |
| | $ | 19 |
| | $ | 501 |
|
The tax positions from current periods primarily relate to federal income tax benefits from deferred ITCs and ITCs impacting the estimated annual effective tax rate for interim reporting purposes. The tax positions from prior periods primarily relate to federal incomestate tax benefits from ITCs, and from deductions forcharitable contribution carryforwards that will be impacted as a result of the proposed settlement of R&E expenditures associated with the Kemper IGCC-related research and experimental (R&E) expenditures.IGCC. See "Section 174 Research and Experimental Deduction" belowherein for additional information. These amounts are presented on a gross basis without considering the related federal or state income tax impact.
The impact on the effective tax rate, if recognized, is as follows:
| | | | As of September 30, 2016 | | As of December 31, 2015 | As of June 30, 2017 | | As of December 31, 2016 |
| | Mississippi Power | | Southern Power | | Southern Company | | Southern Company | Mississippi Power | | Southern Power | | Southern Company | | Southern Company |
| | (in millions) | (in millions) |
| Tax positions impacting the effective tax rate | $ | 1 |
| | $ | 19 |
| | $ | 20 |
| | $ | 10 |
| $ | 4 |
| | $ | 19 |
| | $ | 37 |
| | $ | 20 |
|
| Tax positions not impacting the effective tax rate | 438 |
| | — |
| | 438 |
| | 423 |
| 464 |
| | — |
| | 464 |
| | 464 |
|
| Balance of unrecognized tax benefits | $ | 439 |
| | $ | 19 |
| | $ | 458 |
| | $ | 433 |
| $ | 468 |
| | $ | 19 |
| | $ | 501 |
| | $ | 484 |
|
The tax positions impacting the effective tax rate primarily relate to federal deferred income tax benefits from ITCscredits and Southern Company's estimate of the uncertainty related to the amount of those benefits. The impact onbenefits, and state tax benefits and charitable contribution carryforwards that will be impacted as a result of the effective tax rate is determined based onproposed settlement of R&E expenditures associated with the amount of ITCs, which is uncertain.Kemper IGCC. See "Section 174 Research and Experimental Deduction" herein for additional information. If these tax positions are not able to be recognized due to a federal audit adjustment equal to in
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
the amount that has been estimated, amount, the amount of tax credit carryforwards discussed above would be reduced by approximately $94$98 million.
Accrued interest for all tax positions other than the Section 174 R&E deductions disclosed below was immaterial for all periods presented.
All of the registrants classify interest on tax uncertainties as interest expense. None of the registrants accrued any penalties on uncertain tax positions.
It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits and the U.S. Congress Joint Committee on Taxation approval of the R&E expenditures associated with the Kemper IGCC could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined. See "Section 174 Research and Experimental Deduction" herein for more information.
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2012. Southern Company has filed its 2013, 2014, and 2015 federal income tax returns and has received partial acceptance letters from the IRS; however, the IRS has not finalized its audits. Southern Company is a participant in the Compliance Assurance Process of the IRS. In addition, the pre-Merger Southern Company Gas 2014 federal tax return is currently under audit. The audits for the Southern Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2011.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Section 174 Research and Experimental Deduction
Southern Company has reflected deductions for R&E expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and has filed amended federal income tax returns for 2008 through 2013 to also include such deductions.
The Kemper IGCC is based on first-of-a-kind technology, and Southern Company and Mississippi Power believe that a significant portion of the plant costs qualify as deductible R&E expenditures under Internal Revenue CodeIRC Section 174. Subsequent to September 30,In December 2016, Southern Company and Mississippi Power responded to a notice of proposed assessment from the IRS which is continuingreached a proposed settlement, subject to reviewapproval of the underlying supportU.S. Congress Joint Committee on Taxation, resolving a methodology for the deduction.these deductions. Due to the uncertainty related to this tax position, Southern Company and Mississippi Power had related unrecognized tax benefits associated with these R&E deductions oftotaling approximately $438$464 million and associated interest of $24$36 million as of SeptemberJune 30, 2016. It is reasonably possible that this matter will2017. If the suspension of the Kemper IGCC start-up activities results in an abandonment, any amount not allowed under IRC Section 174 would be resolvedclaimed as a deduction under IRC Section 165, and would result in a reversal of the next 12 months; however, therelated unrecognized tax benefits, excluding interest. The ultimate outcome of this matter cannot be determined at this time.
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. EachSouthern Company Gas' wholesale gas operations use various contracts in its commercial activities that generally meet the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note (C) for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. The cash
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with classification of the hedged interest or principal, respectively.
Energy-Related Derivatives
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas enter into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies and the natural gas distribution utilities of Southern Company Gas have limited exposure to market volatility in energy-related commodity prices. Each of the traditional electric operating companies and certain of the natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs, implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. The Florida PSC extended the moratorium on Gulf Power's fuel-hedging program through January 1, 2021 in connection with the 2017 Rate Case Settlement Agreement. The moratorium does not have an impact on the recovery of existing hedges entered into under the previously-approved hedging program. The traditional electric operating companies (with respect to wholesale generating capacity), and Southern Power and Southern Company Gas have limited exposure to market volatility in energy-related commodity prices because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies Southern Power, and Southern Company GasPower may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted capacity is used to sell electricity and natural gas.
electricity. Southern Company Gas uses storage and transportation capacity contractsretains exposure to manage market price risks. Southern Company Gas purchases natural gas for storage when the current market price paid to buy and transport natural gas plus the cost to store and finance the natural gas is less than the market price Southern Company Gas will receive in the future, resultingchanges that can, in a positive net operating margin. Southern Company Gas uses New York Mercantile Exchange (NYMEX) futuresvolatile energy market, be material 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.operations.
Southern Company Gas also enters into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in the statements of income.
Energy-related derivative contracts are accounted for under one of three methods:
Regulatory Hedges — Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the traditional electric operating companies' and Southern Company Gas'the natural gas distribution utilities' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses.
Cash Flow Hedges — Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings.
Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric and natural gas industries. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
At SeptemberJune 30, 2016,2017, the net volume of energy-related derivative contracts for natural gas positions for the Southern Company system, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows:
| | | | Net Purchased mmBtu | | Longest Hedge Date | | Longest Non-Hedge Date | Net Purchased mmBtu | | Longest Hedge Date | | Longest Non-Hedge Date |
| | (in millions) | | (in millions) | |
Southern Company(*) | 540 | | 2020 | | 2022 | 472 | | 2021 | | 2024 |
| Alabama Power | 75 | | 2020 | | — | 70 | | 2020 | | — |
| Georgia Power | 148 | | 2020 | | — | 160 | | 2020 | | — |
| Gulf Power | 57 | | 2020 | | — | 35 | | 2020 | | — |
| Mississippi Power | 37 | | 2020 | | — | 41 | | 2021 | | — |
| Southern Power | 9 | | 2017 | | 2016 | 25 | | 2017 | | — |
Southern Company Gas(*) | | 141 | | 2019 | | 2024 |
| |
| (*) | Southern Company's and Southern Company Gas' derivative instruments are comprised ofinclude both long and short natural gas positions. A long position is a contract to purchase natural gas and a short position is a contract to sell natural gas. Southern Company Gas' volume represents the net of long natural gas positions of 3.23.5 billion mmBtu and short natural gas positions of 2.93.4 billion mmBtu as of SeptemberJune 30, 2016.2017, which is also included in Southern Company's total volume. |
In addition to the volumes discussed in the above, table, the traditional electric operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 531 million mmBtu for Southern Company, 10 million mmbtu for Georgia Power and GeorgiaSouthern Power, 5 million mmbtu for Alabama Power, and 3 million mmBtu for Gulf Power and Mississippi Power.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
For cash flow hedges of energy-related derivatives, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending SeptemberJune 30, 20172018 are $6 million for Southern Power and immaterial for all other registrants.
Interest Rate Derivatives
Southern Company and certain subsidiaries may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings, providing an offset, with any difference representing ineffectiveness. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
At SeptemberJune 30, 2016,2017, the following interest rate derivatives were outstanding:
|
| | | | | | | | | | | |
| | Notional Amount | | Interest Rate Received | Weighted Average Interest Rate Paid | Hedge Maturity Date | | Fair Value
Gain (Loss) at September 30, 2016 |
| | (in millions) | | | | | | (in millions) |
| Cash Flow Hedges of Forecasted Debt | | | | | | |
| Gulf Power | $ | 80 |
| | 3-month
LIBOR | 2.32% | December 2026 | | $ | (6 | ) |
| Cash Flow Hedges of Existing Debt | | | | | | |
| Mississippi Power | 900 |
| | 1-month
LIBOR | 0.79% | March 2018 | | (1 | ) |
| 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 | 250 |
| | 5.40% | 3-month
LIBOR + 4.02% | June 2018 | | 2 |
|
| Georgia Power | 200 |
| | 4.25% | 3-month
LIBOR + 2.46% | December 2019 | | 5 |
|
| Georgia Power | 500 |
| | 1.95% | 3-month
LIBOR + 0.76% | December 2018 | | 2 |
|
| Derivatives not Designated as Hedges | | | | | | |
| Southern Power | 65 |
| (b)(e) | 3-month
LIBOR | 2.50% | October 2016 | (f) | — |
|
| Southern Power | 47 |
| (c)(e) | 3-month
LIBOR | 2.21% | October 2016 | (f) | — |
|
| Southern Power | 65 |
| (d)(e) | 3-month
LIBOR | 2.21% | November 2016 | (g) | — |
|
| Southern Company Consolidated | $ | 2,657 |
| | | | | | $ | 12 |
|
|
| | | | | | | | | | | |
| | Notional Amount | | Interest Rate Received | Weighted Average Interest Rate Paid | Hedge Maturity Date | | Fair Value
Gain (Loss) at June 30, 2017 |
| | (in millions) | | | | | | (in millions) |
| Cash Flow Hedges of Existing Debt | | | | | | |
| Mississippi Power | $ | 900 |
| | 1-month
LIBOR | 0.79% | March 2018 | | $ | 3 |
|
| Fair Value Hedges of Existing Debt | | | | | | |
Southern Company(*) | 250 |
| | 1.30% | 3-month
LIBOR + 0.17% | August 2017 | | — |
|
Southern Company(*) | 300 |
| | 2.75% | 3-month
LIBOR + 0.92% | June 2020 | | 1 |
|
Southern Company(*) | 1,500 |
| | 2.35% | 1-month
LIBOR + 0.87% | July 2021 | | (14 | ) |
| Georgia Power | 250 |
| | 5.40% | 3-month
LIBOR + 4.02% | June 2018 | | — |
|
| Georgia Power | 500 |
| | 1.95% | 3-month
LIBOR + 0.76% | December 2018 | | (2 | ) |
| Georgia Power | 200 |
| | 4.25% | 3-month
LIBOR + 2.46% | December 2019 | | 1 |
|
| Southern Company Consolidated | $ | 3,900 |
| | | | | | $ | (11 | ) |
| |
(a)(*) | Represents the Southern Company parent entity. |
| |
(b) | Swaption at RE Tranquillity LLC. See Note 12 to the financial statements of Southern Company and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information. |
| |
(c) | Swaption at RE Roserock LLC. See Note 12 to the financial statements of Southern Company and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information. Subsequent to September 30, 2016, Roserock extended the maturity date of its swaption to December 31, 2016. |
| |
(d) | Swaption at RE Garland Holdings LLC. See Note 12 to the financial statements of Southern Company and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information. |
| |
(e) | Amortizing notional amount. |
| |
(f) | Represents the mandatory settlement date. Settlement will be based on a 15-year amortizing swap. |
| |
(g) | Represents the mandatory settlement date. Settlement will be based on a 12-year amortizing swap. |
The estimated pre-tax gains (losses) related to interest rate derivatives expected to be reclassified from accumulated OCI to interest expense for the next 12-month period ending SeptemberJune 30, 20172018 are $(21) million for Southern Company and immaterial for all other registrants. Southern Company and certain subsidiaries have deferred gains and losses that are expected to be amortized into earnings through 2046.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Foreign Currency Derivatives
Southern Company and certain subsidiaries may also enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time that the hedged transactions affect earnings, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Any ineffectiveness is recorded directly to earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
At SeptemberJune 30, 2016,2017, the following foreign currency derivatives were outstanding:
| |
| Pay Notional | Pay Rate | Receive Notional | Receive Rate | Hedge
Maturity Date | Fair Value
Gain (Loss) at September 30, 2016 | Pay Notional | Pay Rate | Receive Notional | Receive Rate | Hedge
Maturity Date | Fair Value
Gain (Loss) at June 30, 2017 |
| (in millions) | | (in millions) | | | (in millions) | (in millions) | | (in millions) | | | (in millions) |
| Cash Flow Hedges of Existing Debt | Cash Flow Hedges of Existing Debt | | | | | Cash Flow Hedges of Existing Debt | | | | |
| Southern Power | $ | 677 |
| 2.95% | € | 600 |
| 1.00% | June 2022 | $ | (2 | ) | $ | 677 |
| 2.95% | € | 600 |
| 1.00% | June 2022 | $ | 18 |
|
| Southern Power | 564 |
| 3.78% | 500 |
| 1.85% | June 2026 | 1 |
| 564 |
| 3.78% | 500 |
| 1.85% | June 2026 | 15 |
|
| Total | $ | 1,241 |
| | € | 1,100 |
| | $ | (1 | ) | $ | 1,241 |
| | € | 1,100 |
| | $ | 33 |
|
The estimated pre-tax gains (losses) related to foreign currency derivatives that will be reclassified from accumulated OCI to earnings for the next 12-month period ending SeptemberJune 30, 20172018 are $(12)$(23) million for Southern Company and Southern Power.
Derivative Financial Statement Presentation and Amounts
Derivative contracts of Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are presented on a net basis in the financial statements to the extent that the contracts are subject to netting arrangements. Some of these energy-related and interest rateenter into derivative contracts that may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Southern Company and certain subsidiaries also utilize master netting agreements to mitigate exposure to counterparty credit risk. These agreements may contain provisions that permit netting across product lines and against cash collateral. The fair value amounts of derivative assets and liabilities on the balance sheet are presented net to the extent that there are netting arrangements or similar agreements with the counterparties.
At September 30, 2016, the
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
The fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:
|
| | | | | | |
| | As of September 30, 2016 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities |
| | (in millions) |
| Southern Company | | |
| Derivatives designated as hedging instruments for regulatory purposes | | |
| Energy-related derivatives: | | |
| Other current assets/Liabilities from risk management activities, net of collateral | $ | 20 |
| $ | (62 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | 13 |
| (53 | ) |
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 33 |
| $ | (115 | ) |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | |
| Energy-related derivatives: | | |
| Other current assets/Liabilities from risk management activities, net of collateral | $ | 4 |
| $ | (6 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| (1 | ) |
Table of Contents |
| | | | | | | | | | | | |
| | As of June 30, 2017 | As of December 31, 2016 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| | (in millions) | (in millions) |
| Southern Company | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Liabilities from risk management activities, net of collateral | $ | 23 |
| $ | 35 |
| $ | 73 |
| $ | 27 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 8 |
| 31 |
| 25 |
| 33 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 31 |
| $ | 66 |
| $ | 98 |
| $ | 60 |
|
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Liabilities from risk management activities, net of collateral | $ | 13 |
| $ | 10 |
| $ | 23 |
| $ | 7 |
|
| Interest rate derivatives: | | | | |
| Other current assets/Liabilities from risk management activities, net of collateral | 11 |
| 1 |
| 12 |
| 1 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 22 |
| 1 |
| 28 |
|
| Foreign currency derivatives: | | | | |
| Other current assets/Liabilities from risk management activities, net of collateral | — |
| 23 |
| — |
| 25 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 56 |
| — |
| — |
| 33 |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 80 |
| $ | 56 |
| $ | 36 |
| $ | 94 |
|
| Derivatives not designated as hedging instruments | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Liabilities from risk management activities, net of collateral | $ | 237 |
| $ | 202 |
| $ | 489 |
| $ | 483 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 102 |
| 86 |
| 66 |
| 81 |
|
| Interest rate derivatives: | | | | |
| Other current assets/Liabilities from risk management activities, net of collateral | — |
| — |
| 1 |
| — |
|
| Total derivatives not designated as hedging instruments | $ | 339 |
| $ | 288 |
| $ | 556 |
| $ | 564 |
|
| Gross amounts recognized | $ | 450 |
| $ | 410 |
| $ | 690 |
| $ | 718 |
|
Gross amounts offset(*) | $ | (219 | ) | $ | (290 | ) | $ | (462 | ) | $ | (524 | ) |
| Net amounts recognized in the Balance Sheets | $ | 231 |
| $ | 120 |
| $ | 228 |
| $ | 194 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | |
| | As of September 30, 2016 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities |
| | (in millions) |
| Interest rate derivatives: |
|
|
| Other current assets/Liabilities from risk management activities, net of collateral | $ | 8 |
| $ | (7 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | 11 |
| — |
|
| Foreign currency derivatives: | | |
| Other current assets/Liabilities from risk management activities, net of collateral | $ | — |
| $ | (24 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | 23 |
| — |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 46 |
| $ | (38 | ) |
| Derivatives not designated as hedging instruments | | |
| Energy-related derivatives: | | |
| Other current assets/Liabilities from risk management activities, net of collateral | $ | 305 |
| $ | (345 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | 58 |
| (74 | ) |
| Total derivatives not designated as hedging instruments | $ | 363 |
| $ | (419 | ) |
| Gross amounts of recognized assets and liabilities | $ | 442 |
| $ | (572 | ) |
Gross amounts offset in the Balance Sheet(*) | $ | (283 | ) | $ | 394 |
|
| Net amounts of assets and liabilities presented in the Balance Sheet | $ | 159 |
| $ | (178 | ) |
| | | |
| Alabama Power | | |
| Derivatives designated as hedging instruments for regulatory purposes | | |
| Energy-related derivatives: | | |
| Other current assets/Liabilities from risk management activities | $ | 4 |
| $ | (14 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | 4 |
| (7 | ) |
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 8 |
| $ | (21 | ) |
| Gross amounts of recognized assets and liabilities | $ | 8 |
| $ | (21 | ) |
Gross amounts offset in the Balance Sheet(*) | $ | (7 | ) | $ | 7 |
|
| Net amounts of assets and liabilities presented in the Balance Sheet | $ | 1 |
| $ | (14 | ) |
| | | |
| Georgia Power | | |
| Derivatives designated as hedging instruments for regulatory purposes | | |
| Energy-related derivatives: | | |
| Other current assets/Other current liabilities | $ | 7 |
| $ | (5 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | 8 |
| (11 | ) |
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 15 |
| $ | (16 | ) |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | |
| Interest rate derivatives: | | |
| Other current assets/Other current liabilities | $ | 5 |
| $ | — |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 5 |
| — |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 10 |
| $ | — |
|
| Gross amounts of recognized assets and liabilities | $ | 25 |
| $ | (16 | ) |
Gross amounts offset in the Balance Sheet(*) | $ | (11 | ) | $ | 11 |
|
| Net amounts of assets and liabilities presented in the Balance Sheet | $ | 14 |
| $ | (5 | ) |
| | | |
Table of Contents |
| | | | | | | | | | | | |
| | As of June 30, 2017 | As of December 31, 2016 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| | (in millions) | (in millions) |
| | | | | |
| Alabama Power | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Liabilities from risk management activities | $ | 7 |
| $ | 7 |
| $ | 13 |
| $ | 5 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 2 |
| 4 |
| 7 |
| 4 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 9 |
| $ | 11 |
| $ | 20 |
| $ | 9 |
|
| Gross amounts recognized | $ | 9 |
| $ | 11 |
| $ | 20 |
| $ | 9 |
|
| Gross amounts offset | $ | (6 | ) | $ | (6 | ) | $ | (8 | ) | $ | (8 | ) |
| Net amounts recognized in the Balance Sheets | $ | 3 |
| $ | 5 |
| $ | 12 |
| $ | 1 |
|
| | | | | |
| Georgia Power | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 10 |
| $ | 4 |
| $ | 30 |
| $ | 1 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 5 |
| 10 |
| 14 |
| 7 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 15 |
| $ | 14 |
| $ | 44 |
| $ | 8 |
|
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Interest rate derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 1 |
| $ | 1 |
| $ | 2 |
| $ | — |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 2 |
| — |
| 3 |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 1 |
| $ | 3 |
| $ | 2 |
| $ | 3 |
|
| Gross amounts recognized | $ | 16 |
| $ | 17 |
| $ | 46 |
| $ | 11 |
|
| Gross amounts offset | $ | (9 | ) | $ | (9 | ) | $ | (8 | ) | $ | (8 | ) |
| Net amounts recognized in the Balance Sheets | $ | 7 |
| $ | 8 |
| $ | 38 |
| $ | 3 |
|
| | | | | |
| Gulf Power | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Liabilities from risk management activities | $ | 1 |
| $ | 16 |
| $ | 4 |
| $ | 12 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 13 |
| 1 |
| 17 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 1 |
| $ | 29 |
| $ | 5 |
| $ | 29 |
|
| Gross amounts recognized | $ | 1 |
| $ | 29 |
| $ | 5 |
| $ | 29 |
|
| Gross amounts offset | $ | (1 | ) | $ | (1 | ) | $ | (4 | ) | $ | (4 | ) |
| Net amounts recognized in the Balance Sheets | $ | — |
| $ | 28 |
| $ | 1 |
| $ | 25 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | |
| | As of September 30, 2016 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities |
| | (in millions) |
| Gulf Power | | |
| Derivatives designated as hedging instruments for regulatory purposes | | |
| Energy-related derivatives: | | |
| Other current assets/Liabilities from risk management activities | $ | 1 |
| $ | (24 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| (27 | ) |
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 1 |
| $ | (51 | ) |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | |
| Interest rate derivatives: | | |
| Other current assets/Liabilities from risk management activities | $ | — |
| $ | (6 | ) |
| Gross amounts of recognized assets and liabilities | $ | 1 |
| $ | (57 | ) |
Gross amounts offset in the Balance Sheet(*) | $ | (1 | ) | $ | 1 |
|
| Net amounts of assets and liabilities presented in the Balance Sheet | $ | — |
| $ | (56 | ) |
| | | |
| Mississippi Power | | |
| Derivatives designated as hedging instruments for regulatory purposes | | |
| Energy-related derivatives: | | |
| Other current assets/Other current liabilities | $ | — |
| $ | (13 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | 1 |
| (8 | ) |
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 1 |
| $ | (21 | ) |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | |
| Interest rate derivatives: | | |
| Other current assets/Other current liabilities | $ | — |
| $ | (1 | ) |
| Gross amounts of recognized assets and liabilities | $ | 1 |
| $ | (22 | ) |
Gross amounts offset in the Balance Sheet(*) | $ | (1 | ) | $ | 1 |
|
| Net amounts of assets and liabilities presented in the Balance Sheet | $ | — |
| $ | (21 | ) |
| | | |
| Southern Power | | |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | |
| Energy-related derivatives: | | |
| Other current assets/Other current liabilities | $ | 2 |
| $ | (3 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| — |
|
| Foreign currency derivatives: | | |
| Other current assets/Other current liabilities | $ | — |
| $ | (24 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | 23 |
| — |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 25 |
| $ | (27 | ) |
| Derivatives not designated as hedging instruments | | |
| Energy-related derivatives: | | |
| Other current assets/Other current liabilities | $ | 1 |
| $ | — |
|
| Gross amounts of recognized assets and liabilities | $ | 26 |
| $ | (27 | ) |
Gross amounts offset in the Balance Sheet(*) | $ | (1 | ) | $ | 1 |
|
| Net amounts of assets and liabilities presented in the Balance Sheet | $ | 25 |
| $ | (26 | ) |
| |
(*) | Includes any cash/financial collateral pledged or received. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
At December 31, 2015, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows: |
| | | | | | | | | | | | | | | |
| Asset Derivatives at December 31, 2015 |
| | Fair Value |
| Derivative Category and Balance Sheet Location | Southern Company | Alabama Power | Georgia Power | Gulf Power | Southern Power |
| | (in millions) |
| Derivatives designated as hedging instruments for regulatory purposes | | | | | |
| Energy-related derivatives: | | | | | |
| Other current assets | $ | 3 |
| $ | 1 |
| $ | 2 |
| $ | — |
| $ | — |
|
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | | |
| Energy-related derivatives: | | | | | |
| Other current assets | $ | 3 |
| $ | — |
| $ | — |
| $ | — |
| $ | 3 |
|
| Interest rate derivatives: | | | | | |
| Other current assets | 19 |
| — |
| 5 |
| 1 |
| — |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 22 |
| $ | — |
| $ | 5 |
| $ | 1 |
| $ | 3 |
|
| Derivatives not designated as hedging instruments | | | | | |
| Energy-related derivatives: | | | | | |
| Other current assets | $ | 1 |
| $ | — |
| $ | — |
| $ | — |
| $ | 1 |
|
| Interest rate derivatives: | | | | | |
| Other current assets | 3 |
| — |
| — |
| — |
| 3 |
|
| Total derivatives not designated as hedging instruments | $ | 4 |
| $ | — |
| $ | — |
| $ | — |
| $ | 4 |
|
| Total asset derivatives | $ | 29 |
| $ | 1 |
| $ | 7 |
| $ | 1 |
| $ | 7 |
|
Table of Contents |
| | | | | | | | | | | | |
| | As of June 30, 2017 | As of December 31, 2016 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| | (in millions) | (in millions) |
| | | | | |
| Mississippi Power | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 1 |
| $ | 6 |
| $ | 2 |
| $ | 6 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 1 |
| 4 |
| 2 |
| 5 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 2 |
| $ | 10 |
| $ | 4 |
| $ | 11 |
|
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Interest rate derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 3 |
| $ | — |
| $ | 2 |
| $ | — |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| — |
| 1 |
| — |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 3 |
| $ | — |
| $ | 3 |
| $ | — |
|
| Gross amounts recognized | $ | 5 |
| $ | 10 |
| $ | 7 |
| $ | 11 |
|
| Gross amounts offset | $ | (2 | ) | $ | (2 | ) | $ | (3 | ) | $ | (3 | ) |
| Net amounts recognized in the Balance Sheets | $ | 3 |
| $ | 8 |
| $ | 4 |
| $ | 8 |
|
| | | | | |
| Southern Power | | | | |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 13 |
| $ | 8 |
| $ | 18 |
| $ | 4 |
|
| Foreign currency derivatives: | | | | |
| Other current assets/Other current liabilities | — |
| 23 |
| — |
| 25 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 56 |
| — |
| — |
| 33 |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 69 |
| $ | 31 |
| $ | 18 |
| $ | 62 |
|
| Derivatives not designated as hedging instruments | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 1 |
| $ | 1 |
| $ | 3 |
| $ | 1 |
|
| Interest rate derivatives: | | | | |
| Other current assets/Other current liabilities | — |
| — |
| 1 |
| — |
|
| Total derivatives not designated as hedging instruments | $ | 1 |
| $ | 1 |
| $ | 4 |
| $ | 1 |
|
| Gross amounts recognized | $ | 70 |
| $ | 32 |
| $ | 22 |
| $ | 63 |
|
| Gross amounts offset | $ | (2 | ) | $ | (2 | ) | $ | (5 | ) | $ | (5 | ) |
| Net amounts recognized in the Balance Sheets | $ | 68 |
| $ | 30 |
| $ | 17 |
| $ | 58 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | |
| Liability Derivatives at December 31, 2015 |
| | Fair Value |
Derivative Category and Balance Sheet Location | Southern Company | Alabama Power | Georgia Power | Gulf Power | Mississippi Power | Southern Power |
| | (in millions) |
| Derivatives designated as hedging instruments for regulatory purposes | | | | | | |
| Energy-related derivatives: | | | | | | |
Liabilities from risk management activities(*) | $ | 130 |
| $ | 40 |
| $ | 12 |
| $ | 49 |
| $ | 29 |
| |
| Other deferred credits and liabilities | 87 |
| 15 |
| 3 |
| 51 |
| 18 |
| |
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 217 |
| $ | 55 |
| $ | 15 |
| $ | 100 |
| $ | 47 |
| N/A |
|
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | | | |
| Energy-related derivatives: | | | | | | |
Liabilities from risk management activities(*) | $ | 2 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 2 |
|
| Interest rate derivatives: | | | | | | |
| Liabilities from risk management activities | 23 |
| 15 |
| — |
| — |
| — |
| — |
|
| Other deferred credits and liabilities | 7 |
| — |
| 6 |
| — |
| — |
| — |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 32 |
| $ | 15 |
| $ | 6 |
| $ | — |
| $ | — |
| $ | 2 |
|
| Derivatives not designated as hedging instruments | | | | | | |
| Energy-related derivatives: | | | | | | |
Liabilities from risk management activities(*) | $ | 1 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 1 |
|
| Total liability derivatives | $ | 250 |
| $ | 70 |
| $ | 21 |
| $ | 100 |
| $ | 47 |
| $ | 3 |
|
|
| | | | | | | | | | | | |
| | As of June 30, 2017 | As of December 31, 2016 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| | (in millions) | (in millions) |
| | | | | |
| Southern Company Gas | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Assets from risk management activities/Liabilities from risk management activities-current | $ | 4 |
| $ | 2 |
| $ | 24 |
| $ | 3 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| — |
| 1 |
| — |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 4 |
| $ | 2 |
| $ | 25 |
| $ | 3 |
|
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Energy-related derivatives: | | | | |
| Assets from risk management activities/Liabilities from risk management activities-current | $ | — |
| $ | 2 |
| $ | 4 |
| $ | 3 |
|
| Derivatives not designated as hedging instruments | | | | |
| Energy-related derivatives: | | | | |
| Assets from risk management activities/Liabilities from risk management activities-current | $ | 236 |
| $ | 201 |
| $ | 486 |
| $ | 482 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 102 |
| 86 |
| 66 |
| 81 |
|
| Total derivatives not designated as hedging instruments | $ | 338 |
| $ | 287 |
| $ | 552 |
| $ | 563 |
|
| Gross amounts of recognized | $ | 342 |
| $ | 291 |
| $ | 581 |
| $ | 569 |
|
Gross amounts offset(*) | $ | (196 | ) | $ | (267 | ) | $ | (435 | ) | $ | (497 | ) |
| Net amounts recognized in the Balance Sheets | $ | 146 |
| $ | 24 |
| $ | 146 |
| $ | 72 |
|
| |
| (*) | Georgia Power, Mississippi Power,Gross amounts offset include cash collateral held on deposit in broker margin accounts of $71 million and Southern Power include current liabilities related to derivatives in other current liabilities.$62 million as of June 30, 2017 and December 31, 2016, respectively. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
In 2015, the derivative contracts of Southern Company, the traditional electric operating companies, and Southern Power are reported gross on each registrant's financial statements. Some of these energy-related and interest rate derivative contracts may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-related derivative contracts and interest rate derivative contracts at December 31, 2015 are presented in the following table:
|
| | | | | | | | | | | | | | | | | | |
| Derivative Contracts at December 31, 2015 |
| | Fair Value |
| | Southern Company | Alabama Power | Georgia Power | Gulf Power | Mississippi Power | Southern Power |
| | (in millions) |
| Assets | | | | | | |
| Energy-related derivatives: | | | | | | |
Energy-related derivatives presented in the Balance Sheet(a) | $ | 7 |
| $ | 1 |
| $ | 2 |
| $ | — |
| $ | — |
| $ | 4 |
|
Gross amounts not offset in the Balance Sheet(b) | (6 | ) | (1 | ) | (2 | ) | — |
| — |
| (1 | ) |
| Net energy-related derivative assets | $ | 1 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 3 |
|
| Interest rate derivatives: | | | | | | |
Interest rate derivatives presented in the Balance Sheet(a) | $ | 22 |
| $ | — |
| $ | 5 |
| $ | 1 |
| $ | — |
| $ | 3 |
|
Gross amounts not offset in the Balance Sheet(b) | (9 | ) | — |
| (4 | ) | — |
| — |
| — |
|
| Net interest rate derivative assets | $ | 13 |
| $ | — |
| $ | 1 |
| $ | 1 |
| $ | — |
| $ | 3 |
|
| Liabilities | | | | | | |
| Energy-related derivatives: | | | | | | |
Energy-related derivatives presented in the Balance Sheet(a) | $ | 220 |
| $ | 55 |
| $ | 15 |
| $ | 100 |
| $ | 47 |
| $ | 3 |
|
Gross amounts not offset in the Balance Sheet(b) | (6 | ) | (1 | ) | (2 | ) | — |
| — |
| (1 | ) |
| Net energy-related derivative liabilities | $ | 214 |
| $ | 54 |
| $ | 13 |
| $ | 100 |
| $ | 47 |
| $ | 2 |
|
| Interest rate derivatives: | | | | | | |
Interest rate derivatives presented in the Balance Sheet(a) | $ | 30 |
| $ | 15 |
| $ | 6 |
| $ | — |
| $ | — |
| $ | — |
|
Gross amounts not offset in the Balance Sheet(b) | (9 | ) | — |
| (4 | ) | — |
| — |
| — |
|
| Net interest rate derivative liabilities | $ | 21 |
| $ | 15 |
| $ | 2 |
| $ | — |
| $ | — |
| $ | — |
|
| |
(a) | As of December 31, 2015, none of the registrants offset fair value amounts for multiple derivative instruments executed with the same counterparty in the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented in the balance sheets are the same. |
| |
(b) | Includes gross amounts subject to netting terms that are not offset in the balance sheets and any cash/financial collateral pledged or received. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
At SeptemberJune 30, 20162017 and December 31, 2015,2016, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:
| | | Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at September 30, 2016 | |
| Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at June 30, 2017 | | Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at June 30, 2017 |
Derivative Category and Balance Sheet Location | Southern Company | Alabama Power | Georgia Power | Gulf Power | Mississippi Power | Southern Company(b) | Alabama Power | Georgia Power | Gulf Power | Mississippi Power | Southern Company Gas(b) |
| | (in millions) | (in millions) | |
| Energy-related derivatives: | | |
| Other regulatory assets, current | $ | (52 | ) | $ | (10 | ) | $ | (2 | ) | $ | (24 | ) | $ | (13 | ) | $ | (24 | ) | $ | (3 | ) | $ | — |
| $ | (15 | ) | $ | (5 | ) | $ | (1 | ) |
| Other regulatory assets, deferred | (42 | ) | (4 | ) | (4 | ) | (26 | ) | (8 | ) | (23 | ) | (2 | ) | (5 | ) | (13 | ) | (3 | ) | — |
|
Other regulatory liabilities, current(a) | 8 |
| 1 |
| 4 |
| — |
| — |
| 13 |
| 3 |
| 6 |
| — |
| — |
| 4 |
|
Other regulatory liabilities, deferred(b) | 1 |
| — |
| 1 |
| — |
| — |
| |
| Total energy-related derivative gains (losses) | $ | (85 | ) | $ | (13 | ) | $ | (1 | ) | $ | (50 | ) | $ | (21 | ) | $ | (34 | ) | $ | (2 | ) | $ | 1 |
| $ | (28 | ) | $ | (8 | ) | $ | 3 |
|
| |
| (a) | Georgia Power includes other regulatory liabilities, current in other current liabilities. |
| |
| (b) | Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $1 million at June 30, 2017. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | |
| Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2016 |
Derivative Category and Balance Sheet Location | Southern Company(c) | Alabama Power | Georgia Power | Gulf Power | Mississippi Power | Southern Company Gas(c) |
| | (in millions) | |
| Energy-related derivatives: | | | | | | |
| Other regulatory assets, current | $ | (16 | ) | $ | (1 | ) | $ | — |
| $ | (9 | ) | $ | (5 | ) | $ | (1 | ) |
| Other regulatory assets, deferred | (19 | ) | — |
| — |
| (16 | ) | (3 | ) | — |
|
Other regulatory liabilities, current(a) | 56 |
| 8 |
| 29 |
| 1 |
| 1 |
| 17 |
|
Other regulatory liabilities, deferred(b) | 12 |
| 4 |
| 7 |
| — |
| — |
| 1 |
|
| Total energy-related derivative gains (losses) | $ | 33 |
| $ | 11 |
| $ | 36 |
| $ | (24 | ) | $ | (7 | ) | $ | 17 |
|
| |
| (a) | Georgia Power includes other regulatory liabilities, current in other current liabilities. |
| |
| (b) | Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities. |
|
| | | | | | | | | | | | | | | |
| Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2015 |
Derivative Category and Balance Sheet Location | Southern Company | Alabama Power | Georgia Power | Gulf Power | Mississippi Power |
| | (in millions) |
| Energy-related derivatives: | | | | | |
| Other regulatory assets, current | $ | (130 | ) | $ | (40 | ) | $ | (12 | ) | $ | (49 | ) | $ | (29 | ) |
| Other regulatory assets, deferred | (87 | ) | (15 | ) | (3 | ) | (51 | ) | (18 | ) |
Other regulatory liabilities, current(*) | 3 |
| 1 |
| 2 |
| — |
| — |
|
| Total energy-related derivative gains (losses) | $ | (214 | ) | $ | (54 | ) | $ | (13 | ) | $ | (100 | ) | $ | (47 | ) |
| |
(*)(c) | Georgia Power includes otherFair value gains and losses recorded in regulatory assets and liabilities currentinclude cash collateral held on deposit in other current liabilities.broker margin accounts of $8 million at December 31, 2016. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
For the three months ended SeptemberJune 30, 20162017 and 2015,2016, the pre-tax effects of energy-related derivatives, interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instruments were as follows:
| | Derivatives in Cash Flow Hedging Relationships | Gain (Loss) Recognized in OCI on Derivative (Effective Portion) | | Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) | Gain (Loss) Recognized in OCI on Derivative (Effective Portion) | | Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) |
| | Statements of Income Location | Amount | | Statements of Income Location | Amount |
| | 2016 | | 2015 | | 2016 | | 2015 | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Southern Company | | | | | | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | — |
| | Amortization | $ | 1 |
| | $ | — |
| $ | (9 | ) | | $ | — |
| | Depreciation and amortization | $ | (2 | ) | | $ | — |
|
| Interest rate derivatives | (6 | ) | | (28 | ) | | Interest expense, net of amounts capitalized | (6 | ) | | (2 | ) | (1 | ) | | 6 |
| | Interest expense, net of amounts capitalized | (5 | ) | | (4 | ) |
| Foreign currency derivatives | 37 |
| | — |
| | Interest expense, net of amounts capitalized | (6 | ) | | — |
| 71 |
| | (39 | ) | | Interest expense, net of amounts capitalized | (5 | ) | | (1 | ) |
| | | | | | Other income (expense), net(*) | 7 |
| | — |
| | | | | Other income (expense), net(*) | 79 |
| | (20 | ) |
| Total | $ | 31 |
| | $ | (28 | ) | | $ | (4 | ) | | $ | (2 | ) | $ | 61 |
| | $ | (33 | ) | | $ | 67 |
| | $ | (25 | ) |
| Alabama Power | | | | | | | | | | | | | | |
| Interest rate derivatives | $ | — |
| | $ | (10 | ) | | Interest expense, net of amounts capitalized | $ | (2 | ) | | $ | (1 | ) | $ | — |
| | $ | — |
| | Interest expense, net of amounts capitalized | $ | (2 | ) | | $ | (2 | ) |
| Georgia Power | | | | | | | | | | | | | | |
| Interest rate derivatives | $ | — |
| | $ | (18 | ) | | Interest expense, net of amounts capitalized | $ | (1 | ) | | $ | (1 | ) | $ | — |
| | $ | — |
| | Interest expense, net of amounts capitalized | $ | (1 | ) | | $ | (1 | ) |
| Gulf Power | | | | | | | | |
| Interest rate derivatives | | $ | (1 | ) | | $ | (2 | ) | | Interest expense, net of amounts capitalized | $ | — |
| | $ | — |
|
| Southern Power | | | | | | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | — |
| | Amortization | $ | 1 |
| | $ | — |
| $ | (7 | ) | | $ | — |
| | Depreciation and amortization | $ | (2 | ) | | $ | — |
|
| Foreign currency derivatives | 37 |
| | — |
| | Interest expense, net of amounts capitalized | (6 | ) | | — |
| 71 |
| | (39 | ) | | Interest expense, net of amounts capitalized | (5 | ) | | (1 | ) |
| | | | | | Other income (expense), net(*) | 7 |
| | — |
| | | | | Other income (expense), net(*) | 79 |
| | (20 | ) |
| Total | $ | 37 |
| | $ | — |
| | $ | 2 |
| | $ | — |
| $ | 64 |
| | $ | (39 | ) | | $ | 72 |
| | $ | (21 | ) |
| |
| (*) | 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)
206(UNAUDITED)
For Southern Company Gas, the pre-tax effect of energy related derivatives and interest rate derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings for the successor three months ended June 30, 2017 and the predecessor three months ended June 30, 2016 were as follows:
|
| | | | | | | | | | | | | | | | | | |
| Gain (Loss) Recognized in OCI on Derivative (Effective Portion) |
|
| Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) |
| Successor |
|
| Predecessor |
|
| Successor |
|
| Predecessor |
| Derivatives in Cash Flow Hedging Relationships | Three Months Ended June 30, 2017 |
|
| Three Months Ended June 30, 2016 |
| Statements of Income Location | Three Months Ended June 30, 2017 |
|
| Three Months Ended June 30, 2016 |
| (in millions) |
|
| (in millions) |
|
| (in millions) |
|
| (in millions) |
| Energy-related derivatives | $ | (2 | ) |
|
| $ | — |
|
| Cost of natural gas | $ | — |
|
|
| $ | (1 | ) |
| Interest rate derivatives | — |
|
|
| (19 | ) |
| Interest expense, net of amounts capitalized | — |
|
|
| (1 | ) |
| Total | $ | (2 | ) |
|
| $ | (19 | ) |
|
| $ | — |
|
|
| $ | (2 | ) |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
For the ninesix months ended SeptemberJune 30, 20162017 and 2015,2016, 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 as follows:
| | Derivatives in Cash Flow
Hedging Relationships | Gain (Loss)
Recognized in OCI
on Derivative
(Effective Portion) | | Gain (Loss) Reclassified from Accumulated OCI into
Income (Effective Portion) | Gain (Loss)
Recognized in OCI
on Derivative
(Effective Portion) | | Gain (Loss) Reclassified from Accumulated OCI into
Income (Effective Portion) |
| | Statements of Income Location | Amount | | Statements of Income Location | Amount |
| | 2016 | | 2015 | | 2016 | | 2015 | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | | (in millions) | (in millions) | | (in millions) |
| Southern Company | | | | | | | | | | | | | | |
| Energy-related derivatives | $ | (1 | ) | | $ | — |
| | Amortization | $ | 1 |
| | $ | — |
| $ | (20 | ) | | $ | — |
| | Depreciation and amortization | $ | (6 | ) | | $ | — |
|
| Interest rate derivatives | (189 | ) | | (26 | ) | | Interest expense, net of amounts capitalized | (13 | ) | | (7 | ) | (1 | ) | | (184 | ) | | Interest expense, net of amounts capitalized | (10 | ) | | (7 | ) |
| Foreign currency derivatives | (1 | ) | | — |
| | Interest expense, net of amounts capitalized | (7 | ) | | — |
| 67 |
| | (39 | ) | | Interest expense, net of amounts capitalized | (12 | ) | | (1 | ) |
| | | | | | Other income (expense), net(*) | (13 | ) | | — |
| | | | | Other income (expense), net(*) | 96 |
| | (20 | ) |
| Total | $ | (191 | ) | | $ | (26 | ) | | $ | (32 | ) | | $ | (7 | ) | $ | 46 |
| | $ | (223 | ) | | $ | 68 |
| | $ | (28 | ) |
| Alabama Power | | | | | | | | | | | | | | |
| Interest rate derivatives | $ | (3 | ) | | $ | (9 | ) | | Interest expense, net of amounts capitalized | $ | (5 | ) | | $ | (2 | ) | $ | — |
| | $ | (4 | ) | | Interest expense, net of amounts capitalized | $ | (3 | ) | | $ | (3 | ) |
| Georgia Power | | | | | | | | | | | | | | |
| Interest rate derivatives | $ | — |
| | $ | (17 | ) | | Interest expense, net of amounts capitalized | $ | (3 | ) | | $ | (3 | ) | $ | — |
| | $ | — |
| | Interest expense, net of amounts capitalized | $ | (3 | ) | | $ | (2 | ) |
| Gulf Power | | | | | | | | | | | | | | |
| Energy-related derivatives | | $ | (1 | ) | | $ | — |
| | Depreciation and amortization | $ | — |
| | $ | — |
|
| Interest rate derivatives | $ | (7 | ) | | $ | — |
| | Interest expense, net of amounts capitalized | $ | — |
| | $ | — |
| (1 | ) | | (7 | ) | | Interest expense, net of amounts capitalized | — |
| | — |
|
| Total | | $ | (2 | ) | | $ | (7 | ) | | $ | — |
| | $ | — |
|
| Mississippi Power | | | | | | | | | | | | | | |
| Interest rate derivatives | $ | (1 | ) | | $ | — |
| | Interest expense, net of amounts capitalized | $ | (1 | ) | | $ | (1 | ) | $ | — |
| | $ | — |
| | Interest expense, net of amounts capitalized | $ | (1 | ) | | $ | (1 | ) |
| Southern Power | | | | | | | | | | | | | | |
| Energy-related derivatives | $ | (1 | ) | | $ | — |
| | Amortization | $ | 1 |
| | $ | — |
| $ | (15 | ) | | $ | — |
| | Depreciation and amortization | $ | (6 | ) | | $ | — |
|
| Interest rate derivatives | — |
| | — |
| | Interest expense, net of amounts capitalized | (1 | ) | | (1 | ) | — |
| | — |
| | Interest expense, net of amounts capitalized | — |
| | (1 | ) |
| Foreign currency derivatives | (1 | ) | | — |
| | Interest expense, net of amounts capitalized | (7 | ) | | — |
| 67 |
| | (39 | ) | | Interest expense, net of amounts capitalized | (12 | ) | | (1 | ) |
| | | | | | Other income (expense), net(*) | (13 | ) | | — |
|
|
| |
|
| | Other income (expense), net(*) | 96 |
| | (20 | ) |
| Total | $ | (2 | ) | | $ | — |
| | $ | (20 | ) | | $ | (1 | ) | $ | 52 |
| | $ | (39 | ) | | $ | 78 |
| | $ | (22 | ) |
| |
| (*) | The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
For Southern Company Gas, the pre-tax effect of energy related derivatives and interest rate derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings for the successor six months ended June 30, 2017 and the predecessor six months ended June 30, 2016 were as follows:
|
| | | | | | | | | | | | | | | | | | |
| | Gain (Loss) Recognized in OCI on Derivative (Effective Portion) | | | Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) |
| | Successor | | | Predecessor | | | Successor | | | Predecessor |
| Derivatives in Cash Flow Hedging Relationships | Six Months Ended June 30, 2017 | | | Six Months Ended June 30, 2016 | | Statements of Income Location | Six Months Ended June 30, 2017 | | | Six Months Ended June 30, 2016 |
| | (in millions) | | | (in millions) | | | (in millions) | | | (in millions) |
| Energy-related derivatives | $ | (4 | ) | | | $ | — |
| | Cost of natural gas | $ | — |
| | | $ | (1 | ) |
| Interest rate derivatives | — |
| | | (64 | ) | | Interest expense, net of amounts capitalized | — |
| | | — |
|
| Total | $ | (4 | ) | | | $ | (64 | ) | | | $ | — |
| | | $ | (1 | ) |
For the three and ninesix months ended SeptemberJune 30, 2017 and 2016, the pre-tax effects of energy-related derivatives and 2015,interest rate derivatives designated as cash flow hedging instruments were immaterial for the other registrants.
For the three and six months ended June 30, 2017 and 2016, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments on the statements of income were as follows:
|
| | | | | | | | | | | | | | |
| | | Gain (Loss) |
| | | Three Months Ended
June 30, | | Six Months Ended
June 30, |
| Derivatives in Non-Designated Hedging Relationships | Statements of Income Location | 2017 | 2016 | | 2017 | 2016 |
| | | (in millions) | | (in millions) |
| Southern Company | | | | | | |
| Energy Related derivatives: | Natural gas revenues(*) | $ | 16 |
| $ | — |
| | $ | 65 |
| $ | — |
|
| | Cost of natural gas | (2 | ) | — |
| | (4 | ) | — |
|
| Total derivatives in non-designated hedging relationships | $ | 14 |
| $ | — |
| | $ | 61 |
| $ | — |
|
| |
| (*) | Excludes gains (losses) recorded in cost of natural gas associated with weather derivatives of $1 million and $15 million for the three and six months ended June 30, 2017, respectively. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | |
| | | Gain (Loss) |
| | | Successor |
|
| Predecessor | | Successor | | | Predecessor |
| Derivatives in Non-Designated Hedging Relationships | Statements of Income Location | Three Months Ended
June 30, 2017 | | | Three Months Ended
June 30, 2016 | | Six Months Ended June 30, 2017 | | | Six Months Ended June 30, 2016 |
| | | (in millions) | | | (in millions) | | (in millions) | | | (in millions) |
| Southern Company Gas | | | | | | | | | | |
| Energy Related derivatives: | Natural gas revenues(*) | $ | 16 |
| | | $ | (21 | ) | | $ | 65 |
| | | $ | (1 | ) |
| | Cost of natural gas | (2 | ) | | | (61 | ) | | (4 | ) | | | (62 | ) |
| Total derivatives in non-designated hedging relationships | $ | 14 |
| | | $ | (82 | ) | | $ | 61 |
| | | $ | (63 | ) |
| |
| (*) | Excludes gains recorded in cost of natural gas associated with weather derivatives of $15 million for the successor six months ended June 30, 2017 and immaterial amounts for all other periods presented. |
For the three and six months ended June 30, 2017 and 2016, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments were immaterial for the traditional electric operating companies and Southern Power.
For the three and six months ended June 30, 2017 and 2016, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were as follows:
|
| | | | | | | | | | | | | | | |
| Derivatives in Fair Value Hedging Relationships |
| | | Gain (Loss) |
| | | Three Months Ended September 30, | Nine Months Ended September 30, |
| Derivative Category | Statements of Income Location | 2016 | | 2015 | 2016 | | 2015 |
| | | (in millions) | (in millions) |
| Southern Company | | | | | | | |
| Interest rate derivatives: | Interest expense, net of amounts capitalized | $ | (9 | ) | | $ | 15 |
| $ | 15 |
| | $ | 19 |
|
| Georgia Power | | | | | | | |
| Interest rate derivatives: | Interest expense, net of amounts capitalized | $ | (5 | ) | | $ | 7 |
| $ | 10 |
| | $ | 9 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | |
| Derivatives in Fair Value Hedging Relationships |
| | | Gain (Loss) |
| | | Three Months Ended June 30, | Six Months Ended June 30, |
| Derivative Category | Statements of Income Location | 2017 | | 2016 | 2017 | | 2016 |
| | | (in millions) | (in millions) |
| Southern Company | | | | | | | |
| Interest rate derivatives: | Interest expense, net of amounts capitalized | $ | 7 |
| | $ | 4 |
| $ | (1 | ) | | $ | 24 |
|
| Georgia Power | | | | | | | |
| Interest rate derivatives: | Interest expense, net of amounts capitalized | $ | — |
| | $ | — |
| $ | (1 | ) | | $ | 15 |
|
For the three and ninesix months ended SeptemberJune 30, 20162017 and 2015,2016, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were offset by changes to the carrying value of long-term debt.
There was no material ineffectiveness recorded in earnings for any registrant for any period presented.
For the three and nine months ended September 30, 2016 and 2015, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments were immaterial for all registrants.
Contingent Features
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At SeptemberJune 30, 2016, Southern Company2017, the registrants had $111 million ofno collateral posted with derivative counterparties. The amount of collateral posted with the derivative counterparties for all other registrants was immaterial.to satisfy these arrangements.
At SeptemberJune 30, 2016,2017, the fair value of derivative liabilities with contingent features was $22 millionimmaterial for all registrants. The maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $22$11 million for all registrantsSouthern Company, $10 million for the traditional electric operating companies and Southern Power, and $1 million for Southern Company Gas. The maximum potential collateral
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
requirements arising from the credit-risk-related contingent features for the traditional electric operating companies and Southern Power include certain agreements that could require collateral in the event that one or more Southern Company power pool participants 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.
Alabama Power and Southern Power maintain accounts with certain regional transmission organizations to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Alabama Power and Southern Power may be required to post collateral. At June 30, 2017, cash collateral posted in these accounts was immaterial. Southern Company Gas maintains accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Southern Company Gas may be required to deposit cash into these accounts. At June 30, 2017, cash collateral held on deposit in broker margin accounts was $71 million.
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas only enter into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate Southern Company's, the traditional electric operating companies', Southern Power's, and Southern Company Gas' exposure to counterparty credit risk. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary. Therefore,
In addition, Southern Company Gasconducts credit evaluations and obtains appropriate internal approvals for the counterparty's line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody's and BBB- from S&P. Generally, Southern Company Gas requires credit enhancements by way of a guaranty, cash deposit, or letter of credit for transaction counterparties that do not have investment grade ratings.
Southern Company Gas also utilizes master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When Southern Company Gas is engaged in more than one outstanding derivative transaction with the same counterparty and it also has a legally enforceable netting agreement with that counterparty, the "net" mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of Southern Company Gas' credit risk. Southern Company Gas also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Master netting agreements enable Southern Company Gas to net certain assets and liabilities by counterparty. Southern Company Gas also nets across product lines and against cash collateral provided the master netting and cash collateral agreements include such provisions. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.
Southern Company, the traditional electric operating companies, Southern Power, and Southern PowerCompany Gas do not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Southern Company
Merger with Southern Company Gas
Southern Company Gas formerly known as AGL Resources Inc., is an energy services holding company whose primary business is the distribution of natural gas through the natural gas distribution utilities. On July 1, 2016, Southern Company completed the Merger for a total purchase price of approximately $8.0 billion and Southern Company Gas became a wholly-owned, direct subsidiary of Southern Company.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
The Merger was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value as of the acquisition date. The following table presents the preliminaryfinal purchase price allocation:
| | | Southern Company Gas Purchase Price | September 30, 2016 | |
| | (in millions) | (in millions) |
| Current assets | $ | 1,557 |
| $ | 1,557 |
|
| Property, plant, and equipment | 10,108 |
| 10,108 |
|
| Goodwill | 5,937 |
| 5,967 |
|
| Intangible assets | 400 |
| 400 |
|
| Regulatory assets | 1,118 |
| 1,118 |
|
| Other assets | 229 |
| 229 |
|
| Current liabilities | (2,201 | ) | (2,201 | ) |
| Other liabilities | (4,712 | ) | (4,742 | ) |
| Long-term debt | (4,261 | ) | (4,261 | ) |
| Noncontrolling interests | (174 | ) | |
| Noncontrolling interest | | (174 | ) |
| Total purchase price | $ | 8,001 |
| $ | 8,001 |
|
The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $5.9$6.0 billion is recognized as goodwill, which is primarily attributable to positioning the Southern Company system to provide natural gas infrastructure to meet customers' growing energy needs and to compete for growth across the energy value chain. Southern Company anticipates that much of the value assigned to goodwill will not be deductible for tax purposes. The estimated fair values noted above are preliminary and are subject to change upon finalization of the purchase accounting assessment as additional information related to the fair value of assets and liabilities becomes available. Subsequent adjustments to the preliminary purchase price allocation are not expected to have a material impact on the results of operations and financial position of Southern Company.
The preliminary valuation of identifiable intangible assets included customer relationships, trade names, and storage and transportation contracts with estimated lives of one to 28 years. The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3).
The results of operations for Southern Company Gas have been included in theSouthern Company's consolidated financial statements from the date of acquisition and consist of operating revenues of $543$716 million and $2.3 billion and net income of $4 million.$49 million and $288 million for the three and six months ended June 30, 2017, respectively.
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)
|
| | | |
| | For the Six Months Ended June 30, |
| | 2016 |
Operating revenues (in millions) | $ | 10,346 |
|
Net income attributable to Southern Company (in millions) | $ | 1,255 |
|
| Basic Earnings Per Share (EPS) | $ | 1.34 |
|
| Diluted EPS | $ | 1.33 |
|
These unaudited pro forma results are for comparative purposes only and may not be indicative of the results that would have occurred had this acquisition been completed on January 1, 2015 or the results that would be attained in the future.
During the three and nine months ended September 30, 2016, Southern Company recorded in its statements of income costs associated with the Merger of approximately $40.8 million and $104.1 million, respectively, of which $40.6 million and $73.5 million is included in operating expenses and $0.2 million and $30.6 million is included in other income and (expense), respectively. These costs include external transaction costs for financing, legal, and consulting services, as well as rate credits and additional compensation-related expenses.
See Note 12 to the financial statements of Southern Company under "Southern Company – Proposed Merger with AGL Resources" in Item 8 of the Form 10-K for additional information.
Acquisition of PowerSecure International, Inc.
On May 9, 2016, Southern Company acquired all of the outstanding stock of PowerSecure, a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure, for $18.75 per common share in cash, resulting in an aggregate purchase price of $429 million. As a result, PowerSecure became a wholly-owned subsidiary of Southern Company.
The acquisition of PowerSecure was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value as of the acquisition date. The allocation offollowing table presents the final purchase price is as follows:allocation:
| | | PowerSecure Purchase Price | September 30, 2016 | |
| | (in millions) | (in millions) |
| Current assets | $ | 172 |
| $ | 172 |
|
| Property, plant, and equipment | 46 |
| 46 |
|
| Intangible assets | | 106 |
|
| Goodwill | 284 |
| 284 |
|
| Intangible assets | 101 |
| |
| Other assets | 6 |
| 4 |
|
| Current liabilities | (145 | ) | (121 | ) |
| Long-term debt, including current portion | (18 | ) | (48 | ) |
| Deferred credits and other liabilities | (17 | ) | (14 | ) |
| Total purchase price | $ | 429 |
| $ | 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 theSouthern Company's consolidated financial statements from the date of acquisition and are immaterial to the consolidated financial results of Southern Company. Pro forma results of operations have not been presented for the acquisition because the effects of the acquisition were immaterial to Southern Company's consolidated financial results for all periods presented.
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.
Acquisitions During the nineSix Months Ended June 30, 2017
During the six months ended SeptemberJune 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 2016,2017, in accordance with itsSouthern Power's overall growth strategy, Southern Power or one of its wholly-owned subsidiaries, Southern Renewable Partnerships, LLC and(SRP), one of Southern Renewable Energy, Inc.,Power's wholly-owned subsidiaries, acquired or contracted to acquire the projects discussed below.Bethel wind facility. Acquisition-related costs were expensed as incurred and were not material. The acquisitions do not include any contingent consideration unless specifically noted.
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 | |
|
| | | | | | | | | |
| Project Facility | Resource | Seller; Acquisition Date | Approximate Nameplate Capacity (MW) | Location | Southern Power Percentage Ownership | Actual COD | PPA Contract Period |
| Bethel | Wind | Invenergy,
January 6, 2017 | 276 | Castro County, TX | 100 | % | | January 2017 | 12 years |
| |
(a) | In additionThe aggregate amounts of revenue and net income, excluding impacts from PTCs, recognized by Southern Power related 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
Bethel facility included in Southern Power's aggregate purchase pricecondensed consolidated statements of income for year-to-date 2017 were immaterial. The Bethel facility did not have operating revenues or activities prior to completion of construction and the assets being placed in service; therefore, supplemental pro forma information for the project facilities acquired during the nine months ended September 30,comparable 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 Calipatriaperiod is not meaningful and Rutherford, SunPower Corp's 49% ownership interest in Henrietta, and the assumption of $217 million inhas been omitted.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
construction debt (non-recourse toIn connection with Southern Power), the total aggregate purchase price is approximately $923 million for the project facilities acquired during the nine months ended September 30, 2016. The fair values of the assets and liabilities acquired through the business combinations were recorded as follows: $1.0 billion as CWIP, $58 million as property, plant, and equipment, $77 million as an intangible asset, $24 million as other assets, and $5 million as accounts payable; however, thePower's 2016 acquisitions, allocations of the purchase price to individual assets have not been finalized. The intangible asset consists of an acquired PPA that will be amortized over its 20-year term. The estimated amortizationwere finalized during the six months ended June 30, 2017 with no changes to amounts originally reported for future periods is approximately $1 million in 2016 and $4 million per year thereafter. For East Pecos,Boulder 1, Grant Plains, Lamesa,Grant Wind, Henrietta, Mankato, Passadumkeag, Salt Fork, Tyler Bluff, and Rutherford, which are currently under construction, total aggregate construction costs, excluding the acquisition costs, are expected to be $708 million to $775 million. The ultimate outcome of these matters cannot be determined at this time.Wake Wind.
Acquisitions Subsequent to SeptemberJune 30, 20162017
Subsequent to June 30, 2017, Southern Power's aggregate purchase price for acquisitions subsequent to September 30, 2016 was approximately $873 million. Including the minority owner Invenergy Wind Global LLC's 9.9%Power acquired a 100% 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 hasand commenced construction of an additional 345-MW expansionthe Cactus Flats 148-MW wind facility, the majority of which is covered with a 20-year PPA. Total aggregate construction costs, excluding the acquisition costs allocated to CWIP, areby two PPAs, which expire in 2030 and 2033. The facility is expected to be $170 million to $190 million.placed in service in mid-2018. The ultimate outcome of this matter cannot be determined at this time.
Acquisition Agreements Executed but Not Yet ClosedConstruction Projects Completed and in Progress
During the ninesix months ended SeptemberJune 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
During the nine months ended September 30, 2016,2017, in accordance with its overall growth strategy, Southern Power completed construction of and placed in service, or continued construction of, the projects set forth in the following table. Through SeptemberJune 30, 2016,2017, total costs of construction incurred for the followingthese projects were $3.0 billion,$421 million, of which $1.2 billion remains$49 million remained in CWIP. IncludingCWIP for the total construction costs incurred through September 30, 2016
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
and the acquisition prices allocated to CWIP, totalMankato facility acquired in 2016. Total aggregate construction costs, excluding the acquisition costs, are expected to be $170 million to $190 million for the following projects are estimated to be $3.1 billion to $3.2 billion.Mankato facility. The ultimate outcome of these mattersthis matter cannot be determined at this time.
|
| | | | | | |
SolarProject Facility | SellerResource | Approximate Nameplate Capacity (MW) | Location | Actual/Expected COD | PPA Counterparties for Plant Output | PPA Contract Period |
Projects Completed During the NineSix Months Ended SeptemberJune 30, 20162017 |
Butler Solar FarmEast Pecos | Strata Solar Development, LLC | 22120 | TaylorPecos County, GATX | February 2016March 2017 | Georgia Power(a)
| 2015 years |
Desert Stateline(b)
Lamesa | First Solar Development, LLC | 299(c)
102 | San BernardinoDawson County, CATX | Through July 2016April 2017 | Southern California Edison Company (SCE) | 2015 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 |
ProjectsProject Under Construction as of SeptemberJune 30, 20162017 |
ButlerMankato | CERSM, LLC and Community Energy, Inc.Natural Gas | 103345 | Taylor County, GAMankato, MN | 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 EnergySecond quarter 2019 | 20 years |
Sandhills | N/A | 146 | Taylor County, GA | October 2016 | Cobb, Flint, Irwin, Middle Georgia and Sawnee Electric Membership Corporations | 25 years |
| |
(a) | Affiliate PPA approved by the FERC. |
| |
(b) | On March 29, 2016, Southern Power acquired an additional 15% interest in Desert Stateline. As a result, Southern Power and the class B member are entitled to 66% and 34%, respectively, of all cash distributions from Desert Stateline. In addition, Southern Power will continue to be entitled to substantially all of the federal tax benefits with respect to the transaction. |
(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)
Development Projects
In December 2016, as part of Southern Power's renewable development strategy, SRP entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct approximately 3,000 MWs of wind projects. Also in December 2016, Southern Power signed agreements and made payments to purchase wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. All of the wind turbine equipment was delivered by April 2017, which allows the projects to qualify for 100% PTCs for 10 years following their expected commercial operation dates between 2018 and 2020. The ultimate outcome of these matters cannot be determined at this time.
| |
| (J) | JOINT OWNERSHIP AGREEMENTS |
Southern Company Gas
See Note 4 to the financial statements of Southern Company Gas in Item 8 of the Form 10-K for additional information.
Equity Method Investments
The carrying amounts of Southern Company Gas' equity method investments as of June 30, 2017 and December 31, 2016 and related income from those investments for the successor three and six month periods ended June 30, 2017 and the predecessor three and six month periods ended June 30, 2016 were as follows:
|
| | | | | | |
| | | |
| Balance Sheet Information | June 30, 2017 | December 31, 2016 |
| | (in millions) |
| SNG | $ | 1,405 |
| $ | 1,394 |
|
| Atlantic Coast Pipeline | 53 |
| 33 |
|
| PennEast Pipeline | 45 |
| 22 |
|
| Triton | 43 |
| 44 |
|
| Pivotal JAX LNG, LLC | 32 |
| 16 |
|
| Horizon Pipeline | 31 |
| 30 |
|
| Other | 1 |
| 2 |
|
| Total | $ | 1,610 |
| $ | 1,541 |
|
|
| | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor | | Successor | | | Predecessor |
| Income Statement Information | Three Months Ended June 30, 2017 | | | Three Months Ended June 30, 2016 | | Six Months Ended June 30, 2017 | | | Six Months Ended June 30, 2016 |
| | (in millions) | | | (in millions) | | (in millions) | | | (in millions) |
| SNG | $ | 24 |
| | | $ | — |
| | $ | 58 |
| | | $ | — |
|
| Triton | 2 |
| | | 1 |
| | 2 |
| | | 1 |
|
| PennEast Pipeline | 1 |
| | | — |
| | 4 |
| | | — |
|
| Atlantic Coast Pipeline | 2 |
| | | — |
| | 3 |
| | | — |
|
| Horizon Pipeline | — |
| | | — |
| | 1 |
| | | 1 |
|
| Total | $ | 29 |
| | | $ | 1 |
| | $ | 68 |
| | | $ | 2 |
|
Southern Natural Gas
In September 2016, Southern Company Gas, through a wholly-owned, indirect subsidiary, acquired a 50% equity interest in SNG, which is accounted for as an equity method investment. On March 31, 2017, Southern Company
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Gas made an additional $50 million contribution to maintain its 50% equity interest in SNG. See Note 11 to the financial statements of Southern Company Gas under "Investment in SNG" in Item 8 of the Form 10-K for additional information on this investment. Selected financial information of SNG for the three and six months ended June 30, 2017 is as follows:
|
| | | | | | |
| Income Statement Information | Three Months Ended June 30, 2017 | Six Months Ended June 30, 2017 |
| | (in millions) |
| Revenues | $ | 143 |
| $ | 298 |
|
| Operating income | $ | 63 |
| $ | 147 |
|
| Net income | $ | 48 |
| $ | 114 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
(K) SEGMENT AND RELATED INFORMATION
Southern Company
The primary businessbusinesses of the Southern Company system isare electricity sales by the traditional electric operating companies and Southern Power and as a result of closing the Merger, the distribution of natural gas by Southern Company Gas. The four traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas is an energy services holding company whose primary business is the distribution ofdistributes natural gas through the seven natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations.
Southern Company's reportable business segments are the sale of electricity by the four traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Company Gas. Revenues from sales by Southern Power to the traditional electric operating companies were $110$90 million and $313$190 million for the three and ninesix months ended SeptemberJune 30, 2016,2017, respectively, and $104$107 million and $303$204 million for the three and ninesix months ended SeptemberJune 30, 2015,2016, respectively. The "All Other" column includes the Southern Company parent entity, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include productsproviding energy technologies and services in the areas of distributed generation, energy efficiency,to electric utilities and utility infrastructure,large industrial, commercial, institutional, and municipal customers; as well as investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Financial data for business segments and products and services for the three and ninesix months ended SeptemberJune 30, 20162017 and 20152016 was as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Electric Utilities | | | | |
| | Traditional Electric Operating Companies | Southern Power | Eliminations | Total | Southern Company Gas | All Other | Eliminations | Consolidated |
| | (in millions) |
Three Months Ended
September 30, 2016: | | | | | | | | |
| Operating revenues | $ | 5,236 |
| $ | 500 |
| $ | (117 | ) | $ | 5,619 |
| $ | 543 |
| $ | 139 |
| $ | (37 | ) | $ | 6,264 |
|
Segment net income (loss)(a)(b) | 1,018 |
| 176 |
| — |
| 1,194 |
| 4 |
| (67 | ) | (1 | ) | 1,130 |
|
Nine Months Ended
September 30, 2016: | | | | | | | | |
| Operating revenues | $ | 13,120 |
| $ | 1,189 |
| $ | (330 | ) | $ | 13,979 |
| $ | 543 |
| $ | 311 |
| $ | (118 | ) | $ | 14,715 |
|
Segment net income (loss)(a)(c) | 2,076 |
| 315 |
| — |
| 2,391 |
| 4 |
| (161 | ) | (8 | ) | 2,226 |
|
| Total assets at September 30, 2016 | $ | 71,448 |
| $ | 12,351 |
| $ | (440 | ) | $ | 83,359 |
| $ | 21,185 |
| $ | 2,974 |
| $ | (1,156 | ) | $ | 106,362 |
|
Three Months Ended
September 30, 2015: | | | | | | | | |
| Operating revenues | $ | 5,098 |
| $ | 401 |
| $ | (109 | ) | $ | 5,390 |
| $ | — |
| $ | 37 |
| $ | (26 | ) | $ | 5,401 |
|
Segment net income (loss)(a)(b) | 874 |
| 102 |
| — |
| 976 |
| — |
| (18 | ) | 1 |
| 959 |
|
Nine Months Ended
September 30, 2015: | | | | | | | | |
| Operating revenues | $ | 13,123 |
| $ | 1,086 |
| $ | (322 | ) | $ | 13,887 |
| $ | — |
| $ | 120 |
| $ | (86 | ) | $ | 13,921 |
|
Segment net income (loss)(a)(c) | 1,912 |
| 181 |
| — |
| 2,093 |
| — |
| 3 |
| — |
| 2,096 |
|
| Total assets at December 31, 2015 | $ | 69,052 |
| $ | 8,905 |
| $ | (397 | ) | $ | 77,560 |
| $ | — |
| $ | 1,819 |
| $ | (1,061 | ) | $ | 78,318 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Electric Utilities | | | | |
| | Traditional Electric Operating Companies | Southern Power | Eliminations | Total | Southern Company Gas | All Other | Eliminations | Consolidated |
| | (in millions) |
Three Months Ended
June 30, 2017: | | | | | | | | |
| Operating revenues | $ | 4,157 |
| $ | 529 |
| $ | (101 | ) | $ | 4,585 |
| $ | 716 |
| $ | 166 |
| $ | (37 | ) | $ | 5,430 |
|
Segment net income (loss)(a)(b) | (1,442 | ) | 82 |
| — |
| (1,360 | ) | 49 |
| (68 | ) | (2 | ) | (1,381 | ) |
Six Months Ended
June 30, 2017: | | | | | | | | |
| Operating revenues | $ | 7,943 |
| $ | 979 |
| $ | (206 | ) | $ | 8,716 |
| $ | 2,276 |
| $ | 289 |
| $ | (79 | ) | $ | 11,202 |
|
Segment net income (loss)(a)(b)(c) | (1,010 | ) | 151 |
| — |
| (859 | ) | 288 |
| (152 | ) | — |
| (723 | ) |
| Total assets at June 30, 2017 | $ | 71,503 |
| $ | 14,703 |
| $ | (317 | ) | $ | 85,889 |
| $ | 21,809 |
| $ | 2,348 |
| $ | (1,362 | ) | $ | 108,684 |
|
Three Months Ended
June 30, 2016: | | | | | | | | |
| Operating revenues | $ | 4,115 |
| $ | 373 |
| $ | (109 | ) | $ | 4,379 |
| $ | — |
| $ | 125 |
| $ | (45 | ) | $ | 4,459 |
|
Segment net income (loss)(a)(b) | 599 |
| 89 |
| — |
| 688 |
| — |
| (61 | ) | (4 | ) | 623 |
|
Six Months Ended
June 30, 2016: | | | | | | | | |
| Operating revenues | $ | 7,884 |
| $ | 688 |
| $ | (212 | ) | $ | 8,360 |
| $ | — |
| $ | 172 |
| $ | (81 | ) | $ | 8,451 |
|
Segment net income (loss)(a)(b) | 1,064 |
| 139 |
| — |
| 1,203 |
| — |
| (84 | ) | (7 | ) | 1,112 |
|
| Total assets at December 31, 2016 | $ | 72,141 |
| $ | 15,169 |
| $ | (316 | ) | $ | 86,994 |
| $ | 21,853 |
| $ | 2,474 |
| $ | (1,624 | ) | $ | 109,697 |
|
| |
| (a) | Attributable to Southern Company. |
| |
| (b) | Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated probable losses on the Kemper IGCC of $88 million$3.0 billion ($54 million2.1 billion after tax) and $150$81 million ($9350 million after tax) for the three months ended SeptemberJune 30, 2017 and 2016, respectively, and 2015,$3.1 billion ($2.2 billion after tax) and $134 million ($83 million after tax) for the six months ended June 30, 2017 and 2016, respectively. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information. |
(c) Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated probable losses on the Kemper IGCC of $222 million ($137 million after tax) and $182 million ($112 million after tax) for the nine months ended September 30, 2016 and 2015, respectively. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate | |
| (c) | Segment net income (loss) for the traditional electric operating companies also includes a pre-tax charge for the write-down of Gulf Power's ownership of Plant Scherer Unit 3 of $33 million ($20 million after tax) for the six months ended June 30, 2017. See Note (B) under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" for additional information. |
Products and Services
|
| | | | | | | | | | | | | | | | |
| | | Electric Utilities' Revenues |
| Period | | Retail | | Wholesale | | Other | | Total |
| | | (in millions) |
| Three Months Ended September 30, 2016 | | $ | 4,808 |
| | $ | 613 |
| | $ | 198 |
| | $ | 5,619 |
|
| Three Months Ended September 30, 2015 | | 4,701 |
| | 520 |
| | 169 |
| | 5,390 |
|
| | | | | | | | | |
| Nine Months Ended September 30, 2016 | | $ | 11,932 |
| | $ | 1,455 |
| | $ | 592 |
| | $ | 13,979 |
|
| Nine Months Ended September 30, 2015 | | 11,958 |
| | 1,435 |
| | 494 |
| | 13,887 |
|
Table of Contents |
| | | | | | | | | | | | | | | | |
| | | Electric Utilities' Revenues |
| Period | | Retail | | Wholesale | | Other | | Total |
| | | (in millions) |
| Three Months Ended June 30, 2017 | | $ | 3,777 |
| | $ | 618 |
| | $ | 190 |
| | $ | 4,585 |
|
| Three Months Ended June 30, 2016 | | 3,748 |
| | 446 |
| | 185 |
| | 4,379 |
|
| | | | | | | | | |
| Six Months Ended June 30, 2017 | | $ | 7,171 |
| | $ | 1,149 |
| | $ | 396 |
| | $ | 8,716 |
|
| Six Months Ended June 30, 2016 | | 7,124 |
| | 842 |
| | 394 |
| | 8,360 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| | | | Southern Company Gas' Revenues | Southern Company Gas' Revenues |
| Period | Gas
Distribution
Operations | Gas
Marketing
Services | All Other | Total | Gas
Distribution
Operations | Gas
Marketing
Services | Other | Total |
| | (in millions) | (in millions) |
| Three and Nine Months Ended September 30, 2016 | $ | 420 |
| $ | 126 |
| $ | (3 | ) | $ | 543 |
| |
| Three Months Ended June 30, 2017 | | $ | 557 |
| $ | 166 |
| $ | (7 | ) | $ | 716 |
|
| Six Months Ended June 30, 2017 | | $ | 1,689 |
| $ | 454 |
| $ | 133 |
| $ | 2,276 |
|
Southern Company Gas
Southern Company Gas manages its business through four reportable segments – gas distribution operations, gas marketing services, wholesale gas services, and gas midstream operations. The non-reportable segments are combined and presented as all other.
Gas distribution operations is the largest component of Southern Company Gas' business and includes natural gas local distribution utilities that construct, manage, and maintain intrastate natural gas pipelines and gas distribution facilities in seven states. Gas marketing services includes natural gas marketing to end-use customers primarily in Georgia and Illinois. Additionally, gas marketing services provides home equipment protection products and services. Wholesale gas services provides natural gas asset management and/or related logistics services for each of Southern Company Gas' utilities except Nicor Gas as well as for non-affiliated companies. Additionally, wholesale gas services engages in natural gas storage and gas pipeline arbitrage and related activities. Gas midstream operations primarily consists of Southern Company Gas' pipeline investments, with storage and fuel operations also aggregated into this segment. The all other column includes segments below the quantitative threshold for separate disclosure, including the subsidiaries that fall below the quantitative threshold for separate disclosure.
After the Merger, Southern Company Gas changed its segment performance measure to net income. In order to properly assess net income by segment, Southern Company Gas executed various intercompany note agreements to revise interest charges to its segments. Since such agreements did not exist in the predecessor period, Southern Company Gas is unable to provide the comparable net income.
Business segment financial data for the successor three and six months ended June 30, 2017and the predecessor three and six months ended June 30, 2016 was as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services(*) | Gas Midstream Operations | Total | All Other | Eliminations | Consolidated |
| | (in millions) |
| Successor – Three Months Ended June 30, 2017: | | | | | | |
| Operating revenues | $ | 603 |
| $ | 166 |
| $ | (12 | ) | $ | 12 |
| $ | 769 |
| $ | 3 |
| $ | (56 | ) | $ | 716 |
|
| Segment net income | 54 |
| 4 |
| (17 | ) | 9 |
| 50 |
| (1 | ) | — |
| 49 |
|
| Successor – Six Months Ended June 30, 2017: | | | | | | |
| Operating revenues | $ | 1,783 |
| $ | 454 |
| $ | 119 |
| $ | 37 |
| $ | 2,393 |
| $ | 5 |
| $ | (122 | ) | $ | 2,276 |
|
| Segment net income | 171 |
| 35 |
| 51 |
| 25 |
| 282 |
| 6 |
| — |
| 288 |
|
Successor – Total assets at
June 30, 2017 | $ | 18,257 |
| $ | 2,093 |
| $ | 989 |
| $ | 2,381 |
| $ | 23,720 |
| $ | 11,182 |
| $ | (13,093 | ) | $ | 21,809 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services(*) | Gas Midstream Operations | Total | All Other | Eliminations | Consolidated |
| | (in millions) |
| Predecessor – Three Months Ended June 30, 2016: | | | | | | |
| Operating revenues | $ | 547 |
| $ | 149 |
| $ | (95 | ) | $ | 10 |
| $ | 611 |
| $ | 2 |
| $ | (42 | ) | $ | 571 |
|
| Segment EBIT | 118 |
| 29 |
| (112 | ) | (5 | ) | 30 |
| (55 | ) | 1 |
| (24 | ) |
| Predecessor – Six Months Ended June 30, 2016: | | | | | | |
| Operating revenues | $ | 1,575 |
| $ | 435 |
| $ | (32 | ) | $ | 25 |
| $ | 2,003 |
| $ | 4 |
| $ | (102 | ) | $ | 1,905 |
|
| Segment EBIT | 353 |
| 109 |
| (68 | ) | (6 | ) | 388 |
| (60 | ) | — |
| 328 |
|
Successor – Total assets at
December 31, 2016 | $ | 19,453 |
| $ | 2,084 |
| $ | 1,127 |
| $ | 2,211 |
| $ | 24,875 |
| $ | 11,145 |
| $ | (14,167 | ) | $ | 21,853 |
|
| |
| (*) | The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table. |
|
| | | | | | | | | | | | | | | | | | | |
| | Third Party Gross Revenues | | Intercompany Revenues | | Total Gross Revenues | | Less Gross Gas Costs | | Operating Revenues |
| | (in millions) |
| Successor – Three Months Ended June 30, 2017 | $ | 1,531 |
| | $ | 123 |
| | $ | 1,654 |
| | $ | 1,666 |
| | $ | (12 | ) |
| Successor – Six Months Ended June 30, 2017 | 3,370 |
| | 259 |
| | 3,629 |
| | 3,510 |
| | 119 |
|
| Predecessor – Three Months Ended June 30, 2016 | $ | 1,061 |
| | $ | 58 |
| | $ | 1,119 |
| | $ | 1,214 |
| | $ | (95 | ) |
| Predecessor – Six Months Ended June 30, 2016 | 2,500 |
| | 143 |
| | 2,643 |
| | 2,675 |
| | (32 | ) |
PART II — OTHER INFORMATION
Item 1. Legal Proceedings.
See the Notes to the Condensed Financial Statements herein for information regarding certain legal and administrative proceedings in which the registrants are involved.
Item 1A. Risk Factors.
See RISK FACTORS in Item 1A of the Form 10-K for a discussion of the risk factors of the registrants. Except as described below, there have been no material changes to these risk factors from those previously disclosed in the Form 10-K.
WithThe bankruptcy filing of the EPC Contractor is expected to have a material impact on the construction cost and schedule of, as well as the cost recovery for, Plant Vogtle Units 3 and 4 and could have a material impact on the financial statements of Southern Company and Georgia Power, and any inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4, and therefore on the financial statements of Southern Company and Georgia Power.
See "Construction Risk" in Item 1A – Risk Factors of Southern Company and Georgia Power in the Form 10-K for a discussion of risks relating to major construction projects, including Plant Vogtle Units 3 and 4 and see Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein and Note (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information.
On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. To provide for a continuation of work at Plant Vogtle Units 3 and 4, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an interim assessment agreement with the EPC Contractor (Interim Assessment Agreement), which the bankruptcy court approved on March 30, 2017.
The Interim Assessment Agreement provided, among other items, that during the term of the Interim Assessment Agreement (i) Georgia Power was obligated to pay, on behalf of the Vogtle Owners, all costs accrued by the EPC Contractor for subcontractors and vendors for services performed or goods provided, with these amounts paid to the EPC Contractor, except that amounts accrued for Fluor Corporation (Fluor) were paid directly to Fluor; (ii) the EPC Contractor provided certain engineering, procurement, and management services for Plant Vogtle Units 3 and 4, to the same extent as contemplated by the Vogtle 3 and 4 Agreement, and Georgia Power, on behalf of the Vogtle Owners, made payments of $5.4 million per week for these services; (iii) Georgia Power had the right to make payments, on behalf of the Vogtle Owners, directly to subcontractors and vendors who had accounts past due with the EPC Contractor; (iv) the EPC Contractor used commercially reasonable efforts to provide information reasonably requested by Georgia Power as was necessary to continue construction and investigation of the completion status of Plant Vogtle Units 3 and 4; (v) the EPC Contractor rejected or accepted the Vogtle 3 and 4 Agreement by the termination of the Interim Assessment Agreement; and (vi) Georgia Power did not exercise any remedies against Toshiba under the Toshiba Guarantee. Under the Interim Assessment Agreement, all parties expressly reserved all rights and remedies under the Vogtle 3 and 4 Agreement and all related security and collateral under applicable law.
The Interim Assessment Agreement, as amended, expired on July 27, 2017. Georgia Power's aggregate liability for the Vogtle Owners under the Interim Assessment Agreement totaled approximately $650 million, of which $552 million had been paid or accrued as of June 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $297 million.
Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor, including Fluor Enterprises, Inc., a subsidiary of Fluor, alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken, and continues to take, actions to remove liens filed by these subcontractors through the posting of surety bonds. Georgia Power estimates the aggregate liability, through July 31, 2017, of the Vogtle Owners for the removal of subcontractor liens and payment of other EPC Contractor pre-petition accounts payable to total approximately
$400 million, of which $354 million had been paid or accrued as of June 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $183 million.
The Vogtle 3 and 4 Agreement also provided for liquidated damages upon the EPC Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to an aggregate cap of 10% of the contract price, or approximately $920 million (approximately $420 million based on Georgia Power's ownership interest). Under the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. In January 2016, Westinghouse delivered to the Vogtle Owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020 and require 60 days' written notice to Georgia Power in the event the Westinghouse Letters of Credit will not be renewed.
Under the terms of the Vogtle 3 and 4 Agreement, the EPC Contractor did not have the right to terminate the Vogtle 3 and 4 Agreement for convenience. In the event of an abandonment of work by the EPC Contractor, the maximum liability of the EPC Contractor under the Vogtle 3 and 4 Agreement was 40% of the contract price (approximately $1.7 billion based on Georgia Power's ownership interest). In addition, the Vogtle Owners could terminate the Vogtle 3 and 4 Agreement for certain breaches by the EPC Contractor, including abandonment of work by the EPC Contractor.
On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion (Guarantee Obligations), of which Georgia Power's proportionate share is approximately $1.7 billion, and that the Guarantee Obligations exist regardless of whether Plant Vogtle Units 3 and 4 are completed. The Guarantee Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations, beginning in October 2017 and continuing through January 2021. In the event Toshiba receives certain payments, including sale proceeds, from or related to Westinghouse (or its subsidiaries) or Toshiba Nuclear Energy Holdings (UK) Limited (or its subsidiaries), it will hold a portion of such payments in trust for the Vogtle Owners and promptly pay them as offsets against any remaining Guarantee Obligations. Under the Guarantee Settlement Agreement, the Vogtle Owners will forbear from exercising certain remedies, including drawing on the Westinghouse Letters of Credit, until June 30, 2020, unless certain events of nonpayment, insolvency, or other material breach of the Guarantee Settlement Agreement by Toshiba occur. If such an event occurs, the balance of the Guarantee Obligations will become immediately due and payable, and the Vogtle Owners may exercise any and all rights and remedies, including drawing on the Westinghouse Letters of Credit without restriction. In addition, the Guarantee Settlement Agreement does not restrict the Vogtle Owners from fully drawing on the Westinghouse Letters of Credit in the event they are not renewed or replaced prior to the expiration date.
On June 23, 2017, Toshiba released a revised outlook for fiscal year 2016, which reflected a negative shareholders' equity balance of approximately $5 billion as of March 31, 2017, and announced that its independent audit process was continuing. Toshiba has also announced the existence of material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern. As a result, substantial risk regarding the Vogtle Owners' ability to fully collect the Guarantee Obligations continues to exist. An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Southern Company's and Georgia Power's financial statements.
Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into a services agreement (Services Agreement), which was amended and restated on July 20, 2017, for the EPC Contractor to transition construction management of Plant Vogtle Units 3 and 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Services Agreement, (ii) assume and assign to the Vogtle Owners certain project-related contracts, (iii) join the
Vogtle Owners as counterparties to certain assumed project-related contracts, and (iv) reject the Vogtle 3 and 4 Agreement. The Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE on July 27, 2017. The Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.
Georgia Power and the other Vogtle Owners are continuing to conduct comprehensive schedule and cost-to-complete assessments, as well as cancellation cost assessments, to determine the impact of the EPC Contractor's bankruptcy filing on the construction cost and schedule for Plant Vogtle Units 3 and 4. Georgia Power's preliminary assessment results indicate that its proportionate share of the remaining estimated cost to complete Plant Vogtle Units 3 and 4 ranges as follows:
|
| | | | | | | |
| Preliminary in-service dates | | | |
| Unit 3 | February 2021 | – | March 2022 |
| Unit 4 | February 2022 | – | March 2023 |
| | (in billions) |
| Preliminary estimated cost to complete | $ | 3.9 |
| – | $ | 4.6 |
|
| CWIP as of June 30, 2017 | 4.5 |
| | 4.5 |
|
| Guarantee Obligations | (1.7 | ) | | (1.7 | ) |
| Estimated capital costs | $ | 6.7 |
| – | $ | 7.4 |
|
| Vogtle Cost Settlement Agreement Revised Forecast | (5.7 | ) | | (5.7 | ) |
| Estimated net additional capital costs | $ | 1.0 |
| – | $ | 1.7 |
|
Georgia Power's estimates for cost to complete and schedule are based on preliminary analysis and remain subject to further refinement of labor productivity and consumable and commodity quantities and costs.
Georgia Power's estimated financing costs during the construction period total approximately $3.1 billion to $3.5 billion, of which approximately $1.4 billion had been incurred through June 30, 2017.
Georgia Power's preliminary cancellation cost estimate results indicate that its proportionate share of the estimated cancellation costs is approximately $400 million. As a result, as of June 30, 2017, total estimated costs subject to evaluation by Georgia Power and the Georgia PSC in the event of a cancellation decision are as follows:
|
| | | |
| | Preliminary Cancellation Cost Estimate |
| | (in billions) |
| CWIP as of June 30, 2017 | $ | 4.5 |
|
| Financing costs collected, net of tax | 1.4 |
|
Cancellation costs(*) | 0.4 |
|
| Total | $ | 6.3 |
|
| |
| (*) | The estimate for cancellation costs includes, but is not limited to, costs to terminate contracts for construction and other services, as well as costs to secure the Plant Vogtle Units 3 and 4 construction site. |
The Guarantee Obligations continue to exist in the event of cancellation. In addition, under Georgia law, prudently incurred costs related to certificated projects cancelled by the Georgia PSC are allowed recovery, including carrying costs, in future retail rates. Georgia Power will continue working with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4, including, but not limited to, the status of construction and rate recovery, and currently expects to include its recommendation in its seventeenth Vogtle Construction Monitoring report to be filed with the Georgia PSC in late August 2017.
The ultimate outcome of these matters is dependent on the completion of the Merger, Southern Company now owns Southern Company Gas, a company whose subsidiaries ownassessments described above, as well as the related regulatory treatment, and operate a natural gas business.
Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through natural gas distribution utilities. Southern Company Gas is involved in several other businesses that are mainly related and complementary to its primary business including: gas 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, Southern Company is now subject to risks to which it was not previously subject and Southern Company stockholders maycannot be adversely affected by these risks. These risks include the following:
Transporting and storing natural gas involves risks that may result in accidents and other operating risks and costs. Southern Company Gas' natural gas distribution and storage activities involve a variety of inherent hazards and operating risks, such as leaks, accidents, explosions, and mechanical problems, which could result in serious injury to employees and non-employees, loss of human life, significant damage to property, environmental pollution, and impairment of its operations.
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 supply energy, including electric, oil, and propane providers and, in some cases, energy marketing and trading companies.
Southern Company Gas may experience reported net income volatility due to mark-to-market accounting. Southern Company Gas utilizes hedging instruments to lock in economic value in its wholesale natural gas segment, which are not designated as hedges for accounting purposes. The difference in accounting treatment for the underlying position and the financial instrument used to hedge the value of the contract can cause volatility in reported net income while the positions are open due to mark-to-market accounting.
determined at this time.Item 6. Exhibits.
The exhibits below with an asterisk (*) preceding the exhibit number are filed herewith. The remaining exhibits have previously been filed with the SEC and are incorporated herein by reference. The exhibits marked with a pound sign (#) are management contracts or compensatory plans or arrangements.
|
| | | | |
| | | (3) Articles of Incorporation and By-Laws |
| | | | |
| | Georgia Power |
| | | | |
| | (a)1 | | By-Laws of Georgia Power, as amended effective August 17, 2016. (Designated in Form 8-K dated August 17, 2016, File No. 1-6468, as Exhibit 3.1.) |
| | | | |
| | Mississippi Power |
| | |
| | (a)1 | | By-Laws of Mississippi Power, as amended, effective October 25, 2016. (Designated in Form 8-K dated October 25, 2016, File No. 001-11229, as Exhibit 3.1.) |
|
| | | | |
| | |
| | (4) Instruments Describing Rights of Security Holders, Including Indentures |
| | | | | |
| | | Southern Company |
| | | | | |
| | * | (a)1 | - | SecondFourth Supplemental Indenture to Junior Subordinated Note Indenture, dated as of September 15, 2016,June 21, 2017, providing for the issuance of the Series 2016A 5.25%2017A 5.325% Junior Subordinated Notes due October June 21, 2057. |
| | | | |
| * | (a)2 | - | Nineteenth Supplemental Indenture to Senior Note Indenture, dated as of June 21, 2017, providing for the issuance of the Series 2017A Floating Rate Senior Notes due September 30, 2020. |
| | | | |
| | Georgia Power |
| | | | |
| | (c)1 2076. | - | Amendment No. 3, dated July 27, 2017 to Loan Guarantee Agreement dated February 20, 2014, between Georgia Power and the DOE. (Designated in Form 8-K dated September 12, 2016,July 27, 2017, File No. 1-3526,1-6468, as Exhibit 4.4.4.1.) |
| | | | |
| | Gulf Power |
| | | | |
| | (d) | - | Twenty-Second Supplemental Indenture to Senior Note Indenture, dated as of May 18, 2017, providing for the issuance of the Series 2017A 3.30% Senior Notes due May 30, 2027. (Designated in Form 8-K dated May 15, 2017, File No. 001-31737, as Exhibit 4.2.) |
| | | | | |
| | | Southern PowerCompany Gas |
| | | |
| | * | (f)(g)1 | - | Twelfth Supplemental Indenture toForm of Southern Company Gas Capital Corporation's Series 2017A 4.400% Senior Note Indenture,Notes due May 30, 2047. (Designated in Form 8-K dated May 4, 2017, File No. 1-14174, as of September 7, 2016.Exhibit 4.1.) |
| | | | | |
| | * | (f)(g)2 | - | Thirteenth Supplemental IndentureForm of Southern Company Gas' Guarantee related to the Series 2017A 4.400% Senior Note Indenture,Notes due May 30, 2047. (Designated in Form 8-K dated May 4, 2017, File No. 1-14174, as Exhibit 4.3.) |
| | | | |
| | (10) Material Contracts |
| | |
| | Georgia Power |
| | | | |
| | (c)1 | - | Amendment No. 2 to Interim Assessment Agreement dated as of SeptemberMarch 29, 2017, by and among Georgia Power, for itself and as agent for Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and The City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, and Westinghouse, WECTEC Staffing Services LLC, and WECTEC. (Designated in Form 8-K dated May 12, 2017, File No. 1-6468, as Exhibit 10.1.) |
| | (c)2 | - | Amendment No. 3 to Interim Assessment Agreement dated as of March 29, 2017, by and among Georgia Power, for itself and as agent for Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and The City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, and Westinghouse, WECTEC Staffing Services LLC, and WECTEC. (Designated in Form 8-K dated June 3, 2017, File No. 1-6468, as Exhibit 10.1.) |
|
| | | | |
| | (c)3 | - | Amendment No. 4 to Interim Assessment Agreement dated as of March 29, 2017, by and among Georgia Power, for itself and as agent for Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and The City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, and Westinghouse, WECTEC Staffing Services LLC, and WECTEC. (Designated in Form 8-K dated June 5, 2017, File No. 1-6468, as Exhibit 10.1.) |
| | (c)4 | - | Amendment No. 5 to Interim Assessment Agreement dated as of March 29, 2017, by and among Georgia Power, for itself and as agent for Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and The City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, and Westinghouse, WECTEC Staffing Services LLC, and WECTEC. (Designated in Form 8-K dated June 16, 2017, File No. 1-6468, as Exhibit 10.2.) |
| | (c)5 | - | Amendment No. 6 to Interim Assessment Agreement dated as of March 29, 2017, by and among Georgia Power, for itself and as agent for Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and The City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, and Westinghouse, WECTEC Staffing Services LLC, and WECTEC. (Designated in Form 8-K dated June 22, 2017, File No. 1-6468, as Exhibit 10.1.) |
| | (c)6 | - | Amendment No. 7 to Interim Assessment Agreement dated as of March 29, 2017, by and among Georgia Power, for itself and as agent for Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and The City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, and Westinghouse, WECTEC Staffing Services LLC, and WECTEC. (Designated in Form 8-K dated June 28, 2017, File No. 1-6468, as Exhibit 10.1.) |
| | (c)7 | - | Amendment No. 8 to Interim Assessment Agreement dated as of March 29, 2017, by and among Georgia Power, for itself and as agent for Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and The City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, and Westinghouse, WECTEC Staffing Services LLC, and WECTEC. (Designated in Form 8-K dated July 20, 2016, providing2017, File No. 1-6468, as Exhibit 10.1.) |
| | (c)8 | - | Settlement Agreement dated as of June 9, 2017, by and among Georgia Power, Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, The City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, and Toshiba Corporation. (Designated in Form 8-K dated June 16, 2017, File No. 1-6468, as Exhibit 10.1.) |
| * | (c)9 | - | Amended and Restated Services Agreement dated as of June 20, 2017, by and among Georgia Power, for itself and as agent for Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, MEAG Power SPVP, LLC, and The City of Dalton, acting by and through its Board of Water, Light and Sinking Fund Commissioners, and Westinghouse and WECTEC. (Georgia Power has requested confidential treatment for certain portions of this document pursuant to an application for confidential treatment sent to the issuance ofSEC. Georgia Power omitted such portions from the Series 2016C 2.75% Senior Notes due September 20, 2023.filing and filed them separately with the SEC.) |
| | | | | |
| | | (24) Power of Attorney and Resolutions |
| | | | | |
| | | Southern Company |
| | | | | |
| | | (a)1 | - | Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2015,2016, File No. 1-3526 as Exhibit 24(a).) |
| | | | | |
| | | Alabama Power |
| | | | | |
| | | (b)1 | - | Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2015,2016, File No. 1-3164 as Exhibit 24(b).) |
| | | | | |
|
| | | | |
| | | Georgia Power |
| | | | | |
| | | (c)1 | - | Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2015,2016, File No. 1-6468 as Exhibit 24(c).) |
| | | | | |
| | | Gulf Power |
| | | | | |
| | | (d)1 | - | Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2015,2016, File No. 001-31737 as Exhibit 24(d).) |
| | | | | |
| | | Mississippi Power |
| | | | | |
| | | (e)1 | - | Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2015,2016, File No. 001-11229 as Exhibit 24(e)1.) |
| | | | |
| | (e)2 | - | Power of Attorney for Anthony L. Wilson. (Designated in the Form 10-K for the year ended December 31, 2015, File No. 001-11229 as Exhibit 24(e)2..) |
| | | | | |
| | | Southern Power |
| | | | | |
| | | (f)1 | - | Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2015,2016, File No. 333-98553001-37803 as Exhibit 24(f)1..) |
| | | | | |
| | | (f)2Southern Company Gas |
| | | | |
| | (g) | - | Power of Attorney for Joseph A. Miller.and resolution. (Designated in the Form 10-K for the year ended December 31, 2015,2016, File No. 333-985531-14174 as Exhibit 24(f)2.24(g).) |
| | | | | |
| | | (31) Section 302 Certifications |
| | | | | |
| | | Southern Company |
| | | | | |
| | * | (a)1 | - | Certificate of Southern Company's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
|
| | | | |
| | * | (a)2 | - | Certificate of Southern Company's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
| | | Alabama Power |
| | | | | |
| | * | (b)1 | - | Certificate of Alabama Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
| | * | (b)2 | - | Certificate of Alabama Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
| | | Georgia Power |
| | | | | |
| | * | (c)1 | - | Certificate of Georgia Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
| | * | (c)2 | - | Certificate of Georgia Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
| | | Gulf Power |
| | | | | |
| | * | (d)1 | - | Certificate of Gulf Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
| | * | (d)2 | - | Certificate of Gulf Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
| | | Mississippi Power |
| | | | | |
| | * | (e)1 | - | Certificate of Mississippi Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
|
| | | | |
| | * | (e)2 | - | Certificate of Mississippi Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
| | | Southern Power |
| | | | | |
| | * | (f)1 | - | Certificate of Southern Power Company's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
| | * | (f)2 | - | Certificate of Southern Power Company's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | | |
| | Southern Company Gas |
| | | | |
| * | (g)1 | - | Certificate of Southern Company Gas' Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | | |
| * | (g)2 | - | Certificate of Southern Company Gas' Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
| | | (32) Section 906 Certifications |
| | | | | |
| | | Southern Company |
| | | | | |
| | * | (a) | - | Certificate of Southern Company's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
| | | Alabama Power |
| | | | | |
| | * | (b) | - | Certificate of Alabama Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
| | | Georgia Power |
| | | | | |
| | * | (c) | - | Certificate of Georgia Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
|
| | | | |
| | | Gulf Power |
| | | | | |
| | * | (d) | - | Certificate of Gulf Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
| | | Mississippi Power |
| | | | | |
| | * | (e) | - | Certificate of Mississippi Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
| | | Southern Power |
| | | | | |
| | * | (f) | - | Certificate of Southern Power Company's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
| | | Southern Company Gas |
| | | | |
| * | (g) | - | Certificate of Southern Company Gas' Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002. |
| | | | |
|
| | | | |
| | (101) Interactive Data Files |
| | | | | |
| | * | INS | - | XBRL Instance Document |
| | * | SCH | - | XBRL Taxonomy Extension Schema Document |
| | * | CAL | - | XBRL Taxonomy Calculation Linkbase Document |
| | * | DEF | - | XBRL Definition Linkbase Document |
| | * | LAB | - | XBRL Taxonomy Label Linkbase Document |
| | * | PRE | - | XBRL Taxonomy Presentation Linkbase Document |
THE SOUTHERN COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
|
| | | |
| | | THE SOUTHERN COMPANY |
| | | | |
| By | | Thomas A. Fanning |
| | | Chairman, President, and Chief Executive Officer |
| | | (Principal Executive Officer) |
| | | | |
| By | | Art P. Beattie |
| | | Executive Vice President and Chief Financial Officer |
| | | (Principal Financial Officer) |
| | | | |
| By | | /s/ Melissa K. Caen | |
| | | (Melissa K. Caen, Attorney-in-fact) | |
Date: November 4, 2016August 1, 2017
ALABAMA POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
|
| | | |
| | | ALABAMA POWER COMPANY |
| | | | |
| By | | Mark A. Crosswhite | |
| | | Chairman, President, and Chief Executive Officer |
| | | (Principal Executive Officer) |
| | | | |
| By | | Philip C. Raymond |
| | | Executive Vice President, Chief Financial Officer, and Treasurer |
| | | (Principal Financial Officer) |
| | | | |
| By | | /s/ Melissa K. Caen | |
| | | (Melissa K. Caen, Attorney-in-fact) | |
Date: November 4, 2016
GEORGIA POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
|
| | | |
| | | GEORGIA POWER COMPANY |
| | | | |
| By | | W. Paul Bowers |
| | | Chairman, President, and Chief Executive Officer |
| | | (Principal Executive Officer) |
| | | | |
| By | | W. Ron Hinson |
| | | Executive Vice President, Chief Financial Officer, and Treasurer |
| | | (Principal Financial Officer) |
| | | | |
| By | | /s/ Melissa K. Caen | |
| | | (Melissa K. Caen, Attorney-in-fact) | |
Date: November 4, 2016
GULF POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
|
| | | |
| | | 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, and Treasurer |
| | | (Principal Financial Officer) |
| | | | |
| By | | /s/ Melissa K. Caen | |
| | | (Melissa K. Caen, Attorney-in-fact) | |
Date: November 4, 2016
MISSISSIPPI POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
|
| | | |
| | | MISSISSIPPI POWER COMPANY |
| | | | |
| By | | Anthony L. Wilson |
| | | Chairman, President, and Chief Executive Officer |
| | | (Principal Executive Officer) |
| | | | |
| By | | Moses H. Feagin |
| | | Vice President, Chief Financial Officer, and Treasurer |
| | | (Principal Financial Officer) |
| | | | |
| By | | /s/ Melissa K. Caen | |
| | | (Melissa K. Caen, Attorney-in-fact) | |
Date: November 4, 2016
SOUTHERN POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
|
| | | |
| | | SOUTHERN POWER COMPANY |
| | | | |
| By | | Joseph A. Miller |
| | | Chairman, President, and Chief Executive Officer |
| | | (Principal Executive Officer) |
| | | | |
| By | | William C. Grantham |
| | | Senior Vice President, Chief Financial Officer, and Treasurer |
| | | (Principal Financial Officer) |
| | | | |
| By | | /s/ Melissa K. Caen | |
| | | (Melissa K. Caen, Attorney-in-fact) | |
Date: November 4, 2016August 1, 2017
SOUTHERN COMPANY GAS
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
|
| | | |
| | SOUTHERN COMPANY GAS |
| | | |
| By | | Andrew W. Evans |
| | Chairman, President, and Chief Executive Officer |
| | (Principal Executive Officer) |
| | | |
| By | | Elizabeth W. Reese |
| | Executive Vice President, Chief Financial Officer, and Treasurer |
| | (Principal Financial Officer) |
| | | |
| By | | /s/ Melissa K. Caen | |
| | (Melissa K. Caen, Attorney-in-fact) | |
Date: August 1, 2017