0000092122 so:GeorgiaPowerMember so:OtherNaturalGasOtherNaturalGasRevenuesMember 2019-04-01 2019-06-30 0000092122 us-gaap:ShortTermDebtMember us-gaap:FairValueHedgingMember 2020-06-30
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, 20172020
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. | |
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| 1-3526 | | The Southern Company (A Delaware Corporation)
30 Ivan Allen Jr. Boulevard, N.W.
Atlanta, Georgia 30308
(404) 506-5000
| | 58-0690070 | |
(A Delaware Corporation)
30 Ivan Allen Jr. Boulevard, N.W.
Atlanta, Georgia30308
(404) 506-5000
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| 1-3164 | | Alabama Power Company (An Alabama Corporation)
600 North 18th Street
Birmingham, Alabama 35203
(205) 257-1000
| | 63-0004250 | |
(An Alabama Corporation)
600 North 18th Street
Birmingham, Alabama35203
(205) 257-1000
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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 |
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(A Georgia Corporation)
241 Ralph McGill Boulevard, N.E.
Atlanta, Georgia30308
(404) 506-6526
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 | |
(A Mississippi Corporation)
2992 West Beach Boulevard
Gulfport, Mississippi39501
(228) 864-1211
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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 | |
(A Delaware Corporation)
30 Ivan Allen Jr. Boulevard, N.W.
Atlanta, Georgia30308
(404) 506-5000
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| 1-14174 | | Southern Company Gas
(A Georgia Corporation)
Ten Peachtree Place, N.E. Atlanta, Georgia 30309
(404) 584-4000
| | 58-2210952 | |
(A Georgia Corporation)
Ten Peachtree Place, N.E.
Atlanta, Georgia30309
(404) 584-4000
Securities registered pursuant to Section 12(b) of the Act:
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| Registrant | Title of Each Class | Trading Symbol(s) | Name of Each Exchange on Which Registered |
| The Southern Company | Common Stock, par value $5 per share | SO | New York Stock Exchange |
| (NYSE) |
| The Southern Company | Series 2015A 6.25% Junior Subordinated Notes due 2075 | SOJA | NYSE |
| The Southern Company | Series 2016A 5.25% Junior Subordinated Notes due 2076 | SOJB | NYSE |
| The Southern Company | Series 2017B 5.25% Junior Subordinated Notes due 2077 | SOJC | NYSE |
| The Southern Company | 2019 Series A Corporate Units | SOLN | NYSE |
| The Southern Company | Series 2020A 4.95% Junior Subordinated Notes due 2080 | SOJD | NYSE |
| Alabama Power Company | 5.00% Series Class A Preferred Stock | ALP PR Q | NYSE |
| Georgia Power Company | Series 2017A 5.00% Junior Subordinated Notes due 2077 | GPJA | NYSE |
| Southern Power Company | Series 2016A 1.000% Senior Notes due 2022 | SO/22B | NYSE |
| Southern Power Company | Series 2016B 1.850% Senior Notes due 2026 | SO/26A | NYSE |
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. Yesþ 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). Yesþ No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "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
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, 20172020 |
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| The Southern Company | | Par Value $5 Per Share | 1,056,130,748 | 1,003,627,691 |
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| Alabama Power Company | | Par Value $40 Per Share | | 30,537,500 |
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| Georgia Power Company | | Without Par Value | | 9,261,500 |
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Gulf Power Company | | Without Par Value | | 7,392,717 |
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| Mississippi Power Company | | Without Par Value | | 1,121,000 |
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| Southern Power Company | | Par Value $0.01 Per Share | | 1,000 |
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| Southern Company Gas | | Par Value $0.01 Per Share | | 100 |
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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 Company Gas. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.
INDEX TO QUARTERLY REPORT ON FORM 10-Q
September 30, 2017
TABLE OF CONTENTS
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| | PART I—FINANCIAL INFORMATION | |
Item 1. | Financial Statements (Unaudited) | |
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INDEX TO QUARTERLY REPORT ON FORM 10-Q
September 30, 2017
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| PART I—FINANCIAL INFORMATION (CONTINUED) | |
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| Item 3. | | |
| Item 4. | | |
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| | PART II—OTHER INFORMATION | |
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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 |
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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 | AlternativeAlternate Rate Plan approved by the Georgia PSC in 2013 for Georgia Power for the years 2014 through 2016 and subsequently extended through 2019 |
| 2019 ARP | Alternate Rate Plan approved by the Georgia PSC in 2019 for Georgia Power for the years 2020 through 2022 |
| AFUDC | Allowance for funds used during construction |
| Alabama Power | Alabama Power Company |
ASCAmended and Restated Loan Guarantee Agreement | Accounting Standards CodificationLoan guarantee agreement entered into by Georgia Power with the DOE in 2014, as amended and restated in March 2019, 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 |
| ARO | Asset retirement obligation |
| ASU | Accounting Standards Update |
| Atlanta Gas Light | Atlanta Gas Light Company, a wholly-owned subsidiary of Southern Company Gas |
| Atlantic Coast Pipeline | Atlantic Coast Pipeline, LLC, a joint venture to construct and operate a natural gas pipeline in which Southern Company Gas hasheld a 5% ownership interest through March 24, 2020 |
Baseload ActAutauga Combined Cycle Acquisition | StateThe purchase and sale agreement entered into in September 2019 by Alabama Power to acquire all of Mississippi legislation designed to enhance the Mississippi PSC's authority to facilitate developmentequity interest in Tenaska Alabama Partners, L.P., the owner and operator of an approximately 885-MW combined cycle generation facility in Autauga County, Alabama |
| Bechtel | Bechtel Power Corporation, the primary contractor for the remaining construction of baseload generation inactivities for Plant Vogtle Units 3 and 4 |
| Bechtel Agreement | The October 23, 2017 construction completion agreement between the State of MississippiVogtle Owners and Bechtel |
| CCR | Coal combustion residuals |
Clean Power PlanCCR Rule | Final actionDisposal of Coal Combustion Residuals from Electric Utilities final rule 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
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CO2
Chattanooga Gas | Carbon dioxideChattanooga Gas Company, a wholly-owned subsidiary of Southern Company Gas |
| COD | Commercial operation date |
| Contractor Settlement Agreement | The December 31, 2015 agreement between Westinghouse and the Vogtle Owners resolving disputes between the Vogtle Owners and the EPC Contractor under the Vogtle 3 and 4 Agreement |
Cooperative EnergyCOVID-19 | Electric cooperativeThe novel coronavirus disease declared a pandemic by the World Health Organization and the Centers for Disease Control and Prevention in Mississippi formerly known as South Mississippi Electric Power Association (SMEPA) |
CPCN | Certificate of public convenience and necessityMarch 2020 |
| CWIP | Construction work in progress |
| Dalton | City of Dalton, Georgia, an incorporated municipality in the State of Georgia, acting by and through its Board of Water, Light, and Sinking Fund Commissioners |
| Dalton Pipeline | A pipeline facility in Georgia in which Southern Company Gas has 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 Planenvironmental 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 loan guarantee program established under Title XVII Loan Guarantee Programof the Energy Policy Act of 2005 |
| EPA | U.S. Environmental Protection Agency |
| EPC Contractor | Westinghouse and its affiliate, WECTEC (formerly known as CB&I Stone & Webster,Global Project Services 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 |
| FFB Credit Facilities | Note purchase agreements among the DOE, Georgia Power, and the FFB and related promissory notes which provide for two multi-advance term loan facilities |
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| Term | Meaning |
| Fitch | Fitch Ratings, Inc. |
| Form 10-K | Annual Report on Form 10-K of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas for the year ended December 31, 2016,2019, as applicable |
| GAAP | U.S. generally accepted accounting principles |
| Georgia Power | Georgia Power Company |
| GRAM | Atlanta Gas Light's Georgia Rate Adjustment Mechanism |
| Guarantee Settlement Agreement | The June 9, 2017 settlement agreement between the Vogtle Owners and Toshiba related to certain payment obligations of the EPC Contractor guaranteed by Toshiba |
| Gulf Power | Gulf Power Company, until January 1, 2019 a wholly-owned subsidiary of Southern Company |
| Heating Degree Days | A measure of weather, calculated when the average daily temperatures are less than 65 degrees Fahrenheit |
Horizon PipelineHeating Season | Horizon PipelineThe period from November through March when Southern Company LLC |
DEFINITIONS
(continued)
| Gas' natural gas usage and operating revenues are generally higher |
| HLBV | |
Term | Meaning |
| Hypothetical liquidation at book value |
| IGCC | Integrated coal gasification combined cycle, the technology originally approved for Mississippi Power's Kemper County energy facility |
| IIC | Intercompany interchange contractInterchange Contract |
Illinois CommissionITAAC | Illinois Commerce Commission,Inspections, Tests, Analyses, and Acceptance Criteria, standards established by the state regulatory agency for Nicor Gas |
IRC | Internal Revenue Code of 1986, as amended |
IRS | Internal Revenue ServiceNRC |
| ITC | Investment tax credit |
Kemper IGCCJEA | Mississippi Power's IGCC project in Kemper County, MississippiJacksonville Electric Authority |
| KWH | Kilowatt-hour |
| LIBOR | London Interbank Offered Rate |
| LIFO | Last-in, first-out |
LNG | Liquefied natural gas |
Loan Guarantee Agreement | Loan guarantee agreement entered into by Georgia Power with the DOE in 2014, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4 |
| LOCOM | Lower of weighted average cost or current market price |
| LTSA | Long-term service agreement |
MATS ruleMarketers | MercuryMarketers selling retail natural gas in Georgia and Air Toxics Standards rulecertificated by the Georgia PSC |
MergerMEAG Power | The merger, effective July 1, 2016,Municipal Electric Authority 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 orderGeorgia |
| 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,and Chattanooga Gas Company, and Elkton Gas) |
| NCCR | Georgia Power's Nuclear Construction Cost Recovery |
New Jersey BPUNDR | New Jersey Board of Public Utilities, the state regulatory agency for Elizabethtown GasAlabama Power's Natural Disaster Reserve |
| NextEra Energy | NextEra Energy, Inc. |
| 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 |
| PennEast Pipeline | PennEast Pipeline Company, LLC, a joint venture to construct and operate a natural gas pipeline in which Southern Company Gas has a 20% ownership interest |
| PEP | Mississippi Power's Performance Evaluation Plan |
Piedmont | Piedmont Natural Gas Company, Inc. |
Pivotal Utility HoldingsLNG | Pivotal Utility Holdings,LNG, Inc., through March 24, 2020 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 (excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations |
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| Term | Meaning |
| PowerSecure | PowerSecure, Inc., a wholly-owned subsidiary of Southern Company |
| PPA | Power purchase agreements, as well as, for Southern Power, contracts for differences that provide the owner of a renewable facility a certain fixed price for the electricity sold to the grid |
| PSC | Public Service Commission |
| PTC | Production tax credit |
| Rate CNP | Alabama Power's Rate Certificated New Plant, |
| consisting of Rate CNP New Plant, Rate CNP Compliance, | Alabama Power's Rate Certificated New Plant Compliance |
| and 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 |
registrantsRegistrants | Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, 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, the Southern Company system service company)company and a wholly-owned subsidiary of Southern Company |
| SEC | U.S. Securities and Exchange Commission |
| SNG | Southern Natural Gas Company, L.L.C., a pipeline system in which Southern Company Gas has a 50% ownership interest |
| Southern Company | The Southern Company |
| Southern Company Gas | Southern Company Gas and its subsidiaries |
| Southern Company Gas Capital | Southern Company Gas Capital Corporation, a 100%-owned subsidiary of Southern Company Gas |
| Southern Company power pool | The operating arrangement whereby the integrated generating resources of the traditional electric operating companies and Southern Power (excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations |
| 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 |
| Southern Holdings | Southern Company Holdings, Inc., a wholly-owned subsidiary of Southern Company |
| Southern Nuclear | Southern Nuclear Operating Company, Inc., a wholly-owned subsidiary of Southern Company |
| Southern Power | Southern Power Company and its subsidiaries |
| SouthStar | SouthStar Energy Services, LLC, a wholly-owned subsidiary of Southern Company Gas |
STRIDESP Solar | AtlantaSP Solar Holdings I, LP, a limited partnership indirectly owning substantially all of Southern Power's solar facilities, in which Southern Power has a 67% ownership interest |
| SP Wind | SP Wind Holdings II, LLC, a holding company owning a portfolio of eight operating wind facilities, in which Southern Power is the controlling partner in a tax equity arrangement |
| Subsidiary Registrants | Alabama Power, Georgia Power, Mississippi Power, Southern Power, and Southern Company Gas Light's Strategic Infrastructure Development |
| Tax Reform | The impact of the Tax Cuts and Enhancement programJobs Act, which became effective on January 1, 2018 |
| Toshiba | Toshiba Corporation, the 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, an investment of Southern Company Gas through May 29, 2019 |
| VCM | Vogtle Construction Monitoring |
| VIE | Variable interest entity |
| 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 |
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| Term | Meaning |
| 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, and rejected in bankruptcy in July 2017, 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, MEAG Power, and Dalton |
| Vogtle Services Agreement | The June 2017 services agreement between the Municipal Electric Authority of Georgia,Vogtle Owners and the CityEPC Contractor, as amended and restated in July 2017, for the EPC Contractor to transition construction management of Dalton, Georgia, an incorporated municipality in the State of Georgia acting byPlant Vogtle Units 3 and through its Board of Water, Light,4 to Southern Nuclear and Sinking Fund Commissionersto provide ongoing design, engineering, and procurement services to Southern Nuclear |
| WACOG | Weighted average cost of gas |
WECTEC | WECTEC Global Project Services Inc. |
| Westinghouse | Westinghouse Electric Company LLC |
| Xcel | Xcel Energy Inc. |
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATIONThis 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, completion of announced acquisitions or dispositions, 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
This Quarterly Report on Form 10-Q contains forward-looking statements. Forward-looking statements include, among other things, the potential and expected effects of the COVID-19 pandemic, statements concerning regulated rates, the strategic goals for the business, customer and sales growth, economic conditions, fuel and environmental cost recovery and other rate actions, projected equity ratios, 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 and costs of construction projects, matters related to the abandonment of the Kemper IGCC, completion of announced acquisitions, filings with state and federal regulatory authorities, and estimated construction plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "would," "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 tax, environmental, and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;
the potential effects of the continued COVID-19 pandemic, including, but not limited to, those described in Item 1A "Risk Factors" herein;
the extent and timing of costs and legal requirements related to CCR;
current and future litigation or regulatory investigations, proceedings, or inquiries, including litigation and other disputes related to the Kemper County energy facility;
the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company's subsidiaries operate, including from the development and deployment of alternative energy sources;
variations in demand for electricity and natural gas;
available sources and costs of natural gas and other fuels;
the ability to complete necessary or desirable pipeline expansion or infrastructure projects, limits on pipeline capacity, and operational interruptions to natural gas distribution and transmission activities;
transmission constraints;
effects of inflation;
the ability to control costs and avoid cost and schedule overruns during the development, construction, and operation of facilities or other projects, including Plant Vogtle Units 3 and 4, which includes components based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale, and including changes in labor costs, availability, and productivity; challenges with management of contractors or vendors; subcontractor performance; adverse weather conditions; shortages, delays, increased costs, or inconsistent quality of equipment, materials, and labor; contractor or supplier delay; delays due to judicial or regulatory action; nonperformance under construction, operating, or other agreements; operational readiness, including specialized operator training and required site safety programs; engineering or design problems; design and other licensing-based compliance matters, including, for nuclear units, the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel; challenges with start-up activities, including major equipment failure, or system integration; and/or operational performance;
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| • | the ability to overcome or mitigate the current challenges at Plant Vogtle Units 3 and 4, including, but not limited to, those related to COVID-19, as described in Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" in Item 1 herein, that could further impact the cost and schedule for the project; |
legal proceedings and regulatory approvals and actions related to construction projects, such as Plant Vogtle Units 3 and 4 and pipeline projects, including PSC approvals and FERC and NRC actions;
under certain specified circumstances, a decision by holders of more than 10% of the ownership interests of Plant Vogtle Units 3 and 4 not to proceed with construction and the ability of other Vogtle Owners to tender a portion of their ownership interests to Georgia Power following certain construction cost increases;
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
(continued)
in the event Georgia Power becomes obligated to provide funding to MEAG Power with respect to the portion of MEAG Power's ownership interest in Plant Vogtle Units 3 and 4 involving JEA, any inability of Georgia Power to receive repayment of such funding;
the ability to construct facilities in accordance with the requirements of permits and licenses (including satisfaction of NRC requirements), to satisfy any environmental performance standards and the requirements of tax credits and other incentives, and to integrate facilities into the Southern Company system upon completion of construction;
investment performance of the employee and retiree benefit plans and nuclear decommissioning trust funds;
advances in technology;
performance of counterparties under 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 relatedrelating to ROE, equity ratios, additional generating capacity, and fuel and other 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;mechanisms;
the ability to successfully operate the electric utilities' generating, transmission, and distribution facilities and Southern Company Gas' natural gas distribution and storage facilities and the successful performance of necessary corporate functions;
the inherent risks involved in operating and constructing nuclear generating facilities, including environmental, health, regulatory, natural disaster, terrorism, and financial risks;facilities;
the inherent risks involved in transporting and storing natural gas;
the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities;
internal restructuring or other restructuring options that may be pursued;
potential business strategies, including acquisitions or dispositions of assets or businesses, including the proposed disposition by a wholly-owned subsidiary of Southern Company Gas of Elizabethtown Gas and Elkton Gas, 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 incidentsphysical attack and the threat of terrorist incidents;physical attacks;
interest rate fluctuations and financial market conditions and the results of financing efforts;
access to capital markets and other financing sources;
changes in Southern Company's and any of its subsidiaries' credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;ratings;
changes in the impactsmethod of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, anddetermining LIBOR or the economy in general, as well as potential impacts on the benefitsreplacement of the DOE loan guarantees;LIBOR with an alternative reference rate;
the ability of Southern Company's electric utilities to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;
catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events, such as influenzas, or other similar occurrences;
the direct or indirect effects on the Southern Company system's business resulting from incidents affecting the U.S. electric grid, natural gas pipeline infrastructure, or operation of generating or storage resources;
impairments of goodwill or long-lived assets;
the effect of accounting pronouncements issued periodically by standard-setting bodies; and
other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the registrantsRegistrants from time to time with the SEC.
The registrantsRegistrants expressly disclaim any obligation to update any forward-looking statements.
THE SOUTHERN COMPANY
AND SUBSIDIARY COMPANIESPART I
Item 1. Financial Statements (Unaudited).
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, |
| | 2017 | | 2016 | | 2017 | | 2016 | 2020 | | 2019 | | 2020 | | 2019 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | | | | | | | | |
| Retail electric revenues | $ | 4,615 |
| | $ | 4,808 |
| | $ | 11,786 |
| | $ | 11,932 |
| $ | 3,182 |
| | $ | 3,540 |
| | $ | 6,260 |
| | $ | 6,623 |
|
| Wholesale electric revenues | 718 |
| | 613 |
| | 1,867 |
| | 1,455 |
| 472 |
| | 542 |
| | 889 |
| | 1,041 |
|
| Other electric revenues | 168 |
| | 181 |
| | 510 |
| | 529 |
| 168 |
| | 161 |
| | 320 |
| | 331 |
|
| Natural gas revenues | 532 |
| | 518 |
| | 2,746 |
| | 518 |
| |
Natural gas revenues (includes alternative revenue programs of
$(2), $1, $7, and $-, respectively) | | 636 |
| | 689 |
| | 1,885 |
| | 2,163 |
|
| Other revenues | 168 |
| | 144 |
| | 494 |
| | 281 |
| 162 |
| | 166 |
| | 284 |
| | 352 |
|
| Total operating revenues | 6,201 |
| | 6,264 |
| | 17,403 |
| | 14,715 |
| 4,620 |
| | 5,098 |
| | 9,638 |
| | 10,510 |
|
| Operating Expenses: | | | | | | | | | | | | | | |
| Fuel | 1,285 |
| | 1,400 |
| | 3,372 |
| | 3,334 |
| 621 |
| | 914 |
| | 1,257 |
| | 1,764 |
|
| Purchased power | 256 |
| | 227 |
| | 646 |
| | 581 |
| 200 |
| | 201 |
| | 381 |
| | 371 |
|
| Cost of natural gas | 134 |
| | 133 |
| | 1,085 |
| | 133 |
| 144 |
| | 191 |
| | 583 |
| | 877 |
|
| Cost of other sales | 90 |
| | 84 |
| | 293 |
| | 161 |
| 74 |
| | 84 |
| | 129 |
| | 203 |
|
| Other operations and maintenance | 1,287 |
| | 1,411 |
| | 3,918 |
| | 3,616 |
| 1,203 |
| | 1,320 |
| | 2,498 |
| | 2,634 |
|
| Depreciation and amortization | 767 |
| | 695 |
| | 2,236 |
| | 1,805 |
| 873 |
| | 755 |
| | 1,730 |
| | 1,506 |
|
| Taxes other than income taxes | 303 |
| | 309 |
| | 941 |
| | 821 |
| 298 |
| | 299 |
| | 629 |
| | 628 |
|
| Estimated loss on Kemper IGCC | 34 |
| | 88 |
| | 3,155 |
| | 222 |
| |
| Estimated loss on Plant Vogtle Units 3 and 4 | | 149 |
| | — |
| | 149 |
| | — |
|
| (Gain) loss on dispositions, net | | — |
| | (8 | ) | | (39 | ) | | (2,506 | ) |
| Total operating expenses | 4,156 |
| | 4,347 |
| | 15,646 |
| | 10,673 |
| 3,562 |
| | 3,756 |
| | 7,317 |
| | 5,477 |
|
| Operating Income | 2,045 |
| | 1,917 |
| | 1,757 |
| | 4,042 |
| 1,058 |
| | 1,342 |
| | 2,321 |
| | 5,033 |
|
| Other Income and (Expense): | | | | | | | | | | | | | | |
| Allowance for equity funds used during construction | 18 |
| | 52 |
| | 133 |
| | 150 |
| 35 |
| | 31 |
| | 68 |
| | 63 |
|
| Earnings from equity method investments | 32 |
| | 29 |
| | 100 |
| | 28 |
| 30 |
| | 33 |
| | 72 |
| | 81 |
|
| Interest expense, net of amounts capitalized | (407 | ) | | (374 | ) | | (1,248 | ) | | (913 | ) | (444 | ) | | (429 | ) | | (900 | ) | | (859 | ) |
| Impairment of leveraged lease | | (154 | ) | | — |
| | (154 | ) | | — |
|
| Other income (expense), net | 11 |
| | (8 | ) | | 2 |
| | (66 | ) | 101 |
| | 99 |
| | 204 |
| | 176 |
|
| Total other income and (expense) | (346 | ) | | (301 | ) | | (1,013 | ) | | (801 | ) | (432 | ) | | (266 | ) | | (710 | ) | | (539 | ) |
| Earnings Before Income Taxes | 1,699 |
| | 1,616 |
| | 744 |
| | 3,241 |
| 626 |
| | 1,076 |
| | 1,611 |
| | 4,494 |
|
| Income taxes | 590 |
| | 439 |
| | 317 |
| | 917 |
| 5 |
| | 145 |
| | 150 |
| | 1,505 |
|
| Consolidated Net Income | 1,109 |
| | 1,177 |
| | 427 |
| | 2,324 |
| 621 |
| | 931 |
| | 1,461 |
| | 2,989 |
|
| Less: | | | | | | | | |
| Dividends on preferred and preference stock of subsidiaries | 10 |
| | 11 |
| | 32 |
| | 34 |
| |
| Net income attributable to noncontrolling interests | 30 |
| | 27 |
| | 48 |
| | 39 |
| |
| Dividends on preferred stock of subsidiaries | | 4 |
| | 3 |
| | 7 |
| | 7 |
|
| Net income (loss) attributable to noncontrolling interests | | 5 |
| | 29 |
| | (26 | ) | | — |
|
Consolidated Net Income Attributable to Southern Company | $ | 1,069 |
| | $ | 1,139 |
| | $ | 347 |
| | $ | 2,251 |
| $ | 612 |
| | $ | 899 |
| | $ | 1,480 |
| | $ | 2,982 |
|
| Common Stock Data: | | | | | | | | | | | | | | |
| Earnings per share — | | | | | | | | |
| Earnings per share - | | | | | | | | |
| Basic | $ | 1.07 |
| | $ | 1.18 |
| | $ | 0.35 |
| | $ | 2.40 |
| $ | 0.58 |
| | $ | 0.86 |
| | $ | 1.40 |
| | $ | 2.86 |
|
| Diluted | $ | 1.06 |
| | $ | 1.17 |
| | $ | 0.35 |
| | $ | 2.38 |
| $ | 0.58 |
| | $ | 0.85 |
| | $ | 1.39 |
| | $ | 2.84 |
|
| Average number of shares of common stock outstanding (in millions) | | | | | | | | | | | | | | |
| Basic | 1,003 |
| | 968 |
| | 998 |
| | 940 |
| 1,058 |
| | 1,044 |
| | 1,057 |
| | 1,041 |
|
| Diluted | 1,010 |
| | 975 |
| | 1,005 |
| | 945 |
| 1,063 |
| | 1,052 |
| | 1,065 |
| | 1,049 |
|
| Cash dividends paid per share of common stock | $ | 0.5800 |
| | $ | 0.5600 |
| | $ | 1.7200 |
| | $ | 1.6625 |
| |
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, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) |
| Consolidated Net Income | $ | 1,109 |
| | $ | 1,177 |
| | $ | 427 |
| | $ | 2,324 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
Changes in fair value, net of tax of $15, $12, $32, and $(74),
respectively | 25 |
| | 19 |
| | 54 |
| | (118 | ) |
Reclassification adjustment for amounts included in net income,
net of tax of $(10), $2, $(36), and $13, respectively | (17 | ) | | 2 |
| | (59 | ) | | 20 |
|
| Pension and other postretirement benefit plans: | | | | | | | |
Reclassification adjustment for amounts included in net income,
net of tax of $1, $1, $2, and $2, respectively | 1 |
| | 1 |
| | 3 |
| | 3 |
|
| Total other comprehensive income (loss) | 9 |
| | 22 |
| | (2 | ) | | (95 | ) |
| Comprehensive Income | 1,118 |
| | 1,199 |
| | 425 |
| | 2,229 |
|
| Less: | | | | | | | |
| Dividends on preferred and preference stock of subsidiaries | 10 |
| | 11 |
| | 32 |
| | 34 |
|
| Comprehensive income attributable to noncontrolling interests | 30 |
| | 27 |
| | 48 |
| | 39 |
|
Consolidated Comprehensive Income Attributable to Southern Company | $ | 1,078 |
| | $ | 1,161 |
| | $ | 345 |
| | $ | 2,156 |
|
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2020 | | 2019 | | 2020 | | 2019 |
| | (in millions) | | (in millions) |
| Consolidated Net Income | $ | 621 |
| | $ | 931 |
| | $ | 1,461 |
| | $ | 2,989 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
Changes in fair value, net of tax of
$4, $(11), $(26), and $(21), respectively | 10 |
| | (32 | ) | | (75 | ) | | (60 | ) |
Reclassification adjustment for amounts included in net income,
net of tax of $(3), $(1), $10, and $8, respectively | (9 | ) | | (3 | ) | | 29 |
| | 24 |
|
| Pension and other postretirement benefit plans: | | | | | | | |
Reclassification adjustment for amounts included in net income,
net of tax of $1, $-, $2, and $-, respectively | 3 |
| | — |
| | 3 |
| | 1 |
|
| Total other comprehensive income (loss) | 4 |
| | (35 | ) | | (43 | ) | | (35 | ) |
| Comprehensive Income | 625 |
| | 896 |
| | 1,418 |
| | 2,954 |
|
| Dividends on preferred stock of subsidiaries | 4 |
| | 3 |
| | 7 |
| | 7 |
|
| Comprehensive income (loss) attributable to noncontrolling interests | 5 |
| | 29 |
| | (26 | ) | | — |
|
Consolidated Comprehensive Income Attributable to
Southern Company | $ | 616 |
| | $ | 864 |
| | $ | 1,437 |
| | $ | 2,947 |
|
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, |
| | 2017 | | 2016 | 2020 | | 2019 |
| | (in millions) | (in millions) |
| Operating Activities: | | | | | | |
| Consolidated net income | $ | 427 |
| | $ | 2,324 |
| $ | 1,461 |
| | $ | 2,989 |
|
| Adjustments to reconcile consolidated net income to net cash provided from operating activities — | | | | | | |
| Depreciation and amortization, total | 2,564 |
| | 2,109 |
| 1,916 |
| | 1,623 |
|
| Deferred income taxes | 15 |
| | (22 | ) | (218 | ) | | 274 |
|
| Utilization of federal investment tax credits | | — |
| | 427 |
|
| Allowance for equity funds used during construction | (133 | ) | | (150 | ) | (68 | ) | | (63 | ) |
| Pension, postretirement, and other employee benefits | (64 | ) | | (158 | ) | (119 | ) | | (65 | ) |
| Settlement of asset retirement obligations | (137 | ) | | (117 | ) | (193 | ) | | (143 | ) |
| Hedge settlements | — |
| | (236 | ) | |
| Estimated loss on Kemper IGCC | 3,148 |
| | 222 |
| |
| Stock based compensation expense | | 84 |
| | 75 |
|
| Estimated loss on Plant Vogtle Units 3 and 4 | | 149 |
| | — |
|
| Storm damage reserve accruals | | 117 |
| | 23 |
|
| Impairment charges | | 154 |
| | 32 |
|
| (Gain) loss on dispositions, net | | (35 | ) | | (2,512 | ) |
| Other, net | (8 | ) | | (1 | ) | 43 |
| | (3 | ) |
| Changes in certain current assets and liabilities — | | | | | | |
| -Receivables | 426 |
| | (458 | ) | 292 |
| | 653 |
|
| -Fossil fuel for generation | 59 |
| | 204 |
| |
| -Natural gas for sale, net of temporary LIFO liquidation | — |
| | (222 | ) | |
| -Prepayments | | (102 | ) | | (53 | ) |
| -Natural gas for sale | | 182 |
| | 255 |
|
| -Other current assets | (164 | ) | | (112 | ) | (253 | ) | | (18 | ) |
| -Accounts payable | (467 | ) | | (9 | ) | (467 | ) | | (1,045 | ) |
| -Accrued taxes | 157 |
| | 1,062 |
| 258 |
| | 511 |
|
| -Accrued compensation | (230 | ) | | (122 | ) | (347 | ) | | (312 | ) |
| -Retail fuel cost over recovery | (211 | ) | | (106 | ) | 174 |
| | 2 |
|
| -Customer refunds | | (223 | ) | | (35 | ) |
| -Other current liabilities | (129 | ) | | 88 |
| 42 |
| | (102 | ) |
| Net cash provided from operating activities | 5,253 |
| | 4,296 |
| 2,847 |
| | 2,513 |
|
| Investing Activities: | | | | | | |
| Business acquisitions, net of cash acquired | (1,032 | ) | | (9,513 | ) | |
| Property additions | (5,242 | ) | | (5,252 | ) | (3,202 | ) | | (3,484 | ) |
| Investment in restricted cash | (16 | ) | | (750 | ) | |
| Distribution of restricted cash | 33 |
| | 746 |
| |
| Nuclear decommissioning trust fund purchases | (585 | ) | | (838 | ) | (524 | ) | | (405 | ) |
| Nuclear decommissioning trust fund sales | 580 |
| | 832 |
| 519 |
| | 400 |
|
| Proceeds from dispositions and asset sales | | 983 |
| | 5,000 |
|
| Cost of removal, net of salvage | (208 | ) | | (155 | ) | (130 | ) | | (197 | ) |
| Change in construction payables, net | 120 |
| | (259 | ) | (103 | ) | | (107 | ) |
| Investment in unconsolidated subsidiaries | (134 | ) | | (1,421 | ) | (78 | ) | | (134 | ) |
| Payments pursuant to LTSAs | (189 | ) | | (125 | ) | (91 | ) | | (64 | ) |
| Other investing activities | (14 | ) | | 95 |
| (29 | ) | | (7 | ) |
| Net cash used for investing activities | (6,687 | ) | | (16,640 | ) | |
| Net cash provided from (used for) investing activities | | (2,655 | ) | | 1,002 |
|
| Financing Activities: | | | | | | |
| Increase (decrease) in notes payable, net | (515 | ) | | 655 |
| (1,170 | ) | | 83 |
|
| Proceeds — | | | | | | |
| Long-term debt | 4,068 |
| | 14,091 |
| 4,293 |
| | 1,390 |
|
| Common stock | 613 |
| | 3,265 |
| 59 |
| | 452 |
|
| Preferred stock | 250 |
| | — |
| |
| Short-term borrowings | 1,263 |
| | — |
| 615 |
| | 250 |
|
| Redemptions and repurchases — | | | | | | |
| Long-term debt | (1,981 | ) | | (2,405 | ) | (2,444 | ) | | (2,560 | ) |
| Preferred and preference stock | (150 | ) | | — |
| |
| Short-term borrowings | (409 | ) | | (475 | ) | (190 | ) | | (1,850 | ) |
| Distributions to noncontrolling interests | (89 | ) | | (22 | ) | (118 | ) | | (82 | ) |
| Capital contributions from noncontrolling interests | 79 |
| | 367 |
| 172 |
| | 5 |
|
| Purchase of membership interests from noncontrolling interests | — |
| | (129 | ) | |
| Payment of common stock dividends | (1,716 | ) | | (1,553 | ) | (1,332 | ) | | (1,269 | ) |
| Other financing activities | (113 | ) | | (185 | ) | (170 | ) | | (67 | ) |
| Net cash provided from financing activities | 1,300 |
| | 13,609 |
| |
| Net Change in Cash and Cash Equivalents | (134 | ) | | 1,265 |
| |
| Cash and Cash Equivalents at Beginning of Period | 1,975 |
| | 1,404 |
| |
| Cash and Cash Equivalents at End of Period | $ | 1,841 |
| | $ | 2,669 |
| |
| Net cash used for financing activities | | (285 | ) | | (3,648 | ) |
| Net Change in Cash, Cash Equivalents, and Restricted Cash | | (93 | ) | | (133 | ) |
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | | 1,978 |
| | 1,519 |
|
| Cash, Cash Equivalents, and Restricted Cash at End of Period | | $ | 1,885 |
| | $ | 1,386 |
|
| Supplemental Cash Flow Information: | | | | | | |
| Cash paid (received) during the period for — | | | | | | |
| Interest (net of $72 and $94 capitalized for 2017 and 2016, respectively) | $ | 1,286 |
| | $ | 766 |
| |
| Interest (net of $41 and $36 capitalized for 2020 and 2019, respectively) | | $ | 852 |
| | $ | 844 |
|
| Income taxes, net | (187 | ) | | (151 | ) | (8 | ) | | 210 |
|
| Noncash transactions — Accrued property additions at end of period | 805 |
| | 578 |
| |
| Noncash transactions — | | | | |
| Accrued property additions at end of period | | 828 |
| | 988 |
|
| Right-of-use assets obtained under operating leases | | 87 |
| | 55 |
|
| Right-of-use assets obtained under finance leases | | 7 |
| | 33 |
|
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, 2017 | | At December 31, 2016 | | At June 30, 2020 | | At December 31, 2019 |
| | | (in millions) | | (in millions) |
| Current Assets: | | | | | | | | |
| Cash and cash equivalents | | $ | 1,841 |
| | $ | 1,975 |
| | $ | 1,879 |
| | $ | 1,975 |
|
| Receivables — | | | | | | | | |
| Customer accounts receivable | | 1,744 |
| | 1,583 |
| | 1,613 |
| | 1,614 |
|
| Energy marketing receivables | | 427 |
| | 623 |
| | 273 |
| | 428 |
|
| Unbilled revenues | | 595 |
| | 706 |
| | 553 |
| | 599 |
|
| Under recovered fuel clause revenues | | 62 |
| | — |
| |
| Income taxes receivable, current | | 138 |
| | 544 |
| |
| Other accounts and notes receivable | | 578 |
| | 377 |
| | 549 |
| | 817 |
|
| Accumulated provision for uncollectible accounts | | (43 | ) | | (43 | ) | | (89 | ) | | (49 | ) |
| Materials and supplies | | 1,499 |
| | 1,462 |
| | 1,490 |
| | 1,388 |
|
| Fossil fuel for generation | | 571 |
| | 689 |
| | 609 |
| | 521 |
|
| Natural gas for sale | | 631 |
| | 631 |
| | 282 |
| | 479 |
|
| Prepaid expenses | | 365 |
| | 364 |
| | 502 |
| | 314 |
|
| Other regulatory assets, current | | 585 |
| | 581 |
| |
| Assets from risk management activities, net of collateral | | | 120 |
| | 183 |
|
| Regulatory assets – asset retirement obligations | | | 252 |
| | 287 |
|
| Other regulatory assets | | | 846 |
| | 885 |
|
| Assets held for sale | | | — |
| | 188 |
|
| Other current assets | | 209 |
| | 230 |
| | 190 |
| | 188 |
|
| Total current assets | | 9,202 |
| | 9,722 |
| | 9,069 |
| | 9,817 |
|
| Property, Plant, and Equipment: | | | | | | | | |
| In service | | 102,014 |
| | 98,416 |
| | 107,320 |
| | 105,114 |
|
| Less: Accumulated depreciation | | 31,164 |
| | 29,852 |
| | 31,477 |
| | 30,765 |
|
| Plant in service, net of depreciation | | 70,850 |
| | 68,564 |
| | 75,843 |
| | 74,349 |
|
| Nuclear fuel, at amortized cost | | 865 |
| | 905 |
| | 835 |
| | 851 |
|
| Construction work in progress | | 8,026 |
| | 8,977 |
| | 8,351 |
| | 7,880 |
|
| Total property, plant, and equipment | | 79,741 |
| | 78,446 |
| | 85,029 |
| | 83,080 |
|
| Other Property and Investments: | | | | | | | | |
| Goodwill | | 6,267 |
| | 6,251 |
| | 5,280 |
| | 5,280 |
|
| Equity investments in unconsolidated subsidiaries | | 1,637 |
| | 1,549 |
| | 1,363 |
| | 1,303 |
|
Other intangible assets, net of amortization of $156 and $62
at September 30, 2017 and December 31, 2016, respectively | | 902 |
| | 970 |
| |
Other intangible assets, net of amortization of $304 and $280
at June 30, 2020 and December 31, 2019, respectively | | | 511 |
| | 536 |
|
| Nuclear decommissioning trusts, at fair value | | 1,783 |
| | 1,606 |
| | 2,014 |
| | 2,036 |
|
| Leveraged leases | | 788 |
| | 774 |
| | 647 |
| | 788 |
|
| Miscellaneous property and investments | | 236 |
| | 270 |
| | 379 |
| | 391 |
|
| Total other property and investments | | 11,613 |
| | 11,420 |
| | 10,194 |
| | 10,334 |
|
| Deferred Charges and Other Assets: | | | | | | | | |
| Operating lease right-of-use assets, net of amortization | | | 1,776 |
| | 1,800 |
|
| Deferred charges related to income taxes | | 1,318 |
| | 1,629 |
| | 797 |
| | 798 |
|
| Unamortized loss on reacquired debt | | 210 |
| | 223 |
| | 290 |
| | 300 |
|
| Regulatory assets – asset retirement obligations, deferred | | | 4,586 |
| | 4,094 |
|
| Other regulatory assets, deferred | | 6,718 |
| | 6,851 |
| | 6,606 |
| | 6,805 |
|
| Assets held for sale, deferred | | | — |
| | 601 |
|
| Other deferred charges and assets | | 1,513 |
| | 1,406 |
| | 1,384 |
| | 1,071 |
|
| Total deferred charges and other assets | | 9,759 |
| | 10,109 |
| | 15,439 |
| | 15,469 |
|
| Total Assets | | $ | 110,315 |
| | $ | 109,697 |
| | $ | 119,731 |
| | $ | 118,700 |
|
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, 2017 | | At December 31, 2016 | | At June 30, 2020 | | At December 31, 2019 |
| | | (in millions) | | (in millions) |
| Current Liabilities: | | | | | | | | |
| Securities due within one year | | $ | 3,505 |
| | $ | 2,587 |
| | $ | 1,596 |
| | $ | 2,989 |
|
| Notes payable | | 2,579 |
| | 2,241 |
| | 1,185 |
| | 2,055 |
|
| Energy marketing trade payables | | 451 |
| | 597 |
| | 284 |
| | 442 |
|
| Accounts payable | | 2,353 |
| | 2,228 |
| | 1,787 |
| | 2,115 |
|
| Customer deposits | | 550 |
| | 558 |
| | 490 |
| | 496 |
|
| Accrued taxes — | | | | | | | | |
| Accrued income taxes | | 176 |
| | 193 |
| | 27 |
| | — |
|
| Unrecognized tax benefits | | 17 |
| | 385 |
| |
| Other accrued taxes | | 690 |
| | 667 |
| | 517 |
| | 659 |
|
| Accrued interest | | 443 |
| | 518 |
| | 499 |
| | 474 |
|
| Accrued compensation | | 703 |
| | 915 |
| | 666 |
| | 992 |
|
| Asset retirement obligations, current | | 245 |
| | 378 |
| |
| Acquisitions payable | | — |
| | 489 |
| |
| Other regulatory liabilities, current | | 139 |
| | 236 |
| |
| Asset retirement obligations | | | 575 |
| | 504 |
|
| Other regulatory liabilities | | | 558 |
| | 756 |
|
| Liabilities held for sale | | | — |
| | 5 |
|
| Operating lease obligations | | | 235 |
| | 229 |
|
| Other current liabilities | | 752 |
| | 925 |
| | 915 |
| | 830 |
|
| Total current liabilities | | 12,603 |
| | 12,917 |
| | 9,334 |
| | 12,546 |
|
| Long-term Debt | | 44,042 |
| | 42,629 |
| | 45,138 |
| | 41,798 |
|
| Deferred Credits and Other Liabilities: | | | | | | | | |
| Accumulated deferred income taxes | | 14,321 |
| | 14,092 |
| | 8,298 |
| | 7,888 |
|
| Deferred credits related to income taxes | | | 5,860 |
| | 6,078 |
|
| Accumulated deferred ITCs | | 2,290 |
| | 2,228 |
| | 2,271 |
| | 2,291 |
|
| Employee benefit obligations | | 2,139 |
| | 2,299 |
| | 1,789 |
| | 1,814 |
|
| Operating lease obligations, deferred | | | 1,611 |
| | 1,615 |
|
| Asset retirement obligations, deferred | | 4,356 |
| | 4,136 |
| | 9,699 |
| | 9,282 |
|
| Accrued environmental remediation | | | 220 |
| | 234 |
|
| Other cost of removal obligations | | 2,708 |
| | 2,748 |
| | 2,258 |
| | 2,239 |
|
| Other regulatory liabilities, deferred | | 449 |
| | 476 |
| | 371 |
| | 256 |
|
| Other deferred credits and liabilities | | 1,048 |
| | 1,278 |
| | 630 |
| | 609 |
|
| Total deferred credits and other liabilities | | 27,311 |
| | 27,257 |
| | 33,007 |
| | 32,306 |
|
| Total Liabilities | | 83,956 |
| | 82,803 |
| | 87,479 |
| | 86,650 |
|
| Redeemable Preferred Stock of Subsidiaries | | 361 |
| | 118 |
| | 291 |
| | 291 |
|
| Redeemable Noncontrolling Interests | | 59 |
| | 164 |
| |
| Stockholders' Equity: | | | | | |
| Common Stockholders' Equity: | | | | | |
| Common stock, par value $5 per share — | | | | | |
| Authorized — 1.5 billion shares | | | | | |
| Issued — September 30, 2017: 1.0 billion shares | | | | | |
| — December 31, 2016: 991 million shares | | | | | |
| Treasury — September 30, 2017: 0.9 million shares | | | | | |
| — December 31, 2016: 0.8 million shares | | | | | |
| Par value | | 5,018 |
| | 4,952 |
| |
| Paid-in capital | | 10,300 |
| | 9,661 |
| |
| Treasury, at cost | | (35 | ) | | (31 | ) | |
| Retained earnings | | 8,981 |
| | 10,356 |
| |
| Accumulated other comprehensive loss | | (182 | ) | | (180 | ) | |
| Total Common Stockholders' Equity | | 24,082 |
| | 24,758 |
| |
| Preferred and Preference Stock of Subsidiaries | | 462 |
| | 609 |
| |
| Noncontrolling Interests | | 1,395 |
| | 1,245 |
| |
| Total Stockholders' Equity | | 25,939 |
| | 26,612 |
| |
Total Stockholders' Equity (See accompanying statements) | | | 31,961 |
| | 31,759 |
|
| Total Liabilities and Stockholders' Equity | | $ | 110,315 |
| | $ | 109,697 |
| | $ | 119,731 |
| | $ | 118,700 |
|
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 ANALYSISCONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED)
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRD QUARTER 2017 vs. THIRD QUARTER 2016
AND
YEAR-TO-DATE 2017 vs. YEAR-TO-DATE 2016
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 businesses of electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas by Southern Company Gas. The four traditional electric operating companies are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. Southern Company's other business activities include providing energy technologies and services to electric utilities and large industrial, commercial, institutional, and municipal customers. Customer solutions include distributed generation systems, utility infrastructure solutions, and energy efficiency products and services. Other business activities also include investments in telecommunications, leveraged lease projects, and gas storage facilities. 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. See FUTURE EARNINGS POTENTIAL herein for information regarding agreements entered into by a wholly-owned subsidiary of Southern Company Gas to sell two of its natural gas distribution utilities.
Southern Company continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, electric and natural gas system reliability, execution of major construction projects, and earnings per share.
Construction Program
See RESULTS OF OPERATIONS – "Estimated Loss on Kemper IGCC," FUTURE EARNINGS POTENTIAL – "Construction Program," 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 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
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 (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.
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
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Southern Company Common Stockholders' Equity | | | | |
| | Number of
Common Shares | | Common Stock | | | | Accumulated
Other
Comprehensive Income
(Loss) | | | | |
| | Issued | | Treasury | | Par Value | | Paid-In Capital | | Treasury | | Retained Earnings | | | Noncontrolling Interests | | Total |
| | (in millions) |
| Balance at December 31, 2018 | 1,035 |
| | (1 | ) | | $ | 5,164 |
| | $ | 11,094 |
| | $ | (38 | ) | | $ | 8,706 |
| | $ | (203 | ) | | $ | 4,316 |
| | $ | 29,039 |
|
| Consolidated net income (loss) | — |
| | — |
| | — |
| | — |
| | — |
| | 2,084 |
| | — |
| | (29 | ) | | 2,055 |
|
| Stock issued | 6 |
| | — |
| | 28 |
| | 196 |
| | — |
| | — |
| | — |
| | — |
| | 224 |
|
| Stock-based compensation | — |
| | — |
| | — |
| | 24 |
| | — |
| | — |
| | — |
| | — |
| | 24 |
|
| Cash dividends of $0.60 per share | — |
| | — |
| | — |
| | — |
| | — |
| | (623 | ) | | — |
| | — |
| | (623 | ) |
| Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 3 |
| | 3 |
|
| Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (41 | ) | | (41 | ) |
| Other | — |
| | — |
| | — |
| | 7 |
| | (2 | ) | | — |
| | — |
| | 1 |
| | 6 |
|
| Balance at March 31, 2019 | 1,041 |
| | (1 | ) | | 5,192 |
| | 11,321 |
| | (40 | ) | | 10,167 |
| | (203 | ) | | 4,250 |
| | 30,687 |
|
| Consolidated net income | — |
| | — |
| | — |
| | — |
| | — |
| | 899 |
| | — |
| | 29 |
| | 928 |
|
| Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (35 | ) | | — |
| | (35 | ) |
| Stock issued | 5 |
| | — |
| | 25 |
| | 203 |
| | — |
| | — |
| | — |
| | — |
| | 228 |
|
| Stock-based compensation | — |
| | — |
| | — |
| | 11 |
| | — |
| | — |
| | — |
| | — |
| | 11 |
|
| Cash dividends of $0.62 per share | — |
| | — |
| | — |
| | — |
| | — |
| | (646 | ) | | — |
| | — |
| | (646 | ) |
| Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 2 |
| | 2 |
|
| Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (47 | ) | | (47 | ) |
| Other | — |
| | — |
| | — |
| | 5 |
| | (1 | ) | | — |
| | — |
| | (1 | ) | | 3 |
|
| Balance at June 30, 2019 | 1,046 |
| | (1 | ) | | $ | 5,217 |
| | $ | 11,540 |
| | $ | (41 | ) | | $ | 10,420 |
| | $ | (238 | ) | | $ | 4,233 |
| | $ | 31,131 |
|
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSISCONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED)
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Southern Company Common Stockholders' Equity | | | | |
| | Number of
Common Shares | | Common Stock | | | | Accumulated
Other
Comprehensive Income
(Loss) | | | | |
| | Issued | | Treasury | | Par Value | | Paid-In Capital | | Treasury | | Retained Earnings | | | Noncontrolling Interests | | Total |
| | (in millions) |
| Balance at December 31, 2019 | 1,054 |
| | (1 | ) | | $ | 5,257 |
| | $ | 11,734 |
| | $ | (42 | ) | | $ | 10,877 |
| | $ | (321 | ) | | $ | 4,254 |
| | $ | 31,759 |
|
| Consolidated net income (loss) | — |
| | — |
| | — |
| | — |
| | — |
| | 868 |
| | — |
| | (31 | ) | | 837 |
|
| Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (47 | ) | | — |
| | (47 | ) |
| Stock issued | 3 |
| | — |
| | 9 |
| | 43 |
| | — |
| | — |
| | — |
| | — |
| | 52 |
|
| Stock-based compensation | — |
| | — |
| | — |
| | 5 |
| | — |
| | — |
| | — |
| | — |
| | 5 |
|
| Cash dividends of $0.62 per share | — |
| | — |
| | — |
| | — |
| | — |
| | (655 | ) | | — |
| | — |
| | (655 | ) |
| Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 16 |
| | 16 |
|
| Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (48 | ) | | (48 | ) |
| Other | — |
| | — |
| | — |
| | — |
| | (2 | ) | | (2 | ) | | 1 |
| | — |
| | (3 | ) |
| Balance at March 31, 2020 | 1,057 |
| | (1 | ) | | 5,266 |
| | 11,782 |
| | (44 | ) | | 11,088 |
| | (367 | ) | | 4,191 |
| | 31,916 |
|
| Consolidated net income | — |
| | — |
| | — |
| | — |
| | — |
| | 612 |
| | — |
| | 5 |
| | 617 |
|
| Other comprehensive income | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 4 |
| | — |
| | 4 |
|
| Stock issued | — |
| | — |
| | — |
| | 7 |
| | — |
| | — |
| | — |
| | — |
| | 7 |
|
| Stock-based compensation | — |
| | — |
| | — |
| | 11 |
| | — |
| | — |
| | — |
| | — |
| | 11 |
|
| Cash dividends of $0.64 per share | — |
| | — |
| | — |
| | — |
| | — |
| | (677 | ) | | — |
| | — |
| | (677 | ) |
| Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 165 |
| | 165 |
|
| Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (70 | ) | | (70 | ) |
| Other | — |
| | — |
| | — |
| | (13 | ) | | — |
| | 1 |
| | — |
| | — |
| | (12 | ) |
| Balance at June 30, 2020 | 1,057 |
| | (1 | ) | | $ | 5,266 |
| | $ | 11,787 |
| | $ | (44 | ) | | $ | 11,024 |
| | $ | (363 | ) | | $ | 4,291 |
| | $ | 31,961 |
|
of the gasifier portion of the Kemper IGCC. Mississippi Power expectsThe accompanying notes as they relate 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).
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 IGCC Settlement Docket, 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 third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination 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 $34 million ($21 million after tax) for the third quarter 2017 and $3.2 billion ($2.2 billion after tax) for the nine months ended September 30, 2017. In the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $6.0 billion ($4.0 billion after tax) through September 30, 2017.
Mississippi Power reached and filed a settlement agreement on August 21, 2017 with certain parties (not including the Mississippi Public Utilities Staff (MPUS)), which it believes met the conditions of the Kemper Settlement Order. The settlement agreement provides for an annual revenue requirement of $126 million for Kemper IGCC-related costs, which would (i) be effective January 1, 2018, (ii) represent no rate increase for customers, and (iii) include no recovery for the costs associated with the gasifier portion of the Kemper IGCC in 2018 or at any future date. In addition, under the settlement agreement, the CPCN for the Kemper IGCC would be modified to limit the Kemper County energy facility to natural gas combined cycle operation and Mississippi Power would, in the future, file a reserve margin plan with the Mississippi PSC. The Mississippi PSC issued a scheduling order, as amended on October 5, 2017, noting Mississippi Power and the MPUS had failed to reach a joint stipulation and ordering a full hearing. The Mississippi PSC is expected to rule on an order resolving this matter in January 2018.
As of September 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 Cooperative Energy. 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.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Nuclear Construction
On March 29, 2017, the EPC Contractor for Plant Vogtle Units 3 and 4 filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. To provide for a continuation of work, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered intoare 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. On October 2, 2017, Georgia Power received the first installment of the Guarantee Obligations of $300 million from Toshiba, of which Georgia Power's proportionate share was $137 million.
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. Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement (Bechtel Agreement) with Bechtel Power Corporation (Bechtel), whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4.
In the seventeenth Vogtle Construction Monitoring (VCM) report filed on August 31, 2017, Georgia Power recommended that construction of Plant Vogtle Units 3 and 4 be continued, with Southern Nuclear serving as project manager. Georgia Power believes that the most reasonable schedule for completing Plant Vogtle Units 3 and 4 is by November 2021 for Unit 3 and by November 2022 for Unit 4, at an additional cost of approximately $1.41 billion, net of the Guarantee Settlement Agreement. The Georgia PSC is expected to make a decision on these matters by February 6, 2018.
On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. Final approval and issuanceintegral part of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to thecondensed consolidated 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.statements.
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 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 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
RESULTS OF OPERATIONS
Net Income
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(70) | | (6.1) | | $(1,904) | | (84.6) |
Consolidated net income attributable to Southern Company was $1.07 billion ($1.07 per share) for the third quarter 2017 compared to $1.14 billion ($1.18 per share) for the corresponding period in 2016. The decrease was primarily due to a decrease in retail electric revenues due to milder weather and lower customer usage, a decrease in tax benefits at Southern Power, and an increase in depreciation and amortization. These changes were partially offset by higher retail electric revenues resulting from increases in base rates and a decrease in operations and maintenance expenses.
Consolidated net income attributable to Southern Company was $347 million ($0.35 per share) for year-to-date 2017 compared to $2.3 billion ($2.40 per share) for the corresponding period in 2016. The decrease was primarily due to charges of $3.2 billion and $222 million for year-to-date 2017 and 2016, respectively, related to the Kemper IGCC at Mississippi Power. Also contributing to the change was an increase of $299 million in net income from Southern Company Gas reflecting the nine-month period in 2017 compared to the three-month period following the Merger closing on July 1, 2016, higher retail electric revenues resulting from increases in base rates, and increases in renewable energy sales at Southern Power, partially offset by a decrease in retail electric revenues due to milder weather and lower customer usage, higher interest expense, and an increase in depreciation and amortization.
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
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(193) | | (4.0) | | $(146) | | (1.2) |
In the third quarter 2017, retail electric revenues were $4.6 billion compared to $4.8 billion for the corresponding period in 2016. For year-to-date 2017, retail electric revenues were $11.8 billion compared to $11.9 billion for the corresponding period in 2016.
Details of the changes in retail electric revenues were as follows:
|
| | | | | | | | | | | | | | |
| | | Third Quarter 2017 | | Year-to-Date 2017 |
| | | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail electric – prior year | | $ | 4,808 |
| | | | $ | 11,932 |
| | |
| Estimated change resulting from – | | | | | | | | |
| Rates and pricing | | 138 |
| | 2.9 |
| | 338 |
| | 2.8 |
|
| Sales decline | | (52 | ) | | (1.1 | ) | | (74 | ) | | (0.6 | ) |
| Weather | | (162 | ) | | (3.4 | ) | | (351 | ) | | (2.9 | ) |
| Fuel and other cost recovery | | (117 | ) | | (2.4 | ) | | (59 | ) | | (0.5 | ) |
| Retail electric – current year | | $ | 4,615 |
| | (4.0 | )% | | $ | 11,786 |
| | (1.2 | )% |
Revenues associated with changes in rates and pricing increased in the third 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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
January 1, 2017, the recovery of Plant Vogtle Units 3 and 4 construction financing costs under the NCCR tariff at Georgia Power, and an increase in retail base revenues effective July 2017 and in environmental cost recovery effective November 2016 at Gulf Power.
See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Alabama Power," " – Georgia Power – Rate Plans," and " – Gulf Power – Retail Base Rate Cases" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.
Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016. Weather-adjusted residential KWH sales decreased 2.0% and 0.6% in the third quarter and year-to-date 2017, respectively, primarily due to decreased customer usage resulting from an increase in penetration of energy efficient residential appliances, partially offset by customer growth. Weather-adjusted commercial KWH sales decreased 1.4% and 1.1% in the third quarter and year-to-date 2017, respectively, primarily due to decreased customer usage resulting from customer initiatives in energy savings and an ongoing migration to the electronic commerce business model, partially offset by customer growth. Industrial KWH sales decreased 0.5% and 1.1% in the third quarter and year-to-date 2017, respectively, primarily in the paper sector, partially offset by increased sales in the primary metals and textile sectors. Despite a more stable dollar and improving global economy, the industrial sector remains constrained by economic policy uncertainty. Additionally, Hurricane Irma negatively impacted customer usage for all customer classes.
Fuel and other cost recovery revenues decreased $117 million and $59 million in the third quarter and year-to-date 2017, respectively, when compared to the corresponding periods in 2016 primarily due to lower energy sales resulting from milder weather and lower coal 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 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $105 | | 17.1 | | $412 | | 28.3 |
Wholesale electric revenues consist of PPAs primarily with investor-owned utilities and electric cooperatives and short-term opportunity sales. Wholesale electric revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues generally represent the greatest contribution to net income and are designed to provide recovery of fixed costs plus a return on investment. Energy revenues will vary depending on fuel prices, the market prices of wholesale energy compared to the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Energy sales from solar and wind PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or through a fixed price related to the energy. As a 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.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In the third quarter 2017, wholesale electric revenues were $718 million compared to $613 million for the corresponding period in 2016. This increase was primarily related to a $78 million increase in energy revenues and a $27 million increase in capacity revenues. For year-to-date 2017, wholesale electric revenues were $1.9 billion compared to $1.5 billion for the corresponding period in 2016. This increase was primarily related to a $354 million increase in energy revenues and a $58 million increase in capacity revenues. The increases in energy revenues primarily relate to Southern Power increases in renewable energy sales arising from new solar and wind facilities and non-PPA revenues from short-term sales. The increases in capacity revenues primarily resulted from PPAs related to new natural gas facilities and additional customer capacity requirements at Southern Power.
Other Electric Revenues
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(13) | | (7.2) | | $(19) | | (3.6) |
In the third quarter 2017, other electric revenues were $168 million compared to $181 million for the corresponding period in 2016. The decrease was primarily related to lower open access transmission tariff revenues, primarily as a result of the expiration of long-term transmission services contracts at Georgia Power and rate adjustments at Alabama Power, and a decrease in solar application fee revenues at Georgia Power.
For year-to-date 2017, other electric revenues were $510 million compared to $529 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 a $12 million decrease in open access transmission tariff revenues, primarily as a result of the expiration of long-term transmission services contracts at Georgia Power, partially offset by a $10 million increase in outdoor lighting sales revenues primarily attributable to LED conversions at Georgia Power.
Natural Gas Revenues
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $14 | | 2.7 | | $2,228 | | N/M |
N/M - Not meaningful
Natural gas revenues represent sales from the natural gas distribution utilities and certain non-regulated operations of Southern Company Gas. In the third quarter 2017, natural gas revenues were $532 million compared to $518 million for the corresponding period in 2016. This increase is primarily due to infrastructure replacement programs and increases in base rate revenues at Southern Company Gas.
For year-to-date 2017, natural gas revenues were $2.7 billion compared to $518 million for the corresponding period in 2016. The increase reflects the inclusion of Southern Company Gas results for the nine-month period in 2017 compared to the three-month period subsequent to the Merger closing on July 1, 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 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $24 | | 16.7 | | $213 | | 75.8 |
In the third quarter 2017, other revenues were $168 million compared to $144 million for the corresponding period in 2016. For year-to-date 2017, other revenues were $494 million compared to $281 million for the corresponding
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
period in 2016. These increases were primarily due to increases of $5 million and $135 million for the third quarter and year-to-date 2017, respectively, from products and services at PowerSecure, which was acquired on May 9, 2016, and $8 million and $70 million for the third quarter and year-to-date 2017, respectively, of revenues from gas marketing products and services at Southern Company Gas following the Merger. Additionally, revenues from certain non-regulated sales of products and services at the traditional electric operating companies increased $5 million and $13 million for the third quarter and year-to-date 2017, respectively, primarily due to additional third-party infrastructure services.
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 2017
vs.
Third Quarter 2016 | | Year-to-Date 2017
vs.
Year-to-Date 2016 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | (115 | ) | | (8.2) | | $ | 38 |
| | 1.1 |
| Purchased power | 29 |
| | 12.8 | | 65 |
| | 11.2 |
| Total fuel and purchased power expenses | $ | (86 | ) | | | | $ | 103 |
| | |
In the third quarter 2017, total fuel and purchased power expenses were $1.5 billion compared to $1.6 billion for the corresponding period in 2016. The decrease was primarily the result of a $104 million net decrease in the volume of KWHs generated and purchased, partially offset by an $18 million net increase in the average cost of fuel and purchased power primarily due to higher natural gas prices.
For year-to-date 2017, total fuel and purchased power expenses were $4.0 billion compared to $3.9 billion for the corresponding period in 2016. The increase was primarily the result of a $277 million increase in the average cost of fuel and purchased power primarily due to higher natural gas prices, partially offset by a $174 million decrease in the volume of KWHs generated and purchased.
Fuel and purchased power energy transactions at the traditional electric operating companies are generally offset by fuel revenues and do not have a significant impact on net income. See FUTURE EARNINGS POTENTIAL – "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 2017 | | Third Quarter 2016 | | Year-to-Date 2017 | | Year-to-Date 2016 |
Total generation (in billions of KWHs) | 54 | | 56 | | 147 | | 145 |
Total purchased power (in billions of KWHs) | 6 | | 6 | | 14 | | 15 |
Sources of generation (percent) — | | | | | | | |
| Coal | 31 | | 38 | | 30 | | 33 |
| Nuclear | 15 | | 15 | | 16 | | 16 |
| Gas | 47 | | 44 | | 46 | | 46 |
| Hydro | 2 | | 1 | | 2 | | 3 |
| Other | 5 | | 2 | | 6 | | 2 |
Cost of fuel, generated (in cents per net KWH) — | | | | | | | |
| Coal | 2.82 | | 2.97 | | 2.82 | | 3.10 |
| Nuclear | 0.80 | | 0.81 | | 0.80 | | 0.82 |
| Gas | 2.92 | | 2.74 | | 2.93 | | 2.40 |
Average cost of fuel, generated (in cents per net KWH) | 2.54 | | 2.54 | | 2.51 | | 2.38 |
Average cost of purchased power (in cents per net KWH)(*) | 4.96 | | 4.98 | | 5.32 | | 4.75 |
| |
(*) | Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider. |
Fuel
In the third quarter 2017, fuel expense was $1.3 billion compared to $1.4 billion for the corresponding period in 2016. The decrease was primarily due to a 21.4% decrease in the volume of KWHs generated by coal and a 5.1% decrease in the average cost of coal per KWH generated, partially offset by a 6.6% increase in the average cost of natural gas per KWH generated and a 1.2% increase in the volume of KWHs generated by natural gas.
For year-to-date 2017, fuel expense was $3.4 billion compared to $3.3 billion for the corresponding period in 2016. The increase was primarily due to a 22.1% increase in the average cost of natural gas per KWH generated, partially offset by a 9.0% decrease in the average cost of coal per KWH generated, a 7.4% decrease in the volume of KWHs generated by coal, and a 3.7% decrease in the volume of KWHs generated by natural gas.
Purchased Power
In the third quarter 2017, purchased power expense was $256 million compared to $227 million for the corresponding period in 2016. The increase was primarily due to a 10.1% increase in the volume of KWHs purchased, partially offset by a 0.4% decrease in the average cost per KWH purchased.
For year-to-date 2017, purchased power expense was $646 million compared to $581 million for the corresponding period in 2016. The increase was primarily due to a 12.0% increase in the average cost per KWH purchased, primarily as a result of higher natural gas prices, partially offset by a 1.3% 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
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1 | | 0.8 | | $952 | | N/M |
N/M - Not meaningful
Cost of natural gas represents the cost of natural gas sold by the natural gas distribution utilities and certain non-regulated operations of Southern Company Gas. In the third quarter 2017, cost of natural gas was $134 million compared to $133 million for the corresponding period in 2016. For year-to-date 2017, cost of natural gas was $1.1 billion compared to $133 million for the corresponding period in 2016. The year-to-date increase reflects the inclusion of Southern Company Gas results for the nine-month period in 2017 compared to the three-month period subsequent to the Merger closing on July 1, 2016.
See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
Cost of Other Sales
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $6 | | 7.1 | | $132 | | 82.0 |
In the third quarter 2017, cost of other sales was $90 million compared to $84 million for the corresponding period in 2016. For year-to-date 2017, cost of other sales was $293 million compared to $161 million for the corresponding period in 2016. The year-to-date increase primarily reflects costs related to sales of products and services by PowerSecure, which was acquired on May 9, 2016, and costs related to gas marketing products and services at Southern Company Gas following the Merger closing on July 1, 2016. See Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(124) | | (8.8) | | $302 | | 8.4 |
In the third quarter 2017, other operations and maintenance expenses were $1.3 billion compared to $1.4 billion for the corresponding period in 2016. The decrease was primarily due to cost containment and modernization activities implemented at Georgia Power in the third quarter 2016 that contributed to decreases of $37 million in maintenance costs, $9 million in customer accounts, service, and sales costs, and $8 million in other employee compensation and benefits. Other factors include a $40 million decrease in acquisition-related expenses and a $31 million decrease in employee compensation and benefits including pension costs.
For year-to-date 2017, other operations and maintenance expenses were $3.9 billion compared to $3.6 billion for the corresponding period in 2016. The increase was primarily due to increases of $420 million and $32 million in operations and maintenance expenses as a result of the inclusion of Southern Company Gas and PowerSecure results for the nine-month period in 2017, respectively, a $48 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 due to cost containment and modernization activities implemented at Georgia Power in the third quarter 2016 that contributed to decreases of $79 million in maintenance costs and $34 million in other employee compensation and benefits. Other factors
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
include a $32 million decrease in acquisition-related expenses, a $25 million decrease in customer accounts, service, and sales costs primarily at Georgia Power, a $19 million increase in gains from sales of integrated transmission system assets at Georgia Power, and a $16 million decrease in scheduled outage and maintenance costs at generation facilities.
See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information regarding the 2017 Rate Case Settlement Agreement and Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information related to the Merger and the acquisition of PowerSecure.
Depreciation and Amortization
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $72 | | 10.4 | | $431 | | 23.9 |
In the third quarter 2017, depreciation and amortization was $767 million compared to $695 million for the corresponding period in 2016. The increase is primarily related to additional plant in service at the traditional electric operating companies, Southern Power, and Southern Company Gas.
For year-to-date 2017, depreciation and amortization was $2.2 billion compared to $1.8 billion for the corresponding period in 2016. The increase reflects $254 million as a result of the inclusion of Southern Company Gas for the nine-month period in 2017 compared to the three-month period subsequent to the Merger closing on July 1, 2016. Additionally, the increase reflects $170 million related to additional plant in service at the traditional electric operating companies and Southern Power. The increase was partially offset by a $34 million increase in the reductions in depreciation authorized in Gulf Power's 2013 rate case settlement approved by the Florida PSC as compared to the corresponding period in 2016.
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 Notes (B) and (I) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" and "Southern Company – Merger with Southern Company Gas," respectively, herein for additional information.
Taxes Other Than Income Taxes
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(6) | | (1.9) | | $120 | | 14.6 |
For year-to-date 2017, taxes other than income taxes were $941 million compared to $821 million for the corresponding period in 2016. The increase primarily reflects the inclusion of Southern Company Gas taxes for the nine-month period in 2017 compared to the three-month period subsequent to the Merger closing on July 1, 2016.
See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Estimated Loss on Kemper IGCC
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(54) | | (61.4) | | $2,933 | | N/M |
N/M - Not meaningful
Estimated probable losses on the Kemper IGCC of $34 million and $3.2 billion were recorded at Mississippi Power in the third quarter and year-to-date 2017, respectively, compared to $88 million and $222 million in the third quarter and year-to-date 2016, respectively. 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 IGCC Settlement Docket, 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. As a result, Mississippi Power suspended the project on June 28, 2017, and recorded $34 million and $2.9 billion of additional charges to income in the third quarter and year-to-date 2017, respectively, for the estimated costs associated with the gasification portions of the plant and lignite mine.
Prior to the project's suspension, Mississippi Power recorded losses for revisions of estimated costs expected to be incurred on construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (Initial DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (construction cost increase demonstrated to produce efficiencies that result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions).
See FUTURE EARNINGS POTENTIAL – "Construction Program – Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Allowance for Equity Funds Used During Construction
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(34) | | (65.4) | | $(17) | | (11.3) |
In the third quarter 2017, AFUDC equity was $18 million compared to $52 million in the corresponding period in 2016. For year-to-date 2017, AFUDC equity was $133 million compared to $150 million in the corresponding period in 2016. These decreases primarily resulted from Mississippi Power's suspension of the Kemper IGCC project in June 2017.
See FUTURE EARNINGS POTENTIAL – "Construction Program – Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Earnings from Equity Method Investments
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $3 | | 10.3 | | $72 | | N/M |
N/M - Not meaningful
In the third quarter 2017, earnings from equity method investments were $32 million compared to $29 million in the corresponding period in 2016. For year-to-date 2017, earnings from equity method investments were $100 million
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
compared to $28 million in the corresponding period in 2016. These increases were primarily related to Southern Company Gas' equity method investment in SNG in September 2016.
See Note 12 to the financial statements of Southern Company under "Southern Company – Investment in Southern Natural Gas" in Item 8 of the Form 10-K for additional information.
Interest Expense, Net of Amounts Capitalized
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $33 | | 8.8 | | $335 | | 36.7 |
In the third quarter 2017, interest expense, net of amounts capitalized was $407 million compared to $374 million in the corresponding period in 2016. The increase was primarily due to an increase in average outstanding long-term debt and a $16 million decrease in interest capitalized, partially offset by a net reduction of $33 million following Mississippi Power's settlement with the IRS related to research and experimental (R&E) deductions.
For year-to-date 2017, interest expense, net of amounts capitalized was $1.2 billion compared to $913 million in the corresponding period in 2016. The increase was primarily due to an increase in average outstanding long-term debt and a $31 million decrease in interest capitalized, partially offset by a net reduction of $33 million following Mississippi Power's settlement with the IRS related to R&E deductions. In addition, year-to-date 2017 includes an additional $106 million reflecting the nine-month period of interest expense for Southern Company Gas compared to the three-month period subsequent to the Merger closing on July 1, 2016.
See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Section 174 Research and Experimental Deduction" and Notes (E) and (G) to the Condensed Financial Statements herein for additional information.
Other Income (Expense), Net
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $19 | | N/M | | $68 | | N/M |
N/M - Not meaningful
In the third quarter 2017, other income (expense), net was $11 million compared to $(8) million for the corresponding period in 2016. For year-to-date 2017, other income (expense), net was $2 million compared to $(66) million for the corresponding period in 2016. These changes were primarily due to $14 million and $16 million from settlement of contractor litigation claims at Southern Company Gas in the third quarter and year-to-date 2017, respectively, and increases of $6 million and $10 million in customer contributions in aid of construction and contract service revenue at Georgia Power in the third quarter and year-to-date 2017, respectively. Additionally, the year-to-date change reflects $30 million of expenses incurred in 2016 associated with bridge financing for the Merger. These changes also include increases of $36 million and $152 million in currency losses arising from a translation of euro-denominated fixed-rate notes into U.S. dollars for the third 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
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $151 | | 34.4 | | $(600) | | (65.4) |
In the third quarter 2017, income taxes were $590 million compared to $439 million for the corresponding period in 2016. The increase was primarily due to a $61 million decrease in income tax benefits from solar ITCs at Southern Power, a $23 million increase in deferred income tax expenses associated with new State of Illinois tax legislation and new tax apportionment factors at Southern Company Gas, and a $21 million decrease in tax benefits related to estimated losses on the Kemper IGCC at Mississippi Power.
For year-to-date 2017, income taxes were $317 million compared to $917 million for the corresponding period in 2016. The decrease was primarily due to $866 million in tax benefits related to estimated losses on the Kemper IGCC at Mississippi Power, partially offset by a $226 million increase reflecting the nine-month period of income taxes at Southern Company Gas in 2017 compared to the three-month period subsequent to the Merger closing on July 1, 2016 and a $44 million net decrease in tax benefits from renewable tax credits at Southern Power.
See Notes (B), (G), and (I) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle," "Effective Tax Rate," and "Southern Company – Merger with Southern Company Gas," respectively, 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. Matters 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 the pace of economic growth that may be affected by changes in regional and global economic conditions, which may
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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.
Southern Power is considering the sale of up to a one-third equity interest in its solar asset portfolio. The ultimate outcome of this matter cannot be determined at this time.
On October 15, 2017, a wholly-owned subsidiary of Southern Company Gas entered into agreements for the sale of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion. As of September 30, 2017, the net book value of the assets to be disposed of in the sale was approximately $1.5 billion, which includes approximately $0.5 billion of goodwill. The goodwill is not deductible for tax purposes and as a result, a deferred tax liability has not yet been provided for goodwill. Through the completion of the sale, Southern Company Gas intends to invest approximately $0.1 billion in capital expenditures which are required for ordinary business operations. The completion of each sale is subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act; (ii) the receipt of required regulatory approvals, including the FERC, the Federal Communications Commission, the New Jersey BPU, and, with respect to the sale of Elkton Gas, the Maryland PSC; and (iii) other customary closing conditions. The sales are expected to be completed by the end of the third quarter 2018. The ultimate outcome of these matters cannot be determined at this time.
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.
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Environmental Statutes and Regulations
Air Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of 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. However, on August 2, 2017, the EPA issued a withdrawal notice of the one-year extension and reinstated the original October 1, 2017 designation deadline. 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.
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 September 18, 2017, the EPA published a final 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 October 16, 2017, the EPA published a proposed rule to repeal the Clean Power Plan. The EPA has not determined whether or when it will promulgate a replacement rule.
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.
Natural Gas Storage
A wholly-owned subsidiary of Southern Company Gas owns and operates a natural gas storage facility consisting of two salt dome caverns in Louisiana. Periodic integrity tests are required in accordance with rules of the Louisiana Department of Natural Resources (LDNR). In August 2017, in connection with an ongoing integrity project, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. At September 30, 2017, the facility's property, plant, and equipment had a net book value of $111 million, of which the cavern itself
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represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including the results of ongoing third-party technical engineering reviews, testing, and compliance with an order from the LDNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining a core sample to determine the composition of the sheath surrounding the edge of the salt dome. Early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. The ultimate outcome of this matter cannot be determined at this time, but could have a significant impact on Southern Company's financial statements.
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 related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' and Southern Power's June 30, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order, or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and Southern Power expect to make a filing within the specified 60 days responding to the FERC's order.
The ultimate outcome of these matters cannot be determined at this time.
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.
On October 13, 2017, the Atlantic Coast Pipeline project received FERC approval.
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 – 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
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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 nine months ended September 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.
In 2015, the Florida PSC approved Gulf Power's three energy purchase agreements totaling 120 MWs of utility-scale solar generation located at three military installations in northwest Florida. Purchases under these agreements began in the summer of 2017.
Mississippi Power placed in service three solar projects in January, June, and October 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 August 17, 2017, the Mississippi PSC approved Mississippi Power's CPCN for the construction, operation, and maintenance of a 52.5-MW solar energy generating facility, which 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.
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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.
Storm Damage Recovery
Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, for incremental operating and maintenance costs of damage from major storms to its transmission and distribution facilities. During September 2017, Hurricane Irma caused significant damage to Georgia Power's transmission and distribution facilities. The total amount of incremental restoration costs related to this hurricane is estimated to be approximately $150 million. As of September 30, 2017, Georgia Power had deferred approximately $145 million in a regulatory asset related to storm damage. As of September 30, 2017, the total balance in Georgia Power's regulatory asset related to storm damage was $360 million. The rate of storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case required to be filed by July 1, 2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's financial statements. See Note 3 to the financial statements of Southern Company under "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.
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. Among the terms of the 2017 Rate Case Settlement Agreement, Gulf Power increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consisted of a $62.0 million increase in annual base revenues less an annual 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.
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Southern Company Gas
Natural Gas Cost Recovery
Southern Company Gas has established natural gas cost recovery rates approved by the relevant state regulatory agencies in the states in which it serves. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. 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 in December 2017, after which rate adjustments will be effective. The ultimate outcome of this matter cannot be determined at this time.
Construction Program
Overview
The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue its strategy of developing and constructing new 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. Following Mississippi Power's suspension of the Kemper IGCC construction, 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). In August 2017, Georgia Power filed its seventeenth VCM report with the Georgia PSC, in which it recommended that construction of Plant Vogtle Units 3 and 4 be continued, with Southern Nuclear serving as project manager. Georgia Power believes that the most reasonable schedule for completing Plant Vogtle Units 3 and 4 is by November 2021 for Unit 3 and by November 2022 for Unit 4, at an additional cost of approximately $1.41 billion, net of the Guarantee Settlement Agreement. The Georgia PSC is expected to make a decision on these and other related matters by February 6, 2018. 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.
For additional information, see Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Nuclear Construction" and " – Southern Company Gas – Regulatory Infrastructure Programs" 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 " – Southern Company Gas–Regulatory Infrastructure Programs" and "Integrated Coal Gasification Combined Cycle" herein. Also 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.
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.
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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 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. 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 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. At September 30, 2017, the related regulatory liability totaled $7 million.
The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO2, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast has decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations has 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.
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.
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 IGCC Settlement Docket, 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 third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension,
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which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination 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 $34 million ($21 million after tax) for the third quarter 2017 and $3.2 billion ($2.2 billion after tax) for the nine months ended September 30, 2017. In the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $6.0 billion ($4.0 billion after tax) through September 30, 2017.
Mississippi Power reached and filed a settlement agreement on August 21, 2017 with certain parties (not including the MPUS), which it believes met the conditions of the Kemper Settlement Order. The settlement agreement provides for an annual revenue requirement of $126 million for Kemper IGCC-related costs, which would (i) be effective January 1, 2018, (ii) represent no rate increase for customers, and (iii) include no recovery for the costs associated with the gasifier portion of the Kemper IGCC in 2018 or at any future date. In addition, under the settlement agreement, the CPCN for the Kemper IGCC would be modified to limit the Kemper County energy facility to natural gas combined cycle operation and Mississippi Power would, in the future, file a reserve margin plan with the Mississippi PSC. The Mississippi PSC issued a scheduling order, as amended on October 5, 2017, noting Mississippi Power and the MPUS had failed to reach a joint stipulation and ordering a full hearing. The Mississippi PSC is expected to rule on an order resolving this matter in January 2018.
As of September 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 Cooperative Energy. 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
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Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the plaintiffs filed notice of an appeal.
On June 9, 2016, Treetop Midstream Services, LLC (Treetop) and other related parties filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint relates to the cancelled CO2 contract with Treetop and alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and seeks compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS 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 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. The Interim Assessment Agreement, as amended, expired on July 27, 2017.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor, including Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, 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 September 30, 2017, of the Vogtle Owners for the removal of subcontractor liens and payment of other EPC Contractor pre-petition accounts payable to total approximately $386 million, of which $340 million had been paid or accrued as of September 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $176 million.
On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into the Guarantee Settlement Agreement. Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation 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, which will reduce CWIP, 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 October 2, 2017, Georgia Power received the first installment of the Guarantee Obligations of $300 million from Toshiba, of which Georgia Power's proportionate share was $137 million. Georgia Power is considering potential options with respect to its right to future payments under the Guarantee Settlement Agreement and its claims against the EPC Contractor in the EPC Contractor's bankruptcy proceeding, including a potential sale of those payment rights and bankruptcy claims. Any such transaction cannot be assured and would be subject to DOE consents and related approvals under the Loan Guarantee Agreement and related agreements.
On August 10, 2017, Toshiba released its financial results for the quarter ended June 30, 2017, which reflected a negative shareholders' equity balance of approximately $4.5 billion as of June 30, 2017. Toshiba previously 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. 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.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into the Bechtel Agreement, whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4. Facility design and engineering remains the responsibility of the EPC Contractor under the Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. Pursuant to the Loan Guarantee Agreement, Georgia Power is required to obtain the DOE's approval of the Bechtel Agreement prior to obtaining any further advances under the Loan Guarantee Agreement.
In connection with the recommendation to continue with construction of Plant Vogtle Units 3 and 4 (described below), the Vogtle Owners agreed on a term sheet to amend the existing joint ownership agreements to provide for additional Vogtle Owner approval requirements. Under the term sheet, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including (i) the bankruptcy of Toshiba or a material breach by Toshiba of the Guarantee Settlement Agreement; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report by more than $1 billion or extension of the project schedule contained in the seventeenth VCM report by more than one year. In addition, under the term sheet, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Services Agreement or agreements with the primary construction contractor or Southern Nuclear.
The term sheet also confirms that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.
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 September 30, 2017, Georgia Power had recovered approximately $1.5 billion of financing costs. Georgia Power expects to file on November 1, 2017 to increase the NCCR tariff by approximately $90 million, effective January 1, 2018, pending Georgia PSC approval.
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
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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.
The Georgia PSC has approved sixteen VCM reports covering the periods through December 31, 2016, including construction capital costs incurred, which through that date totaled $3.9 billion. Georgia Power filed its seventeenth VCM report, covering the period from January 1 through June 30, 2017, requesting approval of $542 million of construction capital costs incurred during that period, with the Georgia PSC on August 31, 2017.
In the seventeenth VCM report, Georgia Power recommended that construction of Plant Vogtle Units 3 and 4 be continued, with Southern Nuclear serving as project manager. Georgia Power believes that the most reasonable schedule for completing Plant Vogtle Units 3 and 4 is by November 2021 for Unit 3 and by November 2022 for Unit 4. Georgia Power's recommendation to go forward with completion of Vogtle Units 3 and 4 is based on the following assumptions about the regulatory treatment of this recommendation, if the recommendation to go forward is adopted by the Georgia PSC: (i) that pursuant to Georgia law, the Georgia PSC in the seventeenth VCM proceeding approves the new cost and schedule forecast and finds that it is a reasonable basis for going forward, and that if the Georgia PSC disapproves all or part of the proposed cost and schedule revisions, Georgia Power may cancel Plant Vogtle Units 3 and 4 and recover its actual investment in Plant Vogtle Units 3 and 4; (ii) that the Vogtle Cost Settlement Agreement remains in full force and effect, including Georgia Power retaining the burden of proving all capital costs above $5.680 billion were prudent; (iii) that while the Georgia PSC will make no prudence finding in the seventeenth VCM proceeding, nor will the certified amount be amended consistent with the Vogtle Cost Settlement Agreement, the Georgia PSC recognizes that the certified amount is not a cap, and all costs that are approved and presumed or shown to be prudently incurred will be recoverable by Georgia Power; (iv) that Georgia Power is not a guarantor of the Toshiba Guarantee, and the failure of Toshiba to pay the Toshiba Guarantee, the failure of the U.S. Congress to extend the PTCs for Plant Vogtle Units 3 and 4, or the failure of the DOE to extend the Loan Guarantee Agreement with Georgia Power to reflect the increased capital amounts, will not reduce the amount of investment Georgia Power is otherwise allowed to collect; and (v) that as conditions change and assumptions are either proven or disproven, Georgia Power and the Georgia PSC may reconsider the decision to go forward. The Georgia PSC is expected to make a decision on these matters by February 6, 2018.
The ultimate outcome of these matters cannot be determined at this time.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Revised Cost and Schedule
Georgia Power's approximate proportionate share of the remaining estimated cost to complete Plant Vogtle Units 3 and 4 is as follows:
|
| | | |
| | (in billions) |
| Estimated cost to complete | $ | 4.2 |
|
| CWIP as of September 30, 2017 | 4.6 |
|
| Guarantee Obligations | (1.7 | ) |
| Estimated capital costs | $ | 7.1 |
|
| Vogtle Cost Settlement Agreement Revised Forecast | (5.7 | ) |
| Estimated net additional capital costs | $ | 1.4 |
|
Georgia Power's estimated financing costs during the construction period total approximately $3.4 billion, of which approximately $1.5 billion had been incurred through September 30, 2017.
Georgia Power's cancellation cost estimate results indicate that its proportionate share of the estimated costs to cancel both units is approximately $350 million. As a result, as of September 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:
|
| | | |
| | Cancellation Cost Estimate |
| | (in billions) |
| CWIP as of September 30, 2017 | $ | 4.6 |
|
| Financing costs collected, net of tax | 1.5 |
|
Cancellation costs(*) | 0.4 |
|
| Guarantee Obligations | (1.7 | ) |
| Estimated net cancellation cost | $ | 4.8 |
|
| |
(*) | 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.
The ultimate outcome of these matters cannot be determined at this time.
Other Matters
As of September 30, 2017, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through the Loan Guarantee Agreement and a multi-advance credit facility among Georgia Power, the DOE, and the FFB, which provides for borrowings of up to $3.46 billion, subject to the satisfaction of certain conditions. On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to the financial statements 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.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 while 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 while 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.
While construction continues, the risk remains that challenges with management of contractors, subcontractors, and vendors, 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
Excluding the Kemper IGCC, approximately $830 million of positive cash flows is expected to result from bonus depreciation for the 2017 tax year. All projected tax benefits previously received for bonus depreciation related to the Kemper IGCC were repaid in connection with third quarter 2017 estimated tax payments. If the suspension of the Kemper IGCC start-up activities ultimately results in an abandonment for income tax purposes, the related deduction would be claimed in the year of the abandonment. 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 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, which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation (JCT), resolving a methodology for these deductions. As a result of the JCT approval, Southern Company recognized $176 million of previously unrecognized tax benefits and reversed $36 million of associated accrued 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.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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Southern Power
During the third quarter 2017, Southern Power began a legal entity reorganization of various direct and indirect subsidiaries that own and operate solar facilities, including certain subsidiaries owned in partnership with various third parties. Southern Power's ownership interests in the various solar entities and facilities will not be affected by the reorganization. The reorganization is expected to result in estimated tax benefits totaling approximately $40 million that will be recorded in the fourth quarter 2017 related to certain changes in state apportionment rates and net operating loss carryforward utilization. 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 or regulatory matters 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'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, to which the plaintiffs filed an opposition on September 11, 2017.
On February 27, 2017, Jean Vineyard filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the defendants caused Southern Company to make false or misleading statements regarding the Kemper 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 and, on May 31, 2017, Judy Mesirov filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. Each
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
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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. Each 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. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. On August 15, 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia and the court deferred the consolidated case until 30 days after certain further action in the purported securities class action complaint discussed above.
Southern Company believes these legal challenges have no merit; however, an adverse outcome in any of these proceedings could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, the ultimate outcome of which cannot be determined at this time.
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 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
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
for the September 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 IGCC Settlement Docket, 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 third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred.
As of September 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 Cooperative Energy. 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 $6.00 billion ($3.96 billion after tax) through September 30, 2017. Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $34 million ($21 million after tax) and $88 million ($54 million after tax) in the third quarter 2017 and the third quarter 2016, respectively, and total pre-tax charges of $3.2 billion ($2.2 billion after tax) and $222 million ($137 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
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Southern Company in Item 7 of the Form 10-K for additional information.
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. Southern Company is evaluating the standard and expects to early adopt ASU 2017-04 effective January 1, 2018.
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. 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.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with early adoption permitted. Southern Company is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on Southern Company's financial statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company in Item 7 of the Form 10-K for additional information. Southern Company's financial condition remained stable at September 30, 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 $5.3 billion for the first nine months of 2017, an increase of $1.0 billion from the corresponding period in 2016. The increase in net cash provided from operating activities was primarily due to an increase of $1.5 billion in 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. Net cash used for investing activities totaled $6.7 billion for the first nine 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 renewable acquisitions. Net cash provided from financing activities totaled $1.3 billion for the first nine months of 2017 primarily due to net issuances of long-term and short-term debt, partially offset by 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 nine months of 2017 include an increase of $1.3 billion in total property, plant, and equipment primarily related to the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities, Southern Company Gas' infrastructure replacement programs, and Southern Power's renewable acquisitions, largely offset by the $2.9 billion write-down of the gasification portions of the Kemper IGCC; a decrease of $0.4 billion in income taxes receivable, current and unrecognized tax benefits primarily related to income tax refunds associated with deductible R&E expenditures; a decrease of $0.5 billion in acquisitions payable related to Southern Power; an increase of $2.3 billion in long-term debt (including amounts due within one year) primarily to fund the Southern Company system's continuous construction programs and for general corporate purposes; and a decrease of $0.7 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.
At the end of the third quarter 2017, the market price of Southern Company's common stock was $49.14 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $23.99 per share, representing a market-to-book 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 third quarter 2017 was $0.58 per share compared to $0.56 per share in the third 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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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, 2017, Alabama Power repaid at maturity $325 million aggregate principal amount of its Series Q 5.50% Senior Notes due October 15, 2017. An additional $3.2 billion will be required through September 30, 2018 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.
The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental 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 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. In addition, Southern Power plans to utilize tax equity partnership contributions. 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, in 2014, Georgia Power entered into the Loan Guarantee Agreement with the DOE, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4. Under the Loan Guarantee Agreement, the DOE agreed to guarantee borrowings of up to $3.46 billion (not to exceed 70% of (i) Eligible Project Costs, less (ii) amounts received from Toshiba under the Guarantee Settlement Agreement and amounts received from the Westinghouse bankruptcy proceeding) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. As of September 30, 2017, Georgia Power had borrowed $2.6 billion under the FFB Credit Facility. On July 27, 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement, which provides that further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement and satisfaction of certain other conditions.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion of additional guaranteed loans under the Loan Guarantee Agreement. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to the financial statements 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 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 September 30, 2017, Southern Company's current liabilities exceeded current assets by $3.4 billion due to long-term debt that is due within one year of $3.5 billion (comprised of approximately $1.0 billion at the parent company, $0.3 billion at Alabama Power, $0.3 billion at Georgia Power, $1.0 billion at Mississippi Power, and $0.9 billion at Southern Power) and notes payable of $2.6 billion (comprised of approximately $1.1 billion at the parent company, $0.4 billion at Georgia Power, $0.1 billion at Southern Power, and $0.9 billion at Southern Company Gas). To meet short-term cash needs and contingencies, the Southern Company system has substantial cash flow from operating activities and access to capital markets and financial institutions. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas intend to utilize operating cash flows, as well as commercial paper, lines of credit, bank notes, and securities issuances, as market conditions permit, as well as, under certain circumstances for the traditional electric operating companies, Southern Power, and Southern Company Gas, equity contributions and/or loans from Southern Company to meet their short-term capital needs.
At September 30, 2017, Southern Company and its subsidiaries had approximately $1.8 billion of cash and cash equivalents. Committed credit arrangements with banks at September 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 | — |
| 35 |
| — |
| 500 |
| 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 | 100 |
| — |
| — |
| — |
| — |
| | 100 |
| | 100 |
| | — |
| | — |
| | — |
| | 100 |
|
Southern Power Company(b) | — |
| — |
| — |
| — |
| 750 |
| | 750 |
| | 728 |
| | — |
| | — |
| | — |
| | — |
|
Southern Company Gas(c) | — |
| — |
| — |
| — |
| 1,900 |
| | 1,900 |
| | 1,861 |
| | — |
| | — |
| | — |
| | — |
|
| Other | — |
| 30 |
| — |
| — |
| — |
| | 30 |
| | 30 |
| | 20 |
| | — |
| | 20 |
| | 10 |
|
| Southern Company Consolidated | $ | 130 |
| $ | 260 |
| $ | 25 |
| $ | 530 |
| $ | 7,200 |
| | $ | 8,145 |
| | $ | 8,066 |
| | $ | 65 |
| | $ | — |
| | $ | 20 |
| | $ | 185 |
|
| |
(a) | Represents the Southern Company parent entity. |
| |
(b) | Does not include Southern Power's $120 million continuing letter of credit facility for standby letters of credit expiring in 2019, of which $111 million has been used for letters of credit and $9 million remains unused at September 30, 2017.
|
| |
(c) | 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.
|
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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. Pursuant to the new multi-year credit arrangement, the allocations may be adjusted. In September 2017, Alabama Power amended its $500 million multi-year credit arrangement, which, among other things, extended the maturity date from 2018 to 2020.
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 September 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 September 30, 2017 was approximately $1.5 billion as compared to $1.9 billion at December 31, 2016. 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 September 30, 2017, the traditional electric operating companies had approximately $699 million of pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to September 30, 2017, $40 million of these pollution control revenue bonds of Georgia Power which were in an index rate mode were remarketed to the public in a long-term fixed rate mode.
Southern Company, the traditional electric operating companies (other than Mississippi Power), Southern Power Company, Southern Company Gas, and Nicor Gas make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Short-term borrowings are included in notes payable in the balance sheets.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of short-term borrowings were as follows:
|
| | | | | | | | | | | | | | | | | | |
| | | Short-term Debt at September 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 | | $ | 1,725 |
| | 1.5 | % | | $ | 1,895 |
| | 1.5 | % | | $ | 2,284 |
|
| Short-term bank debt | | 854 |
| | 2.0 | % | | 938 |
| | 2.1 | % | | 1,017 |
|
| Total | | $ | 2,579 |
| | 1.7 | % | | $ | 2,833 |
| | 1.7 | % | | |
| |
(*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 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 September 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, transmission, and interest rate management.
The maximum potential collateral requirements under these contracts at September 30, 2017 were as follows:
|
| | | |
| Credit Ratings | Maximum Potential
Collateral
Requirements |
| | (in millions) |
| At BBB and/or Baa2 | $ | 38 |
|
| At BBB- and/or Baa3 | $ | 647 |
|
At BB+ and/or Ba1(*) | $ | 2,352 |
|
| |
(*) | 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. On September 21, 2017, Moody's revised its rating outlook for Mississippi Power from under review to stable.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Financing Activities
During the first nine months of 2017, Southern Company issued approximately 10.6 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $479 million.
In addition, during the second and third quarters of 2017, Southern Company issued a total of approximately 2.7 million shares of common stock through at-the-market issuances pursuant to sales agency agreements related to Southern Company's continuous equity offering program and received cash proceeds of approximately $134 million, net of $1.1 million in fees and commissions.
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first nine 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 |
| | $ | 400 |
| | $ | — |
| | $ | 500 |
| | $ | 400 |
|
| Alabama Power | 550 |
| | 200 |
| | 36 |
| | — |
| | — |
|
| Georgia Power | 1,350 |
| | 450 |
| | 65 |
| | 370 |
| | 13 |
|
| Gulf Power | 300 |
| | 85 |
| | — |
| | 6 |
| | — |
|
| Mississippi Power | — |
| | — |
| | — |
| | 40 |
| | 893 |
|
| Southern Power | — |
| | — |
| | — |
| | 43 |
| | 4 |
|
Southern Company Gas(c) | 450 |
| | — |
| | — |
| | 200 |
| | 22 |
|
| Other | — |
| | — |
| | — |
| | — |
| | 12 |
|
Elimination(d) | — |
| | — |
| | — |
| | (40 | ) | | (599 | ) |
| Southern Company Consolidated | $ | 2,950 |
| | $ | 1,135 |
| | $ | 101 |
| | $ | 1,119 |
| | $ | 745 |
|
| |
(a) | Includes reductions in capital lease obligations resulting from cash payments under capital leases. |
| |
(b) | Represents the Southern Company parent entity. |
| |
(c) | The senior notes were issued by Southern Company Gas Capital and guaranteed by the Southern Company Gas parent entity. Other long-term debt issued represents first mortgage bonds issued by Nicor Gas.
|
| |
(d) | Includes intercompany loans from Southern Company to Mississippi Power and reductions in affiliate capital lease obligations at Georgia Power. These transactions are eliminated in Southern Company's Consolidated Financial Statements. |
In March 2017, Southern Company repaid at maturity a $400 million 18-month floating rate bank loan.
In June 2017, Southern Company issued $500 million aggregate principal amount of Series 2017A 5.325% Junior Subordinated Notes due June 21, 2057 and $300 million aggregate principal amount of Series 2017A Floating Rate Senior Notes due September 30, 2020, which bear interest at a floating rate based on three-month LIBOR. 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.
In August 2017, Southern Company borrowed $250 million pursuant to an uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Southern Company and the bank from time to time and is payable on no less than 30 days' demand by the bank. The proceeds were used for working capital and other general corporate purposes.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Also in August 2017, Southern Company repaid at maturity $400 million aggregate principal amount of Series 2014A 1.30% Senior Notes.
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.
In September 2017, Alabama Power issued 10 million shares ($250 million aggregate stated capital) of 5.00% Class A Preferred Stock, Cumulative, Par Value $1 Per Share (Stated Capital $25 Per Share). The proceeds were used in October 2017 to redeem all 2 million shares ($50 million aggregate stated capital) of Alabama Power's 6.50% Series Preference Stock, 6 million shares ($150 million aggregate stated capital) of Alabama Power's 6.45% Series Preference Stock, and 1.52 million shares ($38 million aggregate stated capital) of Alabama Power's 5.83% Class A Preferred Stock and for other general corporate purposes, including Alabama Power's continuous construction program.
Subsequent to September 30, 2017, Alabama Power repaid at maturity $325 million aggregate principal amount of Series Q 5.50% Senior Notes due October 15, 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, with maturity dates of December 1, 2017, May 31, 2018, and June 28, 2018, respectively, which 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 August 2017, Georgia Power repaid its $50 million floating rate bank loan due December 1, 2017 and $250 million of the $500 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement. Also in August 2017, Georgia Power amended its $100 million floating rate bank loan to extend the maturity date from June 28, 2018 to October 26, 2018.
As reflected in the table above under other long-term debt issuances, in September 2017, Georgia Power issued $270 million aggregate principal amount of Series 2017A 5.00% Junior Subordinated Notes due October 1, 2077. The proceeds were used in October 2017 to redeem all 1.8 million shares ($45 million aggregate liquidation amount) of Georgia Power's 6.125% Series Class A Preferred Stock and 2.25 million shares ($225 million aggregate liquidation amount) of Georgia Power's 6.50% Series 2007A Preference Stock.
In March 2017, Gulf Power extended the maturity of 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.
A portion of the proceeds of Gulf Power's senior note issuances was used in June 2017 to redeem 550,000 shares ($55 million aggregate liquidation amount) of Gulf Power's 6.00% Series Preference Stock, 450,000 shares ($45 million aggregate liquidation amount) of Gulf Power's Series 2007A 6.45% Preference Stock, and 500,000 shares ($50 million aggregate liquidation amount) of Gulf Power's Series 2013A 5.60% Preference Stock.
In June 2017, Mississippi Power prepaid $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018.
In September 2017, Southern Power amended its $60 million aggregate principal amount floating rate bank loan to, among other things, increase the aggregate principal amount to $100 million and extend the maturity date from September 2017 to October 2018. The additional $40 million of proceeds were used to repay existing indebtedness and for other general corporate purposes.
In July 2017, Nicor Gas agreed to issue $400 million aggregate principal amount of first mortgage bonds in a private placement. On August 10, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.03% Series due August 10, 2027 and $100 million aggregate principal amount of First Mortgage
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Bonds 3.62% Series due August 10, 2037. The proceeds were used to repay short-term indebtedness incurred under the Nicor Gas commercial paper program and for other working capital needs. The remaining $200 million is expected to be issued in 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 nine months ended September 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 third 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 September 30, | | For the Nine Months Ended September 30, | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2017 | | 2016 | | 2017 | | 2016 | 2020 | | 2019 | | 2020 | | 2019 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | | | | | | | | |
| Retail revenues | $ | 1,595 |
| | $ | 1,629 |
| | $ | 4,155 |
| | $ | 4,139 |
| $ | 1,223 |
| | $ | 1,378 |
| | $ | 2,427 |
| | $ | 2,592 |
|
| Wholesale revenues, non-affiliates | 77 |
| | 82 |
| | 210 |
| | 211 |
| 54 |
| | 62 |
| | 111 |
| | 123 |
|
| Wholesale revenues, affiliates | 18 |
| | 18 |
| | 83 |
| | 49 |
| 7 |
| | 4 |
| | 26 |
| | 63 |
|
| Other revenues | 50 |
| | 56 |
| | 158 |
| | 162 |
| 81 |
| | 69 |
| | 152 |
| | 143 |
|
| Total operating revenues | 1,740 |
| | 1,785 |
| | 4,606 |
| | 4,561 |
| 1,365 |
| | 1,513 |
| | 2,716 |
| | 2,921 |
|
| Operating Expenses: | | | | | | | | | | | | | | |
| Fuel | 343 |
| | 410 |
| | 944 |
| | 973 |
| 199 |
| | 252 |
| | 415 |
| | 553 |
|
| Purchased power, non-affiliates | 57 |
| | 63 |
| | 132 |
| | 139 |
| 49 |
| | 47 |
| | 89 |
| | 84 |
|
| Purchased power, affiliates | 55 |
| | 41 |
| | 117 |
| | 129 |
| 30 |
| | 69 |
| | 49 |
| | 90 |
|
| Other operations and maintenance | 391 |
| | 348 |
| | 1,134 |
| | 1,097 |
| 342 |
| | 402 |
| | 690 |
| | 812 |
|
| Depreciation and amortization | 185 |
| | 177 |
| | 549 |
| | 524 |
| 202 |
| | 200 |
| | 402 |
| | 399 |
|
| Taxes other than income taxes | 93 |
| | 96 |
| | 284 |
| | 286 |
| 102 |
| | 98 |
| | 208 |
| | 200 |
|
| Total operating expenses | 1,124 |
| | 1,135 |
| | 3,160 |
| | 3,148 |
| 924 |
| | 1,068 |
| | 1,853 |
| | 2,138 |
|
| Operating Income | 616 |
| | 650 |
| | 1,446 |
| | 1,413 |
| 441 |
| | 445 |
| | 863 |
| | 783 |
|
| Other Income and (Expense): | | | | | | | | | | | | | | |
| Allowance for equity funds used during construction | 11 |
| | 7 |
| | 27 |
| | 23 |
| 11 |
| | 14 |
| | 22 |
| | 28 |
|
| Interest expense, net of amounts capitalized | (76 | ) | | (77 | ) | | (229 | ) | | (224 | ) | (83 | ) | | (82 | ) | | (171 | ) | | (165 | ) |
| Other income (expense), net | (5 | ) | | (5 | ) | | (8 | ) | | (16 | ) | 26 |
| | 11 |
| | 48 |
| | 25 |
|
| Total other income and (expense) | (70 | ) | | (75 | ) | | (210 | ) | | (217 | ) | (46 | ) | | (57 | ) | | (101 | ) | | (112 | ) |
| Earnings Before Income Taxes | 546 |
| | 575 |
| | 1,236 |
| | 1,196 |
| 395 |
| | 388 |
| | 762 |
| | 671 |
|
| Income taxes | 216 |
| | 219 |
| | 493 |
| | 462 |
| 93 |
| | 89 |
| | 177 |
| | 151 |
|
| Net Income | 330 |
| | 356 |
| | 743 |
| | 734 |
| 302 |
| | 299 |
| | 585 |
| | 520 |
|
| Dividends on Preferred and Preference Stock | 5 |
| | 4 |
| | 14 |
| | 13 |
| |
| Net Income After Dividends on Preferred and Preference Stock | $ | 325 |
| | $ | 352 |
| | $ | 729 |
| | $ | 721 |
| |
| Dividends on Preferred Stock | | 4 |
| | 3 |
| | 7 |
| | 7 |
|
| Net Income After Dividends on Preferred Stock | | $ | 298 |
| | $ | 296 |
| | $ | 578 |
| | $ | 513 |
|
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, |
| | 2017 | | 2016 | | 2017 | | 2016 | 2020 | | 2019 | | 2020 | | 2019 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Net Income | $ | 330 |
| | $ | 356 |
| | $ | 743 |
| | $ | 734 |
| $ | 302 |
| | $ | 299 |
| | $ | 585 |
| | $ | 520 |
|
| 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, $2, and $2, respectively | 1 |
| | 1 |
| | 3 |
| | 3 |
| |
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 |
| | 1 |
| | 3 |
| | 1 |
| 1 |
| | 1 |
| | 2 |
| | 2 |
|
| Comprehensive Income | $ | 331 |
| | $ | 357 |
| | $ | 746 |
| | $ | 735 |
| $ | 303 |
| | $ | 300 |
| | $ | 587 |
| | $ | 522 |
|
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, |
| | 2017 | | 2016 | 2020 | | 2019 |
| | (in millions) | (in millions) |
| Operating Activities: | | | | | | |
| Net income | $ | 743 |
| | $ | 734 |
| $ | 585 |
| | $ | 520 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | | | | |
| Depreciation and amortization, total | 666 |
| | 634 |
| 484 |
| | 493 |
|
| Deferred income taxes | 260 |
| | 267 |
| 38 |
| | 138 |
|
| Allowance for equity funds used during construction | (27 | ) | | (23 | ) | (22 | ) | | (28 | ) |
| Pension, postretirement, and other employee benefits | (4 | ) | | (14 | ) | (50 | ) | | (13 | ) |
| Settlement of asset retirement obligations | | (100 | ) | | (43 | ) |
| Other, net | 43 |
| | (12 | ) | 45 |
| | (1 | ) |
| Changes in certain current assets and liabilities — | | | | | | |
| -Receivables | (163 | ) | | (4 | ) | |
| -Fossil fuel stock | 34 |
| | 18 |
| |
| -Prepayments | | (62 | ) | | (59 | ) |
| -Materials and supplies | | (38 | ) | | 5 |
|
| -Other current assets | (58 | ) | | (46 | ) | (65 | ) | | (4 | ) |
| -Accounts payable | (125 | ) | | (113 | ) | (232 | ) | | (246 | ) |
| -Accrued taxes | 159 |
| | 207 |
| 197 |
| | 8 |
|
| -Accrued compensation | (48 | ) | | (22 | ) | (75 | ) | | (88 | ) |
| -Retail fuel cost over recovery | (76 | ) | | (104 | ) | 66 |
| | — |
|
| -Customer refunds | | (64 | ) | | (1 | ) |
| -Other current liabilities | 7 |
| | 19 |
| (33 | ) | | 14 |
|
| Net cash provided from operating activities | 1,411 |
| | 1,541 |
| 674 |
| | 695 |
|
| Investing Activities: | | | | | | |
| Property additions | (1,211 | ) | | (947 | ) | (686 | ) | | (833 | ) |
| Nuclear decommissioning trust fund purchases | (174 | ) | | (275 | ) | (160 | ) | | (139 | ) |
| Nuclear decommissioning trust fund sales | 174 |
| | 275 |
| 160 |
| | 139 |
|
| Cost of removal, net of salvage | (82 | ) | | (70 | ) | (29 | ) | | (48 | ) |
| Change in construction payables | 105 |
| | (37 | ) | (53 | ) | | (103 | ) |
| Other investing activities | (29 | ) | | (28 | ) | (15 | ) | | (18 | ) |
| Net cash used for investing activities | (1,217 | ) | | (1,082 | ) | (783 | ) | | (1,002 | ) |
| Financing Activities: | | | | | | |
| Proceeds — | | | | | | |
| Senior notes | 550 |
| | 400 |
| |
| Capital contributions from parent company | 337 |
| | 253 |
| 610 |
| | 1,254 |
|
| Preferred stock | 250 |
| | — |
| |
| Other long-term debt | — |
| | 45 |
| |
| Pollution control revenue bonds | | 87 |
| | — |
|
| Redemptions — |
|
| |
| | | |
| Pollution control revenue bonds | (36 | ) | | — |
| (87 | ) | | — |
|
| Senior notes | (200 | ) | | (200 | ) | — |
| | (200 | ) |
| Payment of common stock dividends | (536 | ) | | (574 | ) | (479 | ) | | (422 | ) |
| Other financing activities | (26 | ) | | (21 | ) | (15 | ) | | (15 | ) |
| Net cash provided from (used for) financing activities | 339 |
| | (97 | ) | |
| Net Change in Cash and Cash Equivalents | 533 |
| | 362 |
| |
| Cash and Cash Equivalents at Beginning of Period | 420 |
| | 194 |
| |
| Cash and Cash Equivalents at End of Period | $ | 953 |
| | $ | 556 |
| |
| Net cash provided from financing activities | | 116 |
| | 617 |
|
| Net Change in Cash, Cash Equivalents, and Restricted Cash | | 7 |
| | 310 |
|
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | | 894 |
| | 313 |
|
| Cash, Cash Equivalents, and Restricted Cash at End of Period | | $ | 901 |
| | $ | 623 |
|
| Supplemental Cash Flow Information: | | | | | | |
| Cash paid (received) during the period for — | | | | |
| Interest (net of $10 and $8 capitalized for 2017 and 2016, respectively) | $ | 217 |
| | $ | 215 |
| |
| Cash paid during the period for — | | | | |
| Interest (net of $7 and $10 capitalized for 2020 and 2019, respectively) | | $ | 161 |
| | $ | 154 |
|
| Income taxes, net | 146 |
| | (70 | ) | — |
| | 63 |
|
| Noncash transactions — Accrued property additions at end of period | 189 |
| | 84 |
| |
| Noncash transactions — | | | | |
| Accrued property additions at end of period | | 147 |
| | 168 |
|
| Right-of-use assets obtained under operating leases | | 2 |
| | 5 |
|
| Right-of-use assets obtained under finance leases | | 1 |
| | 1 |
|
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, 2017 | | At December 31, 2016 | | At June 30, 2020 | | At December 31, 2019 |
| | | (in millions) | | (in millions) |
| Current Assets: | | | | | | | | |
| Cash and cash equivalents | | $ | 953 |
| | $ | 420 |
| | $ | 901 |
| | $ | 894 |
|
| Receivables — | | | | | | | | |
| Customer accounts receivable | | 428 |
| | 348 |
| | 407 |
| | 425 |
|
| Unbilled revenues | | 149 |
| | 146 |
| | 153 |
| | 134 |
|
| Affiliated | | | 37 |
| | 37 |
|
| Other accounts and notes receivable | | 47 |
| | 27 |
| | 51 |
| | 72 |
|
| Affiliated | | 45 |
| | 40 |
| |
| Accumulated provision for uncollectible accounts | | (8 | ) | | (10 | ) | | (21 | ) | | (22 | ) |
| Fossil fuel stock | | 171 |
| | 205 |
| | 250 |
| | 212 |
|
| Materials and supplies | | 455 |
| | 435 |
| | 545 |
| | 512 |
|
| Prepaid expenses | | 58 |
| | 34 |
| | 101 |
| | 50 |
|
| Other regulatory assets, current | | 122 |
| | 149 |
| |
| Other regulatory assets | | | 226 |
| | 242 |
|
| Other current assets | | 5 |
| | 11 |
| | 55 |
| | 30 |
|
| Total current assets | | 2,425 |
| | 1,805 |
| | 2,705 |
| | 2,586 |
|
| Property, Plant, and Equipment: | | | | | | | | |
| In service | | 26,619 |
| | 26,031 |
| | 30,619 |
| | 30,023 |
|
| Less: Accumulated provision for depreciation | | 9,463 |
| | 9,112 |
| | 9,647 |
| | 9,540 |
|
| Plant in service, net of depreciation | | 17,156 |
| | 16,919 |
| | 20,972 |
| | 20,483 |
|
| Nuclear fuel, at amortized cost | | 314 |
| | 336 |
| | 275 |
| | 296 |
|
| Construction work in progress | | 928 |
| | 491 |
| | 830 |
| | 890 |
|
| Total property, plant, and equipment | | 18,398 |
| | 17,746 |
| | 22,077 |
| | 21,669 |
|
| Other Property and Investments: | | | | | | | | |
| Equity investments in unconsolidated subsidiaries | | 65 |
| | 66 |
| | 63 |
| | 66 |
|
| Nuclear decommissioning trusts, at fair value | | 869 |
| | 792 |
| | 978 |
| | 1,023 |
|
| Miscellaneous property and investments | | 121 |
| | 112 |
| | 131 |
| | 128 |
|
| Total other property and investments | | 1,055 |
| | 970 |
| | 1,172 |
| | 1,217 |
|
| Deferred Charges and Other Assets: | | | | | | | | |
| Operating lease right-of-use assets, net of amortization | | | 113 |
| | 132 |
|
| Deferred charges related to income taxes | | 525 |
| | 525 |
| | 243 |
| | 244 |
|
| Deferred under recovered regulatory clause revenues | | 17 |
| | 150 |
| | 41 |
| | 40 |
|
| Regulatory assets – asset retirement obligations | | | 1,491 |
| | 1,019 |
|
| Other regulatory assets, deferred | | 1,191 |
| | 1,157 |
| | 1,922 |
| | 1,976 |
|
| Other deferred charges and assets | | 178 |
| | 163 |
| | 362 |
| | 269 |
|
| Total deferred charges and other assets | | 1,911 |
| | 1,995 |
| | 4,172 |
| | 3,680 |
|
| Total Assets | | $ | 23,789 |
| | $ | 22,516 |
| | $ | 30,126 |
| | $ | 29,152 |
|
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, 2017 | | At December 31, 2016 | | At June 30, 2020 | | At December 31, 2019 |
| | | (in millions) | | (in millions) |
| Current Liabilities: | | | | | | | | |
| Securities due within one year | | $ | 325 |
| | $ | 561 |
| | $ | 496 |
| | $ | 251 |
|
| Accounts payable — | | | | | | | | |
| Affiliated | | 275 |
| | 297 |
| | 261 |
| | 316 |
|
| Other | | 376 |
| | 433 |
| | 312 |
| | 514 |
|
| Customer deposits | | 92 |
| | 88 |
| | 103 |
| | 100 |
|
| Accrued taxes — | | | | | |
| Accrued income taxes | | 115 |
| | 45 |
| |
| Other accrued taxes | | 128 |
| | 42 |
| |
| Accrued taxes | | | 274 |
| | 78 |
|
| Accrued interest | | 75 |
| | 78 |
| | 93 |
| | 92 |
|
| Accrued compensation | | 151 |
| | 193 |
| | 156 |
| | 216 |
|
| Other regulatory liabilities, current | | 4 |
| | 85 |
| |
| Asset retirement obligations | | | 254 |
| | 195 |
|
| Other regulatory liabilities | | | 73 |
| | 193 |
|
| Other current liabilities | | 50 |
| | 76 |
| | 101 |
| | 105 |
|
| Total current liabilities | | 1,591 |
| | 1,898 |
| | 2,123 |
| | 2,060 |
|
| Long-term Debt | | 7,083 |
| | 6,535 |
| | 8,028 |
| | 8,270 |
|
| Deferred Credits and Other Liabilities: | | | | | | | | |
| Accumulated deferred income taxes | | 4,919 |
| | 4,654 |
| | 3,325 |
| | 3,260 |
|
| Deferred credits related to income taxes | | 60 |
| | 65 |
| | 1,932 |
| | 1,960 |
|
| Accumulated deferred ITCs | | 118 |
| | 110 |
| | 97 |
| | 100 |
|
| Employee benefit obligations | | 289 |
| | 300 |
| | 200 |
| | 206 |
|
| Asset retirement obligations | | 1,564 |
| | 1,503 |
| |
| Operating lease obligations | | | 91 |
| | 107 |
|
| Asset retirement obligations, deferred | | | 3,722 |
| | 3,345 |
|
| Other cost of removal obligations | | 630 |
| | 684 |
| | 392 |
| | 412 |
|
| Other regulatory liabilities, deferred | | 93 |
| | 100 |
| | 217 |
| | 146 |
|
| Other deferred credits and liabilities | | 51 |
| | 63 |
| | 38 |
| | 40 |
|
| Total deferred credits and other liabilities | | 7,724 |
| | 7,479 |
| | 10,014 |
| | 9,576 |
|
| Total Liabilities | | 16,398 |
| | 15,912 |
| | 20,165 |
| | 19,906 |
|
| Redeemable Preferred Stock | | 329 |
| | 85 |
| | 291 |
| | 291 |
|
| 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 | | 2,961 |
| | 2,613 |
| |
| Retained earnings | | 2,711 |
| | 2,518 |
| |
| Accumulated other comprehensive loss | | (28 | ) | | (30 | ) | |
| Total common stockholder's equity | | 6,866 |
| | 6,323 |
| |
Common Stockholder's Equity (See accompanying statements) | | | 9,670 |
| | 8,955 |
|
| Total Liabilities and Stockholder's Equity | | $ | 23,789 |
| | $ | 22,516 |
| | $ | 30,126 |
| | $ | 29,152 |
|
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 ANALYSISCONDENSED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY (UNAUDITED)
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
| | | | | | | | | | | | | | | | | | | | | | |
| | Number of
Common
Shares
Issued | | Common
Stock | | Paid-In
Capital | | Retained
Earnings | | Accumulated
Other
Comprehensive
Income (Loss) | | Total |
| | (in millions) |
| Balance at December 31, 2018 | 31 |
| | $ | 1,222 |
| | $ | 3,508 |
| | $ | 2,775 |
| | $ | (28 | ) | | $ | 7,477 |
|
Net income after dividends on
preferred stock | — |
| | — |
| | — |
| | 217 |
| | — |
| | 217 |
|
| Capital contributions from parent company | — |
| | — |
| | 1,236 |
| | — |
| | — |
| | 1,236 |
|
| Other comprehensive income | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
| Cash dividends on common stock | — |
| | — |
| | — |
| | (211 | ) | | — |
| | (211 | ) |
| Balance at March 31, 2019 | 31 |
| | 1,222 |
| | 4,744 |
| | 2,781 |
| | (27 | ) | | 8,720 |
|
Net income after dividends on
preferred stock | — |
| | — |
| | — |
| | 296 |
| | — |
| | 296 |
|
| Capital contributions from parent company | — |
| | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
| Other comprehensive income | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
| Cash dividends on common stock | — |
| | — |
| | — |
| | (211 | ) | | — |
| | (211 | ) |
| Balance at June 30, 2019 | 31 |
| | $ | 1,222 |
| | $ | 4,767 |
| | $ | 2,866 |
| | $ | (26 | ) | | $ | 8,829 |
|
| | | | | | | | | | | | |
| Balance at December 31, 2019 | 31 |
| | $ | 1,222 |
| | $ | 4,755 |
| | $ | 3,001 |
| | $ | (23 | ) | | $ | 8,955 |
|
Net income after dividends on
preferred stock | — |
| | — |
| | — |
| | 280 |
| | — |
| | 280 |
|
| Capital contributions from parent company | — |
| | — |
| | 612 |
| | — |
| | — |
| | 612 |
|
| Other comprehensive income | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
| Cash dividends on common stock | — |
| | — |
| | — |
| | (239 | ) | | — |
| | (239 | ) |
| Balance at March 31, 2020 | 31 |
| | 1,222 |
| | 5,367 |
| | 3,042 |
| | (22 | ) | | 9,609 |
|
Net income after dividends on
preferred stock | — |
| | — |
| | — |
| | 298 |
| | — |
| | 298 |
|
| Capital contributions from parent company | — |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
| Other comprehensive income | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
| Cash dividends on common stock | — |
| | — |
| | — |
| | (239 | ) | | — |
| | (239 | ) |
| Balance at June 30, 2020 | 31 |
| | $ | 1,222 |
| | $ | 5,368 |
| | $ | 3,101 |
| | $ | (21 | ) | | $ | 9,670 |
|
THIRD QUARTER 2017 vs. THIRD QUARTER 2016
AND
YEAR-TO-DATE 2017 vs. YEAR-TO-DATE 2016
OVERVIEW
The accompanying notes as they relate to Alabama Power operates as a vertically integrated utility providing electric service to retail and wholesale customers within its traditional service territory located in the Stateare an integral part of Alabama in addition to wholesale customers in the Southeast.these condensed financial statements.
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
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) |
| (% change) |
| (change in millions) |
| (% change) |
| $(27) | | (7.7) | | $8 | | 1.1 |
Alabama Power's net income after dividends on preferred and preference stock for the third quarter 2017 was $325 million compared to $352 million for the corresponding period in 2016. The decrease was primarily related to a decrease in retail revenues associated with milder weather and lower customer usage in the third quarter 2017 compared to the corresponding period in 2016 and an increase in non-fuel operations and maintenance expenses. The decrease was partially offset by an increase in rates under Rate RSE effective January 1, 2017.
Alabama Power's net income after dividends on preferred and preference stock for year-to-date 2017 was $729 million compared to $721 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 retail revenues associated with milder weather and lower customer usage for year-to-date 2017 compared to the corresponding period in 2016, and an increase in non-fuel operations and maintenance expenses.
Retail Revenues
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(34) | | (2.1) | | $16 | | 0.4 |
In the third quarter 2017, retail revenues were $1.60 billion compared to $1.63 billion for the corresponding period in 2016. For year-to-date 2017, retail revenues were $4.16 billion compared to $4.14 billion for the corresponding period in 2016.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of the changes in retail revenues were as follows:
|
| | | | | | | | | | | | | |
| | Third Quarter 2017 |
| Year-to-Date 2017 |
| | (in millions) |
| (% change) |
| (in millions) |
| (% change) |
| Retail – prior year | $ | 1,629 |
| | | | $ | 4,139 |
| | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 85 |
| | 5.2 |
| | 240 |
| | 5.8 |
|
| Sales decline | (18 | ) | | (1.1 | ) | | (31 | ) | | (0.7 | ) |
| Weather | (50 | ) | | (3.1 | ) | | (116 | ) | | (2.8 | ) |
| Fuel and other cost recovery | (51 | ) | | (3.1 | ) | | (77 | ) | | (1.9 | ) |
| Retail – current year | $ | 1,595 |
| | (2.1 | )% | | $ | 4,155 |
| �� | 0.4 | % |
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016 primarily due to an increase in rates under Rate RSE effective January 1, 2017. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016. Weather-adjusted residential KWH sales decreased 2.4% and 1.1% for the third quarter and year-to-date 2017, respectively, primarily due to lower customer usage resulting from an increase in penetration of energy efficient residential appliances, partially offset by customer growth. Weather-adjusted commercial KWH sales decreased 2.3% and 1.4% for the third quarter and year-to-date 2017, respectively, primarily due to lower customer usage resulting from customer initiatives in energy savings and an ongoing migration to the electronic commerce business model, partially offset by customer growth. Industrial KWH sales increased 1.8% and 0.6% for the third quarter and year-to-date 2017, respectively, as a result of an increase in demand resulting from changes in production levels primarily in the primary metals, chemicals, and mining sectors, partially offset by a decrease in demand from the pipeline sector.
Revenues resulting from changes in weather decreased in the third 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 third quarter 2017, the resulting decreases were 5.1% and 2.4% for residential and commercial sales revenues, respectively. For year-to-date 2017, the resulting decreases were 5.2% and 1.8% for residential and commercial sales revenues, respectively.
Fuel and other cost recovery revenues decreased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016 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.
Wholesale Revenues – Affiliates
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $— | | — | | $34 | | 69.4 |
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
marginal cost and energy purchases are generally offset by energy revenues through Alabama Power's energy cost recovery clauses.
For year-to-date 2017, wholesale revenues from sales to affiliates were $83 million compared to $49 million for the corresponding period in 2016. The increase was primarily due to a 52% increase in KWH sales as a result of supporting Southern Company system transmission reliability and an 11% increase in the price of energy due to an increase in natural gas prices.
Other Revenues
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(6) | | (10.7) | | $(4) | | (2.5) |
In the third quarter 2017, other revenues were $50 million compared to $56 million for the corresponding period in 2016. The decrease was primarily due to lower open access transmission tariff revenues as a result of rate adjustments.
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | | |
| | Third Quarter 2017
vs.
Third Quarter 2016 | | Year-to-Date 2017
vs.
Year-to-Date 2016 |
| | (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| Fuel | $ | (67 | ) | | (16.3) | | $ | (29 | ) | | (3.0 | ) |
| Purchased power – non-affiliates | (6 | ) | | (9.5) | | (7 | ) | | (5.0 | ) |
| Purchased power – affiliates | 14 |
| | 34.1 | | (12 | ) | | (9.3 | ) |
| Total fuel and purchased power expenses | $ | (59 | ) | | | | $ | (48 | ) | | |
In the third quarter 2017, fuel and purchased power expenses were $455 million compared to $514 million for the corresponding period in 2016. The decrease was primarily due to a $43 million net decrease related to the volume of KWHs generated and purchased and a $16 million decrease related to the average cost of fuel.
For year-to-date 2017, fuel and purchased power expenses were $1.19 billion compared to $1.24 billion for the corresponding period in 2016. The decrease was primarily due to a $53 million decrease in the volume of KWHs purchased and a $34 million decrease related to the average cost of fuel. This decrease was partially offset by a $35 million increase in the average cost of purchased power.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Alabama Power's energy cost recovery clause. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate ECR" in Item 8 of the Form 10-K for additional information.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of Alabama Power's generation and purchased power were as follows:
|
| | | | | | | |
| | Third Quarter 2017 | | Third Quarter 2016 | | Year-to-Date 2017 |
| Year-to-Date 2016 |
Total generation (in billions of KWHs) | 16 | | 18 | | 46 | | 46 |
Total purchased power (in billions of KWHs) | 2 | | 2 | | 5 | | 6 |
Sources of generation (percent) — | | | | | | | |
| Coal | 52 | | 59 | | 49 | | 51 |
| Nuclear | 24 | | 22 | | 25 | | 24 |
| Gas | 19 | | 18 | | 20 | | 19 |
| Hydro | 5 | | 1 | | 6 | | 6 |
Cost of fuel, generated (in cents per net KWH) — | | | | | | | |
| Coal | 2.61 | | 2.73 | | 2.61 | | 2.80 |
| Nuclear | 0.75 | | 0.77 | | 0.75 | | 0.78 |
| Gas | 2.72 | | 2.85 | | 2.74 | | 2.62 |
Average cost of fuel, generated (in cents per net KWH)(a) | 2.17 | | 2.32 | | 2.15 | | 2.25 |
Average cost of purchased power (in cents per net KWH)(b) | 5.65 | | 5.70 | | 5.57 | | 4.81 |
| |
(a)
| KWHs generated by hydro are excluded from the average cost of fuel, generated. |
| |
(b)
| Average cost of purchased power includes fuel, energy, and transmission purchased by Alabama Power for tolling agreements where power is generated by the provider. |
Fuel
In the third quarter 2017, fuel expense was $343 million compared to $410 million for the corresponding period in 2016. The decrease was primarily due to an 18.4% decrease in the volume of KWHs generated by coal, a 4.6% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, and a 4.4% decrease in average cost of coal per KWH generated. In addition, there was a 194.0% increase in the volume of KWHs generated by hydro facilities as a result of significantly more rainfall in 2017.
For year-to-date 2017, fuel expense was $944 million compared to $973 million for the corresponding period in 2016. The decrease was primarily due to a 6.8% decrease in the average cost of coal per KWH generated and a 2.0% decrease in the volume of KWHs generated by coal. The decrease was partially offset by a 4.8% increase in the volume of KWHs generated by natural gas and a 4.6% increase in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements.
Purchased Power – Affiliates
In the third quarter 2017, purchased power expense from affiliates was $55 million compared to $41 million for the corresponding period in 2016. The increase was primarily related to a 55.2% increase in the amount of energy purchased due to an increase in plant outages and increased purchases from Southern Electric Generating Company (SEGCO). The increase was partially offset by a 14.5% decrease in the average cost per KWH of capacity and energy at SEGCO. See Note 4 to the financial statements of Alabama Power in Item 8 of the Form 10-K for additional information.
For year-to-date 2017, purchased power expense from affiliates was $117 million compared to $129 million for the corresponding period in 2016. The decrease was primarily related to a 26.6% decrease in the amount of energy purchased due to a decrease in demand as a result of milder weather in 2017, partially offset by a 22.9% increase in the average cost of purchased power per KWH as a result of higher 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 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $43 | | 12.4 | | $37 | | 3.4 |
In the third quarter 2017, other operations and maintenance expenses were $391 million compared to $348 million for the corresponding period in 2016. The increase was primarily due to increases of $26 million in scheduled generation outage costs, $11 million in vegetation management costs, and $3 million in employee compensation and benefit costs, including pension costs.
For year-to-date 2017, other operations and maintenance expenses were $1.13 billion compared to $1.10 billion for the corresponding period in 2016. The increase was primarily due to increases of $31 million in vegetation management costs, $10 million in nuclear generation plant improvement costs, and $7 million in employee compensation and benefit costs, including pension costs, partially offset by an $11 million decrease in contract services.
Depreciation and Amortization
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $8 | | 4.5 | | $25 | | 4.8 |
In the third quarter 2017, depreciation and amortization was $185 million compared to $177 million for the corresponding period in 2016. For year-to-date 2017, depreciation and amortization was $549 million compared to $524 million for the corresponding period in 2016. These increases were primarily due to additional plant in service and an increase in depreciation rates, effective January 1, 2017, associated with compliance-related steam projects and asset retirement obligation recovery, partially offset by a decrease in distribution-related depreciation 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.
Income Taxes
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(3) | | (1.4) | | $31 | | 6.7 |
For year-to-date 2017, income taxes were $493 million compared to $462 million for the corresponding period in 2016. The increase was primarily due to higher pre-tax earnings, unrecognized tax benefits related to certain state deductions for federal income taxes, and prior year tax return actualization.
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
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 the pace of economic growth that 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 September 18, 2017, the EPA published a final 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 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
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 October 16, 2017, the EPA published a proposed rule to repeal the Clean Power Plan. The EPA has not determined whether or when it will promulgate a replacement rule.
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 related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including Alabama Power's) and Southern Power's June 30, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including Alabama Power) and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order, or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including Alabama Power) and Southern Power expect to make a filing within the specified 60 days responding to the FERC's order.
The ultimate outcome of these matters cannot be determined at this time.
Retail Regulatory Matters
Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See Notes 1 and 3 to the financial statements of Alabama Power under "Nuclear Outage Accounting Order" and "Retail Regulatory Matters," respectively, in Item 8 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.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported 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 Alabama Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Alabama Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Alabama Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Alabama Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Alabama Power in Item 7 of the Form 10-K for a complete discussion of Alabama Power's critical accounting policies and estimates related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, and Contingent Obligations.
Recently Issued Accounting Standards
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Alabama Power in Item 7 of the Form 10-K for additional information.
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-
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 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. 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.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with early adoption permitted. Alabama Power is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 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 September 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 $1.4 billion for the first nine months of 2017, a decrease of $130 million as compared to the first nine 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 $1.2 billion for the first nine months of 2017 primarily due to gross property additions related to distribution, environmental, transmission, and steam generation. Net cash provided from financing activities totaled $339 million for the first nine months of 2017 primarily due to an issuance of long-term debt and preferred stock 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 nine months of 2017 include increases of $652 million in property, plant, and equipment primarily due to additions to distribution, transmission, and steam generation, $548 million in long-term debt primarily due to the issuance of additional senior notes, $533 million in cash and cash equivalents, $348 million in additional paid-in capital due to capital contributions from Southern Company, $265 million in
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
accumulated deferred income taxes primarily due to bonus depreciation, and $244 million in redeemable preferred stock primarily due to the September 2017 issuance, as well as a decrease of $236 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. Subsequent to September 30, 2017, Alabama Power repaid at maturity $325 million aggregate principal amount of Series Q 5.50% Senior Notes due October 15, 2017. No additional funds will be required through September 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's Board of Directors approved its construction program that is currently estimated to total $2.2 billion for 2018, $1.6 billion for 2019, $1.6 billion for 2020, $1.7 billion for 2021, and $1.4 billion for 2022. The construction program includes capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under LTSAs. Estimated capital expenditures to comply with environmental statutes and regulations included in these amounts are $0.6 billion for 2018, $0.1 billion for 2019, $0.2 billion for 2020, $0.3 billion for 2021, and $0.3 billion for 2022. These estimated expenditures do not include any potential compliance costs that may arise from the EPA's final rules and guidelines or future state plans that would limit CO2 emissions from new, existing, modified, or reconstructed fossil-fuel-fired electric generating units.
Alabama Power also anticipates costs associated with closure in place and monitoring of ash ponds in accordance with the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule), which are reflected in Alabama Power's asset retirement obligation liabilities. These costs, which could change as Alabama Power continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities, are estimated to be $27 million for 2018, $101 million for 2019, $105 million for 2020, $107 million for 2021, and $109 million for 2022. 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 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
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 September 30, 2017, Alabama Power had approximately $953 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2017 were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Expires | | | | | | Expires Within One Year |
| 2018 | | 2020 | | 2022 | | Total | | Unused | | Term Out | | No Term Out |
| (in millions) |
| $ | 35 |
| | $ | 500 |
| | $ | 800 |
| | $ | 1,335 |
| | $ | 1,335 |
| | $ | — |
| | $ | 35 |
|
See Note 6 to the financial statements of Alabama Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
In May 2017 and September 2017, Alabama Power amended its $800 million and $500 million multi-year credit arrangements, which, among other things, extended the maturity dates from 2020 to 2022 and 2018 to 2020, respectively, as reflected in the table above.
Most of these bank credit arrangements, as well as 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 September 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 $854 million as of September 30, 2017. At September 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 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.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of commercial paper borrowings were as follows:
|
| | | | | | | | | | | |
| | | Short-term Debt During the Period(*) |
| | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) |
| Commercial paper | | $ | 30 |
| | 1.3 | % | | $ | 220 |
|
| |
(*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2017. No short-term debt was outstanding at September 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 September 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 September 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 | $ | 338 |
|
Included in these amounts are certain agreements that could require collateral in the event that either Alabama Power or Georgia Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Alabama Power to access capital markets and would be likely to impact the cost at which it does so.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including Alabama Power) from stable to negative.
Financing Activities
In February 2017, Alabama Power repaid at maturity $200 million aggregate principal amount of Series 2007A 5.55% Senior Notes.
In March 2017, Alabama Power issued $550 million aggregate principal amount of Series 2017A 2.45% Senior Notes due March 30, 2022. The proceeds were used to repay Alabama Power's short-term indebtedness and for general corporate purposes, including Alabama Power's continuous construction program.
In July 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).
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In September 2017, Alabama Power issued 10 million shares ($250 million aggregate stated capital) of 5.00% Class A Preferred Stock, Cumulative, Par Value $1 Per Share (Stated Capital $25 Per Share). The proceeds were used in October 2017 to redeem all 2 million shares ($50 million aggregate stated capital) of 6.50% Series Preference Stock, 6 million shares ($150 million aggregate stated capital) of 6.45% Series Preference Stock, and 1.52 million shares ($38 million aggregate stated capital) of 5.83% Class A Preferred Stock and for other general corporate purposes, including Alabama Power's continuous construction program.
Subsequent to September 30, 2017, Alabama Power repaid at maturity $325 million aggregate principal amount of Series Q 5.50% Senior Notes due October 15, 2017.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Alabama Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
GEORGIA POWER COMPANY
GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
| | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2017 | | 2016 | | 2017 | | 2016 | 2020 | | 2019 | | 2020 | | 2019 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | | | | | | | | |
| Retail revenues | $ | 2,402 |
| | $ | 2,540 |
| | $ | 5,995 |
| | $ | 6,164 |
| $ | 1,760 |
| | $ | 1,946 |
| | $ | 3,435 |
| | $ | 3,614 |
|
| Wholesale revenues, non-affiliates | 45 |
| | 49 |
| | 124 |
| | 131 |
| |
| Wholesale revenues, affiliates | 6 |
| | 9 |
| | 23 |
| | 24 |
| |
| Wholesale revenues | | 25 |
| | 36 |
| | 51 |
| | 67 |
|
| Other revenues | 93 |
| | 100 |
| | 284 |
| | 302 |
| 143 |
| | 135 |
| | 268 |
| | 270 |
|
| Total operating revenues | 2,546 |
| | 2,698 |
| | 6,426 |
| | 6,621 |
| 1,928 |
| | 2,117 |
| | 3,754 |
| | 3,951 |
|
| Operating Expenses: | | | | | | | | | | | | | | |
| Fuel | 482 |
| | 575 |
| | 1,297 |
| | 1,390 |
| 226 |
| | 390 |
| | 458 |
| | 689 |
|
| Purchased power, non-affiliates | 119 |
| | 102 |
| | 310 |
| | 277 |
| 133 |
| | 124 |
| | 262 |
| | 242 |
|
| Purchased power, affiliates | 161 |
| | 142 |
| | 470 |
| | 392 |
| 122 |
| | 134 |
| | 251 |
| | 310 |
|
| Other operations and maintenance | 413 |
| | 496 |
| | 1,194 |
| | 1,393 |
| 463 |
| | 463 |
| | 928 |
| | 913 |
|
| Depreciation and amortization | 225 |
| | 215 |
| | 669 |
| | 639 |
| 354 |
| | 244 |
| | 707 |
| | 483 |
|
| Taxes other than income taxes | 112 |
| | 114 |
| | 311 |
| | 311 |
| 108 |
| | 115 |
| | 221 |
| | 220 |
|
| Estimated loss on Plant Vogtle Units 3 and 4 | | 149 |
| | — |
| | 149 |
| | — |
|
| Total operating expenses | 1,512 |
| | 1,644 |
| | 4,251 |
| | 4,402 |
| 1,555 |
| | 1,470 |
| | 2,976 |
| | 2,857 |
|
| Operating Income | 1,034 |
| | 1,054 |
| | 2,175 |
| | 2,219 |
| 373 |
| | 647 |
| | 778 |
| | 1,094 |
|
| Other Income and (Expense): | | | | | | | | | | | | | | |
| Interest expense, net of amounts capitalized | (105 | ) | | (98 | ) | | (310 | ) | | (290 | ) | (105 | ) | | (105 | ) | | (216 | ) | | (201 | ) |
| Other income (expense), net | 5 |
| | 11 |
| | 41 |
| | 35 |
| 51 |
| | 35 |
| | 103 |
| | 77 |
|
| Total other income and (expense) | (100 | ) | | (87 | ) | | (269 | ) | | (255 | ) | (54 | ) | | (70 | ) | | (113 | ) | | (124 | ) |
| Earnings Before Income Taxes | 934 |
| | 967 |
| | 1,906 |
| | 1,964 |
| 319 |
| | 577 |
| | 665 |
| | 970 |
|
| Income taxes | 350 |
| | 363 |
| | 705 |
| | 734 |
| 11 |
| | 129 |
| | 27 |
| | 211 |
|
| Net Income | 584 |
| | 604 |
| | 1,201 |
| | 1,230 |
| $ | 308 |
| | $ | 448 |
| | $ | 638 |
| | $ | 759 |
|
| Dividends on Preferred and Preference Stock | 4 |
| | 4 |
| | 13 |
| | 13 |
| |
| Net Income After Dividends on Preferred and Preference Stock | $ | 580 |
| | $ | 600 |
| | $ | 1,188 |
| | $ | 1,217 |
| |
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, |
| | 2017 | | 2016 | | 2017 | | 2016 | 2020 | | 2019 | | 2020 | | 2019 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Net Income | $ | 584 |
| | $ | 604 |
| | $ | 1,201 |
| | $ | 1,230 |
| $ | 308 |
| | $ | 448 |
| | $ | 638 |
| | $ | 759 |
|
| 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 |
| | 2 |
| |
| Changes in fair value, net of tax of $-, $(9), $(1), and $(9), respectively | | — |
| | (28 | ) | | (2 | ) | | (28 | ) |
Reclassification adjustment for amounts included in net income,
net of tax of $1, $-, $1, and $-, respectively | | 2 |
| | 1 |
| | 3 |
| | 1 |
|
| Total other comprehensive income (loss) | 1 |
| | 1 |
| | 2 |
| | 2 |
| 2 |
| | (27 | ) | | 1 |
| | (27 | ) |
| Comprehensive Income | $ | 585 |
| | $ | 605 |
| | $ | 1,203 |
| | $ | 1,232 |
| $ | 310 |
| | $ | 421 |
| | $ | 639 |
| | $ | 732 |
|
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED) | | | | For the Nine Months Ended September 30, | For the Six Months Ended June 30, |
| | 2017 | | 2016 | 2020 | | 2019 |
| | (in millions) | (in millions) |
| Operating Activities: | | | | | | |
| Net income | $ | 1,201 |
| | $ | 1,230 |
| $ | 638 |
| | $ | 759 |
|
| Adjustments to reconcile net income to net cash provided from operating activities -- | | | | |
| Adjustments to reconcile net income to net cash provided from operating activities — | | | | |
| Depreciation and amortization, total | 821 |
| | 794 |
| 800 |
| | 583 |
|
| Deferred income taxes | 328 |
| | 346 |
| (202 | ) | | 153 |
|
| Allowance for equity funds used during construction | (29 | ) | | (36 | ) | (40 | ) | | (31 | ) |
| Deferred expenses | (30 | ) | | (40 | ) | |
| Pension, postretirement, and other employee benefits | (42 | ) | | (14 | ) | (55 | ) | | (56 | ) |
| Settlement of asset retirement obligations | (95 | ) | | (93 | ) | (78 | ) | | (76 | ) |
| Storm damage reserve accruals | | 107 |
| | 15 |
|
| Estimated loss on Plant Vogtle Units 3 and 4 | | 149 |
| | — |
|
| Other, net | (21 | ) | | 7 |
| 19 |
| | 17 |
|
| Changes in certain current assets and liabilities — | | | | | | |
| -Receivables | (254 | ) | | (162 | ) | (73 | ) | | (43 | ) |
| -Fossil fuel stock | (2 | ) | | 128 |
| (52 | ) | | (26 | ) |
| -Prepaid income taxes | | — |
| | 63 |
|
| -Materials and supplies | | (61 | ) | | 2 |
|
| -Other current assets | (29 | ) | | 62 |
| (26 | ) | | 19 |
|
| -Accounts payable | (161 | ) | | 39 |
| — |
| | (94 | ) |
| -Accrued taxes | (52 | ) | | (22 | ) | 87 |
| | (139 | ) |
| -Accrued compensation | (60 | ) | | (26 | ) | (69 | ) | | (32 | ) |
| -Retail fuel cost over recovery | (84 | ) | | 9 |
| 109 |
| | — |
|
| -Customer refunds | | (159 | ) | | (19 | ) |
| -Other current liabilities | (11 | ) | | 44 |
| 30 |
| | 17 |
|
| Net cash provided from operating activities | 1,480 |
| | 2,266 |
| 1,124 |
| | 1,112 |
|
| Investing Activities: | | | | | | |
| Property additions | (1,907 | ) | | (1,566 | ) | (1,650 | ) | | (1,712 | ) |
| Nuclear decommissioning trust fund purchases | (411 | ) | | (563 | ) | (365 | ) | | (266 | ) |
| Nuclear decommissioning trust fund sales | 406 |
| | 558 |
| 359 |
| | 260 |
|
| Cost of removal, net of salvage | (54 | ) | | (45 | ) | (62 | ) | | (107 | ) |
| Change in construction payables, net of joint owner portion | 180 |
| | (139 | ) | (48 | ) | | (5 | ) |
| Payments pursuant to LTSAs | (59 | ) | | (27 | ) | (41 | ) | | (9 | ) |
| Sale of property | 63 |
| | 10 |
| |
| Proceeds from dispositions and asset sales | | 143 |
| | 9 |
|
| Other investing activities | (52 | ) | | 14 |
| 5 |
| | (4 | ) |
| Net cash used for investing activities | (1,834 | ) | | (1,758 | ) | (1,659 | ) | | (1,834 | ) |
| Financing Activities: | | | | | | |
| Decrease in notes payable, net | (391 | ) | | (63 | ) | |
| Increase (decrease) in notes payable, net | | (25 | ) | | 11 |
|
| Proceeds — | | | | | | |
| FFB loan | | 519 |
| | 835 |
|
| Senior notes | | 1,500 |
| | — |
|
| Pollution control revenue bonds | | 53 |
| | 513 |
|
| Short-term borrowings | | 250 |
| | 250 |
|
| Capital contributions from parent company | 412 |
| | 294 |
| 500 |
| | 46 |
|
| Redemptions and repurchases — | | | | |
| Senior notes | 1,350 |
| | 650 |
| (950 | ) | | — |
|
| Pollution control revenue bonds | | (148 | ) | | (223 | ) |
| FFB loan | — |
| | 300 |
| (32 | ) | | — |
|
| Short-term borrowings | 700 |
| | — |
| |
| Other long-term debt | 370 |
| | — |
| |
| Redemptions and repurchases — | | | | |
| Pollution control revenue bonds | (65 | ) | | (4 | ) | |
| Senior notes | (450 | ) | | (700 | ) | |
| Short-term borrowings | (300 | ) | | — |
| |
| Payment of common stock dividends | (961 | ) | | (979 | ) | (771 | ) | | (788 | ) |
| Other financing activities | (48 | ) | | (26 | ) | (27 | ) | | (24 | ) |
| Net cash provided from (used for) financing activities | 617 |
| | (528 | ) | |
| Net Change in Cash and Cash Equivalents | 263 |
| | (20 | ) | |
| Cash and Cash Equivalents at Beginning of Period | 3 |
| | 67 |
| |
| Cash and Cash Equivalents at End of Period | $ | 266 |
| | $ | 47 |
| |
| Net cash provided from financing activities | | 869 |
| | 620 |
|
| Net Change in Cash, Cash Equivalents, and Restricted Cash | | 334 |
| | (102 | ) |
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | | 52 |
| | 112 |
|
| Cash, Cash Equivalents, and Restricted Cash at End of Period | | $ | 386 |
| | $ | 10 |
|
| Supplemental Cash Flow Information: | | | | | | |
| Cash paid during the period for — | | | | |
| Interest (net of $17 and $15 capitalized for 2017 and 2016, respectively) | $ | 284 |
| | $ | 277 |
| |
| Cash paid (received) during the period for — | | | | |
| Interest (net of $22 and $16 capitalized for 2020 and 2019, respectively) | | $ | 180 |
| | $ | 179 |
|
| Income taxes, net | 369 |
| | 188 |
| — |
| | (6 | ) |
| Noncash transactions — Accrued property additions at end of period | 470 |
| | 226 |
| |
| Noncash transactions — | | | | |
| Accrued property additions at end of period | | 478 |
| | 650 |
|
| Right-of-use assets obtained under operating leases | | 29 |
| | 13 |
|
| Right-of-use assets obtained under finance leases | | — |
| | 28 |
|
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, 2017 | | At December 31, 2016 | | At June 30, 2020 | | At December 31, 2019 |
| | | (in millions) | | (in millions) |
| Current Assets: | | | | | | | | |
| Cash and cash equivalents | | $ | 266 |
| | $ | 3 |
| | $ | 386 |
| | $ | 52 |
|
| Receivables — | | | | | | | | |
| Customer accounts receivable | | 670 |
| | 523 |
| | 580 |
| | 533 |
|
| Unbilled revenues | | 276 |
| | 224 |
| | 261 |
| | 203 |
|
| Under recovered fuel clause revenues | | 62 |
| | — |
| |
| Joint owner accounts receivable | | 222 |
| | 57 |
| | 104 |
| | 136 |
|
| Affiliated | | | 28 |
| | 21 |
|
| Other accounts and notes receivable | | 82 |
| | 81 |
| | 42 |
| | 209 |
|
| Affiliated | | 21 |
| | 18 |
| |
| Accumulated provision for uncollectible accounts | | (3 | ) | | (3 | ) | | (28 | ) | | (2 | ) |
| Fossil fuel stock | | 300 |
| | 298 |
| | 324 |
| | 272 |
|
| Materials and supplies | | 480 |
| | 479 |
| | 558 |
| | 501 |
|
| Prepaid expenses | | 82 |
| | 105 |
| | 58 |
| | 63 |
|
| Other regulatory assets, current | | 200 |
| | 193 |
| |
| Regulatory assets – storm damage reserves | | | 213 |
| | 213 |
|
| Regulatory assets – asset retirement obligations | | | 215 |
| | 254 |
|
| Other regulatory assets | | | 276 |
| | 263 |
|
| Other current assets | | 27 |
| | 38 |
| | 62 |
| | 77 |
|
| Total current assets | | 2,685 |
| | 2,016 |
| | 3,079 |
| | 2,795 |
|
| Property, Plant, and Equipment: | | | | | | | | |
| In service | | 34,589 |
| | 33,841 |
| | 38,852 |
| | 38,137 |
|
| Less: Accumulated provision for depreciation | | 11,655 |
| | 11,317 |
| | 11,964 |
| | 11,753 |
|
| Plant in service, net of depreciation | | 22,934 |
| | 22,524 |
| | 26,888 |
| | 26,384 |
|
| Nuclear fuel, at amortized cost | | 551 |
| | 569 |
| | 560 |
| | 555 |
|
| Construction work in progress | | 5,751 |
| | 4,939 |
| | 6,254 |
| | 5,650 |
|
| Total property, plant, and equipment | | 29,236 |
| | 28,032 |
| | 33,702 |
| | 32,589 |
|
| Other Property and Investments: | | | | | | | | |
| Equity investments in unconsolidated subsidiaries | | 53 |
| | 60 |
| | 50 |
| | 52 |
|
| Nuclear decommissioning trusts, at fair value | | 914 |
| | 814 |
| | 1,036 |
| | 1,013 |
|
| Miscellaneous property and investments | | 51 |
| | 46 |
| | 65 |
| | 64 |
|
| Total other property and investments | | 1,018 |
| | 920 |
| | 1,151 |
| | 1,129 |
|
| Deferred Charges and Other Assets: | | | | | | | | |
| Operating lease right-of-use assets, net of amortization | | | 1,382 |
| | 1,428 |
|
| Deferred charges related to income taxes | | 669 |
| | 676 |
| | 519 |
| | 519 |
|
| Regulatory assets – asset retirement obligations, deferred | | | 2,894 |
| | 2,865 |
|
| Other regulatory assets, deferred | | 2,890 |
| | 2,774 |
| | 2,610 |
| | 2,716 |
|
| Other deferred charges and assets | | 608 |
| | 417 |
| | 488 |
| | 500 |
|
| Total deferred charges and other assets | | 4,167 |
| | 3,867 |
| | 7,893 |
| | 8,028 |
|
| Total Assets | | $ | 37,106 |
| | $ | 34,835 |
| | $ | 45,825 |
| | $ | 44,541 |
|
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, 2017 | | At December 31, 2016 | | At June 30, 2020 | | At December 31, 2019 |
| | | (in millions) | | (in millions) |
| Current Liabilities: | | | | | | | | |
| Securities due within one year | | $ | 261 |
| | $ | 460 |
| | $ | 536 |
| | $ | 1,025 |
|
| Notes payable | | 400 |
| | 391 |
| | 465 |
| | 365 |
|
| Accounts payable — | | | | | | | | |
| Affiliated | | 396 |
| | 438 |
| | 493 |
| | 512 |
|
| Other | | 1,012 |
| | 589 |
| | 672 |
| | 711 |
|
| Customer deposits | | 270 |
| | 265 |
| | 284 |
| | 283 |
|
| Accrued taxes | | 353 |
| | 407 |
| | 442 |
| | 407 |
|
| Accrued interest | | 121 |
| | 106 |
| | 133 |
| | 118 |
|
| Accrued compensation | | 164 |
| | 224 |
| | 152 |
| | 233 |
|
| Asset retirement obligations, current | | 214 |
| | 299 |
| |
| Operating lease obligations | | | 150 |
| | 144 |
|
| Asset retirement obligations | | | 279 |
| | 265 |
|
| Over recovered fuel clause revenues | | | 109 |
| | — |
|
| Other regulatory liabilities | | | 290 |
| | 447 |
|
| Other current liabilities | | 192 |
| | 297 |
| | 206 |
| | 187 |
|
| Total current liabilities | | 3,383 |
| | 3,476 |
| | 4,211 |
| | 4,697 |
|
| Long-term Debt | | 11,610 |
| | 10,225 |
| | 12,337 |
| | 10,791 |
|
| Deferred Credits and Other Liabilities: | | | | | | | | |
| Accumulated deferred income taxes | | 6,328 |
| | 6,000 |
| | 3,190 |
| | 3,257 |
|
| Deferred credits related to income taxes | | | 2,730 |
| | 2,862 |
|
| Accumulated deferred ITCs | | 248 |
| | 256 |
| | 273 |
| | 255 |
|
| Employee benefit obligations | | 665 |
| | 703 |
| | 500 |
| | 540 |
|
| Operating lease obligations, deferred | | | 1,258 |
| | 1,282 |
|
| Asset retirement obligations, deferred | | 2,367 |
| | 2,233 |
| | 5,556 |
| | 5,519 |
|
| Other deferred credits and liabilities | | 232 |
| | 320 |
| | 333 |
| | 273 |
|
| Total deferred credits and other liabilities | | 9,840 |
| | 9,512 |
| | 13,840 |
| | 13,988 |
|
| Total Liabilities | | 24,833 |
| | 23,213 |
| | 30,388 |
| | 29,476 |
|
| 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 | | 7,308 |
| | 6,885 |
| |
| Retained earnings | | 4,311 |
| | 4,086 |
| |
| Accumulated other comprehensive loss | | (10 | ) | | (13 | ) | |
| Total common stockholder's equity | | 12,007 |
| | 11,356 |
| |
Common Stockholder's Equity (See accompanying statements) | | | 15,437 |
| | 15,065 |
|
| Total Liabilities and Stockholder's Equity | | $ | 37,106 |
| | $ | 34,835 |
| | $ | 45,825 |
| | $ | 44,541 |
|
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 ANALYSISCONDENSED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY (UNAUDITED)
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
| | | | | | | | | | | | | | | | | | | | | | |
| | Number of
Common
Shares
Issued | | Common
Stock | | Paid-In
Capital | | Retained
Earnings | | Accumulated
Other
Comprehensive
Income (Loss) | | Total |
| | (in millions) |
| Balance at December 31, 2018 | 9 |
| | $ | 398 |
| | $ | 10,322 |
| | $ | 3,612 |
| | $ | (9 | ) | | $ | 14,323 |
|
| Net income | — |
| | — |
| | — |
| | 311 |
| | — |
| | 311 |
|
| Capital contributions from parent company | — |
| | — |
| | 29 |
| | — |
| | — |
| | 29 |
|
| Other comprehensive income | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
| Cash dividends on common stock | — |
| | — |
| | — |
| | (394 | ) | | — |
| | (394 | ) |
| Other | — |
| | — |
| | (1 | ) | | — |
| | — |
| | (1 | ) |
| Balance at March 31, 2019 | 9 |
| | 398 |
| | 10,350 |
| | 3,529 |
| | (8 | ) | | 14,269 |
|
| Net income | — |
| | — |
| | — |
| | 448 |
| | — |
| | 448 |
|
| Capital contributions from parent company | — |
| | — |
| | 20 |
| | — |
| | — |
| | 20 |
|
| Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | (27 | ) | | (27 | ) |
| Cash dividends on common stock | — |
| | — |
| | — |
| | (394 | ) | | — |
| | (394 | ) |
| Other | — |
| | — |
| | 1 |
| | (1 | ) | | — |
| | — |
|
| Balance at June 30, 2019 | 9 |
| | $ | 398 |
| | $ | 10,371 |
| | $ | 3,582 |
| | $ | (35 | ) | | $ | 14,316 |
|
| | | | | | | | | | | | |
| Balance at December 31, 2019 | 9 |
| | $ | 398 |
| | $ | 10,962 |
| | $ | 3,756 |
| | $ | (51 | ) | | $ | 15,065 |
|
| Net income | — |
| | — |
| | — |
| | 331 |
| | — |
| | 331 |
|
| Capital contributions from parent company | — |
| | — |
| | 502 |
| | — |
| | — |
| | 502 |
|
| Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | (1 | ) | | (1 | ) |
| Cash dividends on common stock | — |
| | — |
| | — |
| | (385 | ) | | — |
| | (385 | ) |
| Balance at March 31, 2020 | 9 |
| | 398 |
| | 11,464 |
| | 3,702 |
| | (52 | ) | | 15,512 |
|
| Net income | — |
| | — |
| | — |
| | 308 |
| | — |
| | 308 |
|
| Capital contributions from parent company | — |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
| Other comprehensive income | — |
| | — |
| | — |
| | — |
| | 2 |
| | 2 |
|
| Cash dividends on common stock | — |
| | — |
| | — |
| | (386 | ) | | — |
| | (386 | ) |
| Balance at June 30, 2020 | 9 |
| | $ | 398 |
| | $ | 11,465 |
| | $ | 3,624 |
| | $ | (50 | ) | | $ | 15,437 |
|
THIRD QUARTER 2017 vs. THIRD QUARTER 2016
AND
YEAR-TO-DATE 2017 vs. YEAR-TO-DATE 2016
OVERVIEW
The accompanying notes as they relate to Georgia Power operatesare an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2020 | | 2019 | | 2020 | | 2019 |
| | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | |
| Retail revenues | $ | 199 |
| | $ | 215 |
| | $ | 398 |
| | $ | 418 |
|
| Wholesale revenues, non-affiliates | 52 |
| | 57 |
| | 103 |
| | 114 |
|
| Wholesale revenues, affiliates | 25 |
| | 37 |
| | 47 |
| | 58 |
|
| Other revenues | 7 |
| | 4 |
| | 11 |
| | 10 |
|
| Total operating revenues | 283 |
| | 313 |
| | 559 |
| | 600 |
|
| Operating Expenses: | | | | | | | |
| Fuel | 83 |
| | 105 |
| | 162 |
| | 198 |
|
| Purchased power | 7 |
| | 6 |
| | 12 |
| | 9 |
|
| Other operations and maintenance | 67 |
| | 72 |
| | 142 |
| | 133 |
|
| Depreciation and amortization | 46 |
| | 48 |
| | 88 |
| | 95 |
|
| Taxes other than income taxes | 30 |
| | 28 |
| | 59 |
| | 55 |
|
| Total operating expenses | 233 |
| | 259 |
| | 463 |
| | 490 |
|
| Operating Income | 50 |
| | 54 |
| | 96 |
| | 110 |
|
| Other Income and (Expense): | | | | | | | |
| Interest expense, net of amounts capitalized | (15 | ) | | (17 | ) | | (31 | ) | | (35 | ) |
| Other income (expense), net | 6 |
| | 5 |
| | 14 |
| | 11 |
|
| Total other income and (expense) | (9 | ) | | (12 | ) | | (17 | ) | | (24 | ) |
| Earnings Before Income Taxes | 41 |
| | 42 |
| | 79 |
| | 86 |
|
| Income taxes | 2 |
| | 5 |
| | 8 |
| | 12 |
|
| Net Income | $ | 39 |
| | $ | 37 |
| | $ | 71 |
| | $ | 74 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2020 | | 2019 | | 2020 | | 2019 |
| | (in millions) | | (in millions) |
| Net Income | $ | 39 |
| | $ | 37 |
| | $ | 71 |
| | $ | 74 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
| Changes in fair value, net of tax of $-, $-, $-, and $-, respectively | — |
| | — |
| | (1 | ) | | — |
|
Reclassification adjustment for amounts included in net income,
net of tax of $-, $-, $-, and $-, respectively | — |
| | — |
| | 1 |
| | 1 |
|
| Total other comprehensive income (loss) | — |
| | — |
| | — |
| | 1 |
|
| Comprehensive Income | $ | 39 |
| | $ | 37 |
| | $ | 71 |
| | $ | 75 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED) |
| | | | | | | |
| | For the Six Months Ended June 30, |
| | 2020 | | 2019 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 71 |
| | $ | 74 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 92 |
| | 98 |
|
| Deferred income taxes | (13 | ) | | (16 | ) |
| Settlement of asset retirement obligations | (9 | ) | | (17 | ) |
| Other, net | 9 |
| | 12 |
|
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (7 | ) | | (8 | ) |
| -Other current assets | (6 | ) | | (3 | ) |
| -Accounts payable | (19 | ) | | (28 | ) |
| -Accrued taxes | (21 | ) | | (43 | ) |
| -Accrued compensation | (15 | ) | | (15 | ) |
| -Other current liabilities | (11 | ) | | 6 |
|
| Net cash provided from operating activities | 71 |
| | 60 |
|
| Investing Activities: | | | |
| Property additions | (111 | ) | | (95 | ) |
| Construction payables | (14 | ) | | (12 | ) |
| Payments pursuant to LTSAs | (10 | ) | | (11 | ) |
| Other investing activities | (10 | ) | | (10 | ) |
| Net cash used for investing activities | (145 | ) | | (128 | ) |
| Financing Activities: | | | |
| Proceeds — | | | |
| Capital contributions from parent company | 75 |
| | 7 |
|
| Short-term borrowings | 40 |
| | — |
|
| Pollution control revenue bonds | 34 |
| | 43 |
|
| Other long-term debt | 100 |
| | — |
|
| Redemptions — | | | |
| Senior notes | (275 | ) | | — |
|
| Short-term borrowings | (40 | ) | | — |
|
| Pollution control revenue bonds | (41 | ) | | — |
|
| Return of capital to parent company | (74 | ) | | (75 | ) |
| Other financing activities | 3 |
| | (1 | ) |
| Net cash used for financing activities | (178 | ) | | (26 | ) |
| Net Change in Cash, Cash Equivalents, and Restricted Cash | (252 | ) | | (94 | ) |
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 286 |
| | 293 |
|
| Cash, Cash Equivalents, and Restricted Cash at End of Period | $ | 34 |
| | $ | 199 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid during the period for — | | | |
| Interest (net of $- and $(1) capitalized for 2020 and 2019, respectively) | $ | 33 |
| | $ | 36 |
|
| Income taxes, net | — |
| | 23 |
|
| Noncash transactions — Accrued property additions at end of period | 21 |
| | 23 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At June 30, 2020 | | At December 31, 2019 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 34 |
| | $ | 286 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 39 |
| | 35 |
|
| Unbilled revenues | | 41 |
| | 39 |
|
| Affiliated | | 31 |
| | 27 |
|
| Other accounts and notes receivable | | 24 |
| | 26 |
|
| Fossil fuel stock | | 24 |
| | 26 |
|
| Materials and supplies | | 62 |
| | 61 |
|
| Other regulatory assets | | 73 |
| | 99 |
|
| Other current assets | | 8 |
| | 10 |
|
| Total current assets | | 336 |
| | 609 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 4,948 |
| | 4,857 |
|
| Less: Accumulated provision for depreciation | | 1,522 |
| | 1,463 |
|
| Plant in service, net of depreciation | | 3,426 |
| | 3,394 |
|
| Construction work in progress | | 132 |
| | 126 |
|
| Total property, plant, and equipment | | 3,558 |
| | 3,520 |
|
| Other Property and Investments | | 129 |
| | 131 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 32 |
| | 32 |
|
| Regulatory assets – asset retirement obligations | | 200 |
| | 210 |
|
| Other regulatory assets, deferred | | 376 |
| | 360 |
|
| Accumulated deferred income taxes | | 134 |
| | 139 |
|
| Other deferred charges and assets | | 56 |
| | 34 |
|
| Total deferred charges and other assets | | 798 |
| | 775 |
|
| Total Assets | | $ | 4,821 |
| | $ | 5,035 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholder's Equity | | At June 30, 2020 | | At December 31, 2019 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | — |
| | $ | 281 |
|
| Notes payable | | 4 |
| | — |
|
| Accounts payable — | | | | |
| Affiliated | | 75 |
| | 76 |
|
| Other | | 44 |
| | 75 |
|
| Accrued taxes | | 84 |
| | 105 |
|
| Accrued interest | | 15 |
| | 15 |
|
| Accrued compensation | | 21 |
| | 35 |
|
| Asset retirement obligations | | 28 |
| | 33 |
|
| Over recovered regulatory clause liabilities | | 29 |
| | 29 |
|
| Other regulatory liabilities | | 47 |
| | 21 |
|
| Other current liabilities | | 59 |
| | 64 |
|
| Total current liabilities | | 406 |
| | 734 |
|
| Long-term Debt | | 1,404 |
| | 1,308 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 422 |
| | 424 |
|
| Deferred credits related to income taxes | | 310 |
| | 352 |
|
| Employee benefit obligations | | 97 |
| | 99 |
|
| Asset retirement obligations, deferred | | 157 |
| | 157 |
|
| Other cost of removal obligations | | 193 |
| | 189 |
|
| Other regulatory liabilities, deferred | | 66 |
| | 76 |
|
| Other deferred credits and liabilities | | 42 |
| | 44 |
|
| Total deferred credits and other liabilities | | 1,287 |
| | 1,341 |
|
| Total Liabilities | | 3,097 |
| | 3,383 |
|
Common Stockholder's Equity (See accompanying statements) | | 1,724 |
| | 1,652 |
|
| Total Liabilities and Stockholder's Equity | | $ | 4,821 |
| | $ | 5,035 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
CONDENSED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY (UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | | | | |
| | Number of
Common
Shares
Issued | | Common
Stock | | Paid-In
Capital | | Retained
Earnings | | Accumulated
Other
Comprehensive
Income (Loss) | | Total |
| | (in millions) |
| Balance at December 31, 2018 | 1 |
| | $ | 38 |
| | $ | 4,546 |
| | $ | (2,971 | ) | | $ | (4 | ) | | $ | 1,609 |
|
| Net income | — |
| | — |
| | — |
| | 37 |
| | — |
| | 37 |
|
| Return of capital to parent company | — |
| | — |
| | (38 | ) | | — |
| | — |
| | (38 | ) |
| Capital contributions from parent company | — |
| | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
| Balance at March 31, 2019 | 1 |
| | 38 |
| | 4,510 |
| | (2,934 | ) | | (4 | ) | | 1,610 |
|
Net income after dividends on
preferred stock | — |
| | — |
| | — |
| | 37 |
| | — |
| | 37 |
|
| Return of capital to parent company | — |
| | — |
| | (38 | ) | | — |
| | — |
| | (38 | ) |
| Capital contributions from parent company | — |
| | — |
| | 8 |
| | — |
| | — |
| | 8 |
|
| Balance at June 30, 2019 | 1 |
| | $ | 38 |
| | $ | 4,480 |
| | $ | (2,897 | ) | | $ | (4 | ) | | $ | 1,617 |
|
| | | | | | | | | | | | |
| Balance at December 31, 2019 | 1 |
| | $ | 38 |
| | $ | 4,449 |
| | $ | (2,832 | ) | | $ | (3 | ) | | $ | 1,652 |
|
| Net income | — |
| | — |
| | — |
| | 32 |
| | — |
| | 32 |
|
| Return of capital to parent company | — |
| | — |
| | (37 | ) | | — |
| | — |
| | (37 | ) |
| Capital contributions from parent company | — |
| | — |
| | 76 |
| | — |
| | — |
| | 76 |
|
| Other | — |
| | — |
| | (1 | ) | | — |
| | — |
| | (1 | ) |
| Balance at March 31, 2020 | 1 |
| | 38 |
| | 4,487 |
| | (2,800 | ) | | (3 | ) | | 1,722 |
|
| Net income | — |
| | — |
| | — |
| | 39 |
| | — |
| | 39 |
|
| Return of capital to parent company | — |
| | — |
| | (37 | ) | | — |
| | — |
| | (37 | ) |
| Balance at June 30, 2020 | 1 |
| | $ | 38 |
| | $ | 4,450 |
| | $ | (2,761 | ) | | $ | (3 | ) | | $ | 1,724 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2020 | | 2019 | | 2020 | | 2019 |
| | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | |
| Wholesale revenues, non-affiliates | $ | 343 |
| | $ | 390 |
| | $ | 629 |
| | $ | 743 |
|
| Wholesale revenues, affiliates | 92 |
| | 117 |
| | 178 |
| | 204 |
|
| Other revenues | 4 |
| | 3 |
| | 7 |
| | 6 |
|
| Total operating revenues | 439 |
| | 510 |
| | 814 |
| | 953 |
|
| Operating Expenses: | | | | | | | |
| Fuel | 102 |
| | 139 |
| | 209 |
| | 284 |
|
| Purchased power | 18 |
| | 32 |
| | 32 |
| | 55 |
|
| Other operations and maintenance | 77 |
| | 79 |
| | 156 |
| | 166 |
|
| Depreciation and amortization | 121 |
| | 119 |
| | 239 |
| | 237 |
|
| Taxes other than income taxes | 10 |
| | 11 |
| | 19 |
| | 21 |
|
| (Gain) loss on dispositions, net | — |
| | (23 | ) | | (39 | ) | | (23 | ) |
| Total operating expenses | 328 |
| | 357 |
| | 616 |
| | 740 |
|
| Operating Income | 111 |
| | 153 |
| | 198 |
| | 213 |
|
| Other Income and (Expense): | | | | | | | |
| Interest expense, net of amounts capitalized | (38 | ) | | (41 | ) | | (77 | ) | | (84 | ) |
| Other income (expense), net | 1 |
| | 40 |
| | 4 |
| | 41 |
|
| Total other income and (expense) | (37 | ) | | (1 | ) | | (73 | ) | | (43 | ) |
| Earnings Before Income Taxes | 74 |
| | 152 |
| | 125 |
| | 170 |
|
| Income taxes (benefit) | 6 |
| | (51 | ) | | 13 |
| | (60 | ) |
| Net Income | 68 |
| | 203 |
| | 112 |
| | 230 |
|
| Net income (loss) attributable to noncontrolling interests | 5 |
| | 29 |
| | (26 | ) | | — |
|
| Net Income Attributable to Southern Power | $ | 63 |
| | $ | 174 |
| | $ | 138 |
| | $ | 230 |
|
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2020 | | 2019 | | 2020 | | 2019 |
| | (in millions) | | (in millions) |
| Net Income | $ | 68 |
| | $ | 203 |
| | $ | 112 |
| | $ | 230 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
Changes in fair value, net of tax of
$4, $(1), $(17), and $(10), respectively | 11 |
| | (1 | ) | | (50 | ) | | (30 | ) |
Reclassification adjustment for amounts included in net income,
net of tax of $(5), $(2), $5, and $6, respectively | (15 | ) | | (7 | ) | | 13 |
| | 17 |
|
| Pension and other postretirement benefit plans: | | | | | | | |
Reclassification adjustment for amounts included in net income,
net of tax of $-, $-, $-, and $-, respectively | 1 |
| | — |
| | 1 |
| | — |
|
| Total other comprehensive income (loss) | (3 | ) | | (8 | ) | | (36 | ) | | (13 | ) |
| Comprehensive Income | 65 |
| | 195 |
| | 76 |
| | 217 |
|
| Comprehensive income (loss) attributable to noncontrolling interests | 5 |
| | 29 |
| | (26 | ) | | — |
|
| Comprehensive Income Attributable to Southern Power | $ | 60 |
| | $ | 166 |
| | $ | 102 |
| | $ | 217 |
|
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, |
| | 2020 | | 2019 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 112 |
| | $ | 230 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 251 |
| | 251 |
|
| Deferred income taxes | (34 | ) | | (63 | ) |
| Utilization of federal investment tax credits | — |
| | 427 |
|
| Amortization of investment tax credits | (30 | ) | | (122 | ) |
| (Gain) loss on dispositions, net | (39 | ) | | (23 | ) |
| Other, net | (31 | ) | | (46 | ) |
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (67 | ) | | (9 | ) |
| -Prepaid income taxes | 73 |
| | 93 |
|
| -Other current assets | (8 | ) | | 4 |
|
| -Accounts payable | (29 | ) | | (17 | ) |
| -Accrued taxes | 16 |
| | 19 |
|
| -Other current liabilities | (19 | ) | | (25 | ) |
| Net cash provided from operating activities | 195 |
| | 719 |
|
| Investing Activities: | | | |
| Business acquisitions, net of cash acquired | (81 | ) | | (2 | ) |
| Property additions | (101 | ) | | (123 | ) |
| Proceeds from dispositions and asset sales | 660 |
| | 540 |
|
| Investment in unconsolidated subsidiaries | — |
| | (116 | ) |
| Payments pursuant to LTSAs | (31 | ) | | (31 | ) |
| Other investing activities | 43 |
| | (14 | ) |
| Net cash provided from investing activities | 490 |
| | 254 |
|
| Financing Activities: | | | |
| Decrease in notes payable, net | (357 | ) | | — |
|
| Redemptions — | | | |
| Short-term borrowings | (100 | ) | | (100 | ) |
| Senior notes | (300 | ) | | — |
|
| Return of capital to parent company | — |
| | (505 | ) |
| Distributions to noncontrolling interests | (118 | ) | | (82 | ) |
| Capital contributions from noncontrolling interests | 172 |
| | 5 |
|
| Payment of common stock dividends | (100 | ) | | (103 | ) |
| Other financing activities | (5 | ) | | 1 |
|
| Net cash used for financing activities | (808 | ) | | (784 | ) |
| Net Change in Cash, Cash Equivalents, and Restricted Cash | (123 | ) | | 189 |
|
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 279 |
| | 181 |
|
| Cash, Cash Equivalents, and Restricted Cash at End of Period | $ | 156 |
| | $ | 370 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
| Interest (net of $7 capitalized for both 2020 and 2019) | $ | 96 |
| | $ | 106 |
|
| Income taxes, net | (5 | ) | | (421 | ) |
| Noncash transactions — | | | |
| Accrued property additions at end of period | 38 |
| | 31 |
|
| Right-of-use assets obtained under operating leases | 30 |
| | — |
|
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, 2020 | | At December 31, 2019 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 154 |
| | $ | 279 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 160 |
| | 107 |
|
| Affiliated | | 46 |
| | 30 |
|
| Other | | 55 |
| | 73 |
|
| Materials and supplies | | 203 |
| | 191 |
|
| Prepaid income taxes | | 402 |
| | 36 |
|
| Other current assets | | 23 |
| | 43 |
|
| Total current assets | | 1,043 |
| | 759 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 13,634 |
| | 13,270 |
|
| Less: Accumulated provision for depreciation | | 2,689 |
| | 2,464 |
|
| Plant in service, net of depreciation | | 10,945 |
| | 10,806 |
|
| Construction work in progress | | 314 |
| | 515 |
|
| Total property, plant, and equipment | | 11,259 |
| | 11,321 |
|
| Other Property and Investments: | | | | |
Intangible assets, net of amortization of $79 and $69
at June 30, 2020 and December 31, 2019, respectively | | 312 |
| | 322 |
|
| Equity investments in unconsolidated subsidiaries | | 19 |
| | 28 |
|
| Total other property and investments | | 331 |
| | 350 |
|
| Deferred Charges and Other Assets: | | | | |
| Operating lease right-of-use assets, net of amortization | | 397 |
| | 369 |
|
| Prepaid LTSAs | | 140 |
| | 128 |
|
| Accumulated deferred income taxes | | 156 |
| | 551 |
|
| Income taxes receivable, non-current | | 11 |
| | 5 |
|
| Assets held for sale | | — |
| | 601 |
|
| Other deferred charges and assets | | 220 |
| | 216 |
|
| Total deferred charges and other assets | | 924 |
| | 1,870 |
|
| Total Assets | | $ | 13,557 |
| | $ | 14,300 |
|
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, 2020 | | At December 31, 2019 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 525 |
| | $ | 824 |
|
| Notes payable | | 92 |
| | 549 |
|
| Accounts payable — | | | | |
| Affiliated | | 52 |
| | 56 |
|
| Other | | 59 |
| | 85 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 10 |
| | — |
|
| Other accrued taxes | | 26 |
| | 26 |
|
| Accrued interest | | 23 |
| | 32 |
|
| Other current liabilities | | 127 |
| | 132 |
|
| Total current liabilities | | 914 |
| | 1,704 |
|
| Long-term Debt | | 3,572 |
| | 3,574 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 114 |
| | 115 |
|
| Accumulated deferred ITCs | | 1,701 |
| | 1,731 |
|
| Operating lease obligations | | 404 |
| | 376 |
|
| Other deferred credits and liabilities | | 193 |
| | 178 |
|
| Total deferred credits and other liabilities | | 2,412 |
| | 2,400 |
|
| Total Liabilities | | 6,898 |
| | 7,678 |
|
Total Stockholders' Equity (See accompanying statements) | | 6,659 |
| | 6,622 |
|
| Total Liabilities and Stockholders' Equity | | $ | 13,557 |
| | $ | 14,300 |
|
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 STOCKHOLDERS' EQUITY (UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Paid-In
Capital | | Retained
Earnings | | Accumulated
Other
Comprehensive
Income (Loss) | | Total Common
Stockholders' Equity | | Noncontrolling Interests | | Total |
| | (in millions) |
| Balance at December 31, 2018 | $ | 1,600 |
| | $ | 1,352 |
| | $ | 16 |
| | $ | 2,968 |
| | $ | 4,316 |
| | $ | 7,284 |
|
| Net income (loss) | — |
| | 56 |
| | — |
| | 56 |
| | (29 | ) | | 27 |
|
| Capital contributions from parent company | 1 |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
|
| Other comprehensive income (loss) | — |
| | — |
| | (4 | ) | | (4 | ) | | — |
| | (4 | ) |
| Cash dividends on common stock | — |
| | (51 | ) | | — |
| | (51 | ) | | — |
| | (51 | ) |
Capital contributions from
noncontrolling interests | — |
| | — |
| | — |
| | — |
| | 3 |
| | 3 |
|
| Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | (41 | ) | | (41 | ) |
| Other | (1 | ) | | (1 | ) | | — |
| | (2 | ) | | 1 |
| | (1 | ) |
| Balance at March 31, 2019 | 1,600 |
| | 1,356 |
| | 12 |
| | 2,968 |
| | 4,250 |
| | 7,218 |
|
| Net income | — |
| | 174 |
| | — |
| | 174 |
| | 29 |
| | 203 |
|
| Return of capital to parent company | (505 | ) | | — |
| | — |
| | (505 | ) | | — |
| | (505 | ) |
| Capital contributions from parent company | 7 |
| | — |
| | — |
| | 7 |
| | — |
| | 7 |
|
| Other comprehensive income (loss) | — |
| | — |
| | (8 | ) | | (8 | ) | | — |
| | (8 | ) |
| Cash dividends on common stock | — |
| | (52 | ) | | — |
| | (52 | ) | | — |
| | (52 | ) |
Capital contributions from
noncontrolling interests | — |
| | — |
| | — |
| | — |
| | 2 |
| | 2 |
|
| Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | (47 | ) | | (47 | ) |
| Other | — |
| | 1 |
| | — |
| | 1 |
| | (1 | ) | | — |
|
| Balance at June 30, 2019 | $ | 1,102 |
| | $ | 1,479 |
| | $ | 4 |
| | $ | 2,585 |
| | $ | 4,233 |
| | $ | 6,818 |
|
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Paid-In
Capital | | Retained
Earnings | | Accumulated
Other
Comprehensive
Income (Loss) | | Total Common
Stockholders' Equity | | Noncontrolling Interests | | Total |
| | (in millions) |
| Balance at December 31, 2019 | $ | 909 |
| | $ | 1,485 |
| | $ | (26 | ) | | $ | 2,368 |
| | $ | 4,254 |
| | $ | 6,622 |
|
| Net income (loss) | — |
| | 75 |
| | — |
| | 75 |
| | (31 | ) | | 44 |
|
| Other comprehensive income (loss) | — |
| | — |
| | (33 | ) | | (33 | ) | | — |
| | (33 | ) |
| Cash dividends on common stock | — |
| | (50 | ) | | — |
| | (50 | ) | | — |
| | (50 | ) |
Capital contributions from
noncontrolling interests | — |
| | — |
| | — |
| | — |
| | 16 |
| | 16 |
|
| Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | (48 | ) | | (48 | ) |
| Balance at March 31, 2020 | 909 |
| | 1,510 |
| | (59 | ) | | 2,360 |
| | 4,191 |
| | 6,551 |
|
| Net income | — |
| | 63 |
| | — |
| | 63 |
| | 5 |
| | 68 |
|
| Other comprehensive income (loss) | — |
| | — |
| | (3 | ) | | (3 | ) | | — |
| | (3 | ) |
| Cash dividends on common stock | — |
| | (50 | ) | | — |
| | (50 | ) | | — |
| | (50 | ) |
Capital contributions from
noncontrolling interests | — |
| | — |
| | — |
| | — |
| | 165 |
| | 165 |
|
| Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | (70 | ) | | (70 | ) |
| Other | (2 | ) | | — |
| | — |
| | (2 | ) | | — |
| | (2 | ) |
| Balance at June 30, 2020 | $ | 907 |
| | $ | 1,523 |
| | $ | (62 | ) | | $ | 2,368 |
| | $ | 4,291 |
| | $ | 6,659 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2020 | | 2019 | | 2020 | | 2019 |
| | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | |
Natural gas revenues (includes revenue taxes of
$22, $23, $69, and $78, respectively) | $ | 638 |
| | $ | 688 |
| | $ | 1,878 |
| | $ | 2,163 |
|
| Alternative revenue programs | (2 | ) | | 1 |
| | 7 |
| | — |
|
| Total operating revenues | 636 |
| | 689 |
| | 1,885 |
| | 2,163 |
|
| Operating Expenses: | | | | | | | |
| Cost of natural gas | 144 |
| | 191 |
| | 583 |
| | 877 |
|
| Other operations and maintenance | 220 |
| | 199 |
| | 479 |
| | 433 |
|
| Depreciation and amortization | 123 |
| | 119 |
| | 243 |
| | 238 |
|
| Taxes other than income taxes | 47 |
| | 46 |
| | 118 |
| | 128 |
|
| Total operating expenses | 534 |
| | 555 |
| | 1,423 |
| | 1,676 |
|
| Operating Income | 102 |
| | 134 |
| | 462 |
| | 487 |
|
| Other Income and (Expense): | | | | | | | |
| Earnings from equity method investments | 30 |
| | 31 |
| | 72 |
| | 80 |
|
| Interest expense, net of amounts capitalized | (57 | ) | | (59 | ) | | (114 | ) | | (118 | ) |
| Other income (expense), net | 12 |
| | 6 |
| | 21 |
| | 10 |
|
| Total other income and (expense) | (15 | ) | | (22 | ) | | (21 | ) | | (28 | ) |
| Earnings Before Income Taxes | 87 |
| | 112 |
| | 441 |
| | 459 |
|
| Income taxes | 16 |
| | 6 |
| | 95 |
| | 83 |
|
| Net Income | $ | 71 |
| | $ | 106 |
| | $ | 346 |
| | $ | 376 |
|
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2020 | | 2019 | | 2020 | | 2019 |
| | (in millions) | | (in millions) |
| Net Income | $ | 71 |
| | $ | 106 |
| | $ | 346 |
| | $ | 376 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
Changes in fair value, net of tax of
$(1), $(1), $(8), and $(1), respectively | (1 | ) | | (3 | ) | | (21 | ) | | (3 | ) |
Reclassification adjustment for amounts included in net income,
net of tax of $-, $-, $2, and $-, respectively | 1 |
| | — |
| | 6 |
| | — |
|
| Pension and other postretirement benefit plans: | | | | | | | |
Reclassification adjustment for amounts included in net income,
net of tax of $-, $(1), $1, and $(1), respectively | — |
| | — |
| | — |
| | (1 | ) |
| Total other comprehensive income (loss) | — |
| | (3 | ) | | (15 | ) | | (4 | ) |
| Comprehensive Income | $ | 71 |
| | $ | 103 |
| | $ | 331 |
| | $ | 372 |
|
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)
|
| | | | | | | |
| | For the Six Months Ended June 30, |
| | 2020 | | 2019 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 346 |
| | $ | 376 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 243 |
| | 238 |
|
| Deferred income taxes | 40 |
| | 59 |
|
| Mark-to-market adjustments | 34 |
| | 30 |
|
| Other, net | 11 |
| | (26 | ) |
| Changes in certain current assets and liabilities — | | | |
| -Receivables | 344 |
| | 717 |
|
| -Natural gas for sale | 182 |
| | 256 |
|
| -Other current assets | 6 |
| | 29 |
|
| -Accounts payable | (176 | ) | | (604 | ) |
| -Accrued taxes | 26 |
| | (54 | ) |
| -Accrued compensation | (31 | ) | | (34 | ) |
| -Other current liabilities | 21 |
| | (56 | ) |
| Net cash provided from operating activities | 1,046 |
| | 931 |
|
| Investing Activities: | | | |
| Property additions | (647 | ) | | (603 | ) |
| Cost of removal, net of salvage | (31 | ) | | (33 | ) |
| Investment in unconsolidated subsidiaries | (78 | ) | | (18 | ) |
| Proceeds from dispositions and asset sales | 178 |
| | 32 |
|
| Other investing activities | 8 |
| | 36 |
|
| Net cash used for investing activities | (570 | ) | | (586 | ) |
| Financing Activities: | | | |
| Decrease in notes payable, net | (321 | ) | | (158 | ) |
| Proceeds — Capital contributions from parent company | 186 |
| | 38 |
|
| Payment of common stock dividends | (266 | ) | | (235 | ) |
| Net cash used for financing activities | (401 | ) | | (355 | ) |
| Net Change in Cash, Cash Equivalents, and Restricted Cash | 75 |
| | (10 | ) |
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 49 |
| | 70 |
|
| Cash, Cash Equivalents, and Restricted Cash at End of Period | $ | 124 |
| | $ | 60 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
| Interest (net of $4 and $3 capitalized for 2020 and 2019, respectively) | $ | 119 |
| | $ | 125 |
|
| Income taxes, net | (4 | ) | | 96 |
|
| Noncash transactions — Accrued property additions at end of period | 123 |
| | 123 |
|
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, 2020 | | At December 31, 2019 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 120 |
| | $ | 46 |
|
| Receivables — | | | | |
| Energy marketing receivables | | 273 |
| | 428 |
|
| Customer accounts receivable | | 269 |
| | 323 |
|
| Unbilled revenues | | 57 |
| | 183 |
|
| Affiliated | | 5 |
| | 5 |
|
| Other accounts and notes receivable | | 117 |
| | 114 |
|
| Accumulated provision for uncollectible accounts | | (35 | ) | | (18 | ) |
| Natural gas for sale | | 282 |
| | 479 |
|
| Prepaid expenses | | 60 |
| | 65 |
|
| Assets from risk management activities, net of collateral | | 103 |
| | 177 |
|
| Other regulatory assets | | 86 |
| | 92 |
|
| Assets held for sale | | — |
| | 171 |
|
| Other current assets | | 49 |
| | 41 |
|
| Total current assets | | 1,386 |
| | 2,106 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 16,718 |
| | 16,344 |
|
| Less: Accumulated depreciation | | 4,704 |
| | 4,650 |
|
| Plant in service, net of depreciation | | 12,014 |
| | 11,694 |
|
| Construction work in progress | | 770 |
| | 613 |
|
| Total property, plant, and equipment | | 12,784 |
| | 12,307 |
|
| Other Property and Investments: | | | | |
| Goodwill | | 5,015 |
| | 5,015 |
|
| Equity investments in unconsolidated subsidiaries | | 1,308 |
| | 1,251 |
|
Other intangible assets, net of amortization of $186 and $176
at June 30, 2020 and December 31, 2019, respectively | | 60 |
| | 70 |
|
| Miscellaneous property and investments | | 20 |
| | 20 |
|
| Total other property and investments | | 6,403 |
| | 6,356 |
|
| Deferred Charges and Other Assets: | | | | |
| Operating lease right-of-use assets, net of amortization | | 88 |
| | 93 |
|
| Other regulatory assets, deferred | | 581 |
| | 618 |
|
| Other deferred charges and assets | | 258 |
| | 207 |
|
| Total deferred charges and other assets | | 927 |
| | 918 |
|
| Total Assets | | $ | 21,500 |
| | $ | 21,687 |
|
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, 2020 | | At December 31, 2019 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 31 |
| | $ | — |
|
| Notes payable | | 329 |
| | 650 |
|
| Energy marketing trade payables | | 284 |
| | 442 |
|
| Accounts payable — | | | | |
| Affiliated | | 50 |
| | 41 |
|
| Other | | 290 |
| | 315 |
|
| Customer deposits | | 86 |
| | 96 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 32 |
| | — |
|
| Other accrued taxes | | 65 |
| | 71 |
|
| Accrued interest | | 53 |
| | 52 |
|
| Accrued compensation | | 68 |
| | 100 |
|
| Liabilities from risk management activities, net of collateral | | 39 |
| | 21 |
|
| Other regulatory liabilities | | 146 |
| | 94 |
|
| Other current liabilities | | 122 |
| | 128 |
|
| Total current liabilities | | 1,595 |
| | 2,010 |
|
| Long-term Debt | | 5,796 |
| | 5,845 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 1,256 |
| | 1,219 |
|
| Deferred credits related to income taxes | | 859 |
| | 874 |
|
| Employee benefit obligations | | 253 |
| | 265 |
|
| Operating lease obligations | | 73 |
| | 78 |
|
| Other cost of removal obligations | | 1,639 |
| | 1,606 |
|
| Accrued environmental remediation | | 220 |
| | 233 |
|
| Other deferred credits and liabilities | | 40 |
| | 51 |
|
| Total deferred credits and other liabilities | | 4,340 |
| | 4,326 |
|
| Total Liabilities | | 11,731 |
| | 12,181 |
|
Common Stockholder's Equity (See accompanying statements) | | 9,769 |
| | 9,506 |
|
| Total Liabilities and Stockholder's Equity | | $ | 21,500 |
| | $ | 21,687 |
|
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 STOCKHOLDER'S EQUITY (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | Paid-In
Capital | | Retained
Earnings (Accumulated Deficit) | | Accumulated
Other
Comprehensive
Income (Loss) | | Total |
| | (in millions) |
| Balance at December 31, 2018 | $ | 8,856 |
| | $ | (312 | ) | | $ | 26 |
| | $ | 8,570 |
|
| Net income | — |
| | 270 |
| | — |
| | 270 |
|
| Capital contributions from parent company | 17 |
| | — |
| | — |
| | 17 |
|
| Other comprehensive income (loss) | — |
| | — |
| | (1 | ) | | (1 | ) |
| Cash dividends on common stock | — |
| | (118 | ) | | — |
| | (118 | ) |
| Balance at March 31, 2019 | 8,873 |
| | (160 | ) | | 25 |
| | 8,738 |
|
| Net income | — |
| | 106 |
| | — |
| | 106 |
|
| Capital contributions from parent company | 35 |
| | — |
| | — |
| | 35 |
|
| Other comprehensive income (loss) | — |
| | — |
| | (3 | ) | | (3 | ) |
| Cash dividends on common stock | — |
| | (117 | ) | | — |
| | (117 | ) |
| Balance at June 30, 2019 | $ | 8,908 |
| | $ | (171 | ) | | $ | 22 |
| | $ | 8,759 |
|
| | | | | | | | |
| Balance at December 31, 2019 | $ | 9,697 |
| | $ | (198 | ) | | $ | 7 |
| | $ | 9,506 |
|
| Net income | — |
| | 275 |
| | — |
| | 275 |
|
| Return of capital to parent company | (2 | ) | | — |
| | — |
| | (2 | ) |
| Other comprehensive income (loss) | — |
| | — |
| | (15 | ) | | (15 | ) |
| Cash dividends on common stock | — |
| | (133 | ) | | — |
| | (133 | ) |
| Balance at March 31, 2020 | 9,695 |
| | (56 | ) | | (8 | ) | | 9,631 |
|
| Net income | — |
| | 71 |
| | — |
| | 71 |
|
| Capital contributions from parent company | 200 |
| | — |
| | — |
| | 200 |
|
| Cash dividends on common stock | — |
| | (133 | ) | | — |
| | (133 | ) |
| Balance at June 30, 2020 | $ | 9,895 |
| | $ | (118 | ) | | $ | (8 | ) | | $ | 9,769 |
|
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS
FOR
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA 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
INDEX TO APPLICABLE NOTES TO FINANCIAL STATEMENTS BY REGISTRANT
The following unaudited notes to the condensed financial statements are a vertically integrated utility providing electric servicecombined presentation; however, information contained herein relating to retail customers withinany individual Registrant is filed by such Registrant on its traditional service territory located withinown behalf and each Registrant makes no representation as to information related to the Stateother Registrants. 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, L |
| Alabama Power | A, B, C, D, F, G, H, I, J, K |
| Georgia Power | A, B, C, D, F, G, H, I, J |
| Mississippi Power | A, B, C, D, F, G, H, I, J |
| Southern Power | A, C, D, E, F, G, H, I, J, K |
| Southern Company Gas | A, B, C, D, E, F, G, H, I, J, K, L |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS
(UNAUDITED)
(A) INTRODUCTION
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, 2019 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 wholesale customerspresent fairly the results of operations for the periods ended June 30, 2020 and 2019. 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 Southeast.
ManyForm 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 and other factors, affectincluding the opportunities, challenges, and risksimpacts 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. EffectivelyCOVID-19 pandemic, operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Georgia Powerresults for the foreseeable future.periods presented are not necessarily indicative of the operating results to be expected for the full year.
Georgia Power continuesCertain prior year data presented in the financial statements have been reclassified to focusconform to the current year presentation. These reclassifications had no impact on several key performance indicatorsthe overall results of operations, financial position, or cash flows of any Registrant.
Goodwill and Other Intangible Assets
Goodwill at June 30, 2020 and December 31, 2019 was as follows: |
| | | |
| | Goodwill |
| | (in millions) |
| Southern Company | $ | 5,280 |
|
| Southern Company Gas: | |
| Gas distribution operations | $ | 4,034 |
|
| Gas marketing services | 981 |
|
| Southern Company Gas total | $ | 5,015 |
|
Goodwill is not amortized but is subject to an annual impairment test in the fourth quarter of the year and on an interim basis as events and changes in circumstances occur, including, but not limited to, customer satisfaction, plant availability, system reliability,a significant change in operating performance, the executionbusiness climate, legal or regulatory factors, or a planned sale or disposition of major construction projects, and net income after dividends on preferred and preference stock.
Nuclear Construction
Georgia Power and the Vogtle Owners have been constructing Plant Vogtle Units 3 and 4 since 2009. On March 29, 2017, the EPC Contractor for Plant Vogtle Units 3 and 4 filed for bankruptcy protection under Chapter 11a significant portion of the U.S. Bankruptcy Code. To provide for a continuation of work, Georgia Power, acting for itselfbusiness. The continued COVID-19 pandemic 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 Powerrelated responses continue to disrupt supply chains and the other Vogtle Ownerscapital markets, reduce labor availability 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,productivity, and that the Guarantee Obligations exist regardless of whether Plant Vogtle Units 3 and 4 are completed. On October 2, 2017, Georgia Power received the first installment of the Guarantee Obligations of $300 million from Toshiba, of which Georgia Power's proportionate share was $137 million.
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. Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement (Bechtel Agreement) with Bechtel Power Corporation (Bechtel), whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4.
In the seventeenth Vogtle Construction Monitoring (VCM) report filed on August 31, 2017, Georgia Power recommended that construction of Plant Vogtle Units 3 and 4 be continued, with Southern Nuclear serving as project manager. Georgia Power believes that the most reasonable schedule for completing Plant Vogtle Units 3 and
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
4 is by November 2021 for Unit 3 and by November 2022 for Unit 4, at an additional cost of approximately $1.41 billion, net of the Guarantee Settlement Agreement. The Georgia PSC is expected to make a decision on these matters by February 6, 2018.
On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to the financial statements 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.
An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreementreduce economic activity. These effects could have a further materialvariety of adverse impacts on Southern Company and its subsidiaries, including the $263 million of goodwill recorded at PowerSecure. If the impact onof the net costCOVID-19 pandemic becomes significant to the Vogtle Owners to complete constructionoperating results of Plant Vogtle Units 3PowerSecure and 4 and, therefore, on Georgia Power's financial statements. The ultimate outcome of these matters 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 cost-to-complete and cancellation cost assessments for Plant Vogtle Units 3 and 4.
RESULTS OF OPERATIONS
Net Income
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(20) | | (3.3) | | $(29) | | (2.4) |
Georgia Power's net income after dividends on preferred and preference stock for the third quarter 2017 was $580 million compared to $600 million for the corresponding period in 2016. For year-to-date 2017, net income after dividends on preferred and preference stock was $1.19 billion compared to $1.22 billion for the corresponding period in 2016. The decreases were primarily due to lower revenues resulting from milder weather and lower customer usage as compared to the corresponding periods in 2016, partially offset by lower non-fuel operations and maintenance expenses.
Retail Revenues
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(138) | | (5.4) | | $(169) | | (2.7) |
In the third quarter 2017, retail revenues were $2.40 billion compared to $2.54 billion for the corresponding period in 2016. For year-to-date 2017, retail revenues were $6.00 billion compared to $6.16 billion for the corresponding period in 2016.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Detailsits businesses, a portion of the changes in retail revenues were as follows:
|
| | | | | | | | | | | | | |
| | Third Quarter 2017 | | Year-to-Date 2017 |
| | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | $ | 2,540 |
| | | | $ | 6,164 |
| | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 41 |
| | 1.6 |
| | 60 |
| | 1.0 |
|
| Sales decline | (39 | ) | | (1.5 | ) | | (50 | ) | | (0.8 | ) |
| Weather | (94 | ) | | (3.7 | ) | | (204 | ) | | (3.3 | ) |
| Fuel cost recovery | (46 | ) | | (1.8 | ) | | 25 |
| | 0.4 |
|
| Retail – current year | $ | 2,402 |
| | (5.4 | )% | | $ | 5,995 |
| | (2.7 | )% |
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016 primarily due to an increase in revenues related to the recovery of Plant Vogtle Units 3 and 4 construction financing costs under the NCCR tariff. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" 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 decreased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016. Weather-adjusted residential KWH sales decreased 3.5% and 0.8% for the third quarter and year-to-date 2017, respectively, primarily due to a decline in average customer usage due to an increase in multi-family housing and energy saving initiatives, partially offset by customer growth. Weather-adjusted commercial KWH sales decreased 1.4% and 1.1% for the third quarter and year-to-date 2017, respectively, primarily due to a decline in average customer usage resulting from an increase in energy saving initiatives and electronic commerce transactions, partially offset by customer growth. Weather-adjusted industrial KWH sales increased 0.8% in the third quarter 2017 primarily due to increased demand in the non-manufacturing, rubber, and textile sectors, partially offset by decreased demand in the chemicals and paper sectors. Weather-adjusted industrial KWH sales decreased 1.2% for year-to-date 2017 primarily due to decreased demand in the paper and chemicals sectors, 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. Additionally, Hurricane Irma negatively impacted customer usage for all customer classes during the third quarter and year-to-date 2017.
Fuel revenues and costs are allocated between retail and wholesale jurisdictions. In the third quarter 2017, retail fuel cost recovery revenues decreased $46 million when compared to the corresponding period in 2016 primarily due to lower coal prices and lower energy sales resulting from milder weather. For year-to-date 2017, retail fuel cost recovery revenues increased $25 million when compared to the corresponding period in 2016 primarily due to higher natural gas prices, partially offset by lower coal prices and lower energy sales resulting from milder weather. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See 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.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Revenues
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(7) | | (7.0) | | $(18) | | (6.0) |
In the third quarter 2017, other revenues were $93 million compared to $100 million for the corresponding period in 2016. The decrease was primarily due to a $3 million decrease in open access transmission tariff revenues, primarily as a result of the expiration of long-term transmission services contracts, and a $3 million decrease in solar application fee revenues, partially offset by a $3 million increase in outdoor lighting sales revenues primarily attributable to LED conversions.
For year-to-date 2017, other revenues were $284 million compared to $302 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 a $12 million decrease in open access transmission tariff revenues, primarily as a result of the expiration of long-term transmission services contracts, partially offset by a $10 million increase in outdoor lighting sales revenues primarily attributable to LED conversions.
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | | | |
| | Third Quarter 2017
vs.
Third Quarter 2016 | | Year-to-Date 2017
vs.
Year-to-Date 2016 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | (93 | ) | | (16.2 | ) | | $ | (93 | ) | | (6.7 | ) |
| Purchased power – non-affiliates | 17 |
| | 16.7 |
| | 33 |
| | 11.9 |
|
| Purchased power – affiliates | 19 |
| | 13.4 |
| | 78 |
| | 19.9 |
|
| Total fuel and purchased power expenses | $ | (57 | ) | | | | $ | 18 |
| | |
In the third quarter 2017, total fuel and purchased power expenses were $762 million compared to $819 million in the corresponding period in 2016. The decrease was primarily due to a $59 million decrease related to the volume of KWHs generated primarily due to milder weather, resulting in lower customer demand, and slight decreases in the volume of KWHs purchased and the average cost of fuel. These decreases were partially offset by a $7 million increase in the average cost of purchased power primarily related to higher natural gas prices.
For year-to-date 2017, total fuel and purchased power expenses were $2.08 billion compared to $2.06 billion in the corresponding period in 2016. The increase was primarily due to a $97 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 $79 million related to the volume of KWHs generated and purchased primarily 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.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of Georgia Power's generation and purchased power were as follows:
|
| | | | | | | |
| | Third Quarter 2017 | | Third Quarter 2016 | | Year-to-Date 2017 | | Year-to-Date 2016 |
Total generation (in billions of KWHs) | 18 | | 20 | | 48 | | 53 |
Total purchased power (in billions of KWHs) | 7 | | 7 | | 20 | | 19 |
Sources of generation (percent) — | | | | | | | |
| Coal | 35 | | 44 | | 33 | | 37 |
| Nuclear | 23 | | 22 | | 24 | | 23 |
| Gas | 41 | | 34 | | 41 | | 38 |
| Hydro | 1 | | — | | 2 | | 2 |
Cost of fuel, generated (in cents per net KWH) — | | | | | | | |
| Coal | 3.08 | | 3.16 | | 3.17 | | 3.32 |
| Nuclear | 0.84 | | 0.85 | | 0.84 | | 0.85 |
| Gas | 2.63 | | 2.61 | | 2.71 | | 2.27 |
Average cost of fuel, generated (in cents per net KWH) | 2.38 | | 2.47 | | 2.40 | | 2.34 |
Average cost of purchased power (in cents per net KWH)(*) | 4.68 | | 4.57 | | 4.63 | | 4.46 |
| |
(*) | Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider. |
Fuel
In the third quarter 2017, fuel expense was $482 million compared to $575 million in the corresponding period in 2016. The decrease was primarily due to a 9.6% decrease in the volume of KWHs generated largely due to milder weather, resulting in lower customer demand, and a 3.6% decrease in the average cost of fuel per KWH generated primarily resulting from lower coal prices.
For year-to-date 2017, fuel expense was $1.30 billion compared to $1.39 billion in the corresponding period in 2016. The decrease was primarily due to an 8.4% decrease in the volume of KWHs generated largely due to milder weather, resulting in lower customer demand, partially offset by a 19.4% increase in the average cost of natural gas per KWH generated.
Purchased Power – Non-Affiliates
In the third quarter 2017, purchased power expense from non-affiliates was $119 million compared to $102 million in the corresponding period in 2016. For year-to-date 2017, purchased power expense from non-affiliates was $310 million compared to $277 million in the corresponding period in 2016. The increases were primarily due to increases in the volume of KWHs purchased of 14.2% and 12.6% in the third quarter and year-to-date 2017, respectively, primarily due to unplanned outages at Georgia Power-owned generating units. The increase for year-to-date 2017 was partially offset by a 1.5% decrease in the average cost per KWH purchased.
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 2017, purchased power expense from affiliates was $161 million compared to $142 million in the corresponding period in 2016. The increase was primarily due to a 1.5% increase in the average cost per KWH purchased primarily resulting from higher natural gas prices, partially offset by a 5.6% decrease in the volume of
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
KWHs purchased due to the expiration of a PPA in May 2017 and milder weather, resulting in lower customer demand.
For year-to-date 2017, purchased power expense from affiliates was $470 million compared to $392 million in the corresponding period in 2016. The increase was primarily the result of a 4.3% increase in the volume of KWHs purchased to support Southern Company system transmission reliability and due to unplanned outages at Georgia Power-owned generating units and a 5.9% 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
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(83) | | (16.7) | | $(199) | | (14.3) |
In the third quarter 2017, other operations and maintenance expenses were $413 million compared to $496 million in the corresponding period in 2016. The decrease was primarily due to cost containment and modernization activities implemented in the third quarter 2016 that contributed to decreases of $29 million in generation maintenance costs, $9 million in customer accounts, service, and sales costs, $8 million in employee benefits, and $8 million in transmission and distribution overhead line maintenance. Other factors include decreases of $12 million in charges related to employee attrition plans and $8 million in scheduled generation outage costs.
For year-to-date 2017, other operations and maintenance expenses were $1.19 billion compared to $1.39 billion in the corresponding period in 2016. The decrease was primarily due to cost containment and modernization activities implemented in the third quarter 2016 that contributed to decreases of $56 million in generation maintenance costs, $34 million in other employee compensation and benefits, and $23 million in transmission and distribution overhead line maintenance. Other factors include a $19 million increase in gains from sales of integrated transmission system assets, a $16 million decrease in customer assistance expenses primarily in demand-side management costs related to the timing of new programs, an $8 million decrease in charges related to employee attrition plans, and a $7 million decrease in billing adjustments with integrated transmission system owners.
Depreciation and Amortization
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $10 | | 4.7 | | $30 | | 4.7 |
In the third quarter 2017, depreciation and amortization was $225 million compared to $215 million in the corresponding period in 2016. The increase was primarily due to an $8 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 $669 million compared to $639 million in the corresponding period in 2016. The increase was primarily due to a $25 million increase related to additional plant in service and an $11 million decrease in amortization of regulatory liabilities related to other cost of removal obligations that expired in December 2016, partially offset by a $5 million decrease in depreciation related to generating unit retirements in 2016.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Interest Expense, Net of Amounts Capitalized
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $7 | | 7.1 | | $20 | | 6.9 |
In the third quarter 2017, interest expense, net of amounts capitalized was $105 million compared to $98 million in the corresponding period in 2016. For year-to-date 2017, interest expense, net of amounts capitalized was $310 million compared to $290 million in the corresponding period in 2016. The increases were primarily due to increases in outstanding borrowings. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information.
Other Income (Expense), Net
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(6) | | (54.5) | | $6 | | 17.1 |
In the third quarter 2017, other income (expense), net was $5 million compared to $11 million in the corresponding period in 2016. The decrease was primarily due to a decrease of $9 million in AFUDC equity resulting from higher short-term borrowings, partially offset by increases of $3 million in customer contributions in aid of construction and $3 million in contract services revenue.
For year-to-date 2017, other income (expense), net was $41 million compared to $35 million in the corresponding period in 2016. The increase was primarily due to increases of $6 million in contract services revenue, $4 million in customer contributions in aid of construction, and $4 million in gains on purchases of state tax credits, partially offset by a $7 million decrease in AFUDC equity resulting from higher short-term borrowings.
Income Taxes
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(13) | | (3.6) | | $(29) | | (4.0) |
In the third quarter 2017, income taxes were $350 million compared to $363 million in the corresponding period in 2016. For year-to-date 2017, income taxes were $705 million compared to $734 million in the corresponding period in 2016. The decreases were primarily due to lower pre-tax earnings and increased state ITCs.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Georgia Power's future earnings potential. The level of Georgia Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Georgia Power's business of providing electric service. These factors include Georgia Power's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs during a time of increasing costs and limited projected demand growth over the next several years. Matters related to Plant Vogtle Units 3 and 4 construction and rate recovery are also major factors. Future earnings will be driven primarily by customer growth. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies, increasing volumes of electronic commerce transactions, and higher multi-family home construction. Earnings are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Georgia Power's service territory. Demand for electricity is primarily driven by the pace of economic
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
growth thatgoodwill 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 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 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. However, on August 2, 2017, the EPA issued a withdrawal notice of the one-year extension and reinstated the original October 1, 2017 designation deadline.become impaired. The ultimate outcome of this matter cannot be determined at this time.
Water Quality
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Other intangible assets were as follows:
|
| | | | | | | | | | | | | | | | | | | |
| | At June 30, 2020 | | At December 31, 2019 |
| | 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 | $ | 212 |
| $ | (126 | ) | $ | 86 |
| | $ | 212 |
| $ | (116 | ) | $ | 96 |
|
| Trade names | 64 |
| (28 | ) | 36 |
| | 64 |
| (25 | ) | 39 |
|
| Storage and transportation contracts | 64 |
| (63 | ) | 1 |
| | 64 |
| (62 | ) | 2 |
|
| PPA fair value adjustments | 390 |
| (79 | ) | 311 |
| | 390 |
| (69 | ) | 321 |
|
| Other | 10 |
| (8 | ) | 2 |
| | 11 |
| (8 | ) | 3 |
|
| Total other intangible assets subject to amortization | $ | 740 |
| $ | (304 | ) | $ | 436 |
|
| $ | 741 |
| $ | (280 | ) | $ | 461 |
|
| Other intangible assets not subject to amortization: | | | | | | | |
| Federal Communications Commission licenses | 75 |
| — |
| 75 |
| | 75 |
| — |
| 75 |
|
| Total other intangible assets | $ | 815 |
| $ | (304 | ) | $ | 511 |
| | $ | 816 |
| $ | (280 | ) | $ | 536 |
|
| | | | | | | | |
| Southern Power | | | | | | | |
| Other intangible assets subject to amortization: | | | | | | | |
| PPA fair value adjustments | $ | 390 |
| $ | (79 | ) | $ | 311 |
| | $ | 390 |
| $ | (69 | ) | $ | 321 |
|
| | | | | | | | |
| Southern Company Gas | | | | | | | |
| Other intangible assets subject to amortization: | | | | | | | |
| Gas marketing services | | | | | | | |
| Customer relationships | $ | 156 |
| $ | (112 | ) | $ | 44 |
| | $ | 156 |
| $ | (104 | ) | $ | 52 |
|
| Trade names | 26 |
| (11 | ) | 15 |
| | 26 |
| (10 | ) | 16 |
|
| Wholesale gas services | | | | | | | |
| Storage and transportation contracts | 64 |
| (63 | ) | 1 |
| | 64 |
| (62 | ) | 2 |
|
| Total other intangible assets subject to amortization | $ | 246 |
| $ | (186 | ) | $ | 60 |
| | $ | 246 |
| $ | (176 | ) | $ | 70 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Amortization associated with other intangible assets was as follows:
|
| | | | | | |
| | Three Months Ended | Six Months Ended |
| | June 30, 2020 |
| | (in millions) |
Southern Company(a) | $ | 13 |
| $ | 25 |
|
Southern Power(b) | $ | 5 |
| $ | 10 |
|
| Southern Company Gas |
|
| |
| Gas marketing services | $ | 5 |
| $ | 9 |
|
Wholesale gas services(b) | — |
| 1 |
|
| Southern Company Gas total | $ | 5 |
| $ | 10 |
|
| |
| (a) | Includes $5 million and $11 million for the three and six months ended June 30, 2020, respectively, recorded as a reduction to operating revenues. |
| |
| (b) | Recorded as a reduction to operating revenues. |
Restricted Cash
The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed balance sheets that total to the amounts shown in the condensed statements of cash flows for the Registrants that had restricted cash at June 30, 2020 and/or December 31, 2019:
|
| | | | | | | | | | | | | | | | | |
| | Southern Company | | Southern Power | | Southern Company Gas |
| | At June 30, 2020 | At December 31, 2019 | | At June 30, 2020 | | At June
30, 2020 | At December 31, 2019 |
| | (in millions) | | (in millions) | | (in millions) |
| Cash and cash equivalents | $ | 1,879 |
| $ | 1,975 |
| | $ | 154 |
| | $ | 120 |
| $ | 46 |
|
Restricted cash(*): | | | | | | | |
| Other accounts and notes receivable | — |
| 3 |
| | — |
| | — |
| 3 |
|
| Other current assets | 4 |
| — |
| | — |
| | 4 |
| — |
|
| Other deferred charges and assets | 2 |
| — |
| | 2 |
| | — |
| — |
|
| Total cash, cash equivalents, and restricted cash | $ | 1,885 |
| $ | 1,978 |
| | $ | 156 |
| | $ | 124 |
| $ | 49 |
|
| |
| (*) | For Southern Company Gas, reflects restricted cash held as collateral for workers' compensation, life insurance, and long-term disability insurance. For Southern Power, reflects restricted cash held for construction payables. |
Natural Gas for Sale
Southern Company Gas, with the exception of Nicor Gas, carries natural gas inventory on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value. Southern Company Gas recorded no material adjustments for the three and six months ended June 30, 2020 and recorded adjustments of $7 million and $10 million for the three and six months ended June 30, 2019, respectively.
Nicor Gas' natural gas inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of natural gas at the actual LIFO
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
cost of the inventory layers liquidated. Nicor Gas' inventory decrement at June 30, 2020 is expected to be restored prior to year end.
Asset Retirement Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Georgia PowerNote 6 to the financial statements in Item 78 of the Form 10-K for additional information regardinginformation.
Details of changes in AROs for Southern Company and Alabama Power during the final effluent guidelines rulefirst six months of 2020 are shown in the following table. There were no material changes in AROs for the other Registrants during the first six months of 2020.
|
| | | | | | |
| | Southern Company | Alabama Power |
| | (in millions) |
| Balance at December 31, 2019 | $ | 9,786 |
| $ | 3,540 |
|
| Liabilities incurred | 15 |
| — |
|
| Liabilities settled | (193 | ) | (100 | ) |
| Accretion | 204 |
| 74 |
|
| Cash flow revisions | 462 |
| 462 |
|
| Balance at June 30, 2020 | $ | 10,274 |
| $ | 3,976 |
|
In June 2020, Alabama Power recorded an increase of approximately $462 million to its AROs related to the CCR Rule and the finalrelated state rule revisingprimarily due to management's completion of a feasibility study and the regulatory definitionrelated cost estimates during the second quarter 2020 for 1 of watersits ash ponds. Alabama Power's increase also reflects costs associated with the addition of a water treatment system to 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 September 18, 2017, the EPA published a final rule establishing a staydesign of the compliance deadlines for certain effluent limitations and pretreatment standardsanother ash pond. The additional estimated costs to close these ash ponds under the rule.planned closure-in-place methodology primarily relate to inputs from contractor bids, design revisions, and changes in the expected volume of ash handling.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
On June 27, 2017, the EPAAlabama and Georgia are subject to approval by environmental regulatory agencies. Absent continued recovery of ARO costs through regulated rates, results of operations, cash flows, and financial condition for Southern Company 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.traditional electric operating companies could be materially impacted. See Note (B) under "Georgia Power – Integrated Resource Plan" for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.
additional information. The ultimate outcome of these matters cannot be determined at this time.
Global Climate IssuesDepreciation and Amortization
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters Note 5 to the financial statements under "Depreciation and Amortization – Global Climate Issues" of Georgia PowerSouthern Power" in Item 78 of the Form 10-K for additional information.
On March 28, 2017,Effective January 1, 2020, Southern Power revised 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 October 16, 2017, the EPA published a proposed rule to repeal the Clean Power Plan. The EPA has not determined whether or when it will promulgate a replacement rule.
On June 1, 2017, the U.S. President announced that the United States will withdraw from the non-binding Paris Agreement and begin renegotiationdepreciable lives of its terms.natural gas generating facilities from up to 45 years to up to 50 years. This revision resulted in an immaterial decrease in depreciation for the three and six months ended June 30, 2020 and is expected to result in an immaterial decrease in annual depreciation for 2020.
The ultimate outcome of these matters cannot be determined at this time.FERC Matters(B) REGULATORY MATTERS
See MANAGEMENT'S DISCUSSION AND ANALYSIS �� FUTURE EARNINGS POTENTIAL – "FERC Matters" of Georgia PowerNote 2 to the financial statements in Item 78 of the Form 10-K for additional information regarding the traditional electric operating companies' and Southern Power's market power proceeding and amendmentrelating to their market-rate tariff.regulatory matters.
On May 17, 2017, the FERC accepted the traditional electric operating companies' (including Georgia Power's) and Southern Power's compliance filing accepting the terms
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
The recovery balances for certain retail regulatory clauses of the traditional electric operating companies (including Georgia Power) and Southern Company Gas at June 30, 2020 and December 31, 2019 were as follows:
|
| | | | | | | |
| Regulatory Clause | Balance Sheet Line Item | June 30,
2020 | December 31,
2019 |
| | | (in millions) |
| Alabama Power | | | |
| Rate CNP Compliance | Other regulatory liabilities, current | $ | 25 |
| $ | 55 |
|
| | Other regulatory liabilities, deferred | — |
| 7 |
|
| Rate CNP PPA | Deferred under recovered regulatory clause revenues | 41 |
| 40 |
|
| Retail Energy Cost Recovery | Other regulatory liabilities, current | 22 |
| 32 |
|
| | Other regulatory liabilities, deferred | 93 |
| 17 |
|
| Natural Disaster Reserve | Other regulatory liabilities, current | 16 |
| 37 |
|
| | Other regulatory liabilities, deferred | 96 |
| 113 |
|
| Georgia Power | | | |
| Fuel Cost Recovery | Other current liabilities | $ | 109 |
| $ | — |
|
| | Other deferred credits and liabilities | 95 |
| 73 |
|
| Mississippi Power | | | |
| Fuel Cost Recovery | Over recovered regulatory clause liabilities | $ | 22 |
| $ | 23 |
|
| Ad Valorem Tax | Other regulatory assets | 11 |
| 47 |
|
| | Other regulatory assets, deferred | 39 |
| — |
|
| Property Damage Reserve | Other regulatory liabilities, deferred | 50 |
| 54 |
|
| Southern Company Gas | | | |
| Natural Gas Cost Recovery | Other regulatory liabilities | $ | 100 |
| $ | 74 |
|
Alabama Power
Petition for Certificate of Convenience and Necessity
On June 9, 2020, the Alabama PSC approved in part Alabama Power's petition for a certificate of convenience and necessity (CCN) which authorizes Alabama Power to their market-based rate tariff. While(i) construct an approximately 720-MW combined cycle facility at Alabama Power's Plant Barry (Plant Barry Unit 8), which is expected to be placed in service by the FERC's order referencesend of 2023, (ii) complete the traditional electric operating companies' (including Georgia Power's) and Southern Power's market power proceeding related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.
On October 25, 2017,Autauga Combined Cycle Acquisition, which was approved by the FERC issued an orderon April 22, 2020 and is expected to close by September 1, 2020, (iii) purchase approximately 240 MWs of combined cycle generation under a long-term PPA expected to begin later in response2020 and (iv) pursue up to approximately 200 MWs of certain demand-side management and distributed energy resource programs.
The Alabama PSC authorized the recovery of actual costs for the construction of Plant Barry Unit 8 up to 5% above the estimated in-service cost of $652 million. In so doing, it recognized the potential for developments that could cause the project costs to exceed the capped amount, in which case Alabama Power would provide documentation to the traditional electric operating companies' (including Georgia Power's)Alabama PSC to explain and Southern Power's June 30, 2017 triennial updated market power analysis. justify potential recovery of the additional costs.
The FERCAlabama PSC further directed that the traditional electric operating companies (including Georgia Power) and Southernproposed solar generation of approximately 400 MWs, coupled with battery energy storage systems (solar/battery systems), be evaluated under an existing Renewable Generation Certificate issued by the Alabama PSC in September 2015.
Alabama Power expects to show cause within 60 days why market-basedrecover all approved costs associated with the CCN through existing rate authority should not be revokedmechanisms as outlined in certain areas adjacentNote 2 to the area presently under mitigationfinancial statements in accordance withItem 8 of the February 2, 2017Form 10-K. The Alabama PSC's approval in part of
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
the CCN will be followed by a written order which is subject to any rehearing request or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including Georgia Power) and Southern Power expect to make a filingjudicial appeal filed within 30 days of the specified 60 days responding to the FERC'sdate of such order.
The ultimate outcome of these matters cannot be determined at this time.
Retail Regulatory MattersGeorgia Power's revenues from regulated retail operations are collected through various rate mechanisms subjectPower
Deferral of Incremental COVID-19 Costs
On April 7, 2020 and June 2, 2020, in response to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, ECCR tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to the construction of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a separate fuel cost recovery tariff. See "Nuclear Construction" herein and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the NCCR tariff. Also see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
– "Retail Regulatory Matters – Fuel Cost Recovery" of Georgia Power in Item 7 of the Form 10-K for additional information regarding fuel cost recovery.
Renewables
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 renewable energy projects.
On May 16, 2017,COVID-19 pandemic, the Georgia PSC approved orders directing Georgia Power's requestPower to build, own,continue its previous, voluntary suspension of customer disconnections through July 14, 2020 and operateto defer the resulting incremental bad debt as a 139-MW solar generation facility atregulatory asset. On June 16, 2020 and July 7, 2020, the Georgia PSC approved orders establishing a U.S. Air Force base thatmethodology for identifying incremental bad debt and allowing the deferral of other incremental costs associated with the COVID-19 pandemic. The period over which such costs will be recovered is expected to be placeddetermined in service byGeorgia Power's next base rate case. At June 30, 2020, the end of 2019.
During the nine months ended September 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.
incremental costs deferred totaled approximately $34 million. The ultimate outcome of these mattersthis matter cannot be determined at this time.
Integrated Resource Plan
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Integrated Resource Plan"On March 5, 2020, the Sierra Club filed a petition for judicial review in the Superior Court of Fulton County to appeal the Georgia PSC's decision in the 2019 ARP allowing Georgia Power to recover compliance costs for CCR AROs. Georgia Power intervened 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.appeal on June 22, 2020. The ultimate outcome of this matter cannot be determined at this time.
Storm DamageFuel Cost Recovery
On May 28, 2020, the Georgia PSC approved a stipulation agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors to lower total fuel billings by approximately $740 million over a two-year period effective June 1, 2020. In addition, Georgia Power will further lower fuel billings by approximately $44 million under an interim fuel rider effective June 1, 2020 through September 30, 2020. Georgia Power continues to be allowed to adjust its fuel cost recovery rates under an interim fuel rider prior to its next fuel case if the under or over recovered fuel balance exceeds $200 million. Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, for incremental operating and maintenance costs of damage from major stormsscheduled to file its transmission and distribution facilities. During September 2017, Hurricane Irma caused significant damage to Georgia Power's transmission and distribution facilities. The total amount of incremental restoration costs related to this hurricane is estimated to be approximately $150 million. As of September 30, 2017, Georgia Power had deferred approximately $145 million in a regulatory asset related to storm damage. As of September 30, 2017, the total balance in the regulatory asset related to storm damage was $360 million. The rate of storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base ratefuel 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.no later than February 28, 2023.
Nuclear Construction
See Note 3 toIn 2009, the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding thePSC certified 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,in which Georgia Power acting for itselfholds a 45.7% ownership interest. In 2012, the NRC issued the related combined construction and as agent for the Vogtle Owners, entered into the Vogtle 3 and 4 Agreement, pursuant tooperating licenses, which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4. Under the termsallowed full construction of the Vogtle 32 AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and 4 Agreement, the Vogtle Owners agreedrelated facilities 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 ofbegin. Until March 2017, construction on Plant Vogtle Units 3 and 4 is 45.7%.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 Contractorcontinued under the Vogtle 3 and 4 Agreement, which was 40% of the contracta substantially fixed price (approximately $1.7 billion based on Georgia Power's ownership interest).
Onagreement. In 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 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. The Interim Assessment Agreement, as amended, expired on July 27, 2017.
Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor, including Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, 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 September 30, 2017, of the Vogtle Owners for the removal of subcontractor liens and payment of other EPC Contractor pre-petition accounts payable to total approximately $386 million, of which $340 million had been paid or accrued as of September 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $176 million.
On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into the Guarantee Settlement Agreement. Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation 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, which will reduce CWIP, 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 October 2, 2017, Georgia Power received the first installment of the Guarantee Obligations of $300 million from Toshiba, of which Georgia Power's proportionate share was $137 million. Georgia Power is considering potential optionsconnection with respect to its right to future payments under the Guarantee Settlement Agreement and its claims against
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
the EPC Contractor in the EPC Contractor's bankruptcy proceeding, including a potential sale of those payment rights and bankruptcy claims. Any such transaction cannot be assured and would be subject to DOE consents and related approvals under the Loan Guarantee Agreement and related agreements.
On August 10, 2017, Toshiba released its financial results for the quarter ended June 30, 2017, which reflected a negative shareholders' equity balance of approximately $4.5 billion as of June 30, 2017. Toshiba previously 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 Georgia Power's financial statements.
Additionally, on June 9, 2017,filing, 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 onseveral transitional arrangements to allow construction to continue. In 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.
Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into the BechtelVogtle Services Agreement, whereby BechtelWestinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis. The Vogtle Services Agreement provides that it will serve ascontinue until the primary contractor for the remaining construction activities forstart-up and testing of Plant Vogtle Units 3 and 4. Facility design4 are complete and engineering remainselectricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the responsibility ofVogtle Owners upon 30 days' written notice.
In October 2017, Georgia Power, acting for itself and as agent for the EPC Contractor underother Vogtle Owners, executed the Services Agreement. The Bechtel Agreement, is a cost reimbursable plus fee arrangement, whereby Bechtel will beis reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule
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targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. Pursuant
See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for information on the Amended and Restated Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
Cost and Schedule
Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 by the expected in-service dates of November 2021 and November 2022, respectively, is as follows:
|
| | | |
| | (in billions) |
Base project capital cost forecast(a)(b) | $ | 8.4 |
|
| Construction contingency estimate | 0.1 |
|
Total project capital cost forecast(a)(b) | 8.5 |
|
Net investment as of June 30, 2020(b) | (6.6 | ) |
Remaining estimate to complete(a) | $ | 1.9 |
|
| |
| (a) | Excludes financing costs expected to be capitalized through AFUDC of approximately $260 million, of which $52 million had been accrued through June 30, 2020. |
| |
| (b) | Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds. |
Georgia Power is required to obtain the DOE's approval of the Bechtel Agreement prior to obtaining any further advances under the Loan Guarantee Agreement.
In connection with the recommendation to continue withestimates that its financing costs for construction of Plant Vogtle Units 3 and 4 (described below)will total approximately $3.0 billion, of which $2.4 billion had been incurred through June 30, 2020.
As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of engineering support, commodity installation, system turnovers, and workforce statistics.
During the second quarter 2020, approximately $194 million of construction contingency was assigned to the base capital cost forecast for cost risks including, among other things, construction productivity, including the April 2020 reduction in workforce designed to mitigate impacts of the COVID-19 pandemic described below, field support, subcontracts, engineering resources, and procurement. The second quarter 2020 assignment of contingency exceeded the remaining balance of the $366 million construction contingency originally established in the second quarter 2018 by approximately $34 million. Through June 30, 2020, assignments of contingency for cost risks also have included, among other factors, construction productivity; craft labor incentives; adding resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement. As a result of these factors, Southern Nuclear recommended establishing additional construction contingency, of which Georgia Power's share is approximately $115 million, for further potential risks including, among other factors, construction productivity and expected impacts of the COVID-19 pandemic; adding resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement.
After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income
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of $149 million ($111 million after tax) for the increase in the total project capital cost forecast as of June 30, 2020. As and when these amounts are spent, Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery.
In April 2019, Southern Nuclear established aggressive target values for monthly construction production and system turnover activities as part of a strategy to maintain and, where possible, build margin to the regulatory-approved in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4. Through early 2020, the project faced challenges with the April 2019 aggressive strategy targets including, but not limited to, electrical and pipefitting labor productivity and work package closure rates, which resulted in a backlog of activities and completion percentages below the April 2019 aggressive strategy targets.
In February 2020, Southern Nuclear updated its cost and schedule forecast, which, at that time, did not change the total project capital cost forecast and confirmed the expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4. This update included initiatives to improve productivity while refining and extending system turnover plans and certain near-term milestone dates. Other milestone dates did not change. Achievement of the February 2020 aggressive site work plan relied on meeting increased monthly production and activity target values during 2020.
In mid-March 2020, Southern Nuclear began implementing policies and procedures designed to mitigate the risk of transmission of COVID-19 at the construction site, including worker distancing measures, isolating individuals who have tested positive for COVID-19, are showing symptoms consistent with COVID-19, are being tested for COVID-19, or have been in close contact with such persons, requiring self-quarantine, and adopting additional precautionary measures.
In April 2020, Georgia Power, acting for itself and as agent for the other Vogtle Owners, announced a reduction in workforce at Plant Vogtle Units 3 and 4, which totaled approximately 20% of the then-existing site workforce. This reduction in workforce was a mitigation action intended to address the impact of the COVID-19 pandemic on the Plant Vogtle Units 3 and 4 workforce and construction site, including challenges with labor productivity that were exacerbated by the impact of the COVID-19 pandemic. The April 2020 workforce reduction was intended to provide operational efficiencies by increasing productivity of the remaining workforce and reducing workforce fatigue and absenteeism. Further, it was also intended to allow for increased social distancing by the workforce and facilitate compliance with the recommendations from the Centers for Disease Control and Prevention. The April 2020 workforce reduction did reduce absenteeism, providing an improvement in operational efficiency and allowing for increased social distancing. From the initial peak in April 2020, the number of active cases at the site declined significantly during May and early June, but began increasing again in mid-June and continues to impact productivity levels and pace of activity completion. As a result of these factors, overall production improvements have not been achieved at the levels anticipated, contributing to the allocation of, and increase in, construction contingency described above. Through mid-July 2020, Unit 3 mechanical, electrical, and subcontract activities continued to build a backlog to Southern Nuclear's February 2020 aggressive site work plan.
To address these issues, in July 2020, Southern Nuclear updated its aggressive site work plan for both Unit 3 and Unit 4. To meet the targets in the July 2020 aggressive site work plan, absenteeism rates must continue to normalize and overall construction productivity and production levels, including subcontractors, must significantly improve and be sustained above pre-pandemic levels. In addition, appropriate levels of craft laborers, particularly electrical and pipefitter craft labor, must be added and maintained. While Southern Nuclear's July 2020 aggressive site work plan extended milestone dates from the February 2020 aggressive site work plan, Georgia Power still expects to achieve the regulatory-approved in-service dates of November 2021 and November 2022 for Plant Vogtle Units 3 and 4, respectively. Southern Nuclear and Georgia Power continue to believe that pursuit of an aggressive site work plan is an appropriate strategy to achieve completion of the units by their regulatory-approved in-service dates.
As construction, including subcontract work, continues and testing and system turnover activities increase, challenges with management of contractors and vendors; subcontractor performance; supervision of craft labor and related productivity, particularly in the installation of electrical, mechanical, and instrumentation and controls commodities, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication,
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delivery, assembly, installation, system turnover, and the initial testing and start-up, including any required engineering changes or any remediation related thereto, of plant systems, structures, or components (some of which are based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale), any of which may require additional labor and/or materials; or other issues could arise and change the projected schedule and estimated cost.
In addition, the continuing effects of the COVID-19 pandemic could further disrupt or delay construction, testing, supervisory, and support activities at Plant Vogtle Units 3 and 4. Georgia Power's proportionate share of the estimated incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is currently estimated to be between $70 million and $115 million, which is included in the total project capital cost forecast and assumes (i) absenteeism rates continue to normalize and (ii) the intended productivity efficiencies and production targets assumed in Southern Nuclear's July 2020 aggressive site work plan are realized in the coming months. However, the ultimate impact of the COVID-19 pandemic on the construction schedule and budget for Plant Vogtle Units 3 and 4 cannot be determined at this time.
There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel, may arise, which may result in additional license amendments or require other resolution. As part of the aggressive site work plan, in January 2020, Southern Nuclear notified the NRC of its intent to load fuel in 2020. On May 11, 2020, the Blue Ridge Environmental Defense League filed a petition with the NRC that challenges a license amendment request. On June 15, 2020, the NRC issued an appealable order rejecting Nuclear Watch South's April 20, 2020 petition requesting a hearing and challenging the closure of certain ITAAC. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.
The ultimate outcome of these matters cannot be determined at this time. However, any extension of the regulatory-approved project schedule is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $10 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.
Joint Owner Contracts
In November 2017, the Vogtle Owners agreed on a term sheetentered into an amendment to amend the existingtheir joint ownership agreements for Plant Vogtle Units 3 and 4 to provide for, among other conditions, additional Vogtle Owner approval requirements. UnderEffective in August 2018, the term sheet,Vogtle Owners further amended the joint ownership agreements to clarify and provide procedures for certain provisions of the joint ownership agreements related to adverse events that require the vote of the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including (i) the bankruptcy of Toshiba or a material breach by Toshiba of the Guarantee Settlement Agreement; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3(as amended, and 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report by more than $1 billion or extension of the project schedule contained in the seventeenth VCM report by more than one year. In addition, under the term sheet, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Services Agreement or agreementstogether with the primary construction contractor or Southern Nuclear.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
November 2017 amendment, the Vogtle Joint Ownership Agreements). The term sheetVogtle Joint Ownership Agreements also confirmsconfirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.
As a result of an increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs in conjunction with the nineteenth VCM report in 2018, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue
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(UNAUDITED)
construction. In September 2018, the Vogtle Owners unanimously voted to continue construction of Plant Vogtle Units 3 and 4.
Amendments to the Vogtle Joint Ownership Agreements
In connection with the vote to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and MEAG Power's wholly-owned subsidiaries MEAG Power SPVJ, LLC (MEAG SPVJ), MEAG Power SPVM, LLC (MEAG SPVM), and MEAG Power SPVP, LLC (MEAG SPVP) to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners, including additional amendments to the Vogtle Joint Ownership Agreements and the purchase of PTCs from the other Vogtle Owners at pre-established prices, and (ii) a term sheet (MEAG Term Sheet) with MEAG Power and MEAG SPVJ to provide up to $300 million of funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. In January 2019, Georgia Power, MEAG Power, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. In February 2019, Georgia Power, the other Vogtle Owners, and MEAG Power's wholly-owned subsidiaries MEAG SPVJ, MEAG SPVM, and MEAG SPVP entered into certain amendments to the Vogtle Joint Ownership Agreements to implement the provisions of the Vogtle Owner Term Sheet (Global Amendments).
As previously disclosed, pursuant to the Global Amendments: (i) each Vogtle Owner must pay its proportionate share of qualifying construction costs for Plant Vogtle Units 3 and 4 based on its ownership percentage up to the estimated cost at completion (EAC) for Plant Vogtle Units 3 and 4 which formed the basis of Georgia Power's forecast of $8.4 billion in the nineteenth VCM plus $800 million; (ii) Georgia Power will be responsible for 55.7% of actual qualifying construction costs between $800 million and $1.6 billion over the EAC in the nineteenth VCM (resulting in $80 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests; and (iii) Georgia Power will be responsible for 65.7% of qualifying construction costs between $1.6 billion and $2.1 billion over the EAC in the nineteenth VCM (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests. If the EAC is revised and exceeds the EAC in the nineteenth VCM by more than $2.1 billion, each of the other Vogtle Owners will have a one-time option at the time the project budget forecast is so revised to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100% of such Vogtle Owner's remaining share of total construction costs in excess of the EAC in the nineteenth VCM plus $2.1 billion.
In addition, pursuant to the Global Amendments, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including, among other events: (i) the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power's public announcement of its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 or the Georgia PSC determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Vogtle Owners pursuant to the Global Amendments described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Georgia PSC for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates; and (iv) an incremental extension of one year or more over the most recently approved schedule.
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.Plant Vogtle Units 3 and 4. Financing costs are recovered on all
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(UNAUDITED)
applicable certified costs through annual adjustments to the NCCR tariff by includingup to the related CWIP accounts in rate base during the construction period. Ascertified capital cost of September$4.418 billion. At June 30, 2017,2020, Georgia Power had recovered approximately $1.5$2.4 billion of financing costs. Financing costs related to capital costs above $4.418 billion are being recognized through AFUDC and are expected to be recovered through retail rates over the life of Plant Vogtle Units 3 and 4; however, Georgia Power expectswill not record AFUDC related to file on November 1, 2017any capital costs in excess of the total deemed reasonable by the Georgia PSC (currently $7.3 billion) and not requested for rate recovery. In December 2019, the Georgia PSC approved Georgia Power's request to increasedecrease the NCCR tariff by approximately $90$62 million annually, effective January 1, 2018, pending2020.
Georgia Power is required to file semi-annual VCM reports with the Georgia PSC approval.by February 28 and August 31 of each year. In 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.
On December 20,In 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) Georgia Power's seventeenth VCM report and modified the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following prudence matters:regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report willshould be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement iswas 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$5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, and (c)(b) Georgia Power would have the burden to show that any capital costs above $5.68 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the Revised Forecast are reasonable and prudent. Underimpact of payments received under the terms of the Vogtle CostGuarantee Settlement Agreement and related customer refunds) was found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the certified in-service capitalrevised cost for purposes of calculatingforecast does not represent a cost cap and that prudence decisions on cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the 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(a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016. For purposes of the AFUDC calculation,2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE on costs between $4.418 billion and $5.440 billionin no case will also be 10.00% and the ROE on any amounts above $5.440 billion would beless than Georgia Power's average cost of long-term debt. Ifdebt); (viii) reduced the Georgia PSC adjusts Georgia Power's ROE rate setting point in a rate case prior toused for AFUDC equity for Plant Vogtle Units 3 and 4 being placed intofrom 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail rate base thenrates would be adjusted to include carrying costs on those capital costs deemed prudent in 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. IfVogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not placed in servicecommercially operational by December 31, 2020, then (i)June 1, 2021 and June 1, 2022, respectively, the ROE for purposes of calculatingused to calculate the NCCR tariff will be further reduced an additional 300by 10 basis points or $8 million pereach 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(but not lower than Georgia Power's average cost of long-term debt.debt) until the respective Unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $75 million in 2019 and are estimated to have negative earnings impacts of approximately $145 million, $255 million, and $200 million in 2020, 2021, and 2022, respectively. In its January 11, 2018 order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.
In February 2018, Georgia Interfaith Power & Light, Inc. (GIPL) and Partnership for Southern Equity, Inc. (PSE) filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. In March 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's decision and denial of Georgia Watch's motion for reconsideration. In December 2018, the Fulton County Superior Court granted Georgia Power's motion to dismiss the 2 appeals. In January 2019, GIPL, PSE,
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and Georgia Watch filed an appeal of this decision with the Georgia Court of Appeals. In October 2019, the Georgia Court of Appeals issued an opinion affirming the Fulton County Superior Court's ruling that the Georgia PSC's January 11, 2018 order was not a final, appealable decision. In addition, the Georgia Court of Appeals remanded the case to the Fulton County Superior Court to clarify its ruling as to whether the petitioners showed that review of the Georgia PSC's final order would not provide them an adequate remedy. On April 21, 2020, the Fulton County Superior Court granted Georgia Power's motion to dismiss the 2 appeals. The petitioners filed a notice of appeal of the dismissal on May 20, 2020. Georgia Power believes the petitions have no merit; however, an adverse outcome in the litigation combined with subsequent adverse action by the Georgia PSC could have a material impact on Southern Company's and Georgia Power's results of operations, financial condition, and liquidity.
The Georgia PSC has approved sixteen21 VCM reports covering the periods through December 31, 2016,June 30, 2019, including total construction capital costs incurred which through that date totaled $3.9 billion.of $6.7 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds). On August 18, 2020, the Georgia Power filed its seventeenthPSC is scheduled to vote on Georgia Power's twenty-second VCM report, covering the period from January 1 through June 30, 2017, requestingwhich requested approval of $542$674 million of construction capital costs incurred during that period,from July 1, 2019 through December 31, 2019.
Georgia Power expects to file its twenty-third VCM report with the Georgia PSC onby August 31, 2017.
In2020, which will reflect the seventeenth VCM report, Georgia Power recommended thatrevised capital cost forecast discussed above and request approval of $701 million of construction of Plant Vogtle Units 3 and 4 be continued, with Southern Nuclear serving as project manager. Georgia Power believes that the most reasonable schedule for completing Plant Vogtle Units 3 and 4 is by November 2021 for Unit 3 and by November 2022 for Unit 4. Georgia Power's recommendation to go forward with completion of Vogtle Units 3 and 4 is based on the following assumptions about the regulatory treatment of this recommendation, if the recommendation to go forward
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
is adopted by the Georgia PSC: (i) that pursuant to Georgia law, the Georgia PSC in the seventeenth VCM proceeding approves the new cost and schedule forecast and finds that it is a reasonable basis for going forward, and that if the Georgia PSC disapproves all or part of the proposed cost and schedule revisions, Georgia Power may cancel Plant Vogtle Units 3 and 4 and recover its actual investment in Plant Vogtle Units 3 and 4; (ii) that the Vogtle Cost Settlement Agreement remains in full force and effect, including Georgia Power retaining the burden of proving all capital costs above $5.680 billion were prudent; (iii) that while the Georgia PSC will make no prudence finding in the seventeenth VCM proceeding, nor will the certified amount be amended consistent with the Vogtle Cost Settlement Agreement, the Georgia PSC recognizes that the certified amount is not a cap, and all costs that are approved and presumed or shown to be prudently incurred will be recoverable by Georgia Power; (iv) that Georgia Power is not a guarantor of the Toshiba Guarantee, and the failure of Toshiba to pay the Toshiba Guarantee, the failure of the U.S. Congress to extend the PTCs for Plant Vogtle Units 3 and 4, or the failure of the DOE to extend the Loan Guarantee Agreement with Georgia Power to reflect the increased capital amounts, will not reduce the amount of investment Georgia Power is otherwise allowed to collect; and (v) that as conditions change and assumptions are either proven or disproven, Georgia Power and the Georgia PSC may reconsider the decision to go forward. The Georgia PSC is expected to make a decision on these matters by February 6, 2018.from January 1, 2020 through June 30, 2020.
The ultimate outcome of these matters cannot be determined at this time.
Mississippi Power
2019 Base Rate Case
On March 17, 2020, the Mississippi PSC approved a settlement agreement between Mississippi Power and Schedulethe Mississippi Public Utilities Staff related to Mississippi Power's base rate case filed in November 2019 (Mississippi Power Rate Case Settlement Agreement).
Georgia Power's approximate proportionate shareUnder the terms of the remaining estimated costMississippi Power Rate Case Settlement Agreement, annual retail rates decreased approximately $16.7 million, or 1.85%, effective for the first billing cycle of April 2020, based on a test year period of January 1, 2020 through December 31, 2020, a 53% average equity ratio, an allowed maximum actual equity ratio of 55% by the end of 2020, and a 7.57% return on investment.
Additionally, the approved Mississippi Power Rate Case Settlement Agreement: (i) established common amortization periods of four years for regulatory assets and three years for regulatory liabilities included in the approved revenue requirement, including those related to completeunprotected deferred income taxes; (ii) established new depreciation rates reflecting an annual increase in depreciation of approximately $10 million; and (iii) excluded certain compensation costs totaling approximately $3.9 million. It also eliminated separate rates for costs associated with Plant Vogtle Units 3Ratcliffe and 4 isenergy efficiency initiatives and includes such costs in the PEP, ECO Plan, and ad valorem tax adjustment factor, as follows:applicable. In accordance with the previous order of the Mississippi PSC suspending the operation of PEP and the ECO Plan for 2018 through 2020, Mississippi Power plans to resume PEP proceedings and ECO Plan filings for 2021.
Performance Evaluation Plan
On July 24, 2020, the Mississippi PSC approved Mississippi Power's July 14, 2020 filing of its PEP compliance rate clause reflecting revisions agreed to in the Mississippi Power Rate Case Settlement Agreement. These revisions include, among other things, changing the filing date for the annual PEP rate filing from November of the immediately preceding year to March of the current year, utilizing a historic test year adjusted for "known and measurable" changes, using discounted cash flow and regression formulas to determine base return on equity, and moving all embedded ad valorem property taxes currently collected in PEP to the ad valorem tax adjustment clause.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
|
| | | |
| | (in billions) |
| Estimated cost to complete | $ | 4.2 |
|
| CWIP as of September 30, 2017 | 4.6 |
|
| Guarantee Obligations | (1.7 | ) |
| Estimated capital costs | $ | 7.1 |
|
| Vogtle Cost Settlement Agreement Revised Forecast | (5.7 | ) |
| Estimated net additional capital costs | $ | 1.4 |
|
Georgia Power's estimated financingDeferral of Incremental COVID-19 Costs
On April 14, 2020 and May 12, 2020, in order to mitigate the economic impact of the COVID-19 pandemic on customers, the Mississippi PSC approved orders directing Mississippi Power to continue its previous, voluntary suspension of customer disconnections through May 25, 2020 and to defer as a regulatory asset all necessary and reasonable incremental costs or expenses to plan, prepare, stage, or react to protect and keep safe its employees and customers, and to reliably operate its utility system during the constructionCOVID-19 pandemic. The period totalover which such costs will be recovered is expected to be determined in a future PEP filing. At June 30, 2020, the incremental costs deferred totaled approximately $3.4 billion,$2 million. The ultimate outcome of which approximately $1.5 billion had been incurred through September 30, 2017.this matter cannot be determined at this time.
GeorgiaMunicipal and Rural Associations Tariff
On June 25, 2020, the FERC accepted Mississippi Power's cancellation cost estimate results indicate thatApril 27, 2020 request for an increase in wholesale base revenues under the MRA tariff as agreed upon in a settlement agreement reached with its proportionate sharewholesale customers. The MRA settlement agreement resulted in a $2 million annual increase in base rates effective June 1, 2020.
Southern Company Gas
Rate Proceedings
On June 1, 2020, Virginia Natural Gas filed a general rate case with the Virginia Commission seeking an increase in rates of the estimated$49.6 million primarily to recover investments and increased costs associated with infrastructure, technology, and workforce development. The requested increase is based on a projected 12-month test year beginning November 1, 2020, a ROE of 10.35%, and an equity ratio of 54%. Rate adjustments are expected to cancel both units is approximately $350 million. As a result, as of September 30, 2017, total estimated costsbe effective November 1, 2020, subject to evaluationrefund. The Virginia Commission is expected to rule on the requested increase in the second quarter 2021.
On July 1, 2020, Atlanta Gas Light filed its 2020 GRAM filing with the Georgia PSC. The filing requests an annual base rate increase of $37.6 million based on the projected 12-month period beginning January 1, 2021, which does not exceed the 5% limitation established by Georgia Power and the Georgia PSC in its December 2019 approval of Atlanta Gas Light's general base rate case. Resolution of the event of a cancellation decision are as follows:
|
| | | |
| | Cancellation Cost Estimate |
| | (in billions) |
| CWIP as of September 30, 2017 | $ | 4.6 |
|
| Financing costs collected, net of tax | 1.5 |
|
Cancellation costs(*) | 0.4 |
|
| Guarantee Obligations | (1.7 | ) |
| Estimated net cancellation cost | $ | 4.8 |
|
| |
(*) | 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 cancelled2020 GRAM filing is expected by the Georgia PSC are allowed recovery, including carrying
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
costs, in future retail rates. Georgia Power will continue workingDecember 31, 2020, 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.rates effective January 1, 2021.
The ultimate outcome of these matters cannot be determined at this time.
Deferral of Incremental COVID-19 Costs
Atlanta Gas Light
On April 30, 2020, in response to the COVID-19 pandemic, the Georgia PSC approved orders directing Atlanta Gas Light to continue its previous, voluntary suspension of customer disconnections. On June 22, 2020, the Georgia PSC ordered Atlanta Gas Light to resume customer disconnections beginning July 1, 2020, with exceptions for customers still covered by a shelter-in-place order. The orders provide the Marketers, including SouthStar, with a mechanism to receive credits from Atlanta Gas Light for the base rates it charged to the Marketers of non-paying customers during the suspension. Atlanta Gas Light expects to recover these credits through the annual revenue true-up process within its 2021 GRAM filing, which would impact rates effective January 1, 2022. The ultimate outcome of this matter cannot be determined at this time.
Nicor Gas
On March 18, 2020, the Illinois Commission issued an order directing utilities to cease disconnections for non-payment and to suspend the imposition of late payment fees or penalties until the Governor of Illinois announces the end of the COVID-19 state of emergency. In response to this order, on March 27, 2020, Nicor Gas and other utilities in Illinois filed their plans seeking cost recovery and more flexible credit and collection plans.
On June 18, 2020, the Illinois Commission approved a stipulation pursuant to which the utilities will provide more flexible credit and collection procedures to assist customers with financial hardship and which authorizes a special
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
purpose rider for recovery of the following COVID-19 pandemic-related impacts: incremental costs directly associated with the COVID-19 pandemic, net of the offset for COVID-19 pandemic-related credits received, foregone late fees, foregone reconnection charges, and the costs associated with a bill payment assistance program. The special purpose rider is proposed to be effective on October 1, 2020 and continue over a 24-month period. At June 30, 2020, Nicor Gas' related regulatory asset was $12 million. The ultimate outcome of this matter cannot be determined at this time.
Virginia Natural Gas
In response to the COVID-19 pandemic, the Virginia Commission issued orders requiring Virginia Natural Gas to suspend disconnections beginning on March 16, 2020 and also to suspend late payment and reconnection fees beginning on April 9, 2020, both of which continue in effect through August 31, 2020. On April 29, 2020, the Virginia Commission authorized Virginia Natural Gas to defer the following COVID-19 pandemic-related costs as a regulatory asset: incremental uncollectible expense incurred, suspended late fees, suspended reconnection charges, carrying costs, and other incremental prudently incurred costs associated with the COVID-19 pandemic. Specific recovery of the amounts deferred in a regulatory asset will be addressed in a future rate proceeding. At June 30, 2020, Virginia Natural Gas' related regulatory asset was $1 million. The ultimate outcome of this matter cannot be determined at this time.
Infrastructure Replacement Programs and Capital Projects
In December 2019, Virginia Natural Gas filed an application with the Virginia Commission for a 24.1-mile header improvement project to improve resiliency and increase the supply of natural gas delivered to energy suppliers, including Virginia Natural Gas. On June 26, 2020, the Virginia Commission issued an order requiring Virginia Natural Gas to submit additional information by December 31, 2020 related to the financing plans of the project's primary customer before ruling on the December 2019 application. The ultimate outcome of this matter cannot be determined at this time.
(C) CONTINGENCIES
See Note 3 to the financial statements in Item 8 of the Form 10-K for information relating to various lawsuits and other contingencies.
General Litigation Matters
The Registrants are involved in various other matters being litigated and regulatory matters. The ultimate outcome of such pending or potential litigation or regulatory matters against each Registrant and any subsidiaries cannot be determined at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such Registrant's financial statements.
The Registrants believe the pending legal challenges discussed below have no merit; however, the ultimate outcome of these matters cannot be determined at this time.
Southern Company
In January 2017, a securities class action complaint was filed in the U.S. District Court for the Northern District of Georgia 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 names as defendants Southern Company, certain of its current and former officers, and certain former Mississippi Power officers and alleges that the defendants made materially false and misleading statements regarding the Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. In 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. Also in 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
opposition. In 2018, the court issued an order dismissing certain claims against certain officers of Southern Company and Mississippi Power and dismissing the allegations related to a number of the statements that plaintiffs challenged as being false or misleading. In 2018, the court denied the defendants' motion for reconsideration and also denied a motion to certify the issue for interlocutory appeal. In the third quarter 2019, the court certified the plaintiffs' proposed class and the defendants filed a petition for interlocutory appeal of the class certification order with the U.S. Court of Appeals for the Eleventh Circuit. In December 2019, the U.S. District Court for the Northern District of Georgia entered an order staying all deadlines in the case pending mediation. The stay automatically expired on March 31, 2020; however, in light of the COVID-19 pandemic, the U.S. District Court for the Northern District of Georgia vacated all existing discovery deadlines until June 15, 2020. On June 30, 2020, the court entered a revised scheduling order, which resumed discovery and set out remaining case deadlines.
In February 2017, Jean Vineyard and Judy Mesirov each filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its current and former officers, and certain former Mississippi Power officers. In 2017, these 2 shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. In 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the securities class action.
In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, Georgia that names as defendants Southern Company, certain of its directors, certain of its current and former 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 County energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. 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. In 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the securities class action. In August 2019, the court granted a motion filed by the plaintiff in July 2019 to substitute a new named plaintiff, Martin J. Kobuck, in place of Helen E. Piper Survivor's Trust.
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 amounts for municipal franchise fees (which fees are paid to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state law claims. This case has been ruled upon and appealed numerous times over the last several years. In one recent appeal, the Georgia Supreme Court remanded the case and noted that the trial court could refer the matter to the Georgia PSC to interpret its tariffs. Following a motion by Georgia Power, in February 2019, the Superior Court of Fulton County ordered the parties to submit petitions to the Georgia PSC for a declaratory ruling and also conditionally certified the proposed class. In March 2019, Georgia Power and the plaintiffs filed petitions with the Georgia PSC seeking confirmation of the proper application of the municipal franchise fee schedule pursuant to the Georgia PSC's orders. Also in March 2019, Georgia Power appealed the class certification decision to the Georgia Court of Appeals. In October 2019, the Georgia PSC issued an order that found Georgia Power has appropriately implemented the municipal franchise fee schedule. On March 11, 2020, the Georgia Court of Appeals vacated the Superior Court of Fulton County's February 2019 order granting conditional class certification. The Court of
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Appeals remanded the case to the Superior Court of Fulton County for further proceedings. The amount of any possible losses cannot be calculated at this time because, among other factors, it is unknown whether a class will be certified, the ultimate composition of any class, and whether any losses would be subject to recovery from any municipalities.
On July 29, 2020, a group of individual plaintiffs filed a complaint in the Superior Court of Fulton County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater, surface water, and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages, a medical monitoring fund, and injunctive relief.
Mississippi Power
In May 2018, Southern Company and Mississippi Power received a notice of dispute and arbitration demand filed by Martin Product Sales, LLC (Martin) based on 2 agreements, both related to Kemper IGCC byproducts for which Mississippi Power provided termination notices in 2017. Martin alleges breach of contract, breach of good faith and fair dealing, fraud and misrepresentation, and civil conspiracy and makes a claim for damages in the amount of approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest. A portion of the claim for damages was on behalf of Martin Transport, Inc. (Martin Transport), an affiliate of Martin. In May 2019, the arbitration panel denied Mississippi Power's and Southern Company's motions to dismiss. In September 2019, Martin Transport filed a separate complaint against Mississippi Power in the Circuit Court of Kemper County, Mississippi alleging claims of fraud, negligent misrepresentation, promissory estoppel, and equitable estoppel, each arising out of the same alleged facts and circumstances that underlie Martin's arbitration demand. Martin Transport seeks compensatory damages of $5 million and punitive damages of $50 million. In November 2019, Martin Transport's claim was combined with the Martin arbitration case and the separate court case was dismissed. In December 2019, Southern Company and Mississippi Power each filed motions for summary judgment on all claims. On February 17, 2020, the arbitration panel granted Southern Company's motion and dismissed Southern Company from the arbitration. On March 12, 2020, the arbitration panel denied Mississippi Power's motions for summary judgment. An adverse outcome in this proceeding could have a material impact on Southern Company's and Mississippi Power's financial statements.
In November 2018, Ray C. Turnage and 10 other individual plaintiffs filed a putative class action complaint against Mississippi Power and the 3 then-serving members of the Mississippi PSC in the U.S. District Court for the Southern District of Mississippi. Mississippi Power received Mississippi PSC approval in 2013 to charge a mirror CWIP rate premised upon including in its rate base pre-construction and construction costs for the Kemper IGCC prior to placing the Kemper IGCC into service. The Mississippi Supreme Court reversed that approval and ordered Mississippi Power to refund the amounts paid by customers under the previously-approved mirror CWIP rate. The plaintiffs allege that the initial approval process, and the amount approved, were improper. They also allege that Mississippi Power underpaid customers by up to $23.5 million in the refund process by applying an incorrect interest rate. The plaintiffs seek to recover, on behalf of themselves and their putative class, actual damages, punitive damages, pre-judgment interest, post-judgment interest, attorney's fees, and costs. In response to Mississippi Power and the Mississippi PSC each filing a motion to dismiss, the plaintiffs filed an amended complaint in March 2019. The amended complaint included 4 additional plaintiffs and additional claims for gross negligence, reckless conduct, and intentional wrongdoing. Mississippi Power and the Mississippi PSC have each filed a motion to dismiss the amended complaint. On March 27, 2020, the Mississippi PSC's motion to dismiss was granted. Also on March 27, 2020, the plaintiffs filed a motion seeking to name the new members of the Mississippi PSC, the Mississippi Development Authority, and Southern Company as additional defendants and add a cause of action against all defendants based on a dormant commerce clause theory under the U.S. Constitution. On April 9, 2020 and April 10, 2020, Mississippi Power and the Mississippi PSC, respectively, filed responses opposing the motion for leave to file a second amended complaint. On May 26, 2020, Mississippi Power's motion to dismiss the first amended complaint filed in 2019 was granted. On July 6, 2020, the plaintiffs filed a motion for revision of the court's decision. The plaintiffs' motion for leave to file a second amended complaint also remains pending before the court. An adverse outcome in this proceeding could have a material impact on Mississippi Power's financial statements.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility" in Item 8 of the Form 10-K for additional information.
Environmental Remediation
The Southern Company system must comply with environmental laws and regulations governing the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companies and the natural gas distribution utilities in Illinois and Georgia 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.
Georgia Power's environmental remediation liability was $14 million and $15 million as of June 30, 2020 and December 31, 2019, respectively. Georgia Power has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected.
In December 2019, Mississippi Power entered into an agreement with the Mississippi Commission on Environmental Quality related to groundwater conditions arising from the closed ash pond at Plant Watson. Mississippi Power will complete an assessment and remediation consistent with the requirements of the agreement and the CCR Rule. Potential remediation activities and related cost estimates are pending the result of further site assessment and cannot be determined at this time. Mississippi Power expects to recover the retail portion of remedial costs through the ECO Plan and the wholesale portion through MRA rates.
Southern Company Gas' environmental remediation liability was $253 million and $269 million as of June 30, 2020 and December 31, 2019, respectively, based on the estimated cost of environmental investigation and remediation associated with known current and former manufactured gas plant operating sites. These environmental remediation expenditures are generally recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies of the natural gas distribution utilities.
The ultimate outcome of these matters cannot be determined at this time; however, as a result of the regulatory treatment for environmental remediation expenses described above, the final disposition of these matters is not expected to have a material impact on the financial statements of the applicable Registrants.
Other MattersPerformance Evaluation Plan
AsOn July 24, 2020, the Mississippi PSC approved Mississippi Power's July 14, 2020 filing of Septemberits PEP compliance rate clause reflecting revisions agreed to in the Mississippi Power Rate Case Settlement Agreement. These revisions include, among other things, changing the filing date for the annual PEP rate filing from November of the immediately preceding year to March of the current year, utilizing a historic test year adjusted for "known and measurable" changes, using discounted cash flow and regression formulas to determine base return on equity, and moving all embedded ad valorem property taxes currently collected in PEP to the ad valorem tax adjustment clause.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Deferral of Incremental COVID-19 Costs
On April 14, 2020 and May 12, 2020, in order to mitigate the economic impact of the COVID-19 pandemic on customers, the Mississippi PSC approved orders directing Mississippi Power to continue its previous, voluntary suspension of customer disconnections through May 25, 2020 and to defer as a regulatory asset all necessary and reasonable incremental costs or expenses to plan, prepare, stage, or react to protect and keep safe its employees and customers, and to reliably operate its utility system during the COVID-19 pandemic. The period over which such costs will be recovered is expected to be determined in a future PEP filing. At June 30, 2017, Georgia Power had borrowed $2.6 billion related2020, the incremental costs deferred totaled approximately $2 million. The ultimate outcome of this matter cannot be determined at this time.
Municipal and Rural Associations Tariff
On June 25, 2020, the FERC accepted Mississippi Power's April 27, 2020 request for an increase in wholesale base revenues under the MRA tariff as agreed upon in a settlement agreement reached with its wholesale customers. The MRA settlement agreement resulted in a $2 million annual increase in base rates effective June 1, 2020.
Southern Company Gas
Rate Proceedings
On June 1, 2020, Virginia Natural Gas filed a general rate case with the Virginia Commission seeking an increase in rates of$49.6 million primarily to Plant Vogtle Units 3recover investments and 4increased costs through the Loan Guarantee Agreementassociated with infrastructure, technology, and workforce development. The requested increase is based on a multi-advance credit facility among Georgia Power, the DOE,projected 12-month test year beginning November 1, 2020, a ROE of 10.35%, and the FFB, which provides for borrowingsan equity ratio of up54%. Rate adjustments are expected to $3.46 billion,be effective November 1, 2020, subject to refund. The Virginia Commission is expected to rule on the satisfactionrequested increase in the second quarter 2021.
On July 1, 2020, Atlanta Gas Light filed its 2020 GRAM filing with the Georgia PSC. The filing requests an annual base rate increase of certain conditions. On September 28, 2017,$37.6 million based on the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans underprojected 12-month period beginning January 1, 2021, which does not exceed the Loan Guarantee Agreement. Final approval and issuance of these additional loan guarantees5% limitation established by the DOE cannot be assured and are subject to the negotiationGeorgia PSC in its December 2019 approval of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to the financial statements of Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8Atlanta Gas Light's general base rate case. Resolution 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 to2020 GRAM filing is expected by December 31, 2020, with rates effective January 1, 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 while 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 while 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.
While construction continues, the risk remains that challenges with management of contractors, subcontractors, and vendors, 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.
Deferral of Incremental COVID-19 Costs
Atlanta Gas Light
On April 30, 2020, in response to the COVID-19 pandemic, the Georgia PSC approved orders directing Atlanta Gas Light to continue its previous, voluntary suspension of customer disconnections. On June 22, 2020, the Georgia PSC ordered Atlanta Gas Light to resume customer disconnections beginning July 1, 2020, with exceptions for customers still covered by a shelter-in-place order. The orders provide the Marketers, including SouthStar, with a mechanism to receive credits from Atlanta Gas Light for the base rates it charged to the Marketers of non-paying customers during the suspension. Atlanta Gas Light expects to recover these credits through the annual revenue true-up process within its 2021 GRAM filing, which would impact rates effective January 1, 2022. The ultimate outcome of this matter cannot be determined at this time.
Nicor Gas
On March 18, 2020, the Illinois Commission issued an order directing utilities to cease disconnections for non-payment and to suspend the imposition of late payment fees or penalties until the Governor of Illinois announces the end of the COVID-19 state of emergency. In response to this order, on March 27, 2020, Nicor Gas and other utilities in Illinois filed their plans seeking cost recovery and more flexible credit and collection plans.
On June 18, 2020, the Illinois Commission approved a stipulation pursuant to which the utilities will provide more flexible credit and collection procedures to assist customers with financial hardship and which authorizes a special
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
purpose rider for recovery of the following COVID-19 pandemic-related impacts: incremental costs directly associated with the COVID-19 pandemic, net of the offset for COVID-19 pandemic-related credits received, foregone late fees, foregone reconnection charges, and the costs associated with a bill payment assistance program. The special purpose rider is proposed to be effective on October 1, 2020 and continue over a 24-month period. At June 30, 2020, Nicor Gas' related regulatory asset was $12 million. The ultimate outcome of this matter cannot be determined at this time.
Virginia Natural Gas
In response to the COVID-19 pandemic, the Virginia Commission issued orders requiring Virginia Natural Gas to suspend disconnections beginning on March 16, 2020 and also to suspend late payment and reconnection fees beginning on April 9, 2020, both of which continue in effect through August 31, 2020. On April 29, 2020, the Virginia Commission authorized Virginia Natural Gas to defer the following COVID-19 pandemic-related costs as a regulatory asset: incremental uncollectible expense incurred, suspended late fees, suspended reconnection charges, carrying costs, and other incremental prudently incurred costs associated with the COVID-19 pandemic. Specific recovery of the amounts deferred in a regulatory asset will be addressed in a future rate proceeding. At June 30, 2020, Virginia Natural Gas' related regulatory asset was $1 million. The ultimate outcome of this matter cannot be determined at this time.
Infrastructure Replacement Programs and Capital Projects
In December 2019, Virginia Natural Gas filed an application with the Virginia Commission for a 24.1-mile header improvement project to improve resiliency and increase the supply of natural gas delivered to energy suppliers, including Virginia Natural Gas. On June 26, 2020, the Virginia Commission issued an order requiring Virginia Natural Gas to submit additional information by December 31, 2020 related to the financing plans of the project's primary customer before ruling on the December 2019 application. The ultimate outcome of this matter cannot be determined at this time.
(C) CONTINGENCIES
See RISK FACTORS of Georgia PowerNote 3 to the financial statements in Item 1A8 of the Form 10-K for a discussion of certain risks associated with the licensing, construction,information relating to various lawsuits 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.other contingencies.
General Litigation Matters
Georgia Power isThe Registrants are 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.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The ultimate outcome of such pending or potential litigation or regulatory matters against each Registrant and any subsidiaries cannot be predicteddetermined at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Georgia Power'ssuch Registrant's financial statements. See Note (B)
The Registrants believe the pending legal challenges discussed below have no merit; however, the ultimate outcome of these matters cannot be determined at this time.
Southern Company
In January 2017, a securities class action complaint was filed in the U.S. District Court for the Northern District of Georgia 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 names as defendants Southern Company, certain of its current and former officers, and certain former Mississippi Power officers and alleges that the defendants made materially false and misleading statements regarding the Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. In 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. Also in 2017, the defendants filed a motion to dismiss the Condensedplaintiffs' amended complaint with prejudice, to which the plaintiffs filed an
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
opposition. In 2018, the court issued an order dismissing certain claims against certain officers of Southern Company and Mississippi Power and dismissing the allegations related to a number of the statements that plaintiffs challenged as being false or misleading. In 2018, the court denied the defendants' motion for reconsideration and also denied a discussionmotion to certify the issue for interlocutory appeal. In the third quarter 2019, the court certified the plaintiffs' proposed class and the defendants filed a petition for interlocutory appeal of variousthe class certification order with the U.S. Court of Appeals for the Eleventh Circuit. In December 2019, the U.S. District Court for the Northern District of Georgia entered an order staying all deadlines in the case pending mediation. The stay automatically expired on March 31, 2020; however, in light of the COVID-19 pandemic, the U.S. District Court for the Northern District of Georgia vacated all existing discovery deadlines until June 15, 2020. On June 30, 2020, the court entered a revised scheduling order, which resumed discovery and set out remaining case deadlines.
In February 2017, Jean Vineyard and Judy Mesirov each filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its current and former officers, and certain former Mississippi Power officers. In 2017, these 2 shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. In 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the securities class action.
In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, Georgia that names as defendants Southern Company, certain of its directors, certain of its current and former officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other contingencies, regulatory matters,things, breached their fiduciary duties in connection with schedule delays and other matters being litigated which may affect future earnings potential.cost overruns associated with the construction of the Kemper County energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. 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. In 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the securities class action. In August 2019, the court granted a motion filed by the plaintiff in July 2019 to substitute a new named plaintiff, Martin J. Kobuck, in place of Helen E. Piper Survivor's Trust.
Georgia Power regularly reviews its business to transform and modernize. Primarily in response to changing customer expectations and payment patterns, including electronic payments and alternative payment locations, and ongoing efforts to increase overall operating efficiencies,
In 2011, plaintiffs filed a putative class action against Georgia Power initiatedin the closureSuperior Court of Fulton County, Georgia alleging that Georgia Power's collection in rates of amounts for municipal franchise fees (which fees are paid to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state law claims. This case has been ruled upon and appealed numerous times over the last several years. In one recent appeal, the Georgia Supreme Court remanded the case and noted that the trial court could refer the matter to the Georgia PSC to interpret its remaining payment officestariffs. Following a motion by Georgia Power, in February 2019, the Superior Court of Fulton County ordered the parties to submit petitions to the Georgia PSC for a declaratory ruling and also conditionally certified the proposed class. In March 2019, Georgia Power and the plaintiffs filed petitions with the Georgia PSC seeking confirmation of the proper application of the municipal franchise fee schedule pursuant to the Georgia PSC's orders. Also in March 2019, Georgia Power appealed the class certification decision to the Georgia Court of Appeals. In October 2019, the Georgia PSC issued an employee attrition plan affectingorder that found Georgia Power has appropriately implemented the municipal franchise fee schedule. On March 11, 2020, the Georgia Court of Appeals vacated the Superior Court of Fulton County's February 2019 order granting conditional class certification. The Court of
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Appeals remanded the case to the Superior Court of Fulton County for further proceedings. The amount of any possible losses cannot be calculated at this time because, among other factors, it is unknown whether a class will be certified, the ultimate composition of any class, and whether any losses would be subject to recovery from any municipalities.
On July 29, 2020, a group of individual plaintiffs filed a complaint in the Superior Court of Fulton County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater, surface water, and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages, a medical monitoring fund, and injunctive relief.
Mississippi Power
In May 2018, Southern Company and Mississippi Power received a notice of dispute and arbitration demand filed by Martin Product Sales, LLC (Martin) based on 2 agreements, both related to Kemper IGCC byproducts for which Mississippi Power provided termination notices in 2017. Martin alleges breach of contract, breach of good faith and fair dealing, fraud and misrepresentation, and civil conspiracy and makes a claim for damages in the amount of approximately 300 positions. Charges associated$143 million, as well as additional unspecified damages, attorney's fees, costs, and interest. A portion of the claim for damages was on behalf of Martin Transport, Inc. (Martin Transport), an affiliate of Martin. In May 2019, the arbitration panel denied Mississippi Power's and Southern Company's motions to dismiss. In September 2019, Martin Transport filed a separate complaint against Mississippi Power in the Circuit Court of Kemper County, Mississippi alleging claims of fraud, negligent misrepresentation, promissory estoppel, and equitable estoppel, each arising out of the same alleged facts and circumstances that underlie Martin's arbitration demand. Martin Transport seeks compensatory damages of $5 million and punitive damages of $50 million. In November 2019, Martin Transport's claim was combined with these activities did notthe Martin arbitration case and the separate court case was dismissed. In December 2019, Southern Company and Mississippi Power each filed motions for summary judgment on all claims. On February 17, 2020, the arbitration panel granted Southern Company's motion and dismissed Southern Company from the arbitration. On March 12, 2020, the arbitration panel denied Mississippi Power's motions for summary judgment. An adverse outcome in this proceeding could have a material impact on GeorgiaSouthern Company's and Mississippi Power's results of operations, financial position, or cash flows. The efficiencies gained are expected to place downward pressure on operating costs in 2018.statements.
ACCOUNTING POLICIES
Application of Critical Accounting PoliciesIn November 2018, Ray C. Turnage and Estimates
Georgia10 other individual plaintiffs filed a putative class action complaint against Mississippi Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 toand the financial statements of Georgia Power in Item 83 then-serving members of the Form 10-K.Mississippi PSC in the U.S. District Court for the Southern District of Mississippi. Mississippi Power received Mississippi PSC approval in 2013 to charge a mirror CWIP rate premised upon including in its rate base pre-construction and construction costs for the Kemper IGCC prior to placing the Kemper IGCC into service. The Mississippi Supreme Court reversed that approval and ordered Mississippi Power to refund the amounts paid by customers under the previously-approved mirror CWIP rate. The plaintiffs allege that the initial approval process, and the amount approved, were improper. They also allege that Mississippi Power underpaid customers by up to $23.5 million in the refund process by applying an incorrect interest rate. The plaintiffs seek to recover, on behalf of themselves and their putative class, actual damages, punitive damages, pre-judgment interest, post-judgment interest, attorney's fees, and costs. In response to Mississippi Power and the applicationMississippi PSC each filing a motion to dismiss, the plaintiffs filed an amended complaint in March 2019. The amended complaint included 4 additional plaintiffs and additional claims for gross negligence, reckless conduct, and intentional wrongdoing. Mississippi Power and the Mississippi PSC have each filed a motion to dismiss the amended complaint. On March 27, 2020, the Mississippi PSC's motion to dismiss was granted. Also on March 27, 2020, the plaintiffs filed a motion seeking to name the new members of these policies, certain estimates are made that maythe Mississippi PSC, the Mississippi Development Authority, and Southern Company as additional defendants and add a cause of action against all defendants based on a dormant commerce clause theory under the U.S. Constitution. On April 9, 2020 and April 10, 2020, Mississippi Power and the Mississippi PSC, respectively, filed responses opposing the motion for leave to file a second amended complaint. On May 26, 2020, Mississippi Power's motion to dismiss the first amended complaint filed in 2019 was granted. On July 6, 2020, the plaintiffs filed a motion for revision of the court's decision. The plaintiffs' motion for leave to file a second amended complaint also remains pending before the court. An adverse outcome in this proceeding could have a material impact on Georgia Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Georgia Power in Item 7 of the Form 10-K for a complete discussion of Georgia Power's critical accounting policies and estimates related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, and Contingent Obligations.
Recently Issued Accounting Standards
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Georgia Power in Item 7 of the Form 10-K for additional information.
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 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 with these customers will not result in a significant shift in the timing of revenue recognition for such sales.
Georgia Power's ongoing evaluation of other revenue streams and related contracts includes 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 GeorgiaMississippi 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 new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Georgia Power intends to use the modified retrospective method of adoption effective January 1, 2018. Georgia Power has
statements.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OFNOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(UNAUDITED)
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 Georgia Power's financial 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 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. 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.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with early adoption permitted. Georgia Power is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 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 September 30, 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 "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $1.48 billion for the first nine months of 2017 compared to $2.27 billion for the corresponding period in 2016. The decrease was primarily due to the timing of vendor payments and fossil fuel stock purchases and an increase in under-recovered fuel costs. Net cash used for investing activities totaled $1.83 billion for the first nine months of 2017 compared to $1.76 billion for the corresponding period in 2016 primarily related to installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities. Net cash provided from financing activities totaled $617 million for the first nine months of 2017 compared to $528 million used for financing activities in the
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
corresponding period in 2016. The increase in cash provided from financing activities is primarily due to an increase in short-term borrowings, higher issuances of senior notes and junior subordinated notes, and a decrease in maturities of senior notes, partially offset by a decrease in borrowings from the FFB for construction of Plant Vogtle Units 3 and 4 and an increase in redemptions of short-term borrowings. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first nine months of 2017 include increases of $1.2 billion in property, plant, and equipment to comply with environmental standards and the construction of generation, transmission, and distribution facilities, $1.2 billion in long-term debt primarily due to issuances of senior notes and junior subordinated notes, $423 million in accounts payable, other primarily due to charges for restoration costs related to Hurricane Irma and liabilities for the removal of subcontractor liens related to the EPC Contractor's bankruptcy, and $423 million in paid-in capital primarily due to capital contributions received from Southern Company. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Storm Damage Recovery" and " – Nuclear Construction" for additional information regarding Hurricane Irma and the EPC Contractor's bankruptcy, respectively.
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 $261 million will be required through September 30, 2018 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information. Also see FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating units, to meet regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. See Note 32 to the financial statements of Georgiaunder "Mississippi Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein for information regarding additional factors that may impact construction expenditures, including Georgia Power's cost-to-complete and cancellation cost assessments for Plant Vogtle Units 3 and 4.
Sources of Capital
Georgia Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, external security issuances, term loans, equity contributions from Southern Company, and, to the extent available, borrowings from the FFB. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Georgia Power in Item 7 of the Form 10-K for additional information.
In 2014, Georgia Power entered into the Loan Guarantee Agreement with the DOE, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 (i) Eligible Project Costs, less (ii) amounts received from Toshiba under the Guarantee Settlement Agreement and amounts received from the Westinghouse bankruptcy proceeding) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. As of September 30, 2017, Georgia Power had borrowed $2.6 billion under the FFB Credit Facility. On July 27, 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement, which provides that further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement and satisfaction of certain other conditions.
On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion of additional guaranteed loans under the Loan Guarantee Agreement. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to the financial statements 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 "Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
At September 30, 2017, Georgia Power's current liabilities exceeded current assets by $698 million. Georgia Power's current liabilities frequently exceed current assets because of scheduled maturities of long-term debt ($261 million at September 30, 2017) and the periodic use of short-term debt as a funding source ($400 million at September 30, 2017), as well as significant seasonal fluctuations in cash needs. Georgia Power intends to utilize operating cash flows, short-term debt, external security issuances, term loans, equity contributions from Southern Company, and, to the extent available, borrowings from the FFB to fund its short-term capital needs. Georgia Power has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet liquidity needs.
At September 30, 2017, Georgia Power had approximately $266 million of cash and cash equivalents. Georgia Power's committed credit arrangement with banks at September 30, 2017 was $1.75 billion of which $1.73 billion was unused. In May 2017, Georgia Power amended its multi-year credit arrangement, which, among other things, extended the maturity date from 2020 to 2022.
This bank credit arrangement, as well as Georgia Power's term loan arrangements, contains a covenant that limits debt levels and contains a cross-acceleration provision to other indebtedness (including guarantee obligations) of Georgia Power. Such cross-acceleration provision to other indebtedness would trigger an event of default if Georgia Power defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2017, Georgia Power was in compliance with this covenant. This bank credit arrangement does not contain a material adverse change clause at the time of borrowing.
Subject to applicable market conditions, Georgia Power expects to renew or replace this credit arrangement, as needed, prior to expiration. In connection therewith, Georgia Power may extend the maturity date and/or increase or decrease the lending commitments thereunder.
See Note 6 to the financial statements of Georgia Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
A portion of the unused credit with banks is allocated to provide liquidity support to Georgia Power's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of September 30, 2017 was approximately $550 million as compared to $868 million at December 31, 2016. 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
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
credit arrangement. In addition, at September 30, 2017, Georgia Power had $509 million of pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to September 30, 2017, $40 million of these pollution control revenue bonds which were in an index rate mode were remarketed to the public in a long-term fixed rate mode.
Georgia Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Georgia Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Georgia Power are loaned directly to Georgia Power. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support. Commercial paper is included in notes payable in the balance sheets.
Details of short-term borrowings were as follows:
|
| | | | | | | | | | | | | | | | | | |
| | | Short-term Debt at September 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 | | $ | — |
| | — | % | | $ | 109 |
| | 1.5 | % | | $ | 428 |
|
| Short-term bank debt | | 400 |
| | 2.0 | % | | 568 |
| | 2.0 | % | | 800 |
|
| Total | | $ | 400 |
| | 2.0 | % | | $ | 677 |
| | 2.0 | % | | |
| |
(*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2017. |
Georgia Power believes the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, short-term bank notes, and operating cash flows.
Credit Rating Risk
At September 30, 2017, Georgia Power did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, and transmission.
The maximum potential collateral requirements under these contracts at September 30, 2017 were as follows:
|
| | | |
| Credit Ratings | Maximum Potential
Collateral
Requirements |
| | (in millions) |
| At BBB- and/or Baa3 | $ | 87 |
|
| Below BBB- and/or Baa3 | $ | 1,021 |
|
Included in these amounts are certain agreements that could require collateral in the event that Georgia Power or Alabama Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Georgia Power to access capital markets and would be likely to impact the cost at which it does so.
On March 20, 2017, Moody's revised its rating outlook for Georgia Power from stable to negative.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including Georgia Power) from stable to negative.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
On March 30, 2017, Fitch placed the ratings of Georgia Power on rating watch negative.
Financing Activities
In March 2017, Georgia Power issued $450 million aggregate principal amount of Series 2017A 2.00% Senior Notes due March 30, 2020 and $400 million aggregate principal amount of Series 2017B 3.25% Senior Notes due March 30, 2027. The proceeds were used to repay a portion of Georgia Power's short-term indebtedness and for general corporate purposes, including Georgia Power's continuous construction program.
In April 2017, Georgia Power purchased and held $27 million aggregate principal amount of Development Authority of BurkeKemper County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1995. Subsequent to September 30, 2017, Georgia Power remarketed these bonds to the public.
In June 2017, Georgia Power repaid at maturity $450 million aggregate principal amount of Series 2007B 5.70% Senior Notes.
In June 2017, Georgia Power entered into three floating rate bank loans in aggregate principal amounts of $50 million, $150 million, and $100 million, with maturity dates of December 1, 2017, May 31, 2018, and June 28, 2018, respectively, which 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 August 2017, Georgia Power repaid $250 million of the $500 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement. Also in August 2017, Georgia Power amended its $100 million floating rate bank loan to extend the maturity date from June 28, 2018 to October 26, 2018.
Also in August 2017, Georgia Power issued $500 million aggregate principal amount of Series 2017C 2.00% Senior Notes due September 8, 2020. The proceeds were used to repay Georgia Power's $50 million floating rate bank loan due December 1, 2017 and outstanding commercial paper borrowings and for general corporate purposes.
Also in August 2017, Georgia Power purchased and held $38 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 1997. Subsequent to September 30, 2017, Georgia Power remarketed these bonds to the public.
In September 2017, Georgia Power issued $270 million aggregate principal amount of Series 2017A 5.00% Junior Subordinated Notes due October 1, 2077. The proceeds were used in October 2017 to redeem all 1.8 million shares ($45 million aggregate liquidation amount) of Georgia Power's 6.125% Series Class A Preferred Stock and 2.25 million shares ($225 million aggregate liquidation amount) of Georgia Power's 6.50% Series 2007A Preference Stock.
In 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, |
| | 2017 |
| 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | |
| Retail revenues | $ | 375 |
| | $ | 377 |
| | $ | 972 |
| | $ | 978 |
|
| Wholesale revenues, non-affiliates | 14 |
| | 17 |
| | 44 |
| | 48 |
|
| Wholesale revenues, affiliates | 28 |
| | 23 |
| | 75 |
| | 59 |
|
| Other revenues | 20 |
| | 19 |
| | 53 |
| | 51 |
|
| Total operating revenues | 437 |
| | 436 |
| | 1,144 |
| | 1,136 |
|
| Operating Expenses: | | | | | | | |
| Fuel | 127 |
| | 141 |
| | 323 |
| | 342 |
|
| Purchased power, non-affiliates | 37 |
| | 33 |
| | 104 |
| | 95 |
|
| Purchased power, affiliates | 2 |
| | 3 |
| | 13 |
| | 9 |
|
| Other operations and maintenance | 81 |
| | 86 |
| | 252 |
| | 239 |
|
| Depreciation and amortization | 42 |
| | 49 |
| | 95 |
| | 129 |
|
| Taxes other than income taxes | 33 |
| | 34 |
| | 88 |
| | 93 |
|
| Loss on Plant Scherer Unit 3 | — |
| | — |
| | 33 |
| | — |
|
| Total operating expenses | 322 |
| | 346 |
| | 908 |
| | 907 |
|
| Operating Income | 115 |
| | 90 |
| | 236 |
| | 229 |
|
| Other Income and (Expense): | | | | | | | |
| Interest expense, net of amounts capitalized | (13 | ) | | (11 | ) | | (37 | ) | | (36 | ) |
| Other income (expense), net | 1 |
| | (2 | ) | | — |
| | (4 | ) |
| Total other income and (expense) | (12 | ) | | (13 | ) | | (37 | ) | | (40 | ) |
| Earnings Before Income Taxes | 103 |
| | 77 |
| | 199 |
| | 189 |
|
| Income taxes | 40 |
| | 30 |
| | 78 |
| | 74 |
|
| Net Income | 63 |
| | 47 |
| | 121 |
| | 115 |
|
| Dividends on Preference Stock | — |
| | 2 |
| | 4 |
| | 7 |
|
| Net Income After Dividends on Preference Stock | $ | 63 |
| | $ | 45 |
| | $ | 117 |
| | $ | 108 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) |
| Net Income | $ | 63 |
| | $ | 47 |
| | $ | 121 |
| | $ | 115 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
| Changes in fair value, net of tax of $-, $-, $(1), and $(3), respectively | — |
| | — |
| | (1 | ) | | (4 | ) |
| Total other comprehensive income (loss) | — |
| | — |
| | (1 | ) | | (4 | ) |
| Comprehensive Income | $ | 63 |
| | $ | 47 |
| | $ | 120 |
| | $ | 111 |
|
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, |
| | 2017 | | 2016 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 121 |
| | $ | 115 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 100 |
| | 134 |
|
| Deferred income taxes | 57 |
| | 15 |
|
| Loss on Plant Scherer Unit 3 | 33 |
| | — |
|
| Other, net | (5 | ) | | (2 | ) |
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (65 | ) | | (9 | ) |
| -Fossil fuel stock | 7 |
| | 49 |
|
| -Other current assets | 11 |
| | 3 |
|
| -Accrued taxes | 21 |
| | 40 |
|
| -Accrued compensation | (10 | ) | | (5 | ) |
| -Over recovered regulatory clause revenues | (8 | ) | | 26 |
|
| -Other current liabilities | 10 |
| | 8 |
|
| Net cash provided from operating activities | 272 |
| | 374 |
|
| Investing Activities: | | | |
| Property additions | (142 | ) | | (106 | ) |
| Cost of removal, net of salvage | (16 | ) | | (8 | ) |
| Change in construction payables | (9 | ) | | (7 | ) |
| Other investing activities | (6 | ) | | (6 | ) |
| Net cash used for investing activities | (173 | ) | | (127 | ) |
| Financing Activities: | | | |
| Decrease in notes payable, net | (268 | ) | | (42 | ) |
| Proceeds — | | | |
| Common stock issued to parent | 175 |
| | — |
|
| Capital contributions from parent company | 7 |
| | 10 |
|
| Senior notes | 300 |
| | — |
|
| Redemptions — | | | |
| Preference stock | (150 | ) | | — |
|
| Senior notes | (85 | ) | | (125 | ) |
| Payment of common stock dividends | (94 | ) | | (90 | ) |
| Other financing activities | (3 | ) | | (5 | ) |
| Net cash used for financing activities | (118 | ) | | (252 | ) |
| Net Change in Cash and Cash Equivalents | (19 | ) | | (5 | ) |
| Cash and Cash Equivalents at Beginning of Period | 56 |
| | 74 |
|
| Cash and Cash Equivalents at End of Period | $ | 37 |
| | $ | 69 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid during the period for — | | | |
| Interest (net of $- and $- capitalized for 2017 and 2016, respectively) | $ | 24 |
| | $ | 29 |
|
| Income taxes, net | 19 |
| | 14 |
|
| Noncash transactions — Accrued property additions at end of period | 25 |
| | 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, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 37 |
| | $ | 56 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 96 |
| | 72 |
|
| Unbilled revenues | | 68 |
| | 55 |
|
| Under recovered regulatory clause revenues | | 15 |
| | 17 |
|
| Income taxes receivable, current | | 15 |
| | — |
|
| Other accounts and notes receivable | | 12 |
| | 6 |
|
| Affiliated | | 13 |
| | 17 |
|
| Accumulated provision for uncollectible accounts | | (1 | ) | | (1 | ) |
| Fossil fuel stock | | 64 |
| | 71 |
|
| Materials and supplies | | 58 |
| | 55 |
|
| Other regulatory assets, current | | 55 |
| | 44 |
|
| Other current assets | | 15 |
| | 30 |
|
| Total current assets | | 447 |
| | 422 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 5,181 |
| | 5,140 |
|
| Less: Accumulated provision for depreciation | | 1,457 |
| | 1,382 |
|
| Plant in service, net of depreciation | | 3,724 |
| | 3,758 |
|
| Construction work in progress | | 75 |
| | 51 |
|
| Total property, plant, and equipment | | 3,799 |
| | 3,809 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 56 |
| | 58 |
|
| Other regulatory assets, deferred | | 499 |
| | 512 |
|
| Other deferred charges and assets | | 22 |
| | 21 |
|
| Total deferred charges and other assets | | 577 |
| | 591 |
|
| Total Assets | | $ | 4,823 |
| | $ | 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, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 7 |
| | $ | 87 |
|
| Notes payable | | — |
| | 268 |
|
| Accounts payable — | | | | |
| Affiliated | | 46 |
| | 59 |
|
| Other | | 55 |
| | 54 |
|
| Customer deposits | | 35 |
| | 35 |
|
| Accrued taxes | | 41 |
| | 20 |
|
| Accrued interest | | 20 |
| | 8 |
|
| Accrued compensation | | 30 |
| | 40 |
|
| Deferred capacity expense, current | | 22 |
| | 22 |
|
| Other regulatory liabilities, current | | 1 |
| | 16 |
|
| Other current liabilities | | 37 |
| | 40 |
|
| Total current liabilities | | 294 |
| | 649 |
|
| Long-term Debt | | 1,285 |
| | 987 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 1,003 |
| | 948 |
|
| Employee benefit obligations | | 90 |
| | 96 |
|
| Deferred capacity expense | | 103 |
| | 119 |
|
| Asset retirement obligations, deferred | | 125 |
| | 120 |
|
| Other cost of removal obligations | | 218 |
| | 249 |
|
| Other regulatory liabilities, deferred | | 45 |
| | 47 |
|
| Other deferred credits and liabilities | | 71 |
| | 71 |
|
| Total deferred credits and other liabilities | | 1,655 |
| | 1,650 |
|
| Total Liabilities | | 3,234 |
| | 3,286 |
|
| Preference Stock | | — |
| | 147 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, without par value — | | | | |
| Authorized — 20,000,000 shares | | | | |
| Outstanding — September 30, 2017: 7,392,717 shares | | | | |
| — December 31, 2016: 5,642,717 shares | | 678 |
| | 503 |
|
| Paid-in capital | | 600 |
| | 589 |
|
| Retained earnings | | 312 |
| | 296 |
|
| Accumulated other comprehensive income (loss) | | (1 | ) | | 1 |
|
| Total common stockholder's equity | | 1,589 |
| | 1,389 |
|
| Total Liabilities and Stockholder's Equity | | $ | 4,823 |
| | $ | 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
THIRD QUARTER 2017 vs. THIRD QUARTER 2016
AND
YEAR-TO-DATE 2017 vs. YEAR-TO-DATE 2016
OVERVIEW
Gulf Power operates as a vertically integrated utility providing electric service to retail customers within its traditional service territory located in northwest Florida and to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of Gulf Power's business of providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, reliability, restoration following major storms, fuel, and capital expenditures. Gulf Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Gulf Power for the foreseeable future.
On April 4, 2017, the Florida PSC approved a settlement agreement (2017 Rate Case Settlement Agreement) among Gulf Power and three intervenors with respect to Gulf Power's request to increase retail base rates. Among the terms of the 2017 Rate Case Settlement Agreement, Gulf Power increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consisted of a $62.0 million increase in annual base revenues less an annual 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%), 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), which was recorded in the first quarter 2017. The remaining issues related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause rate approved by the Florida PSC in November 2016.
Gulf Power continues to focus on several key performance indicators including, but not limited to, customer satisfaction, plant availability, system reliability, and net income after dividends on preference stock.
RESULTS OF OPERATIONS
Net Income
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $18 | | 40.0 | | $9 | | 8.3 |
Gulf Power's net income after dividends on preference stock for the third quarter 2017 was $63 million compared to $45 million for the corresponding period in 2016. The increase was primarily due to an increase in retail base revenues and a decrease in depreciation.
Gulf Power's net income after dividends on preference stock for year-to-date 2017 was $117 million compared to $108 million for the corresponding period in 2016. The increase was primarily due to a decrease in depreciation and
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
an increase in retail base revenues, partially offset by a write-down of $32.5 million ($20 million after tax) of Gulf Power's ownership of Plant Scherer Unit 3 resulting from the 2017 Rate Case Settlement Agreement and higher operations and maintenance expenses. See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information regarding the 2017 Rate Case Settlement Agreement.
Retail Revenues
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(2) | | (0.5) | | $(6) | | (0.6) |
In the third quarter 2017, retail revenues were $375 million compared to $377 million for the corresponding period in 2016. For year-to-date 2017, retail revenues were $972 million compared to $978 million for the corresponding period in 2016.
Details of the changes in retail revenues were as follows:
|
| | | | | | | | | | | | | |
| | Third Quarter 2017 | | Year-to-Date 2017 |
| | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | $ | 377 |
| | | | $ | 978 |
| | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 21 |
| | 5.6 |
| | 28 |
| | 2.9 |
|
| Sales growth | 3 |
| | 0.8 |
| | 1 |
| | 0.1 |
|
| Weather | (9 | ) | | (2.4 | ) | | (14 | ) | | (1.4 | ) |
| Fuel and other cost recovery | (17 | ) | | (4.5 | ) | | (21 | ) | | (2.2 | ) |
| Retail – current year | $ | 375 |
| | (0.5 | )% | | $ | 972 |
| | (0.6 | )% |
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" of Gulf Power in Item 7 and Note 1 to the financial statements of Gulf Power under "Revenues" and Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information regarding Gulf Power's retail base rate case and cost recovery clauses, including Gulf Power's fuel cost recovery, purchased power capacity recovery, environmental cost recovery, and energy conservation cost recovery clauses.
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016 primarily due to an increase in retail base revenues effective July 2017, as well as an increase in environmental cost recovery effective November 2016 resulting from Gulf Power's ownership of Plant Scherer Unit 3 being rededicated to retail service.
Revenues attributable to changes in sales increased slightly in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016. For the third quarter 2017, weather-adjusted KWH sales to residential and commercial customers increased 5.2% and 1.5%, respectively. Weather-adjusted KWH sales to residential customers increased 1.3% year-to-date 2017. These increases were primarily due to customer growth, partially offset by lower customer usage primarily resulting from efficiency improvements in appliances and lighting. Weather-adjusted KWH sales to commercial customers decreased slightly year-to-date 2017 as a result of lower customer usage primarily resulting from efficiency improvements in appliances and lighting, mostly offset by customer growth. KWH sales to industrial customers decreased 7.1% and 6.1% for the third quarter and year-to-date 2017, respectively, primarily due to changes in customers' operations and energy efficiency improvements.
Fuel and other cost recovery revenues decreased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016, primarily due to lower fuel, purchased power capacity, and energy conservation recoverable costs, partially offset by higher environmental recoverable costs. Fuel and other cost recovery
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
provisions include fuel expenses, the energy component of purchased power costs, purchased power capacity costs, the difference between projected and actual costs and revenues related to energy conservation and environmental compliance, and a credit for certain wholesale revenues as a result of the 2017 Rate Case Settlement Agreement. 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 cost recovery clauses and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information regarding the 2017 Rate Case Settlement Agreement.
Wholesale Revenues – Non-Affiliates
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(3) | | (17.6) | | $(4) | | (8.3) |
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 2017, wholesale revenues from sales to non-affiliates were $14 million compared to $17 million for the corresponding period in 2016. The decrease was primarily due to a 28.4% decrease in KWH sales attributable to decreased market demand for energy as a result of milder weather.
For year-to-date 2017, wholesale revenues from sales to non-affiliates were $44 million compared to $48 million for the corresponding period in 2016. The decrease was primarily due to a 20.9% decrease in capacity revenues resulting from the expiration of a Plant Scherer Unit 3 long-term sales agreement in 2016.
Wholesale Revenues – Affiliates
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $5 | | 21.7 | | $16 | | 27.1 |
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since the revenue related to these energy sales generally offsets the cost of energy sold.
In the third quarter 2017, wholesale revenues from sales to affiliates were $28 million compared to $23 million for the corresponding period in 2016. The increase was primarily due to a 24.1% increase in KWH sales resulting from outages of affiliate generation resources.
For year-to-date 2017, wholesale revenues from sales to affiliates were $75 million compared to $59 million for the corresponding period in 2016. The increase was primarily due to a 19.5% increase in KWH sales as a result of the availability of lower-cost Gulf Power generation resources.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | | | |
| | Third Quarter 2017
vs.
Third Quarter 2016 | | Year-to-Date 2017
vs.
Year-to-Date 2016 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | (14 | ) | | (9.9 | ) | | $ | (19 | ) | | (5.6 | ) |
| Purchased power – non-affiliates | 4 |
| | 12.1 |
| | 9 |
| | 9.5 |
|
| Purchased power – affiliates | (1 | ) | | (33.3 | ) | | 4 |
| | 44.4 |
|
| Total fuel and purchased power expenses | $ | (11 | ) | | | | $ | (6 | ) | | |
In the third quarter 2017, total fuel and purchased power expenses were $166 million compared to $177 million for the corresponding period in 2016. The decrease was primarily the result of a $7 million net decrease due to the lower average cost of fuel and a $6 million net decrease related to the volume of KWHs generated and purchased due to milder weather in 2017 reducing demand.
For year-to-date 2017, total fuel and purchased power expenses were $440 million compared to $446 million for the corresponding period in 2016. The decrease was primarily the result of a $19 million net decrease related to the volume of KWHs generated and purchased due to milder weather in 2017 reducing demand, partially offset by a $12 million net increase related to the higher average cost of fuel and purchased power.
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"Energy Facility" in Item 8 of the Form 10-K for additional information.
Environmental Remediation
The Southern Company system must comply with environmental laws and regulations governing the handling and disposal of Gulf Power's generationwaste and purchased power were as follows:
|
| | | | | | | |
| | Third Quarter 2017 | | Third Quarter 2016 | | Year-to-Date 2017 | | Year-to-Date 2016 |
Total generation (in millions of KWHs) | 2,780 | | 2,775 | | 7,000 | | 6,654 |
Total purchased power (in millions of KWHs) | 1,686 | | 1,906 | | 4,362 | | 5,295 |
Sources of generation (percent) – | | | | | | | |
| Coal | 59 | | 68 | | 55 | | 57 |
| Gas | 41 | | 32 | | 45 | | 43 |
Cost of fuel, generated (in cents per net KWH) – | | | | | | | |
| Coal | 3.04 | | 3.55 | | 3.15 | | 3.80 |
| Gas | 3.71 | | 4.38 | | 3.60 | | 4.06 |
Average cost of fuel, generated (in cents per net KWH) | 3.31 | | 3.81 | | 3.35 | | 3.91 |
Average cost of purchased power (in cents per net KWH)(*) | 4.32 | | 3.79 | | 4.70 | | 3.51 |
| |
(*) | Average cost of purchased power includes fuel purchased by Gulf Power for tolling agreements where power is generated by the provider. |
Fuel
In the third quarter 2017, fuel expense was $127 million compared to $141 million for the corresponding period in 2016. The decrease was primarily due to a 13.1% decrease in the average costreleases of fuel resulting from lower coalhazardous substances. Under these various laws and natural gas prices, partially offset by a 29.3% increase in the volume of KWHs generated by Gulf Power's gas-fired generation resources.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2017, fuel expense was $323 million compared to $342 million for the corresponding period in 2016. The decrease was primarily due to a 14.3% decrease in the average cost of fuel resulting from lower coal and natural gas prices, partially offset by a 10.3% increase in the volume of KWHs generated by Gulf Power's gas-fired generation resources.
Purchased Power – Non-Affiliates
In the third quarter 2017, purchased power expense from non-affiliates was $37 million compared to $33 million for the corresponding period in 2016. For year-to-date 2017, purchased power expense from non-affiliates was $104 million compared to $95 million for the corresponding period in 2016. These increases were primarily due to increases of 16.3% and 35.9% for the third quarter and year-to-date 2017, respectively, in the average cost per KWH purchased, partially offset by decreases of 11.1% and 20.2% for the third quarter and year-to-date 2017, respectively, in the volume of KWHs purchased due to lower territorial load.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost ofregulations, the Southern Company system's generation, demand for energy within the Southern Company system'ssystem could incur substantial costs to clean up affected sites. The traditional electric service territory,operating companies and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the third quarter 2017, purchased power expense from affiliates was $2 million compared to $3 million for the corresponding period in 2016. The decrease was primarily due to a 38.3% decrease in the average cost per KWH purchased primarily resulting from lower priced power pool resources and a 20.5% decrease in the volume of KWHs purchased due to lower territorial load.
For year-to-date 2017, purchased power expense from affiliates was $13 million compared to $9 million for the corresponding period in 2016. The increase was primarily due to a 13.2% increase in the volume of KWHs purchased due to more planned outages for Gulf Power generation resources and a 29.3% increase in the average cost per KWH purchased primarily due to increased natural gas prices.
Energy purchasesdistribution utilities in Illinois and Georgia have each received authority 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 IICtheir respective state PSCs or other contractual agreements,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 FERC.state PSCs or other applicable state regulatory agencies.
Other OperationsGeorgia Power's environmental remediation liability was $14 million and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(5) | | (5.8) | | $13 | | 5.4 |
In December 2019, Mississippi Power entered into an agreement with the third quarter 2017, other operationsMississippi Commission on Environmental Quality related to groundwater conditions arising from the closed ash pond at Plant Watson. Mississippi Power will complete an assessment and maintenance expenses were $81 million compared to $86 million forremediation consistent with the corresponding period in 2016. The decrease was primarily due to lower employee compensation and benefits, including pension costs,requirements of the agreement and the suspension of the property damage reserve accrual in accordance with the 2017 Rate Case Settlement Agreement.
For year-to-date 2017, other operationsCCR Rule. Potential remediation activities and maintenance expenses were $252 million compared to $239 million for the corresponding period in 2016. The increase was primarily due to higher expenses at generation facilities associated with routine and planned maintenance.
See Note (A) to the Condensed Financial Statements under "Property Damage Reserve" herein for additional information regarding Gulf Power's property damage reserve accrual suspension and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information regarding the 2017 Rate Case Settlement Agreement.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Depreciation and Amortization
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(7) | | (14.3) | | $(34) | | (26.4) |
In the third quarter 2017, depreciation and amortization was $42 million compared to $49 million for the corresponding period in 2016. For year-to-date 2017, depreciation and amortization was $95 million compared to $129 million for the corresponding period in 2016. These decreases were primarily due to changes in the reductions in depreciation, as authorized in a settlement agreement approved by the Florida PSC in 2013 (2013 Rate Case Settlement Agreement), of $6 million and $34 million in the third quarter and year-to-date 2017, respectively, compared to the corresponding periods in 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 "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information.
Income Taxes
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $10 | | 33.3 | | $4 | | 5.4 |
In the third quarter 2017, income taxes were $40 million compared to $30 million for the corresponding period in 2016. For year-to-date 2017, income taxes were $78 million compared to $74 million for the corresponding period in 2016. These increases were primarily due to higher pre-tax earnings.
Dividends on Preference Stock
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(2) | | N/M | | $(3) | | (42.9) |
N/M - Not meaningful
In the third quarter 2017, there were no dividends on preference stock compared to $2 million for the corresponding period in 2016. For year-to-date 2017, dividends on preference stock were $4 million compared to $7 million for the corresponding period in 2016. These decreases wererelated cost estimates are pending the result of the redemption of all preference stock in June 2017. See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Gulf Power's future earnings potential. The level of Gulf Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Gulf Power's business of providing electric service. These factors include Gulf Power's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs during a time of increasing costs and limited projected demand growth over the next several years. Future earnings will be driven primarily by customer growth. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies due to changes in the minimum allowable equipment efficiencies along with the continuation of changes in customer behavior. Earnings are subject to a variety of other factors. These factors include weather, competition, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Gulf Power's service territory. Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings. Current proposals related to
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 rulesfurther site assessment and cannot be determined at this time, but could have a material impacttime. Mississippi Power expects to recover the retail portion of remedial costs through the ECO Plan and the wholesale portion through MRA rates.
Southern Company Gas' environmental remediation liability was $253 million and $269 million as of June 30, 2020 and December 31, 2019, respectively, based on Gulf Power's financial statements. For additional information relating to these issues, see RISK FACTORS in Item 1Athe estimated cost of environmental investigation and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Gulf Power in Item 7remediation associated with known current and former manufactured gas plant operating sites. These environmental remediation expenditures are generally recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies 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 legislative or regulatory changes cannot be determined at this time. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higher costs that are recovered through regulated rates or long-term wholesale agreements could contribute to reduced demand for electricity as well as impact the cost competitiveness of wholesale capacity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters," "Retail Regulatory Matters – Cost Recovery Clauses – Environmental Cost Recovery," and "Other Matters" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Statutes and Regulations
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the final 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 September 18, 2017, the EPA published a final 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.natural gas distribution utilities.
The ultimate outcome of these matters cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Gulf Power in Item 7 of the Form 10-K for additional information.
On March 28, 2017, the 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
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
those rules. On October 16, 2017, the EPA published a proposed rule to repeal the Clean Power Plan. The EPA has not determined whether or when it will promulgate a replacement rule.
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 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 related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including Gulf Power's) and Southern Power's June 30, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including Gulf Power) and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order, or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including Gulf Power) and Southern Power expect to make a filing within the specified 60 days responding to the FERC's order.
The ultimate outcome of these matters cannot be determined at this time.
Retail Regulatory Matters
Gulf Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Florida PSC. Gulf Power's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased energy costs, purchased power capacity costs, energy conservation and demand side management programs, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are recovered through base rates. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.
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 could 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. Through June 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 three intervenors with respect to Gulf Power's request to increase retail base rates. Among the terms of the 2017 Rate Case Settlement Agreement, Gulf Power increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consisted of a $62.0 million increase in annual base revenues less an annual equivalent credit of approximately $7.7 million for 2017 for
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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%), 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 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, 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 resolvedtime; however, as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated withregulatory treatment for environmental remediation expenses described above, the ongoing ownership and operation of the unit through the environmental cost recovery clause rate approved by the Florida PSC in November 2016.
Cost Recovery Clauses
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Cost Recovery Clauses" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K for additional information regarding Gulf Power's recovery of retail costs through various regulatory clauses and accounting orders. Gulf Power has four regulatory clauses which are approved by the Florida PSC. See Note (B) to the Condensed Financial Statements herein for additional information.
As discussed previously, the 2017 Rate Case Settlement Agreement resolved the remaining issues related to Gulf Power's inclusion of certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 in the environmental cost recovery clause and no adjustment to the environmental cost recovery clause rate approved by the Florida PSC in November 2016 was made.
On October 25, 2017, the Florida PSC approved Gulf Power's annual rate clause request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2018. The net effect of the approved changes is a $63 million increase in annual revenues effective in January 2018, the majority of which will be offset by related expense increases.
Renewables
In 2015, the Florida PSC approved three energy purchase agreements totaling 120 MWs of utility-scale solar generation located at three military installations in northwest Florida. Purchases under these agreements began in the summer of 2017.
Other Matters
Gulf Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Gulf Power is subject to certain claims and legal actions arising in the ordinary course of business. Gulf Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation or regulatory matters 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 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.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 applicationfinal disposition of these policies, certain estimates are made that may have a material impact on Gulf Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Gulf Power in Item 7 of the Form 10-K for a complete discussion of Gulf Power's critical accounting policies and estimates related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, and Contingent Obligations.
Recently Issued Accounting Standards
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Gulf Power in Item 7 of the Form 10-K for additional information.
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 Gulf Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Gulf Power's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term, 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 shift in the timing of revenue recognition for such sales.
Gulf 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 Gulf 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, Gulf Power expects CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Gulf Power intends to use the modified retrospective method of adoption effective January 1, 2018. Gulf 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,matters is not expected to have a material impact on either the timing or amount of revenues recognized in Gulf Power's financial 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 items as other compensation costs and requires the other components of net periodic pension and postretirement benefit
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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. 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.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with early adoption permitted. Gulf Power is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 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 September 30, 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 $272 million for the first nine months of 2017 compared to $374 million for the corresponding period in 2016. The $102 million decrease in net cash was primarily due to decreases related to certain cost recovery clauses, the timing of fossil fuel stock purchases, and a federal income tax refund received in 2016. Net cash used for investing activities totaled $173 million in the first nine months of 2017 primarily due to property additions to utility plant. Net cash used for financing activities totaled $118 million for the first nine months of 2017 primarily due to the payment of short-term debt, redemptions of preference stock and long-term debt, and common stock dividend payments, partially offset by proceeds from issuances of long-term debt and common stock. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first nine months of 2017 primarily reflect the financing activities described above. Other significant changes include an increase in accumulated deferred income taxes due to accelerated depreciation and repair deductions and a decrease in other cost of removal obligations, as authorized in the 2013 Rate Case Settlement Agreement. See "Financing Activities" herein and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Gulf Power in Item 7 of the Form 10-K for a description of Gulf Power's capital requirements for its construction program, including estimated capital expenditures to comply
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, leases, derivative obligations, purchase commitments, and trust funding requirements. Approximately $7 million will be required through September 30, 2018 to fund maturities of long-term debt. See "Financing Activities" herein for additional information.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating units, to meet regulatory requirements; changes in the expected environmental compliance programs; changes in FERC rules and regulations; Florida PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Sources of Capital
Gulf Power plans to obtain the funds required to meet its future capital needs from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, external security issuances, term loans, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Gulf Power in Item 7 of the Form 10-K for additional information.
Gulf Power's current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt, as well as significant seasonal fluctuations in cash needs. Gulf Power has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet short-term liquidity needs, including its commercial paper program which is supported by bank credit facilities.
At September 30, 2017, Gulf Power had approximately $37 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2017 were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Expires | | | | | | Executable Term Loans | | Expires Within One Year |
| 2017 | | 2018 | | 2019 | | 2020 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out |
| (in millions) |
| $ | 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-acceleration provisions to other indebtedness (including guarantee obligations) of Gulf Power. Such cross-acceleration provisions to other indebtedness would trigger an event of default if Gulf Power defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2017, Gulf Power was in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, Gulf Power expects to renew or replace its bank credit arrangements, as needed, prior to expiration. In connection therewith, Gulf Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Most of the unused credit arrangements with banks are allocated to provide liquidity support to Gulf Power's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of September 30, 2017 was approximately $82 million. In addition, at September 30, 2017, Gulf Power had approximately $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. Short-term borrowings are included in notes payable in the balance sheets.
Details of short-term borrowings were as follows:
|
| | | | | | | | | | | |
| | | Short-term Debt During the Period(*) |
| | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) |
| Commercial paper | | $ | 23 |
| | 1.4 | % | | $ | 78 |
|
| |
(*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2017. No short-term debt was outstanding at September 30, 2017. |
Gulf Power believes the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, short-term bank loans, and operating cash flows.
Credit Rating Risk
At September 30, 2017, Gulf Power did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management.
The maximum potential collateral requirements under these contracts at September 30, 2017 were as follows:
|
| | | |
| Credit Ratings | Maximum Potential Collateral Requirements |
| | (in millions) |
| At BBB- and/or Baa3 | $ | 167 |
|
| Below BBB- and/or Baa3 | $ | 579 |
|
Included in these amounts are certain agreements that could require collateral in the event that Alabama Power or Georgia Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Gulf Power to access capital markets and would be likely to impact the cost at which it does so.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including Gulf Power) from stable to negative.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Market Price Risk
Gulf Power's market risk exposure relative to interest rate changes for the third quarter and year-to-date 2017 has not changed materially compared to the December 31, 2016 reporting period. Gulf Power's exposure to market volatility in commodity fuel prices and prices of electricity with respect to its wholesale generating capacity is limited because its long-term sales agreement shifts substantially all fuel cost responsibility to the purchaser.
In connection with the 2017 Rate Case Settlement Agreement, Gulf Power recorded a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 in the first quarter 2017 to resolve the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates and no adjustment to the environmental cost recovery clause rate 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 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 until January 1, 2021 in connection with the 2017 Rate Case Settlement Agreement. The moratorium does not have an impact on the recovery of existing hedges entered into under the previously-approved hedging program.
For additional discussion of Gulf Power's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Gulf Power in Item 7 of the Form 10-K.
Financing Activities
In January 2017, Gulf Power issued 1,750,000 shares of common stock to Southern Company and realized proceeds of $175 million. The proceeds were used for general corporate purposes, including Gulf Power's continuous construction program.
In March 2017, Gulf Power extended the maturity of a $100 million short-term floating rate bank loan bearing interest based on one-month LIBOR from April 2017 to October 2017 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 May 30, 2027. The proceeds, together with other funds, were used to repay at maturity $85 million aggregate principal amount of Series 2007A 5.90% Senior Notes due June 15, 2017; to repay outstanding commercial paper borrowings; to repay a $100 million short-term floating rate bank loan, as discussed above; and to redeem, in June 2017, 550,000 shares ($55 million aggregate liquidation amount) of 6.00% Series Preference Stock, 450,000 shares ($45 million aggregate liquidation amount) of Series 2007A 6.45% Preference Stock, and 500,000 shares ($50 million aggregate liquidation amount) of Series 2013A 5.60% Preference Stock.
In 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, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | |
| Retail revenues | $ | 243 |
| | $ | 263 |
| | $ | 665 |
| | $ | 652 |
|
| Wholesale revenues, non-affiliates | 72 |
| | 78 |
| | 196 |
| | 198 |
|
| Wholesale revenues, affiliates | 21 |
| | 7 |
| | 40 |
| | 23 |
|
| Other revenues | 5 |
| | 4 |
| | 14 |
| | 12 |
|
| Total operating revenues | 341 |
| | 352 |
| | 915 |
| | 885 |
|
| Operating Expenses: | | | | | | | |
| Fuel | 120 |
| | 112 |
| | 301 |
| | 268 |
|
| Purchased power, non-affiliates | 4 |
| | 3 |
| | 7 |
| | 4 |
|
| Purchased power, affiliates | 2 |
| | 5 |
| | 13 |
| | 14 |
|
| Other operations and maintenance | 66 |
| | 74 |
| | 206 |
| | 211 |
|
| Depreciation and amortization | 39 |
| | 30 |
| | 120 |
| | 114 |
|
| Taxes other than income taxes | 25 |
| | 31 |
| | 77 |
| | 81 |
|
| Estimated loss on Kemper IGCC | 34 |
| | 88 |
| | 3,155 |
| | 222 |
|
| Total operating expenses | 290 |
| | 343 |
| | 3,879 |
| | 914 |
|
| Operating Income (Loss) | 51 |
| | 9 |
| | (2,964 | ) | | (29 | ) |
| Other Income and (Expense): | | | | | | | |
| Allowance for equity funds used during construction | 1 |
| | 31 |
| | 72 |
| | 90 |
|
| Interest expense, net of amounts capitalized | 13 |
| | (15 | ) | | (23 | ) | | (46 | ) |
| Other income (expense), net | (1 | ) | | (1 | ) | | (3 | ) | | (4 | ) |
| Total other income and (expense) | 13 |
| | 15 |
| | 46 |
| | 40 |
|
| Earnings (Loss) Before Income Taxes | 64 |
| | 24 |
| | (2,918 | ) | | 11 |
|
| Income taxes (benefit) | 24 |
| | (2 | ) | | (885 | ) | | (29 | ) |
| Net Income (Loss) | 40 |
| | 26 |
| | (2,033 | ) | | 40 |
|
| Dividends on Preferred Stock | — |
| | — |
| | 1 |
| | 1 |
|
| Net Income (Loss) After Dividends on Preferred Stock | $ | 40 |
| | $ | 26 |
| | $ | (2,034 | ) | | $ | 39 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) |
| Net Income (Loss) | $ | 40 |
| | $ | 26 |
| | $ | (2,033 | ) | | $ | 40 |
|
| 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) | $ | 39 |
| | $ | 26 |
| | $ | (2,032 | ) | | $ | 40 |
|
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, |
| | 2017 | | 2016 |
| | (in millions) |
| Operating Activities: | | | |
| Net income (loss) | $ | (2,033 | ) | | $ | 40 |
|
| Adjustments to reconcile net income (loss) to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 144 |
| | 115 |
|
| Deferred income taxes | (1,159 | ) | | 34 |
|
| Allowance for equity funds used during construction | (72 | ) | | (90 | ) |
| Estimated loss on Kemper IGCC | 3,148 |
| | 222 |
|
| Other, net | (26 | ) | | (1 | ) |
| Changes in certain current assets and liabilities — | | | |
| -Receivables | 438 |
| | 3 |
|
| -Fossil fuel stock | 21 |
| | 8 |
|
| -Other current assets | (9 | ) | | 34 |
|
| -Accounts payable | (21 | ) | | 5 |
|
| -Accrued taxes | 20 |
| | 96 |
|
| -Accrued compensation | (12 | ) | | (5 | ) |
| -Over recovered regulatory clause revenues | (47 | ) | | (20 | ) |
| -Customer liability associated with Kemper refunds | — |
| | (73 | ) |
| -Other current liabilities | (31 | ) | | 5 |
|
| Net cash provided from operating activities | 361 |
| | 373 |
|
| Investing Activities: | | | |
| Property additions | (411 | ) | | (592 | ) |
| Construction payables | (47 | ) | | (25 | ) |
| Government grant proceeds | — |
| | 137 |
|
| Other investing activities | (25 | ) | | (29 | ) |
| Net cash used for investing activities | (483 | ) | | (509 | ) |
| Financing Activities: | | | |
| Decrease in notes payable, net | (23 | ) | | — |
|
| Proceeds — | | | |
| Capital contributions from parent company | 1,002 |
| | 227 |
|
| Long-term debt to parent company | 40 |
| | 200 |
|
| Other long-term debt | — |
| | 900 |
|
| Short-term borrowings | 113 |
| | — |
|
| Redemptions — | | | |
| Short-term borrowings | (109 | ) | | (475 | ) |
| Long-term debt to parent company | (591 | ) | | (225 | ) |
| Other long-term debt | (300 | ) | | (425 | ) |
| Other financing activities | (3 | ) | | (5 | ) |
| Net cash provided from financing activities | 129 |
| | 197 |
|
| Net Change in Cash and Cash Equivalents | 7 |
| | 61 |
|
| Cash and Cash Equivalents at Beginning of Period | 224 |
| | 98 |
|
| Cash and Cash Equivalents at End of Period | $ | 231 |
| | $ | 159 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
Interest (paid $73 and $72, net of $28 and $36 capitalized for 2017
and 2016, respectively) | $ | 45 |
| | $ | 36 |
|
| Income taxes, net | (209 | ) | | (231 | ) |
| Noncash transactions — Accrued property additions at end of period | 32 |
| | 80 |
|
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, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 231 |
| | $ | 224 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 38 |
| | 29 |
|
| Unbilled revenues | | 41 |
| | 42 |
|
| Income taxes receivable, current | | 102 |
| | 544 |
|
| Other accounts and notes receivable | | 15 |
| | 14 |
|
| Affiliated | | 15 |
| | 15 |
|
| Fossil fuel stock | | 20 |
| | 100 |
|
| Materials and supplies | | 45 |
| | 76 |
|
| Other regulatory assets, current | | 113 |
| | 115 |
|
| Other current assets | | 8 |
| | 8 |
|
| Total current assets | | 628 |
| | 1,167 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 4,836 |
| | 4,865 |
|
| Less: Accumulated provision for depreciation | | 1,312 |
| | 1,289 |
|
| Plant in service, net of depreciation | | 3,524 |
| | 3,576 |
|
| Construction work in progress | | 75 |
| | 2,545 |
|
| Total property, plant, and equipment | | 3,599 |
| | 6,121 |
|
| Other Property and Investments | | 28 |
| | 12 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 62 |
| | 361 |
|
| Other regulatory assets, deferred | | 436 |
| | 518 |
|
| Accumulated deferred income taxes | | 279 |
| | — |
|
| Other deferred charges and assets | | 23 |
| | 56 |
|
| Total deferred charges and other assets | | 800 |
| | 935 |
|
| Total Assets | | $ | 5,055 |
| | $ | 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, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year — | | | | |
| Parent | | $ | — |
| | $ | 551 |
|
| Other | | 1,028 |
| | 78 |
|
| Notes payable | | 4 |
| | 23 |
|
| Accounts payable — | | | | |
| Affiliated | | 56 |
| | 62 |
|
| Other | | 82 |
| | 135 |
|
| Customer deposits | | 16 |
| | 16 |
|
| Accrued taxes | | 78 |
| | 99 |
|
| Unrecognized tax benefits | | 2 |
| | 383 |
|
| Accrued interest | | 16 |
| | 46 |
|
| Accrued compensation | | 29 |
| | 42 |
|
| Asset retirement obligations, current | | 15 |
| | 32 |
|
| Over recovered fuel clause liabilities | | 4 |
| | 51 |
|
| Other current liabilities | | 67 |
| | 20 |
|
| Total current liabilities | | 1,397 |
| | 1,538 |
|
| Long-term Debt | | 1,167 |
| | 2,424 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | — |
| | 756 |
|
| Employee benefit obligations | | 109 |
| | 115 |
|
| Asset retirement obligations, deferred | | 150 |
| | 146 |
|
| Other cost of removal obligations | | 175 |
| | 170 |
|
| Other regulatory liabilities, deferred | | 87 |
| | 84 |
|
| Other deferred credits and liabilities | | 23 |
| | 26 |
|
| Total deferred credits and other liabilities | | 544 |
| | 1,297 |
|
| Total Liabilities | | 3,108 |
| | 5,259 |
|
| Redeemable Preferred Stock | | 33 |
| | 33 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, without par value — | | | | |
| Authorized — 1,130,000 shares | | | | |
| Outstanding — 1,121,000 shares | | 38 |
| | 38 |
|
| Paid-in capital | | 4,529 |
| | 3,525 |
|
| Accumulated deficit | | (2,650 | ) | | (616 | ) |
| Accumulated other comprehensive loss | | (3 | ) | | (4 | ) |
| Total common stockholder's equity | | 1,914 |
| | 2,943 |
|
| Total Liabilities and Stockholder's Equity | | $ | 5,055 |
| | $ | 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
THIRD QUARTER 2017 vs. THIRD QUARTER 2016
AND
YEAR-TO-DATE 2017 vs. YEAR-TO-DATE 2016
OVERVIEW
Mississippi Power operates as a vertically integrated utility providing electric service to retail customers within its traditional service territory located within the State of Mississippi and to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of Mississippi Power's business of providing electric service. These factors include Mississippi Power's ability to maintain and grow energy sales and to operate in a constructive regulatory environment that provides timely recovery of prudently-incurred costs. These costs include those related to the Kemper County energy facility, projected long-term demand growth, reliability, fuel, and stringent environmental standards, as well as ongoing capital expenditures required for maintenance and restoration following major storms. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Mississippi Power for the foreseeable future.
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 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 (construction cost increase demonstrated to produce efficiencies that result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (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 (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. 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 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. At September 30, 2017, the related regulatory liability totaled $7 million.
The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO2, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast has decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations has 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 (Kemper Settlement Order). The Kemper Settlement Order established a new docket for the purposes of pursuing a global
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
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 grants from the DOE received on April 8, 2016 (Additional DOE Grants).
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 IGCC Settlement Docket, 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 third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination 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 $34 million ($21 million after tax) for the third quarter 2017 and $3.2 billion ($2.2 billion after tax) for the nine months ended September 30, 2017. In the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $6.0 billion ($4.0 billion after tax) through September 30, 2017.
Mississippi Power reached and filed a settlement agreement on August 21, 2017 with certain parties (not including the MPUS), which it believes met the conditions of the Kemper Settlement Order. The settlement agreement provides for an annual revenue requirement of $126 million for Kemper IGCC-related costs, which would (i) be effective January 1, 2018, (ii) represent no rate increase for customers, and (iii) include no recovery for the costs associated with the gasifier portion of the Kemper IGCC in 2018 or at any future date. In addition, under the settlement agreement, the CPCN for the Kemper IGCC would be modified to limit the Kemper County energy facility to natural gas combined cycle operation and Mississippi Power would, in the future, file a reserve margin plan with the Mississippi PSC. The Mississippi PSC issued a scheduling order, as amended on October 5, 2017, noting Mississippi Power and the MPUS had failed to reach a joint stipulation and ordering a full hearing. The Mississippi PSC is expected to rule on an order resolving this matter in January 2018.
As of September 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 Cooperative Energy. 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.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For additional information on the Kemper IGCC, including information on the project economic viability analysis, pending lawsuits, and an ongoing SEC investigation, see Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and "Other Matters" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein.
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; (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 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 (E) to the Condensed Financial Statements under "Going Concern" herein.
In addition to the rate recovery of the Kemper County energy facility, Mississippi Power continues to focus on several key performance indicators. In recognition that Mississippi Power's long-term financial success is dependent upon how well it satisfies its customers' needs, Mississippi Power's retail base rate mechanism, PEP, includes performance indicators that directly tie customer service indicators to Mississippi Power's allowed ROE. Mississippi Power also focuses on broader measures of customer satisfaction, plant availability, system reliability, and net income after dividends on preferred stock.
RESULTS OF OPERATIONS
Net Income (Loss)
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $14 | | 53.8 | | $(2,073) | | N/M |
N/M - Not meaningful
Mississippi Power's net income after dividends on preferred stock for the third quarter 2017 was $40 million compared to $26 million for the corresponding period in 2016. The increase was due to lower pre-tax charges associated with the Kemper IGCC and a decrease in interest expense, net of amounts capitalized, partially offset by an increase in income taxes and decreases in retail revenues and AFUDC equity.
Mississippi Power's net loss after dividends on preferred stock for year-to-date 2017 was $2.03 billion compared to net income of $39 million for the corresponding period in 2016. The decrease in net income was related to higher pre-tax charges associated with the Kemper IGCC.
See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Retail Revenues
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(20) | | (7.6) | | $13 | | 2.0 |
In the third quarter 2017, retail revenues were $243 million compared to $263 million for the corresponding period in 2016. For year-to-date 2017, retail revenues were $665 million compared to $652 million for the corresponding period in 2016.
Details of the changes in retail revenues were as follows:
|
| | | | | | | | | | | | | |
| | Third Quarter 2017 | | Year-to-Date 2017 |
| | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | $ | 263 |
| | | | $ | 652 |
| | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | (10 | ) | | (3.8 | ) | | 9 |
| | 1.4 |
|
| Sales growth | 1 |
| | 0.4 |
| | 4 |
| | 0.6 |
|
| Weather | (9 | ) | | (3.4 | ) | | (16 | ) | | (2.5 | ) |
| Fuel and other cost recovery | (2 | ) | | (0.8 | ) | | 16 |
| | 2.5 |
|
| Retail – current year | $ | 243 |
| | (7.6 | )% | | $ | 665 |
| | 2.0 | % |
Revenues associated with changes in rates and pricing decreased in the third quarter 2017 when compared to the corresponding period in 2016 primarily due to recognition of a regulatory liability as directed by the Mississippi PSC in a July 6, 2017 order following full amortization of certain regulatory assets and an ECO Plan rate decrease implemented in the second quarter 2017.
Revenues associated with changes in rates and pricing increased in year-to-date 2017 when compared to the corresponding period in 2016 primarily due to an ECO Plan rate increase implemented in the third quarter 2016, partially offset by the recognition of a regulatory liability as directed by the Mississippi PSC in a July 6, 2017 order following full amortization of certain regulatory assets and an ECO Plan rate decrease implemented in the second quarter 2017.
See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Mississippi Power – Environmental Compliance Overview Plan" and "Integrated Coal Gasification Combined Cycle" herein for additional information.
Revenues attributable to changes in sales increased slightly for the third quarter 2017 when compared to the corresponding period in 2016. Weather-adjusted KWH sales to residential customers increased 2.9% due to higher customer usage. Weather-adjusted KWH sales to commercial customers decreased 1.2% due to lower customer usage, partially offset by customer growth. KWH sales to industrial customers decreased 2.4% primarily due to an unplanned outage by a large customer in 2017, the impacts of Hurricane Harvey on petroleum pipeline customers, and a decrease in the number of mid-size customers.
Revenues attributable to changes in sales increased slightly for year-to-date 2017 when compared to the corresponding period in 2016. Weather-adjusted KWH sales to residential customers increased 0.8% due to higher customer usage. Weather-adjusted KWH sales to commercial customers decreased 0.7% due to lower customer usage, partially offset by customer growth. KWH sales to industrial customers decreased 1.1% primarily due to unplanned outages by a large customer in 2017, the impacts of Hurricane Harvey on petroleum pipeline customers, and a decrease in the number of mid-size customers.
Fuel and other cost recovery revenues decreased in the third quarter 2017 when compared to the corresponding period in 2016 primarily as a result of lower recoverable fuel costs. Fuel and other cost recovery revenues increased
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
for year-to-date 2017 when compared to the corresponding period in 2016 primarily as a result of higher recoverable fuel costs. See "Fuel and Purchased Power Expenses" herein for additional information. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power's service territory. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income.
Wholesale Revenues – Affiliates
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $14 | | N/M | | $17 | | 73.9 |
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 third quarter 2017, wholesale revenues from sales to affiliates were $21 million compared to $7 million for the corresponding period in 2016. The increase was due to a $13 million increase in KWH sales as a result of supporting Southern Company system transmission reliability and a $1 million increase primarily due to higher natural gas prices.
For year-to-date 2017, wholesale revenues from sales to affiliates were $40 million compared to $23 million for the corresponding period in 2016. The increase was primarily due to higher KWH sales as a result of supporting Southern Company system transmission reliability and higher natural gas prices.
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | |
| | Third Quarter 2017
vs.
Third Quarter 2016 | | Year-to-Date 2017
vs.
Year-to-Date 2016 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | 8 |
| | 7.1 | | $ | 33 |
| | 12.3 |
| Purchased power – non-affiliates | 1 |
| | 33.3 | | 3 |
| | 75.0 |
| Purchased power – affiliates | (3 | ) | | (60.0) | | (1 | ) | | (7.1) |
| Total fuel and purchased power expenses | $ | 6 |
| | | | $ | 35 |
| | |
In the third quarter 2017, total fuel and purchased power expenses were $126 million compared to $120 million for the corresponding period in 2016. The increase was due to a $6 million increase in the volume of KWHs generated and purchased.
For year-to-date 2017, total fuel and purchased power expenses were $321 million compared to $286 million for the corresponding period in 2016. The increase was primarily due to a $42 million increase in the average cost of natural gas and purchased power, partially offset by a $4 million decrease in coal prices and a $3 million decrease in the volume of KWHs generated and purchased.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Mississippi Power's fuel cost recovery clause.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of Mississippi Power's generation and purchased power were as follows:
|
| | | | | | | |
| | Third Quarter 2017 | | Third Quarter 2016 | | Year-to-Date 2017 | | Year-to-Date 2016 |
Total generation (in millions of KWHs) | 4,453 | | 4,255 | | 11,542 | | 11,570 |
Total purchased power (in millions of KWHs)(*) | 164 | | 288 | | 527 | | 877 |
Sources of generation (percent) – | | | | | | | |
| Coal | 8 | | 10 | | 8 | | 9 |
| Gas | 92 | | 90 | | 92 | | 91 |
Cost of fuel, generated (in cents per net KWH) – | | | | | | | |
| Coal | 3.80 | | 4.02 | | 3.60 | | 4.09 |
| Gas | 2.77 | | 2.64 | | 2.72 | | 2.34 |
Average cost of fuel, generated (in cents per net KWH) | 2.86 | | 2.79 | | 2.80 | | 2.50 |
Average cost of purchased power (in cents per net KWH)(*) | 3.74 | | 2.59 | | 3.78 | | 2.04 |
| |
(*) | Includes energy produced during the test period for the Kemper IGCC, which is accounted for in accordance with FERC guidance. |
Fuel
In the third quarter 2017, total fuel expense was $120 million compared to $112 million for the corresponding period in 2016. The increase was due to a 2.5% increase in the average cost of fuel per KWH generated, primarily due to a 4.5% higher cost of natural gas, and a 5.4% increase in the volume of KWHs generated.
For year-to-date 2017, total fuel expense was $301 million compared to $268 million for the corresponding period in 2016. The increase was due to a 12.0% increase in the average cost of fuel per KWH generated primarily due to a 16.2% higher cost of natural gas.
Purchased Power
Energy purchases will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation. Energy purchases from affiliates are made in accordance with the IIC, as approved by the FERC.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(8) | | (10.8) | | $(5) | | (2.4) |
In the third quarter 2017, other operations and maintenance expenses were $66 million compared to $74 million for the corresponding period in 2016. The decrease was primarily due to a $5 million decrease in transmission and distribution expenses related to overhead line maintenance and a $4 million decrease related to decreases in employee compensation and benefits and corporate advertising.
For year-to-date 2017, other operations and maintenance expenses were $206 million compared to $211 million for the corresponding period in 2016. The decrease was primarily due to a $6 million decrease in transmission and distribution expenses related to overhead line maintenance and a $5 million decrease related to decreases in employee compensation and benefits and corporate advertising, partially offset by a $5 million increase associated with the Kemper IGCC in-service assets.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Rate Case" herein for additional information.
Depreciation and Amortization
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $9 | | 30.0 | | $6 | | 5.3 |
In the third quarter 2017, depreciation and amortization was $39 million compared to $30 million for the corresponding period in 2016. The increase was primarily related to $6 million in amortization and deferrals associated with regulatory assets and liabilities and $3 million in depreciation related to additional plant in service.
For year-to-date 2017, depreciation and amortization was $120 million compared to $114 million for the corresponding period in 2016. The increase was primarily related to $5 million in depreciation related to additional plant in service.
See Note 1 to the financial statements of Mississippi Power under "Depreciation, Depletion, and Amortization" in Item 8 of the Form 10-K.
Taxes Other Than Income Taxes
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(6) | | (19.4) | | $(4) | | (4.9) |
In the third quarter 2017, taxes other than income taxes were $25 million compared to $31 million for the corresponding period in 2016. For year-to-date 2017, taxes other than income taxes were $77 million compared to $81 million for the corresponding period in 2016. These decreases were primarily due to a decrease in franchise taxes of $5 million and $4 million for the third quarter and year-to-date 2017, respectively, as well as a decrease in payroll taxes of $1 million for the third quarter 2017.
Estimated Loss on Kemper IGCC
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(54) | | (61.4) | | $2,933 | | N/M |
N/M - Not meaningful
Estimated probable losses on the Kemper IGCC of $34 million and $3.2 billion were recorded in the third quarter and year-to-date 2017, respectively, compared to $88 million and $222 million in the third quarter and year-to-date 2016, respectively. 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 IGCC Settlement Docket, 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. As a result, Mississippi Power suspended the project on June 28, 2017, and recorded $34 million and $2.9 billion of additional charges to income in the third quarter and year-to-date 2017, respectively, for the estimated costs associated with the gasification portions of the plant and lignite mine.
Prior to the project's suspension, Mississippi Power recorded losses for revisions of estimated costs expected to be incurred on construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of the Initial DOE Grants and excluding the Cost Cap Exceptions.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Allowance for Equity Funds Used During Construction
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| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(30) | | (96.8) | | $(18) | | (20.0) |
In the third quarter 2017, AFUDC equity was $1 million compared to $31 million for the corresponding period in 2016. For year-to-date 2017, AFUDC equity was $72 million compared to $90 million for the corresponding period in 2016. The decreases resulted from the Kemper IGCC project suspension in June 2017.
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 FUTURE EARNINGS POTENTIAL – "Integrated Coal 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
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(28) | | N/M | | $(23) | | 50.0 |
N/M - Not meaningful
In the third quarter 2017, interest expense, net of amounts capitalized was $(13) million compared to $15 million for the corresponding period in 2016. The decrease was primarily associated with a $33 million net reduction in interest following a settlement with the IRS related to research and experimental (R&E) deductions. Also contributing to the decrease was a $4 million decrease in interest related to long-term debt. These decreases were partially offset by an $11 million reduction in interest capitalized following suspension of the Kemper IGCC construction.
For year-to-date 2017, interest expense, net of amounts capitalized was $23 million compared to $46 million for the corresponding period in 2016. The decrease was primarily associated with a $33 million net reduction in interest following a settlement with the IRS related to R&E deductions. Also contributing to the decrease was a $2 million decrease in interest related to short-term debt and a $1 million decrease in interest related to long-term debt. These decreases were partially offset by an $8 million reduction in interest capitalized following suspension of the Kemper IGCC construction and the amortization of $7 million in interest deferrals in accordance with the In-Service Asset Rate Order.
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.
Income Taxes (Benefit)
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| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $26 | | N/M | | $(856) | | N/M |
N/M - Not meaningful
In the third quarter 2017, income taxes were $24 million compared to an income tax benefit of $2 million for the corresponding period in 2016. For year-to-date 2017, income tax benefit was $885 million compared to $29 million
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
for the corresponding period in 2016. The changes were primarily due to the estimated probable losses on the Kemper IGCC, net of the non-deductible AFUDC equity portion and the 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 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 County energy facility. 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, 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 the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings.
On October 4, 2017, Mississippi Power executed agreements with its largest retail customer, Chevron Products Company (Chevron), to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038, subject to the approval of the Mississippi PSC. The new agreements are not expected to have a material impact on Mississippi Power's earnings; however, the co-generation assets located at the refinery are expected to be accounted for as a sales-type lease in accordance with the new lease accounting rules that become effective in 2019. These assets are also subject to a security interest granted to Chevron. See FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.
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 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 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 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
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the 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 September 18, 2017, the EPA published a final 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 Mississippi 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 October 16, 2017, the EPA published a proposed rule to repeal the Clean Power Plan. The EPA has not determined whether or when it will promulgate a replacement rule.
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
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 the Kemper IGCC.
In March 2016, Mississippi Power reached a settlement agreement with its wholesale customers, which was subsequently approved by the FERC, for an increase in wholesale base revenues under the MRA cost-based electric tariff, primarily as a result of placing scrubbers for Plant Daniel Units 1 and 2 in service in 2015. The settlement agreement became effective for services rendered beginning May 1, 2016, resulting in an estimated annual revenue increase of $7 million under the MRA cost-based electric tariff. Additionally, under the settlement agreement, the tariff customers agreed to similar regulatory treatment for MRA tariff ratemaking as the treatment approved for retail ratemaking 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)
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 totaled approximately $22 million through the suspension of Kemper 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. At September 30, 2017, the amount of over-recovered wholesale MRA fuel costs included in the balance sheets was $3 million compared to $13 million at December 31, 2016. Over-recovered wholesale MB fuel costs included in the balance sheets were immaterial at September 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 related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including Mississippi Power's) and Southern Power's June 30, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including Mississippi Power) and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order, or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including Mississippi Power) and Southern Power expect to make a filing within the specified 60 days responding to the FERC's order.
The ultimate outcome of these matters cannot be determined at this time.
Cooperative Energy Shared Service Agreement and PPA
Mississippi Power provides electricity to a municipality and various rural electric cooperative associations located in southeastern Mississippi, including Cooperative Energy. These generation services are provided under long-term contracts subject to a cost-based, FERC regulated MRA electric tariff and a long-term market-based wholesale contract.
On September 18, 2017, Mississippi Power and Cooperative Energy executed a Shared Service Agreement (SSA), as part of the MRA tariff, under which Mississippi Power and Cooperative Energy will share in providing electricity to all Cooperative Energy delivery points, in lieu of the current arrangement under which each delivery point is specifically assigned to either entity. The SSA becomes effective on January 1, 2018, subject to the FERC's acceptance, and may be cancelled by Cooperative Energy with 10 years notice after December 31, 2021.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The SSA provides Cooperative Energy the option to decrease its use of Mississippi Power's generation services under the MRA tariff, subject to annual and cumulative caps and a one-year notice requirement. In the event Cooperative Energy elects to reduce these services, the related reduction in Mississippi Power's revenues is not expected to be significant through 2020.
In 2008, Mississippi Power entered into a 10-year Power Supply Agreement (PSA) with Cooperative Energy for approximately 152 MWs, which became effective in 2011. Following certain plant retirements, the current PSA capacity is 86 MWs. On September 28, 2017, Mississippi Power and Cooperative Energy executed an amendment to the PSA effective October 1, 2017, increasing the capacity to 286 MWs under the PSA.
Cooperative Energy also has a 10-year Network Integration Transmission Service Agreement (NITSA) with SCS for transmission service to certain delivery points on the Mississippi Power transmission system that became effective in 2011. As a result of the PSA amendments, Cooperative Energy and SCS are amending the terms of the NITSA to provide for the purchase of incremental transmission capacity for service beginning April 1, 2018. This NITSA amendment remains subject to execution and acceptance by the FERC.
The ultimate outcome of these matters cannot be determined at this time.
Retail Regulatory Matters
Mississippi Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Mississippi PSC. Mississippi Power's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased power, energy efficiency programs, ad valorem taxes, property damage, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are expected to be 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 "Regulatory Matters – Mississippi Power" and "Integrated Coal Gasification Combined Cycle" herein for additional information.
Renewables
Mississippi Power placed in service three solar projects in January, June, and October 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 August 17, 2017, the Mississippi PSC approved Mississippi Power's CPCN for the construction, operation, and maintenance of a 52.5-MW solar energy generating facility, which 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,July 24, 2020, the Mississippi PSC approved Mississippi Power's July 14, 2020 filing of its PEP compliance rate clause reflecting revisions agreed to in the Mississippi Power submitted itsRate Case Settlement Agreement. These revisions include, among other things, changing the filing date for the annual PEP lookbackrate filing from November of the immediately preceding year to March of the current year, utilizing a historic test year adjusted for 2016, which reflected"known and measurable" changes, using discounted cash flow and regression formulas to determine base return on equity, and moving all embedded ad valorem property taxes currently collected in PEP to the need for a $5 million surchargead valorem tax adjustment clause.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Deferral of Incremental COVID-19 Costs
On April 14, 2020 and May 12, 2020, in order to mitigate the economic impact of the COVID-19 pandemic on customers, the Mississippi PSC.
On November 15, 2017,PSC approved orders directing Mississippi Power to continue its previous, voluntary suspension of customer disconnections through May 25, 2020 and to defer as a regulatory asset all necessary and reasonable incremental costs or expenses to plan, prepare, stage, or react to protect and keep safe its employees and customers, and to reliably operate its utility system during the COVID-19 pandemic. The period over which such costs will be recovered is expected to makebe determined in a future PEP filing. At June 30, 2020, the incremental costs deferred totaled approximately $2 million. The ultimate outcome of this matter cannot be determined at this time.
Municipal and Rural Associations Tariff
On June 25, 2020, the FERC accepted Mississippi Power's April 27, 2020 request for an increase in wholesale base revenues under the MRA tariff as agreed upon in a settlement agreement reached with its wholesale customers. The MRA settlement agreement resulted in a $2 million annual PEP filing for 2018. Retailincrease in base rates effective June 1, 2020.
Southern Company Gas
Rate Proceedings
On June 1, 2020, Virginia Natural Gas filed a general rate case with the Virginia Commission seeking an increase in rates of$49.6 million primarily to recover investments and increased costs associated with infrastructure, technology, and workforce development. The requested increase is based on a projected 12-month test year beginning November 1, 2020, a ROE of 10.35%, and an equity ratio of 54%. Rate adjustments under PEP are limitedexpected to 4% of annual retail revenue and arebe effective November 1, 2020, subject to Mississippirefund. The Virginia Commission is expected to rule on the requested increase in the second quarter 2021.
On July 1, 2020, Atlanta Gas Light filed its 2020 GRAM filing with the Georgia PSC. The filing requests an annual base rate increase of $37.6 million based on the projected 12-month period beginning January 1, 2021, which does not exceed the 5% limitation established by the Georgia PSC approval.in its December 2019 approval of Atlanta Gas Light's general base rate case. Resolution of the 2020 GRAM filing is expected by December 31, 2020, with rates effective January 1, 2021.
The ultimate outcome of these matters cannot be determined at this time.
Energy EfficiencyDeferral of Incremental COVID-19 Costs
Atlanta Gas Light
On April 30, 2020, in response to the COVID-19 pandemic, the Georgia PSC approved orders directing Atlanta Gas Light to continue its previous, voluntary suspension of customer disconnections. On June 22, 2020, the Georgia PSC ordered Atlanta Gas Light to resume customer disconnections beginning July 6, 2017,1, 2020, with exceptions for customers still covered by a shelter-in-place order. The orders provide the Mississippi PSC issued an order approving Mississippi Power's Energy Efficiency Cost Rider complianceMarketers, including SouthStar, with a mechanism to receive credits from Atlanta Gas Light for the base rates it charged to the Marketers of non-paying customers during the suspension. Atlanta Gas Light expects to recover these credits through the annual revenue true-up process within its 2021 GRAM filing, which increased annual retail revenues by approximately $2 millionwould impact rates effective with the first billing cycle for August 2017.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Environmental Compliance Overview Plan
On May 4, 2017, the Mississippi PSC approved Mississippi Power's ECO Plan filing for 2017, which requested the maximum 2% annual increase in revenues, approximately $18 million, primarily related to the Plant Daniel UnitsJanuary 1, and 2 scrubbers placed in service in 2015. The rates became effective with the first billing cycle for June 2017. Approximately $26 million of related revenue requirements in excess of the 2% maximum was deferred for inclusion in the 2018 filing.
Fuel Cost Recovery
At September 30, 2017, the amount of over-recovered retail fuel costs included on the condensed balance sheet was $2 million compared to $37 million at December 31, 2016.
On November 15, 2017, Mississippi Power is expected to file its annual rate adjustment under the retail fuel cost recovery clause.2022. The ultimate outcome of this matter cannot be determined at this time.
Ad Valorem Tax AdjustmentNicor Gas
On July 6, 2017,March 18, 2020, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment factor filingIllinois Commission issued an order directing utilities to cease disconnections for 2017, which included an annual rate increasenon-payment and to suspend the imposition of 0.85%,late payment fees or $8 millionpenalties until the Governor of Illinois announces the end of the COVID-19 state of emergency. In response to this order, on March 27, 2020, Nicor Gas and other utilities in annual retail revenues, primarily due to increased assessments.
Provision for Property DamageIllinois filed their plans seeking cost recovery and more flexible credit and collection plans.
On October 8, 2017, Hurricane Nate hitJune 18, 2020, the Gulf CoastIllinois Commission approved a stipulation pursuant to which the utilities will provide more flexible credit and collection procedures to assist customers with financial hardship and which authorizes a special
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
purpose rider for recovery of the following COVID-19 pandemic-related impacts: incremental costs have been estimateddirectly associated with the COVID-19 pandemic, net of the offset for COVID-19 pandemic-related credits received, foregone late fees, foregone reconnection charges, and the costs associated with a bill payment assistance program. The special purpose rider is proposed to be immaterial. These costs mayeffective on October 1, 2020 and continue over a 24-month period. At June 30, 2020, Nicor Gas' related regulatory asset was $12 million. The ultimate outcome of this matter cannot be chargeddetermined at this time.
Virginia Natural Gas
In response to the retail property damage reserveCOVID-19 pandemic, the Virginia Commission issued orders requiring Virginia Natural Gas to suspend disconnections beginning on March 16, 2020 and also to suspend late payment and reconnection fees beginning on April 9, 2020, both of which continue in effect through August 31, 2020. On April 29, 2020, the Virginia Commission authorized Virginia Natural Gas to defer the following COVID-19 pandemic-related costs as a regulatory asset: incremental uncollectible expense incurred, suspended late fees, suspended reconnection charges, carrying costs, and other incremental prudently incurred costs associated with the COVID-19 pandemic. Specific recovery of the amounts deferred in a regulatory asset will be addressed in a subsequent System Restoration Riderfuture rate filing.proceeding. At June 30, 2020, Virginia Natural Gas' related regulatory asset was $1 million. The ultimate outcome of this matter cannot be determined at this time.
Infrastructure Replacement Programs and Capital Projects
In December 2019, Virginia Natural Gas filed an application with the Virginia Commission for a 24.1-mile header improvement project to improve resiliency and increase the supply of natural gas delivered to energy suppliers, including Virginia Natural Gas. On June 26, 2020, the Virginia Commission issued an order requiring Virginia Natural Gas to submit additional information by December 31, 2020 related to the financing plans of the project's primary customer before ruling on the December 2019 application. The ultimate outcome of this matter cannot be determined at this time.
Integrated Coal Gasification Combined Cycle(C) CONTINGENCIES
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 was designedrelating to utilize IGCC technology with an expected output capacity of 582 MWs and to be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper IGCC, Mississippi Power constructed approximately 61 miles of CO2 pipeline infrastructure for the transport of captured CO2 for use in enhanced oil recovery.
Kemper IGCC Schedule and Cost Estimate
In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of Initial DOE Grants and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014.
The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
CO2, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast has decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations has 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, 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.
Mississippi Power's Kemper IGCC 2010 project estimate totaled $2.97 billion, which included capped costs of $2.4 billion. At the time of project suspension in June 2017, 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 above the cost cap for the Kemper IGCC of $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.
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 IGCC Settlement Docket, 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 third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costsvarious lawsuits and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination 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 $34 million ($21 million after tax) for the third quarter 2017 and $3.2 billion ($2.2 billion after tax) for the nine months ended September 30, 2017.
As of September 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. The Kemper combined cycle balances as presented in the condensed balance sheet at September 30, 2017 include $1.1 billion in property, plant, and equipment, net of $80 million in accumulated depreciation; $15 million in materials and supplies; $10 million in other deferred charges and assets; and $113 million in regulatory assets, net of accumulated amortization of $63 million, of which $21 million is included in other regulatory assets, current and $92 million in other regulatory assets, deferred.
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Rate Recovery of Kemper IGCC Costs
Given the variety of potential scenarios and the uncertainty of the outcome of future regulatory proceedings with the Mississippi PSC (and any subsequent related legal challenges), the ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, cannot now be determined but could result in further material charges that could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity.
Kemper 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.
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 reached and filed a settlement agreement on August 21, 2017 with certain parties (not including the MPUS), which it believes met the conditions of the Kemper Settlement Order. The settlement agreement provides for an annual revenue requirement of $126 million for Kemper IGCC-related costs, which would (i) be effective January 1, 2018, (ii) represent no rate increase for customers, and (iii) include no recovery for the costs associated with the gasifier portion of the Kemper IGCC in 2018 or at any future date. In addition, under the settlement agreement, the CPCN for the Kemper IGCC would be modified to limit the Kemper County energy facility to natural gas combined cycle operation and Mississippi Power would, in the future, file a reserve margin plan with the Mississippi PSC. The Mississippi PSC issued a scheduling order, as amended on October 5, 2017, noting Mississippi Power and the MPUS had failed to reach a joint stipulation and ordering a full hearing. The Mississippi PSC is expected to rule on an order resolving this matter in January 2018.
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 IGCC Settlement Docket, 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 third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred.
As of September 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
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$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 Cooperative Energy. 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 was to be 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 was to be 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 utilize this information in connection with the ultimate 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. The 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 to address this matter in connection with the Kemper IGCC Settlement Docket.
2015 Rate Case
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 Kemper IGCC assets that were commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power's actual
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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 Cooperative Energy but reserved Mississippi Power's right to seek recovery in a future proceeding. See "Termination of Proposed Sale of Undivided Interest" herein for additional information.
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 September 30, 2017, the balance associated with these regulatory assets was $113 million, of which $21 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, for the May 31, 2016 and 2017 calculations. At September 30, 2017, Mississippi Power's related regulatory liability 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. At September 30, 2017, the related regulatory liability totaled $7 million.
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 was placed in service, based on a mirror CWIP methodology (Mirror CWIP rate).
On February 12, 2015, the Mississippi Supreme Court reversed the 2013 MPSC Rate Order and, 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, along with associated carrying costs of $29 million.
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 continued to record AFUDC on the Kemper IGCC. Between the original May 2014 estimated in-service date and the June 2017 project suspension date, Mississippi Power recorded $494 million of AFUDC on the Kemper IGCC subject to the $2.88 billion cost cap and Cost Cap Exception amounts, of which $460 million related to the gasification portions of the Kemper IGCC.
Mississippi Power expects the Mississippi PSC to address this matter in connection with the Kemper IGCC Settlement Docket.
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Lignite Mine and CO2 Pipeline Facilities
In conjunction with the Kemper IGCC, Mississippi Power owns the lignite mine and equipment and 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 responsible for the mining operations through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. In addition to the obligation to fund the reclamation activities, Mississippi Power provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. During the suspension period, these costs are approximately $2 million per month and are being recognized in income as incurred. 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 constructed 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. Denbury has the right to terminate the contract at any time because Mississippi Power did not place the Kemper IGCC in service by July 1, 2017.
The ultimate outcome of these matters cannot be determined at this time.
Termination of Proposed Sale of Undivided Interest
In 2010 and as amended in 2012, Mississippi Power and Cooperative Energy (formerly known as SMEPA) entered into an agreement whereby Cooperative Energy agreed to purchase a 15% undivided interest in the Kemper IGCC. On May 20, 2015, Cooperative Energy notified Mississippi Power of its termination of the agreement. Mississippi Power previously received a total of $275 million of deposits from Cooperative Energy that were required to be returned to Cooperative Energy with interest. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to Cooperative Energy. 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. 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 of an appeal.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 moved to compel arbitration pursuant to the terms of the CO2 contract, which the court granted on May 4, 2017. On June 28, 2017, Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a claim for arbitration requesting $500 million in damages.
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 or implement credits, refunds, or rebates to customers for costs incurred in connection with such cancelled generating plant.contingencies.
Income TaxGeneral Litigation 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 on bonus depreciation, investment tax credits, and the Section 174 research and experimental deduction.
Bonus Depreciation
All projected tax benefits previously received for bonus depreciation related to the Kemper IGCC were repaid in connection with third quarter 2017 estimated tax payments. If the suspension of the Kemper IGCC start-up activities ultimately results in an abandonment for income tax purposes, the related deduction would be claimed in the year of the abandonment. 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, on behalf of Mississippi Power, has reflected deductions for R&E expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation (JCT), resolving a methodology for these deductions. As a result of the JCT approval, Mississippi Power recognized $176 million of previously unrecognized tax benefits and reversed $36 million of associated accrued 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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Other Matters
Mississippi Power isRegistrants are involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Mississippi Power is subject to certain claims and legal actions arising in the ordinary course of business. Mississippi Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation or regulatory matters against each Registrant and any subsidiaries cannot be predicteddetermined 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 Mississippi Power'ssuch Registrant's financial statements. See Note (B)
The Registrants believe the pending legal challenges discussed below have no merit; however, the ultimate outcome of these matters cannot be determined at this time.
Southern Company
In January 2017, a securities class action complaint was filed in the U.S. District Court for the Northern District of Georgia 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 names as defendants Southern Company, certain of its current and former officers, and certain former Mississippi Power officers and alleges that the defendants made materially false and misleading statements regarding the Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. In 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. Also in 2017, the defendants filed a motion to dismiss the Condensedplaintiffs' amended complaint with prejudice, to which the plaintiffs filed an
The SEC is conducting a formal investigation
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(UNAUDITED)
opposition. In 2018, the court issued an order dismissing certain claims against certain officers of Southern Company and Mississippi Power concerningand dismissing the estimatedallegations related to a number of the statements that plaintiffs challenged as being false or misleading. In 2018, the court denied the defendants' motion for reconsideration and also denied a motion to certify the issue for interlocutory appeal. In the third quarter 2019, the court certified the plaintiffs' proposed class and the defendants filed a petition for interlocutory appeal of the class certification order with the U.S. Court of Appeals for the Eleventh Circuit. In December 2019, the U.S. District Court for the Northern District of Georgia entered an order staying all deadlines in the case pending mediation. The stay automatically expired on March 31, 2020; however, in light of the COVID-19 pandemic, the U.S. District Court for the Northern District of Georgia vacated all existing discovery deadlines until June 15, 2020. On June 30, 2020, the court entered a revised scheduling order, which resumed discovery and set out remaining case deadlines.
In February 2017, Jean Vineyard and Judy Mesirov each filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its current and former officers, and certain former Mississippi Power officers. In 2017, these 2 shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain changes to Southern Company's corporate governance and expected in-service dateinternal processes. In 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the securities class action.
In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, Georgia that names as defendants Southern Company, certain of its directors, certain of its current and former 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.County energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. 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. In 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the securities class action. In August 2019, the court granted a motion filed by the plaintiff in July 2019 to substitute a new named plaintiff, Martin J. Kobuck, in place of Helen E. Piper Survivor's Trust.
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 amounts for municipal franchise fees (which fees are paid to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state law claims. This case has been ruled upon and appealed numerous times over the last several years. In one recent appeal, the Georgia Supreme Court remanded the case and noted that the trial court could refer the matter to the Georgia PSC to interpret its tariffs. Following a motion by Georgia Power, in February 2019, the Superior Court of Fulton County ordered the parties to submit petitions to the Georgia PSC for a declaratory ruling and also conditionally certified the proposed class. In March 2019, Georgia Power and the plaintiffs filed petitions with the Georgia PSC seeking confirmation of the proper application of the municipal franchise fee schedule pursuant to the Georgia PSC's orders. Also in March 2019, Georgia Power appealed the class certification decision to the Georgia Court of Appeals. In October 2019, the Georgia PSC issued an order that found Georgia Power has appropriately implemented the municipal franchise fee schedule. On March 11, 2020, the Georgia Court of Appeals vacated the Superior Court of Fulton County's February 2019 order granting conditional class certification. The Court of
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Appeals remanded the case to the Superior Court of Fulton County for further proceedings. The amount of any possible losses cannot be calculated at this time because, among other factors, it is unknown whether a class will be certified, the ultimate composition of any class, and whether any losses would be subject to recovery from any municipalities.
On July 29, 2020, a group of individual plaintiffs filed a complaint in the Superior Court of Fulton County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater, surface water, and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages, a medical monitoring fund, and injunctive relief.
Mississippi Power
In May 2018, Southern Company and Mississippi Power believereceived a notice of dispute and arbitration demand filed by Martin Product Sales, LLC (Martin) based on 2 agreements, both related to Kemper IGCC byproducts for which Mississippi Power provided termination notices in 2017. Martin alleges breach of contract, breach of good faith and fair dealing, fraud and misrepresentation, and civil conspiracy and makes a claim for damages in the amount of approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest. A portion of the claim for damages was on behalf of Martin Transport, Inc. (Martin Transport), an affiliate of Martin. In May 2019, the arbitration panel denied Mississippi Power's and Southern Company's motions to dismiss. In September 2019, Martin Transport filed a separate complaint against Mississippi Power in the Circuit Court of Kemper County, Mississippi alleging claims of fraud, negligent misrepresentation, promissory estoppel, and equitable estoppel, each arising out of the same alleged facts and circumstances that underlie Martin's arbitration demand. Martin Transport seeks compensatory damages of $5 million and punitive damages of $50 million. In November 2019, Martin Transport's claim was combined with the Martin arbitration case and the separate court case was dismissed. In December 2019, Southern Company and Mississippi Power each filed motions for summary judgment on all claims. On February 17, 2020, the arbitration panel granted Southern Company's motion and dismissed Southern Company from the arbitration. On March 12, 2020, the arbitration panel denied Mississippi Power's motions for summary judgment. An adverse outcome in this proceeding could have a material impact on Southern Company's and Mississippi Power's financial statements.
In November 2018, Ray C. Turnage and 10 other individual plaintiffs filed a putative class action complaint against Mississippi Power and the 3 then-serving members of the Mississippi PSC in the U.S. District Court for the Southern District of Mississippi. Mississippi Power received Mississippi PSC approval in 2013 to charge a mirror CWIP rate premised upon including in its rate base pre-construction and construction costs for the Kemper IGCC prior to placing the Kemper IGCC into service. The Mississippi Supreme Court reversed that approval and ordered Mississippi Power to refund the amounts paid by customers under the previously-approved mirror CWIP rate. The plaintiffs allege that the initial approval process, and the amount approved, were improper. They also allege that Mississippi Power underpaid customers by up to $23.5 million in the refund process by applying an incorrect interest rate. The plaintiffs seek to recover, on behalf of themselves and their putative class, actual damages, punitive damages, pre-judgment interest, post-judgment interest, attorney's fees, and costs. In response to Mississippi Power and the Mississippi PSC each filing a motion to dismiss, the plaintiffs filed an amended complaint in March 2019. The amended complaint included 4 additional plaintiffs and additional claims for gross negligence, reckless conduct, and intentional wrongdoing. Mississippi Power and the Mississippi PSC have each filed a motion to dismiss the amended complaint. On March 27, 2020, the Mississippi PSC's motion to dismiss was granted. Also on March 27, 2020, the plaintiffs filed a motion seeking to name the new members of the Mississippi PSC, the Mississippi Development Authority, and Southern Company as additional defendants and add a cause of action against all defendants based on a dormant commerce clause theory under the U.S. Constitution. On April 9, 2020 and April 10, 2020, Mississippi Power and the Mississippi PSC, respectively, filed responses opposing the motion for leave to file a second amended complaint. On May 26, 2020, Mississippi Power's motion to dismiss the first amended complaint filed in 2019 was granted. On July 6, 2020, the plaintiffs filed a motion for revision of the court's decision. The plaintiffs' motion for leave to file a second amended complaint also remains pending before the court. An adverse outcome in this proceeding could have a material impact on Mississippi Power's financial statements.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility" in Item 8 of the Form 10-K for additional information.
Environmental Remediation
The Southern Company system must comply with environmental laws and regulations governing the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companies and the natural gas distribution utilities in Illinois and Georgia 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.
Georgia Power's environmental remediation liability was $14 million and $15 million as of June 30, 2020 and December 31, 2019, respectively. Georgia Power has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected.
In December 2019, Mississippi Power entered into an agreement with the Mississippi Commission on Environmental Quality related to groundwater conditions arising from the closed ash pond at Plant Watson. Mississippi Power will complete an assessment and remediation consistent with the requirements of the agreement and the CCR Rule. Potential remediation activities and related cost estimates are pending the result of further site assessment and cannot be determined at this time. Mississippi Power expects to recover the retail portion of remedial costs through the ECO Plan and the wholesale portion through MRA rates.
Southern Company Gas' environmental remediation liability was $253 million and $269 million as of June 30, 2020 and December 31, 2019, respectively, based on the estimated cost of environmental investigation is focused primarily on periods subsequent to 2010 and on accounting matters, disclosure controls and procedures, and internal controls over financial reportingremediation associated with known current and former manufactured gas plant operating sites. These environmental remediation expenditures are generally recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies of the natural gas distribution utilities.
The ultimate outcome of these matters cannot be determined at this time; however, as a result of the regulatory treatment for environmental remediation expenses described above, the final disposition of these matters is not expected to have a material impact on the financial statements of the applicable Registrants.
Other Matters
Southern Company
See Notes 1 and 3 under "Leveraged Leases" and "Other Matters – Southern Company," respectively, in Item 8 of the Form 10-K for discussion of challenges associated with a leveraged lease agreement with a subsidiary of Southern Holdings. While all required lease payments through June 30, 2020 have been paid in full, the operational and remarketing risks and the resulting cash liquidity challenges persist and significant concerns continue regarding the lessee's ability to make the remaining required semi-annual lease payments to the Southern Holdings subsidiary through the term of the lease.
In its annual impairment analysis of the expected residual value of the generation assets and the overall collectability of the related lease receivable, Southern Company uses multiple scenarios of long-term market energy prices to estimate the cash flows expected to be received from remarketing the generation assets following the expiration of the existing PPA in 2032 and the residual value of the generation assets at the end of the lease in 2047. Southern Company received the latest annual forecasts of natural gas prices during the second quarter 2020 and considered the significant decline in forecasted prices to be an indicator of potential impairment that required an interim impairment assessment. Accordingly, consistent with prior years, Southern Company evaluated the recoverability of the lease receivable and the expected residual value of the generation assets under various natural gas price scenarios. Based on the current forecasts of energy prices in the years following the expiration of the
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
existing PPA, Southern Company concluded that it is no longer probable that any of the associated rental payments will be received, because it is no longer probable the generation assets will be successfully remarketed and continue to operate after that date. During the second quarter 2020, Southern Company revised the estimated cash flows to be received under the leveraged lease to reflect this conclusion, which resulted in a full impairment of the lease investment and a pre-tax charge to earnings of $154 million ($74 million after tax).
If any future lease payment due prior to the expiration of the associated PPA is not paid in full, the Southern Holdings subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. Failure to make the required payment to the debtholders could represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the generation assets, in effect terminating the lease. As the full amount of the lease investment has been charged against earnings as of June 30, 2020, termination would not be expected to result in additional charges. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments and meet its obligations associated with a future closure or retirement of the generation assets and associated properties, including the dry ash landfill.
Mississippi Power
Kemper County Energy Facility
See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility" in Item 8 of the Form 10-K for additional information.
As the mining permit holder, Liberty Fuels Company, LLC has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities related to the lignite mine and equipment and mineral reserves located around the Kemper IGCC.County energy facility site. As a result of the abandonment of the Kemper IGCC, final mine reclamation began in 2018 and is expected to be substantially completed in 2020, with monitoring expected to continue through 2027. See ACCOUNTING POLICIES – "ApplicationNote 6 to the financial statements in Item 8 of Critical Accounting Policies and Estimates" hereinthe Form 10-K for additional informationinformation.
Dismantlement of the abandoned gasifier-related assets and site restoration activities are expected to be completed in 2025. The additional pre-tax period costs associated with dismantlement and site restoration activities, including related costs for compliance and safety, ARO accretion, and property taxes, are estimated to total $5 million for the remainder of 2020, $16 million in 2021, and $11 million to $13 million annually in 2022 through 2025. In addition, closure costs for the mine and gasifier-related assets, currently estimated at up to $6 million pre-tax (excluding dismantlement costs, net of salvage), may be incurred during the remainder of 2020.
In December 2019, Mississippi Power transferred ownership of the CO2 pipeline to an unrelated gas pipeline company, with no resulting impact on income. In conjunction with the transfer of the CO2 pipeline, the parties agreed to enter into a 15-year firm transportation agreement, which is expected to be signed by the end of 2020, providing for the conversion by the pipeline company of the CO2 pipeline to a natural gas pipeline to be used for the delivery of natural gas to Plant Ratcliffe. The agreement will be treated as a finance lease for accounting purposes upon commencement.
In 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the $387 million of grants received for the Kemper IGCC.County energy facility. Mississippi Power expects to close out the DOE contract in 2020. In connection with the DOE closeout discussions, in April 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power of an investigation related to the Kemper County energy facility. The ultimate outcome of this matter cannot be determined at this time; however, it is not expected tocould have a material impact on Southern Company's and Mississippi Power's financial statements.
Plant Daniel
In conjunction with Southern Company's sale of Gulf Power, Mississippi Power and Gulf Power agreed to seek a restructuring of their 50% undivided ownership interests in Plant Daniel such that each of them would, after the financial statementsrestructuring, own 100% of a generating unit. On April 24, 2020, Mississippi Power.Power and Gulf Power amended the
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
terms of the agreement to extend the deadline from May 1, 2020 to August 1, 2020 for Mississippi Power to notify Gulf Power of which generating unit it has selected for 100% ownership. Mississippi Power and Gulf Power are continuing negotiations on a mutually acceptable revised operating agreement for Plant Daniel and, as a result, the parties have agreed not to select a specific unit on August 1, 2020. The impacts of operating the units on an individual basis continue to be evaluated by Mississippi Power and any transfer of ownership would be subject to approval by the FERC and the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time.
ACCOUNTING POLICIESSouthern Company Gas
Application of Critical Accounting PoliciesSee Notes 3 and Estimates
Mississippi Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 17 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 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 $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
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
project completion date are no longer considered significant accounting estimates. Significant accounting estimates for the September 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 IGCC Settlement Docket, 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 third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred.
As of September 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 Cooperative Energy. 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 $6.00 billion ($3.96 billion after tax) through September 30, 2017. Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $34 million ($21 million after tax) and $88 million ($54 million after tax) in the third quarter 2017 and the third quarter 2016, respectively, and total pre-tax charges of $3.2 billion ($2.2 billion after tax) and $222 million ($137 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 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 under "Other Matters – Southern Company Gas" and "Southern Company Gas," respectively, and Note (B) to the Condensed Financial Statements(E) under "Integrated Coal Gasification Combined CycleSouthern Company Gas" herein for additional information.
Recently Issued Accounting StandardsOn March 24, 2020, Southern Company Gas completed the sale of its interest in Atlantic Coast Pipeline. See Note (K) under "Southern Company Gas" for additional information.
On February 20, 2020, the FERC approved a two-year extension for PennEast Pipeline to complete the project by January 19, 2022.
In September 2019, an appellate court ruled that the PennEast Pipeline does not have federal eminent domain authority over lands in which a state has property rights interests. On June 29, 2020, the U.S. Supreme Court requested the U.S. Solicitor General to provide an opinion on PennEast Pipeline's petition for a writ of certiorari seeking its review of the appellate court's decision.
Expected project costs related to the PennEast Pipeline for Southern Company Gas total approximately $300 million, excluding financing costs. The ultimate outcome of the PennEast Pipeline construction project cannot be determined at this time; however, any work delays, whether caused by judicial or regulatory action, abnormal weather, or other conditions, may result in additional cost or schedule modifications or, ultimately, in project cancellation, any of which could result in impairment of Southern Company Gas' investment and could have a significant impact on Southern Company's financial statements and a material impact on Southern Company Gas' financial statements.
(D) REVENUE FROM CONTRACTS WITH CUSTOMERS AND LEASE INCOME
Revenue from Contracts with Customers
The Registrants generate revenues from a variety of sources, some of which are not accounted for as revenue from contracts with customers, such as leases, derivatives, and certain cost recovery mechanisms. See Note 1 to the financial statements under "Revenues" in Item 8 of the Form 10-K for additional information on the revenue policies of the Registrants. See "Lease Income" herein and Note (J) for additional information on revenue accounted for under lease and derivative accounting guidance, respectively.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
The following table disaggregates revenue from contracts with customers for the three and six months ended June 30, 2020 and 2019:
|
| | | | | | | | | | | | | | | | | | |
| | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| | (in millions) |
| Three Months Ended June 30, 2020 | | | | | | |
| Operating revenues | | | | | | |
| Retail electric revenues | | | | | | |
| Residential | $ | 1,430 |
| $ | 549 |
| $ | 817 |
| $ | 64 |
| $ | — |
| $ | — |
|
| Commercial | 1,103 |
| 353 |
| 689 |
| 61 |
| — |
| — |
|
| Industrial | 642 |
| 302 |
| 273 |
| 67 |
| — |
| — |
|
| Other | 23 |
| 6 |
| 15 |
| 2 |
| — |
| — |
|
| Total retail electric revenues | 3,198 |
| 1,210 |
| 1,794 |
| 194 |
| — |
| — |
|
| Natural gas distribution revenues | | | | | | |
| Residential | 239 |
| — |
| — |
| — |
| — |
| 239 |
|
| Commercial | 58 |
| — |
| — |
| — |
| — |
| 58 |
|
| Transportation | 234 |
| — |
| — |
| — |
| — |
| 234 |
|
| Industrial | 5 |
| — |
| — |
| — |
| — |
| 5 |
|
| Other | 49 |
| — |
| — |
| — |
| — |
| 49 |
|
| Total natural gas distribution revenues | 585 |
| — |
| — |
| — |
| — |
| 585 |
|
| Wholesale electric revenues | | | | | | |
| PPA energy revenues | 167 |
| 28 |
| 7 |
| 2 |
| 134 |
| — |
|
| PPA capacity revenues | 108 |
| 25 |
| 13 |
| 1 |
| 71 |
| — |
|
| Non-PPA revenues | 50 |
| 5 |
| 2 |
| 73 |
| 59 |
| — |
|
| Total wholesale electric revenues | 325 |
| 58 |
| 22 |
| 76 |
| 264 |
| — |
|
| Other natural gas revenues | | | | | | |
| Wholesale gas services | 341 |
| — |
| — |
| — |
| — |
| 341 |
|
| Gas marketing services | 57 |
| — |
| — |
| — |
| — |
| 57 |
|
| Other natural gas revenues | 8 |
| — |
| — |
| — |
| — |
| 8 |
|
| Total natural gas revenues | 406 |
| — |
| — |
| — |
| — |
| 406 |
|
| Other revenues | 251 |
| 44 |
| 119 |
| 6 |
| 4 |
| — |
|
| Total revenue from contracts with customers | 4,765 |
| 1,312 |
| 1,935 |
| 276 |
| 268 |
| 991 |
|
Other revenue sources(a) | 728 |
| 53 |
| (7 | ) | 7 |
| 171 |
| 518 |
|
Other adjustments(b) | (873 | ) | — |
| — |
| — |
| — |
| (873 | ) |
| Total operating revenues | $ | 4,620 |
| $ | 1,365 |
| $ | 1,928 |
| $ | 283 |
| $ | 439 |
| $ | 636 |
|
| | | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | |
| | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| | (in millions) |
| Six Months Ended June 30, 2020 | | | | | | |
| Operating revenues | | | | | | |
| Retail electric revenues | | | | | | |
| Residential | $ | 2,801 |
| $ | 1,103 |
| $ | 1,577 |
| $ | 121 |
| $ | — |
| $ | — |
|
| Commercial | 2,247 |
| 717 |
| 1,409 |
| 121 |
| — |
| — |
|
| Industrial | 1,323 |
| 623 |
| 555 |
| 145 |
| — |
| — |
|
| Other | 46 |
| 11 |
| 31 |
| 4 |
| — |
| — |
|
| Total retail electric revenues | 6,417 |
| 2,454 |
| 3,572 |
| 391 |
| — |
| — |
|
| Natural gas distribution revenues | | | | | | |
| Residential | 736 |
| — |
| — |
| — |
| — |
| 736 |
|
| Commercial | 188 |
| — |
| — |
| — |
| — |
| 188 |
|
| Transportation | 499 |
| — |
| — |
| — |
| — |
| 499 |
|
| Industrial | 17 |
| — |
| — |
| — |
| — |
| 17 |
|
| Other | 144 |
| — |
| — |
| — |
| — |
| 144 |
|
| Total natural gas distribution revenues | 1,584 |
| — |
| — |
| — |
| — |
| 1,584 |
|
| Wholesale electric revenues | | | | | | |
| PPA energy revenues | 326 |
| 55 |
| 15 |
| 4 |
| 259 |
| — |
|
| PPA capacity revenues | 213 |
| 52 |
| 25 |
| 2 |
| 136 |
| — |
|
| Non-PPA revenues | 100 |
| 24 |
| 4 |
| 142 |
| 117 |
| — |
|
| Total wholesale electric revenues | 639 |
| 131 |
| 44 |
| 148 |
| 512 |
| — |
|
| Other natural gas revenues | | | | | | |
| Wholesale gas services | 737 |
| — |
| — |
| — |
| — |
| 737 |
|
| Gas marketing services | 220 |
| — |
| — |
| — |
| — |
| 220 |
|
| Other natural gas revenues | 15 |
| — |
| — |
| — |
| — |
| 15 |
|
| Total natural gas revenues | 972 |
| — |
| — |
| — |
| — |
| 972 |
|
| Other revenues | 441 |
| 78 |
| 214 |
| 13 |
| 7 |
| — |
|
| Total revenue from contracts with customers | 10,053 |
| 2,663 |
| 3,830 |
| 552 |
| 519 |
| 2,556 |
|
Other revenue sources(a) | 1,599 |
| 53 |
| (76 | ) | 7 |
| 295 |
| 1,343 |
|
Other adjustments(b) | (2,014 | ) | — |
| — |
| — |
| — |
| (2,014 | ) |
| Total operating revenues | $ | 9,638 |
| $ | 2,716 |
| $ | 3,754 |
| $ | 559 |
| $ | 814 |
| $ | 1,885 |
|
| | | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | |
| | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| | (in millions) |
| Three Months Ended June 30, 2019 | | | | | | |
| Operating revenues | | | | | | |
| Retail electric revenues | | | | | | |
| Residential | $ | 1,491 |
| $ | 592 |
| $ | 831 |
| $ | 68 |
| $ | — |
| $ | — |
|
| Commercial | 1,264 |
| 422 |
| 770 |
| 72 |
| — |
| — |
|
| Industrial | 766 |
| 369 |
| 327 |
| 70 |
| — |
| — |
|
| Other | 25 |
| 7 |
| 15 |
| 3 |
| — |
| — |
|
| Total retail electric revenues | 3,546 |
| 1,390 |
| 1,943 |
| 213 |
| — |
| — |
|
| Natural gas distribution revenues | | | | | | |
| Residential | 229 |
| — |
| — |
| — |
| — |
| 229 |
|
| Commercial | 65 |
| — |
| — |
| — |
| — |
| 65 |
|
| Transportation | 213 |
| — |
| — |
| — |
| — |
| 213 |
|
| Industrial | 5 |
| — |
| — |
| — |
| — |
| 5 |
|
| Other | 45 |
| — |
| — |
| — |
| — |
| 45 |
|
| Total natural gas distribution revenues | 557 |
| — |
| — |
| — |
| — |
| 557 |
|
| Wholesale electric revenues | | | | | | |
| PPA energy revenues | 208 |
| 35 |
| 17 |
| 3 |
| 163 |
| — |
|
| PPA capacity revenues | 109 |
| 25 |
| 13 |
| 1 |
| 81 |
| — |
|
| Non-PPA revenues | 53 |
| 3 |
| 1 |
| 89 |
| 68 |
| — |
|
| Total wholesale electric revenues | 370 |
| 63 |
| 31 |
| 93 |
| 312 |
| — |
|
| Other natural gas revenues | | | | | | |
| Wholesale gas services | 444 |
| — |
| — |
| — |
| — |
| 444 |
|
| Gas marketing services | 55 |
| — |
| — |
| — |
| — |
| 55 |
|
| Other natural gas revenues | 12 |
| — |
| — |
| — |
| — |
| 12 |
|
| Total natural gas revenues | 511 |
| — |
| — |
| — |
| — |
| 511 |
|
| Other revenues | 238 |
| 37 |
| 95 |
| 4 |
| 3 |
| — |
|
| Total revenue from contracts with customers | 5,222 |
| 1,490 |
| 2,069 |
| 310 |
| 315 |
| 1,068 |
|
Other revenue sources(a) | 1,050 |
| 23 |
| 48 |
| 3 |
| 195 |
| 795 |
|
Other adjustments(b) | (1,174 | ) | — |
| — |
| — |
| — |
| (1,174 | ) |
| Total operating revenues | $ | 5,098 |
| $ | 1,513 |
| $ | 2,117 |
| $ | 313 |
| $ | 510 |
| $ | 689 |
|
| | | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | |
| | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| | (in millions) |
| Six Months Ended June 30, 2019 | | | | | | |
| Operating revenues | | | | | | |
| Retail electric revenues | | | | | | |
| Residential | $ | 2,818 |
| $ | 1,151 |
| $ | 1,539 |
| $ | 128 |
| $ | — |
| $ | — |
|
| Commercial | 2,390 |
| 790 |
| 1,463 |
| 137 |
| — |
| — |
|
| Industrial | 1,474 |
| 707 |
| 623 |
| 144 |
| — |
| — |
|
| Other | 44 |
| 13 |
| 25 |
| 6 |
| — |
| — |
|
| Total retail electric revenues | 6,726 |
| 2,661 |
| 3,650 |
| 415 |
| — |
| — |
|
| Natural gas distribution revenues | | | | | | |
| Residential | 830 |
| — |
| — |
| — |
| — |
| 830 |
|
| Commercial | 235 |
| — |
| — |
| — |
| — |
| 235 |
|
| Transportation | 469 |
| — |
| — |
| — |
| — |
| 469 |
|
| Industrial | 22 |
| — |
| — |
| — |
| — |
| 22 |
|
| Other | 161 |
| — |
| — |
| — |
| — |
| 161 |
|
| Total natural gas distribution revenues | 1,717 |
| — |
| — |
| — |
| — |
| 1,717 |
|
| | | | | | | |
| Wholesale electric revenues | | | | | | |
| PPA energy revenues | 398 |
| 67 |
| 28 |
| 5 |
| 314 |
| — |
|
| PPA capacity revenues | 217 |
| 52 |
| 27 |
| 2 |
| 163 |
| — |
|
| Non-PPA revenues | 108 |
| 62 |
| 3 |
| 164 |
| 109 |
| — |
|
| Total wholesale electric revenues | 723 |
| 181 |
| 58 |
| 171 |
| 586 |
| — |
|
| Other natural gas revenues | | | | | | |
| Wholesale gas services | 1,165 |
| — |
| — |
| — |
| — |
| 1,165 |
|
| Gas marketing services | 276 |
| — |
| — |
| — |
| — |
| 276 |
|
| Other natural gas revenues | 22 |
| — |
| — |
| — |
| — |
| 22 |
|
| Total natural gas revenues | 1,463 |
| — |
| — |
| — |
| — |
| 1,463 |
|
| Other revenues | 502 |
| 83 |
| 186 |
| 10 |
| 6 |
| — |
|
| Total revenue from contracts with customers | 11,131 |
| 2,925 |
| 3,894 |
| 596 |
| 592 |
| 3,180 |
|
Other revenue sources(a) | 2,413 |
| (4 | ) | 57 |
| 4 |
| 361 |
| 2,017 |
|
Other adjustments(b) | (3,034 | ) | — |
| — |
| — |
| — |
| (3,034 | ) |
| Total operating revenues | $ | 10,510 |
| $ | 2,921 |
| $ | 3,951 |
| $ | 600 |
| $ | 953 |
| $ | 2,163 |
|
| |
| (a) | Other revenue sources primarily relate to revenues from customers accounted for as derivatives and leases, as well as alternative revenue programs at Southern Company Gas and other cost recovery mechanisms at the traditional electric operating companies. |
| |
| (b) | Other adjustments relate to the cost of Southern Company Gas' energy and risk management activities. Wholesale gas services revenues are presented net of the related costs of those activities on the statement of income. See Note (L) under "Southern Company Gas" for additional information on the components of wholesale gas services' operating revenues. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Contract Balances
The following table reflects the closing balances of receivables, contract assets, and contract liabilities related to revenues from contracts with customers at June 30, 2020 and December 31, 2019:
|
| | | | | | | | | | | | | | | | | | |
| | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| | (in millions) |
| Accounts Receivables | | | | | | |
| As of June 30, 2020 | $ | 2,283 |
| $ | 592 |
| $ | 796 |
| $ | 84 |
| $ | 115 |
| $ | 523 |
|
| As of December 31, 2019 | 2,413 |
| 586 |
| 688 |
| 79 |
| 97 |
| 749 |
|
| Contract Assets | | | | | | |
| As of June 30, 2020 | $ | 103 |
| $ | — |
| $ | 54 |
| $ | 1 |
| $ | — |
| $ | — |
|
| As of December 31, 2019 | 117 |
| — |
| 69 |
| — |
| — |
| — |
|
| Contract Liabilities | | | | | | |
| As of June 30, 2020 | $ | 57 |
| $ | 6 |
| $ | 23 |
| $ | — |
| $ | 1 |
| $ | 2 |
|
| As of December 31, 2019 | 52 |
| 10 |
| 13 |
| — |
| 1 |
| 1 |
|
As of June 30, 2020 and December 31, 2019, Georgia Power had contract assets primarily related to unregulated service agreements, where payment is contingent on project completion, and fixed retail customer bill programs, where the payment is contingent upon Georgia Power's continued performance and the customer's continued participation in the program over a one-year contract term. Contract liabilities for Georgia Power relate to cash collections recognized in advance of revenue for certain unregulated service agreements. Alabama Power had contract liabilities for outstanding performance obligations primarily related to extended service agreements. Southern Company's unregulated distributed generation business had $41 million and $40 million of contract assets and $26 million and $28 million of contract liabilities at June 30, 2020 and December 31, 2019, respectively, for outstanding performance obligations.
Revenues recognized by Southern Company in the three and six months ended June 30, 2020, which were included in contract liabilities at December 31, 2019, were $11 million and $21 million, respectively, and immaterial for all other applicable Registrants.
Remaining Performance Obligations
The traditional electric operating companies and Southern Power have long-term contracts with customers in which revenues are recognized as performance obligations are satisfied over the contract term. These contracts primarily relate to PPAs whereby the traditional electric operating companies and Southern Power provide electricity and generation capacity to a customer. The revenue recognized for the delivery of electricity is variable; however, certain PPAs include a fixed payment for fixed generation capacity over the term of the contract. Southern Company's unregulated distributed generation business also has partially satisfied performance obligations related to certain fixed price contracts. Revenue from contracts with customers related to these performance obligations remaining at June 30, 2020 are expected to be recognized as follows:
|
| | | | | | | | | | | | | | | | | | |
| | 2020 (remaining) | 2021 | 2022 | 2023 | 2024 | 2025 and Thereafter |
| | (in millions) |
| Southern Company | $ | 319 |
| $ | 432 |
| $ | 362 |
| $ | 339 |
| $ | 319 |
| $ | 3,062 |
|
| Alabama Power | 12 |
| 33 |
| 31 |
| 24 |
| 7 |
| 5 |
|
| Georgia Power | 37 |
| 70 |
| 39 |
| 34 |
| 23 |
| 62 |
|
| Southern Power | 156 |
| 290 |
| 292 |
| 282 |
| 290 |
| 3,013 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Revenue expected to be recognized for performance obligations remaining at June 30, 2020 was immaterial for Mississippi Power.
Lease Income
Lease income for the three and six months ended June 30, 2020 and 2019 is as follows:
|
| | | | | | | | | | | | | | | | | | |
| | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| | (in millions) |
| For the Three Months Ended June 30, 2020 | | | | | | |
| Lease income - interest income on sales-type leases | $ | 3 |
| $ | — |
| $ | — |
| $ | 3 |
| $ | — |
| $ | — |
|
| Lease income - operating leases | 47 |
| 6 |
| 15 |
| — |
| 21 |
| 9 |
|
| Variable lease income | 126 |
| — |
| — |
| — |
| 136 |
| — |
|
| Total lease income | $ | 176 |
| $ | 6 |
| $ | 15 |
| $ | 3 |
| $ | 157 |
| $ | 9 |
|
| | | | | | | |
| For the Six Months Ended June 30, 2020 | | | | | | |
| Lease income - interest income on sales-type leases | $ | 6 |
| $ | — |
| $ | — |
| $ | 5 |
| $ | — |
| $ | — |
|
| Lease income - operating leases | 97 |
| 13 |
| 30 |
| — |
| 45 |
| 17 |
|
| Variable lease income | 200 |
| — |
| — |
| — |
| 215 |
| — |
|
| Total lease income | $ | 303 |
| $ | 13 |
| $ | 30 |
| $ | 5 |
| $ | 260 |
| $ | 17 |
|
| | | | | | | |
| For the Three Months Ended June 30, 2019 | | | | | | |
| Lease income - interest income on sales-type leases | $ | 2 |
| $ | — |
| $ | — |
| $ | 2 |
| $ | — |
| $ | — |
|
| Lease income - operating leases | 67 |
| 7 |
| 19 |
| — |
| 44 |
| 9 |
|
| Variable lease income | 115 |
| — |
| — |
| — |
| 129 |
| — |
|
| Total lease income | $ | 184 |
| $ | 7 |
| $ | 19 |
| $ | 2 |
| $ | 173 |
| $ | 9 |
|
| | | | | | | |
| For the Six Months Ended June 30, 2019 | | | | | | |
| Lease income - interest income on sales-type leases | $ | 5 |
| $ | — |
| $ | — |
| $ | 5 |
| $ | — |
| $ | — |
|
| Lease income - operating leases | 139 |
| 13 |
| 39 |
| — |
| 90 |
| 17 |
|
| Variable lease income | 182 |
| — |
| — |
| — |
| 204 |
| — |
|
| Total lease income | $ | 326 |
| $ | 13 |
| $ | 39 |
| $ | 5 |
| $ | 294 |
| $ | 17 |
|
Lease income for Southern Power is included in wholesale revenues. Lease payments received under tolling arrangements and PPAs consist of either scheduled payments or variable payments based on the amount of energy produced by the underlying electric generating units.
(E) CONSOLIDATED ENTITIES AND EQUITY METHOD INVESTMENTS
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Mississippi PowerNote 7 to the financial statements in Item 78 of the Form 10-K for additional information.
Southern Power
Variable Interest Entities
Southern Power has certain subsidiaries that are determined to be VIEs. Southern Power is considered the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacingprimary beneficiary of these VIEs because it controls 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 principlemost significant activities of the standardVIEs, including operating and maintaining the respective assets, and has the obligation to absorb expected losses of these VIEs to the extent of its equity interests.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
SP Solar and SP Wind
At June 30, 2020 and December 31, 2019, SP Solar had total assets of $6.2 billion and $6.4 billion, respectively, and total liabilities of $381 million. Noncontrolling interests totaled $1.1 billion at both June 30, 2020 and December 31, 2019. Cash distributions from SP Solar are allocated 67% to Southern Power and 33% to Global Atlantic in accordance with their partnership interest percentage. Under the terms of the limited partnership agreement, distributions without limited partner consent are limited to available cash and SP Solar is obligated to recognize revenuedistribute all such available cash to depictits partners each quarter. Available cash includes all cash generated in the transferquarter subject to the maintenance of goods or servicesappropriate operating reserves.
At June 30, 2020 and December 31, 2019, SP Wind had total assets of $2.4 billion and $2.5 billion, respectively, total liabilities of $125 million and $128 million, respectively, and noncontrolling interests of $44 million and $45 million, respectively. Under the terms of the limited liability agreement, distributions without Class A member consent are limited to customers atavailable cash and SP Wind is obligated to distribute all such available cash to its members each quarter. Available cash includes all cash generated in the amount expectedquarter subject to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing,maintenance of appropriate operating reserves. Cash distributions from SP Wind are generally allocated 60% to Southern Power and uncertainty40% to the 3 financial investors in accordance with the limited liability agreement.
Southern Power consolidates both SP Solar and SP Wind, as the primary beneficiary, since it controls the most significant activities of revenueeach entity, including operating and maintaining their assets. Certain transfers and sales of the assets in the VIEs are subject to partner consent 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
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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,liabilities 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 use the modified retrospective method of adoption effective January 1, 2018. Mississippi 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 Mississippi Power's financial 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 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. 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.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with early adoption permitted. Mississippi Power is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on Mississippi Power's financial statements.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Mississippi Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information. Earnings for the nine months ended September 30, 2017 were negatively affected by revisionsnon-recourse to the cost estimate for the Kemper IGCC.
Mississippi Power'sgeneral credit of Southern Power. Liabilities consist of customary working capital expendituresitems and debt maturities are expected to materially exceed operating cash flows through 2022. Projected capital expenditures in that period include investments to maintain existing generation facilities, to add environmental modifications to existing generating units, and to expand and improve transmission and distribution facilities.
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 prepay $901 million of outstanding debt.
As of September 30, 2017, Mississippi Power's current liabilities exceeded current assets by approximately $769 million primarily due to $935 million in long-term debt that matures within the next 12 months and $94 million of short-term debt. 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.
Net cash provided from operating activities totaled $361 million for the first nine months of 2017, a decrease of $12 million as compared to the corresponding period in 2016. The decrease in cash provided from operating activities is primarily due to deferred income taxes related to the Kemper IGCC, partially offset by the timing of payments received from affiliates and customers and the completion of Mirror CWIP 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 $483 million for the first nine months of 2017 primarily due to gross property additions related to the Kemper IGCC. Net cash provided from financing activities totaled $129 million for the first nine months of 2017 primarily due to capital contributions from Southern Company, partially offset by redemptions of long-term debt and short-term borrowings. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first nine months of 2017 include an increase in paid-in capital of $1.0 billion due to capital contributions from Southern Company, a portion of which was used to repay $300 million of securities due within one year, $591 million of long-term debt, and $10 million of short-term debt. Securities due within one year decreased $551 million due to the repayment of promissory notes to Southern Company. Long-term debt decreased primarily due to the reclassification of $1.2 billion in unsecured term loans to securities due within one year. Other significant changes include decreases of $2.5 billion in CWIP, $756 million in accumulated deferred income taxes, and $299 million in deferred charges related to income taxes. All of these changes primarily resulted from the Kemper IGCC suspension and related estimated loss. Income taxes receivable and unrecognized tax benefits also decreased due to tax refunds associated with the IRS Section 174 R&E settlement. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and 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.
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,
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
scheduled maturities of long-term debt, as well as related interest, leases, purchase commitments, derivative obligations, preferred stock dividends, trust funding requirements, and unrecognized tax benefits. Approximately $935 million will be required through September 30, 2018 to fund maturities of long-term debt and $4 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" and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information.
The construction program of Mississippi Power is currently estimated to be $582 million for 2017, $203 million for 2018, $177 million for 2019, $204 million for 2020, $199 million for 2021, and $240 million for 2022. These estimated expenditures do not include potential compliance costsany long-term debt.
Other Variable Interest Entities
Southern Power has other consolidated VIEs that may ariserelate to certain subsidiaries that have either sold noncontrolling interests to tax-equity investors or acquired less than a 100% interest from facility developers. These entities are considered VIEs because the EPA's final rules and guidelines or future state plans that would limit CO2 emissions from existing, new, modified, or reconstructed fossil-fuel-fired electric generating units.
The construction program is subjectarrangements are structured similar 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;a limited partnership and the costnoncontrolling members do not have substantive kick-out rights.
At June 30, 2020 and December 31, 2019, the other VIEs had total assets of capital.
Sources$1.5 billion and $1.1 billion, respectively, total liabilities of Capital
Mississippi Power plans to obtain$160 million and $104 million, respectively, and noncontrolling interests of $557 million and $409 million, respectively. Under the funds required for construction and other 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 resolutionterms of the Kemper County energy facility cost recovery.partnership agreements, distributions of all available cash are required each month or quarter and additional distributions require partner consent.
Equity Method Investments
At June 30, 2020 and December 31, 2019, Southern Power had equity method investments in wind and battery storage projects totaling $19 million and $28 million, respectively.
Southern Company Gas
Equity Method Investments
On March 24, 2020, Southern Company Gas completed the sale of its interests in Pivotal LNG and Atlantic Coast Pipeline. 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" of Mississippi Power in Item 7 of the Form 10-KNote (K) under "Southern Company Gas" for additional information.
On February 28, 2017, the maturity dates for $551 million in promissory notes
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
The carrying amounts of Southern Company were extended to JulyGas' equity method investments as of June 30, 2020 and December 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; (ii) repay all of the $591 million outstanding principal amount of promissory notes to Southern Company;2019 and (iii) repay $10 million of the outstanding principal amount of bank loans.
In September 2017, Mississippi Power issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $150 million bearing interest based on one-month LIBOR. Mississippi Power borrowed $109 million under this promissory note primarily to satisfy its federalrelated income tax obligationsfrom those investments for the quarter ending Septemberthree and six months ended June 30, 20172020 and subsequently repaid the promissory note upon receipt of its income tax refund from the U.S. federal government related to the settlement concerning deductible R&E expenditures. See Note (G) to the Condensed Financial Statements under "Section 174 Research and Experimental Deduction" herein for additional information.
As of September 30, 2017, Mississippi Power's current liabilities exceeded current assets by approximately $769 million primarily due to $935 million in long-term debt that matures within the next 12 months and $94 million of short-term debt. Mississippi Power intends to utilize operating cash flows, lines of credit, and bank term loans, as
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 (E) to the Condensed Financial Statements under "Going Concern" herein.
At September 30, 2017, Mississippi Power had approximately $231 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 20172019 were as follows:
|
| | | | | | |
| Investment Balance | June 30, 2020 | December 31, 2019(a) |
| | (in millions) |
SNG(b) | $ | 1,189 |
| $ | 1,137 |
|
PennEast Pipeline(c) | 87 |
| 82 |
|
| Other | 32 |
| 32 |
|
| Total | $ | 1,308 |
| $ | 1,251 |
|
| |
| (a) | Excludes investments in Atlantic Coast Pipeline and Pivotal JAX LNG classified as held for sale at December 31, 2019. See Note 15 to the financial statements under "Assets Held for Sale" in Item 8 of the Form 10-K for additional information. |
| |
| (b) | Increase primarily relates to a capital contribution, partially offset by the continued amortization of deferred tax assets established upon acquisition. |
| |
| (c) | See Note (C) under "Other Matters – Southern Company Gas" for additional information on the PennEast Pipeline. |
|
| | | | | | | | | | | | |
| Earnings from Equity Method Investments | Three Months Ended June 30, 2020 | Three Months Ended June 30, 2019 | Six Months Ended June 30, 2020 | Six Months Ended June 30, 2019 |
| | (in millions) |
| SNG | $ | 28 |
| $ | 32 |
| $ | 65 |
| $ | 74 |
|
Atlantic Coast Pipeline(a)(b) | — |
| 3 |
| 3 |
| 6 |
|
PennEast Pipeline(a) | 1 |
| 1 |
| 3 |
| 3 |
|
| Other | 1 |
| (5 | ) | 1 |
| (3 | ) |
| Total | $ | 30 |
| $ | 31 |
| $ | 72 |
| $ | 80 |
|
| |
| (a) | Amounts primarily result from AFUDC equity recorded by the project entity. |
| |
| (b) | On March 24, 2020, Southern Company Gas completed the sale of its interest in Atlantic Coast Pipeline. See Note (K) under "Southern Company Gas" for additional information. |
SNG
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Expires | | | | Executable Term Loans | | Expires Within One Year |
| 2017 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out |
| (in millions) |
| $ | 100 |
| | $ | 100 |
| | $ | 100 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 100 |
|
|
| | | | | | | | | | | | |
| Income Statement Information | Three Months Ended June 30, 2020 | Three Months Ended June 30, 2019 | Six Months Ended June 30, 2020 | Six Months Ended June 30, 2019 |
| | (in millions) |
| Revenues | $ | 149 |
| $ | 155 |
| $ | 307 |
| $ | 321 |
|
| Operating income | 78 |
| 86 |
| 176 |
| 192 |
|
| Net income | 55 |
| 64 |
| 130 |
| 148 |
|
(F) FINANCING
Bank Credit Arrangements
See Note 68 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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
At June 30, 2020, committed credit arrangements with banks were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Expires | | | |
| Company | 2020 | 2021 | 2022 | 2023 | 2024 | | Total | | Unused | Due within One Year |
| | (in millions) |
| Southern Company parent | $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 2,000 |
| | $ | 2,000 |
| | $ | 1,999 |
| $ | — |
|
| Alabama Power | 3 |
| — |
| 525 |
| — |
| 800 |
| | 1,328 |
| | 1,328 |
| 3 |
|
| Georgia Power | — |
| — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,733 |
| — |
|
| Mississippi Power | — |
| — |
| 150 |
| 125 |
| — |
| | 275 |
| | 250 |
| — |
|
Southern Power(a) | — |
| — |
| — |
| — |
| 600 |
| | 600 |
| | 590 |
| — |
|
Southern Company Gas(b) | — |
| — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,745 |
| — |
|
| SEGCO | — |
| 30 |
| — |
| — |
| — |
| | 30 |
| | 30 |
| 30 |
|
| Southern Company | $ | 3 |
| $ | 30 |
| $ | 675 |
| $ | 125 |
| $ | 6,900 |
| | $ | 7,733 |
| | $ | 7,675 |
| $ | 33 |
|
| |
| (a) | Does not include Southern Power Company's $120 million and $60 million continuing letter of credit facilities for standby letters of credit expiring in 2021 and 2023, respectively, of which $19 million and $60 million, respectively, was unused at June 30, 2020. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities. |
| |
| (b) | Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.25 billion of this arrangement. Southern Company Gas' committed credit arrangement also includes $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. Pursuant to this multi-year credit arrangement, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted. |
As reflected in the table above, in March 2020, Mississippi Power entered into a $125 million revolving credit facility that matures in March 2023.
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.
These bank credit arrangements, as well as Mississippi Power'sthe term loan agreement,arrangements of the Registrants and SEGCO, contain covenants that limit debt levels and typically contain cross accelerationcross-acceleration or, in the case of Southern Power, cross-default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of Mississippi Power.the individual company. Such cross-default provisions to other indebtedness would trigger an event of default if Southern Power defaulted on indebtedness or guarantee obligations over a specified threshold. Such cross-acceleration provisions to other indebtedness would trigger an event of default if Mississippi Powerthe applicable borrower defaulted on indebtedness, the payment of which was then accelerated. At SeptemberJune 30, 2017, Mississippi Power was2020, the Registrants, Nicor Gas, and SEGCO were 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.borrowings.
A portion of the $100 million unused credit arrangements with banks is allocated to provide liquidity support to Mississippi Power's pollution controlthe revenue bonds.bonds of the traditional electric operating companies and the commercial paper programs of the Registrants, Nicor Gas, and SEGCO. The amount of variable rate pollution control revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of Septemberat June 30, 20172020 was approximately $40 million.$1.4 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia Power, and $34 million at Mississippi Power). In addition, at SeptemberJune 30, 2017, Mississippi2020, Georgia Power had approximately $50$257 million of fixed rate pollution controlrevenue bonds outstanding that wereare required to be remarketed within the next 12 months.
Earnings per Share
For Southern Company, the only differences in computing basic and diluted earnings per share are attributable to awards outstanding under stock-based compensation plans and, as a result of stock price volatility in the first six months of 2020, the equity units issued in August 2019. Earnings per share dilution resulting from stock-based
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
compensation plans and the equity units issuance is determined using the treasury stock method. See Note 8 to the financial statements under "Equity Units" in Item 8 of the Form 10-K for information on the August 2019 equity units issuance and Note 12 to the financial statements in Item 8 of the Form 10-K for information on stock-based compensation plans. Shares used to compute diluted earnings per share were as follows:
|
| | | | | | | | |
| | Three Months Ended June 30, 2020 | Three Months Ended June 30, 2019 | Six Months Ended June 30, 2020 | Six Months Ended June 30, 2019 |
| | (in millions) |
| As reported shares | 1,058 |
| 1,044 |
| 1,057 |
| 1,041 |
|
| Effect of stock-based compensation | 5 |
| 8 |
| 7 |
| 8 |
|
| Effect of equity units | — |
| — |
| 1 |
| — |
|
| Diluted shares | 1,063 |
| 1,052 |
| 1,065 |
| 1,049 |
|
An immaterial number of stock-based compensation awards was not included in the diluted earnings per share calculation because the awards were anti-dilutive for the three and six months ended June 30, 2020. There were 0 such amounts for the three and six months ended June 30, 2019.
(G) INCOME TAXES
See Note 10 to the financial statements in Item 8 of the Form 10-K for additional tax information.
Current and Deferred Income Taxes
Tax Credit and Net Operating Loss Carryforwards
The utilization of each Registrants' estimated tax credit and net operating loss carryforwards and related valuation allowances could be impacted by numerous factors, including the acquisition of additional renewable projects, the purchase of rights to additional PTCs of Plant Vogtle Units 3 and 4 pursuant to certain joint ownership agreements, potential impacts of the COVID-19 pandemic, and changes in taxable income projections. See Note (B) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information on Plant Vogtle Units 3 and 4.
Effective Tax Rate
Details of significant changes in the effective tax rate for the applicable Registrants are provided herein.
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 at the traditional electric operating companies, flowback of excess deferred income taxes at the regulated utilities, and federal income tax benefits from ITCs and PTCs primarily at Southern Power.
Southern Company's effective tax rate was 9.3% for the six months ended June 30, 2020 compared to 33.5% for the corresponding period in 2019. The effective tax rate decrease was primarily due to the tax impact from the sale of Gulf Power in 2019, as well as an increase in the flowback of excess deferred income taxes in 2020 primarily at Georgia Power. See Note 15 to the financial statements under "Southern Company" in Item 8 of the Form 10-K for additional information.
Georgia Power
Georgia Power's effective tax rate was 4.0% for the six months ended June 30, 2020 compared to 21.7% for the corresponding period in 2019. The effective tax rate decrease was primarily due to an increase in the flowback of excess deferred income taxes in 2020 as authorized in the 2019 ARP, as well as the second quarter 2020 charge to
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
earnings associated with the construction of Plant Vogtle Units 3 and 4. See Note (B) under "Georgia Power – Nuclear Construction" and Note 2 to the financial statements under "Georgia Power" in Item 8 of the Form 10-K for additional information.
Mississippi Power
Mississippi Power's effective tax rate was 10.6% for the six months ended June 30, 2020 compared to 14.0% for the corresponding period in 2019. The effective tax rate decrease was primarily due to an increase in the flowback of excess deferred income taxes in 2020 as authorized in the Mississippi Power Rate Case Settlement Agreement. See Note (B) under "Mississippi Power – 2019 Base Rate Case" for additional information.
Southern Power
Southern Power's effective tax rate was 10.5% for the six months ended June 30, 2020 compared to a benefit rate of (35.5)% for the corresponding period in 2019. The effective tax rate increase was primarily due to tax benefits resulting from ITCs recognized upon the sale of Plant Nacogdoches in 2019. See Note (K) under "Southern Power" for additional information.
Southern Company Gas
Southern Company Gas' effective tax rate was 21.5% for the six months ended June 30, 2020 compared to 18.0% for the corresponding period in 2019. The effective tax rate increase was primarily due to higher flowback of excess deferred income taxes in 2019, primarily at Atlanta Gas Light as previously authorized by the Georgia PSC, and the reversal of a federal tax valuation allowance in connection with Southern Company Gas' sale of its investment in Triton in 2019. See Notes 2 and 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
(H) RETIREMENT BENEFITS
The Southern Company system has a qualified defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees at PowerSecure. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). NaN mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2020. The Southern Company system also provides certain non-qualified defined benefits for a select group of management and highly compensated employees, which are funded on a cash basis. In addition, the Southern Company system provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric operating companies fund other postretirement trusts to the extent required by their respective regulatory commissions. Southern Company Gas has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses.
See Note 11 to the financial statements in Item 8 of the Form 10-K for additional information.
Effective January 1, 2020, Southern Company adopted a change in method of calculating the market-related value of the liability-hedging securities included in its pension plan assets. The market-related value is used to determine the expected return on plan assets component of net periodic pension cost. Southern Company previously used the calculated value approach for all plan assets, which smoothed asset returns and deferred gains and losses by amortizing them into the calculation of the market-related value over five years. Southern Company changed to the fair value approach for liability-hedging securities, which includes measuring the market-related value of that portion of the plan assets at fair value for purposes of determining the expected return on plan assets. The remaining asset classes of plan assets will continue to use the calculated value approach in determining the market-related value. Southern Company considers the fair value approach to be preferable because it results in a current reflection of changes in the value of plan assets in the measurement of net periodic pension cost. Southern Company evaluated the effect of this change in accounting method and deemed it immaterial to the historical and current financial statements of all Registrants and therefore did not account for the change retrospectively. The change in accounting principle was recorded through earnings as a prior period adjustment for the amounts related to the unregulated
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
businesses of Southern Company and Southern Power. Amounts related to the traditional electric operating companies and the natural gas distribution utilities have been reflected as adjustments to regulatory assets as appropriate, consistent with the expected regulatory treatment.
On each Registrant's condensed statements of income, the service cost component of net periodic benefit costs is included in other operations and maintenance expenses and all other components of net periodic benefit costs are included in notes payableother income (expense), net. Components of the net periodic benefit costs for the three and six months ended June 30, 2020 and 2019 are presented in the balance sheets. Detailsfollowing tables.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, 2020 | Southern Company | | Alabama Power | | Georgia Power | | Mississippi Power | | Southern Power | | Southern Company Gas |
| | (in millions) |
| Pension Plans |
| Service cost | $ | 94 |
| | $ | 22 |
| | $ | 24 |
| | $ | 4 |
| | $ | 2 |
| | $ | 8 |
|
| Interest cost | 108 |
| | 25 |
| | 34 |
| | 5 |
| | 2 |
| | 7 |
|
| Expected return on plan assets | (275 | ) | | (66 | ) | | (87 | ) | | (12 | ) | | (3 | ) | | (20 | ) |
| Amortization: | | | | | | | | | | | |
| Prior service costs | — |
| | — |
| | 1 |
| | — |
| | — |
| | — |
|
| Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 4 |
|
| Net (gain)/loss | 67 |
| | 18 |
| | 21 |
| | 3 |
| | — |
| | 3 |
|
| Net periodic pension cost (income) | $ | (6 | ) | | $ | (1 | ) | | $ | (7 | ) | | $ | — |
| | $ | 1 |
| | $ | 2 |
|
| Postretirement Benefits |
| Service cost | $ | 6 |
| | $ | 1 |
| | $ | 2 |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
|
| Interest cost | 14 |
| | 3 |
| | 5 |
| | 1 |
| | — |
| | 4 |
|
| Expected return on plan assets | (18 | ) | | (7 | ) | | (6 | ) | | (1 | ) | | — |
| | (2 | ) |
| Amortization: | | | | | | | | | | | |
| Prior service costs | (1 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
| Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 1 |
|
| Net (gain)/loss | — |
| | — |
| | — |
| | — |
| | — |
| | (1 | ) |
| Net periodic postretirement benefit cost | $ | 1 |
| | $ | (3 | ) | | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | 3 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Six Months Ended June 30, 2020 | Southern Company | | Alabama Power | | Georgia Power | | Mississippi Power | | Southern Power | | Southern Company Gas |
| | (in millions) |
| Pension Plans |
| Service cost | $ | 188 |
| | $ | 44 |
| | $ | 48 |
| | $ | 8 |
| | $ | 4 |
| | $ | 16 |
|
| Interest cost | 216 |
| | 50 |
| | 67 |
| | 10 |
| | 3 |
| | 15 |
|
| Expected return on plan assets | (550 | ) | | (132 | ) | | (174 | ) | | (25 | ) | | (6 | ) | | (39 | ) |
| Amortization: | | | | | | | | | | | |
| Prior service costs | 1 |
| | — |
| | 1 |
| | — |
| | — |
| | (1 | ) |
| Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 8 |
|
| Net (gain)/loss | 134 |
| | 36 |
| | 43 |
| | 6 |
| | 1 |
| | 5 |
|
| Net periodic pension cost (income) | $ | (11 | ) | | $ | (2 | ) | | $ | (15 | ) | | $ | (1 | ) | | $ | 2 |
| | $ | 4 |
|
| | | | | | | | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Six Months Ended June 30, 2020 | Southern Company | | Alabama Power | | Georgia Power | | Mississippi Power | | Southern Power | | Southern Company Gas |
| | (in millions) |
| Postretirement Benefits |
| Service cost | $ | 11 |
| | $ | 3 |
| | $ | 3 |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
|
| Interest cost | 27 |
| | 6 |
| | 10 |
| | 1 |
| | — |
| | 6 |
|
| Expected return on plan assets | (36 | ) | | (14 | ) | | (13 | ) | | (1 | ) | | — |
| | (4 | ) |
| Amortization: | | | | | | | | | | | |
| Prior service costs | (1 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
| Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 3 |
|
| Net (gain)/loss | 1 |
| | — |
| | 1 |
| | — |
| | — |
| | (2 | ) |
| Net periodic postretirement benefit cost | $ | 2 |
| | $ | (5 | ) | | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | 4 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, 2019 | Southern Company | | Alabama Power | | Georgia Power | | Mississippi Power | | Southern Power | | Southern Company Gas |
| | (in millions) |
| Pension Plans |
| Service cost | $ | 73 |
|
| $ | 17 |
|
| $ | 18 |
|
| $ | 3 |
|
| $ | 1 |
|
| $ | 6 |
|
| Interest cost | 123 |
|
| 29 |
|
| 39 |
|
| 5 |
|
| 2 |
|
| 9 |
|
| Expected return on plan assets | (221 | ) |
| (52 | ) |
| (73 | ) |
| (10 | ) |
| (3 | ) |
| (15 | ) |
| Amortization: | | | | | | | | | | | |
| Prior service costs | 1 |
|
| 1 |
|
| 1 |
|
| — |
|
| — |
|
| — |
|
| Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 4 |
|
| Net (gain)/loss | 30 |
|
| 9 |
|
| 11 |
|
| 2 |
|
| — |
|
| — |
|
| Net periodic pension cost (income) | $ | 6 |
|
| $ | 4 |
|
| $ | (4 | ) |
| $ | — |
|
| $ | — |
|
| $ | 4 |
|
| Postretirement Benefits |
| Service cost | $ | 4 |
| | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Interest cost | 17 |
| | 4 |
| | 6 |
| | 1 |
| | — |
| | 3 |
|
| Expected return on plan assets | (17 | ) | | (7 | ) | | (6 | ) | | (1 | ) | | — |
| | (1 | ) |
| Amortization: | | | | | | | | | | | |
| Prior service costs | 1 |
| | 1 |
| | — |
| | — |
| | — |
| | — |
|
| Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 1 |
|
| Net (gain)/loss | — |
| | — |
| | — |
| | — |
| | — |
| | (1 | ) |
| Net periodic postretirement benefit cost | $ | 5 |
| | $ | (1 | ) | | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 2 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Six Months Ended June 30, 2019 | Southern Company | | Alabama Power | | Georgia Power | | Mississippi Power | | Southern Power | | Southern Company Gas |
| | (in millions) |
| Pension Plans |
| Service cost | $ | 146 |
| | $ | 34 |
| | $ | 37 |
| | $ | 6 |
| | $ | 3 |
| | $ | 12 |
|
| Interest cost | 246 |
| | 57 |
| | 78 |
| | 11 |
| | 3 |
| | 18 |
|
| Expected return on plan assets | (442 | ) | | (103 | ) | | (146 | ) | | (20 | ) | | (5 | ) | | (30 | ) |
| Amortization: | | | | | | | | | | | |
| Prior service costs | 1 |
| | 1 |
| | 1 |
| | — |
| | — |
| | (1 | ) |
| Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 7 |
|
| Net (gain)/loss | 60 |
| | 18 |
| | 22 |
| | 3 |
| | — |
| | 1 |
|
| Net periodic pension cost (income) | $ | 11 |
| | $ | 7 |
| | $ | (8 | ) | | $ | — |
| | $ | 1 |
| | $ | 7 |
|
| Postretirement Benefits |
| Service cost | $ | 9 |
| | $ | 2 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
| Interest cost | 34 |
| | 8 |
| | 13 |
| | 2 |
| | — |
| | 5 |
|
| Expected return on plan assets | (33 | ) | | (13 | ) | | (12 | ) | | (1 | ) | | — |
| | (3 | ) |
| Amortization: | | | | | | | | | | | |
| Prior service costs | 2 |
| | 2 |
| | — |
| | — |
| | — |
| | — |
|
| Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 3 |
|
| Net (gain)/loss | (1 | ) | | — |
| | — |
| | — |
| | — |
| | (2 | ) |
| Net periodic postretirement benefit cost | $ | 11 |
| | $ | (1 | ) | | $ | 3 |
| | $ | 1 |
| | $ | — |
| | $ | 4 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
(I) FAIR VALUE MEASUREMENTS
As of June 30, 2020, 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:
|
| | | | | | | | | | | | | | | | |
| | | Short-term Debt at September 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 | | $ | 4 |
| | 3.8% | | $ | 28 |
| | 2.8% | | $ | 126 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using: | | |
| As of June 30, 2020: | 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) | $ | 388 |
| | $ | 181 |
| | $ | 143 |
| | $ | — |
| | $ | 712 |
|
| Interest rate derivatives | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
Investments in trusts:(b)(c) | | | | | | | | | |
| Domestic equity | 703 |
| | 128 |
| | — |
| | — |
| | 831 |
|
| Foreign equity | 65 |
| | 202 |
| | — |
| | — |
| | 267 |
|
| U.S. Treasury and government agency securities | — |
| | 268 |
| | — |
| | — |
| | 268 |
|
| Municipal bonds | — |
| | 106 |
| | — |
| | — |
| | 106 |
|
| Pooled funds – fixed income | — |
| | 16 |
| | — |
| | — |
| | 16 |
|
| Corporate bonds | 19 |
| | 369 |
| | — |
| | — |
| | 388 |
|
| Mortgage and asset backed securities | — |
| | 75 |
| | — |
| | — |
| | 75 |
|
| Private equity | — |
| | — |
| | — |
| | 61 |
| | 61 |
|
| Other | 26 |
| | 3 |
| | — |
| | — |
| | 29 |
|
| Cash equivalents | 1,315 |
| | 13 |
| | — |
| | — |
| | 1,328 |
|
| Other investments | 9 |
| | 21 |
| | — |
| | — |
| | 30 |
|
| Total | $ | 2,525 |
| | $ | 1,405 |
| | $ | 143 |
| | $ | 61 |
| | $ | 4,134 |
|
| Liabilities: | | | | | | | | | |
Energy-related derivatives(a) | $ | 468 |
| | $ | 187 |
| | $ | 63 |
| | $ | — |
| | $ | 718 |
|
| Interest rate derivatives | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
| Foreign currency derivatives | — |
| | 49 |
| | — |
| | — |
| | 49 |
|
| Contingent consideration | — |
| | — |
| | 19 |
| | — |
| | 19 |
|
| Total | $ | 468 |
| | $ | 259 |
| | $ | 82 |
| | $ | — |
| | $ | 809 |
|
| | | | | | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using: | | |
| As of June 30, 2020: | 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) |
| Alabama Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 11 |
| | $ | — |
| | $ | — |
| | $ | 11 |
|
Nuclear decommissioning trusts:(b) | | | | | | | | |
|
|
| Domestic equity | 442 |
| | 117 |
| | — |
| | — |
| | 559 |
|
| Foreign equity | 65 |
| | 59 |
| | — |
| | — |
| | 124 |
|
| U.S. Treasury and government agency securities | — |
| | 22 |
| | — |
| | — |
| | 22 |
|
| Municipal bonds | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
| Corporate bonds | 19 |
| | 155 |
| | — |
| | — |
| | 174 |
|
| Mortgage and asset backed securities | — |
| | 28 |
| | — |
| | — |
| | 28 |
|
| Private equity | — |
| | — |
| | — |
| | 61 |
| | 61 |
|
| Other | 8 |
| | — |
| | — |
| | — |
| | 8 |
|
| Cash equivalents | 692 |
| | 13 |
| | — |
| | — |
| | 705 |
|
| Other investments | — |
| | 21 |
| | — |
| | — |
| | 21 |
|
| Total | $ | 1,226 |
| | $ | 427 |
| | $ | — |
| | $ | 61 |
| | $ | 1,714 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 19 |
| | $ | — |
| | $ | — |
| | $ | 19 |
|
| | | | | | | | | | |
| Georgia Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 10 |
| | $ | — |
| | $ | — |
| | $ | 10 |
|
Nuclear decommissioning trusts:(b)(c) | | | | | | | | | |
| Domestic equity | 261 |
| | 1 |
| | — |
| | — |
| | 262 |
|
| Foreign equity | — |
| | 141 |
| | — |
| | — |
| | 141 |
|
| U.S. Treasury and government agency securities | — |
| | 246 |
| | — |
| | — |
| | 246 |
|
| Municipal bonds | — |
| | 105 |
| | — |
| | — |
| | 105 |
|
| Corporate bonds | — |
| | 214 |
| | — |
| | — |
| | 214 |
|
| Mortgage and asset backed securities | — |
| | 47 |
| | — |
| | — |
| | 47 |
|
| Other | 18 |
| | 3 |
| | — |
| | — |
| | 21 |
|
| Cash equivalents | 349 |
| | — |
| | — |
| | — |
| | 349 |
|
| Total | $ | 628 |
| | $ | 767 |
| | $ | — |
| | $ | — |
| | $ | 1,395 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 40 |
| | $ | — |
| | $ | — |
| | $ | 40 |
|
| | | | | | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using: | | |
| As of June 30, 2020: | 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) |
| Mississippi Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 6 |
| | $ | — |
| | $ | — |
| | $ | 6 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 22 |
| | $ | — |
| | $ | — |
| | $ | 22 |
|
| | | | | | | | | | |
| Southern Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 2 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 3 |
|
| Foreign currency derivatives | — |
| | 49 |
| | — |
| | — |
| | 49 |
|
| Contingent consideration | — |
| | — |
| | 19 |
| | — |
| | 19 |
|
| Total | $ | — |
|
| $ | 52 |
|
| $ | 19 |
|
| $ | — |
|
| $ | 71 |
|
| | | | | | | | | | |
| Southern Company Gas | | | | | | | | | |
| Assets: | | | | | | | | | |
Energy-related derivatives(a) | $ | 388 |
| | $ | 152 |
| | $ | 143 |
| | $ | — |
| | $ | 683 |
|
| Non-qualified deferred compensation trusts: | | | | | | | | | |
| Domestic equity | — |
| | 10 |
| | — |
| | — |
| | 10 |
|
| Foreign equity | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
| Pooled funds – fixed income | — |
| | 16 |
| | — |
| | — |
| | 16 |
|
| Cash equivalents and restricted cash | 40 |
| | — |
| | — |
| | — |
| | 40 |
|
| Total | $ | 428 |
|
| $ | 180 |
|
| $ | 143 |
|
| $ | — |
|
| $ | 751 |
|
| Liabilities: | | | | | | | | | |
Energy-related derivatives(a) | $ | 468 |
| | $ | 103 |
| | $ | 63 |
| | $ | — |
| | $ | 634 |
|
| Interest rate derivatives | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
| Total | $ | 468 |
|
| $ | 126 |
|
| $ | 63 |
|
| $ | — |
|
| $ | 657 |
|
| |
| (a) | Energy-related derivatives exclude cash collateral of $114 million. |
| |
| (b) | Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information. |
| |
| (c) | Includes investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of June 30, 2020, approximately $45 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. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
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, including reinvested interest and dividends and excluding the funds' expenses, increased (decreased) by the amounts shown in the table below for the three and six months ended June 30, 2020 and 2019. The changes were recorded as a change to the regulatory assets and liabilities related to AROs for Georgia Power and Alabama Power, respectively.
|
| | | | | | | | | | | | |
| Fair value increases (decreases) | Three Months Ended June 30, 2020 | Three Months Ended June 30, 2019 | Six Months Ended June 30, 2020 | Six Months Ended June 30, 2019 |
| | (in millions) |
| Southern Company | $ | 223 |
| $ | 75 |
| $ | (23 | ) | $ | 227 |
|
| Alabama Power | 124 |
| 38 |
| (42 | ) | 125 |
|
| Georgia Power | 99 |
| 37 |
| 19 |
| 102 |
|
Valuation Methodologies
The energy-related derivatives primarily consist of exchange-traded and over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The fair value of cross-currency swaps reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and discount rates. The interest rate derivatives and cross-currency swaps are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note (J) for additional information on how these derivatives are used.
For fair value measurements of the investments within the nuclear decommissioning trusts and the non-qualified deferred compensation 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.
The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. See Note 6 to the financial statements 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 primarily obligated to make generation-based payments to the seller, which commenced at the commercial operation of the respective facility and continue through 2026. The obligation is categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
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 traded in the open market that have maturities greater than 90 days, which are categorized as Level 2 under Fair Value Measurements and are comprised of corporate bonds, bank certificates of deposit, treasury bonds, and/or agency bonds.
As of June 30, 2020, the fair value measurements of private equity investments held in Alabama Power's nuclear decommissioning trusts that are calculated at net asset value per share (or its equivalent) as a practical expedient totaled $61 million and unfunded commitments related to the private equity investments totaled $72 million. Private equity investments include high-quality private equity funds across several market sectors and funds that invest in real estate assets. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated.
As of June 30, 2020, other financial instruments for which the carrying amount did not equal fair value were as follows:
|
| | | | | | | | | | | | | | | | | | |
| | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas(*) |
| | (in millions) |
| Long-term debt, including securities due within one year: | | | | |
| Carrying amount | $ | 46,513 |
| $ | 8,519 |
| $ | 12,720 |
| $ | 1,404 |
| $ | 4,097 |
| $ | 5,827 |
|
| Fair value | 53,079 |
| 10,008 |
| 15,092 |
| 1,571 |
| 4,423 |
| 6,817 |
|
| |
| (*) | Average and maximum amounts are based upon daily balances duringThe long-term debt of Southern Company Gas is recorded at amortized cost, including the three-month period ended September 30, 2017.fair value adjustments at the effective date of the 2016 merger with Southern Company. Southern Company Gas amortizes the fair value adjustments over the lives of the respective bonds. |
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.
Commodity Contracts with Level 3 Valuation Inputs
As of June 30, 2020, the fair value of Southern Company Gas' Level 3 physical natural gas forward contracts was $80 million. Since commodity contracts classified as Level 3 typically include a combination of observable and unobservable components, the changes in fair value may include amounts due in part to observable market factors, or changes to assumptions on the unobservable components. The following table includes transfers to Level 3, which represent the fair value of Southern Company Gas' commodity derivative contracts that include a significant unobservable component for the first time during the period.
148 |
| | | | | | |
| | Three Months Ended June 30, 2020 | Six Months Ended June 30, 2020 |
| | (in millions) |
| Beginning balance | $ | 76 |
| $ | 14 |
|
| Transfers to Level 3 | — |
| 70 |
|
| Transfers from Level 3 | — |
| (3 | ) |
| Instruments realized or otherwise settled during period | (6 | ) | (7 | ) |
| Changes in fair value | 10 |
| 6 |
|
| Ending balance | $ | 80 |
| $ | 80 |
|
Changes in fair value of Level 3 instruments represent changes in gains and losses for the periods that are reported on Southern Company Gas' statements of income in natural gas revenues.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OFNOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
FINANCIAL CONDITION AND RESULTS OF OPERATIONS(UNAUDITED)
Credit Rating RiskThe valuation of certain commodity contracts requires the use of certain unobservable inputs. All forward pricing used in the valuation of such contracts is directly based on third-party market data, such as broker quotes and exchange settlements, when that data is available. If third-party market data is not available, then industry standard methodologies are used to develop inputs that maximize the use of relevant observable inputs and minimize the use of unobservable inputs. Observable inputs, including some forward prices used for determining fair value, reflect the best available market information. Unobservable inputs are updated using industry standard techniques such as extrapolation, combining observable forward inputs supplemented by historical market and other relevant data. Level 3 physical natural gas forward contracts include unobservable forward price inputs (ranging from $(0.91) to $0.99 per mmBtu). Forward price increases (decreases) as of June 30, 2020 would have resulted in higher (lower) values on a net basis.
(J) DERIVATIVES
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Southern Company Gas' wholesale gas operations use various contracts in its commercial activities that generally meet the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note (I) for additional fair value information. In the statements of cash flows, any cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Any cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with classification of the hedged interest or principal, respectively. See Note 1 to the financial statements under "Financial Instruments" in Item 8 of the Form 10-K for additional information.
Energy-Related Derivatives
The traditional electric operating companies, Southern Power, and Southern Company Gas enter into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies and the natural gas distribution utilities have limited exposure to market volatility in energy-related commodity prices. Each of the traditional electric operating companies and certain of the natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs, implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies, through the use of financial derivative contracts, which are expected to continue to mitigate price volatility. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in energy-related commodity prices because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted capacity is used to sell electricity. Southern Company Gas retains exposure to price changes that can, in a volatile energy market, be material and can adversely affect its results of operations.
Southern Company Gas also enters into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in operating revenues.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Energy-related derivative contracts are accounted for under one of three methods:
| |
| • | Regulatory Hedges — Energy-related derivative contracts designated as regulatory hedges relate primarily to the traditional electric operating companies' and the natural gas distribution utilities' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses. |
| |
| • | Cash Flow Hedges — Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in accumulated OCI before being recognized in the statements of income in the same period and in the same income statement line item as the earnings effect of the hedged transactions. |
| |
| • | Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. |
Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric and natural gas industries. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.
At SeptemberJune 30, 2017,2020, the net volume of energy-related derivative contracts for natural gas positions, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows:
|
| | | | | |
| | Net Purchased mmBtu | | Longest Hedge Date | | Longest Non-Hedge Date |
| | (in millions) | | | | |
Southern Company(*) | 944 | | 2024 | | 2031 |
| Alabama Power | 85 | | 2024 | | — |
| Georgia Power | 152 | | 2023 | | — |
| Mississippi Power | 91 | | 2024 | | — |
| Southern Power | 15 | | 2022 | | 2021 |
Southern Company Gas(*) | 601 | | 2022 | | 2031 |
| |
| (*) | Southern Company Gas' derivative instruments include both long and short natural gas positions. A long position is a contract to purchase natural gas and a short position is a contract to sell natural gas. Southern Company Gas' volume represents the net of long natural gas positions of 4.6 billion mmBtu and short natural gas positions of 4.0 billion mmBtu as of June 30, 2020, which is also included in Southern Company's total volume. |
At June 30, 2020, the net volume of Southern Power's energy-related derivative contracts for power to be sold was 1 million MWHs, all of which expire in 2020.
In addition to the volumes discussed above, the traditional electric operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess natural gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 16 million mmBtu for Southern Company, which includes 4 million mmBtu for Alabama Power, 5 million mmBtu for Georgia Power, 2 million mmBtu for Mississippi Power, doesand 5 million mmBtu for Southern Power.
For cash flow hedges of energy-related derivatives, the estimated pre-tax gains (losses) expected to be reclassified from accumulated OCI to earnings for the 12-month period ending June 30, 2021 are immaterial for all Registrants.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Interest Rate Derivatives
Southern Company and certain subsidiaries may 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 derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and presented on the same income statement line item as the earnings effect of the hedged transactions. 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 on the same income statement line item. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
At June 30, 2020, the following interest rate derivatives were outstanding:
|
| | | | | | | | | | | |
| | Notional Amount | | Interest Rate Received | Weighted Average Interest Rate Paid | Hedge Maturity Date | | Fair Value Gain (Loss) at June 30, 2020 |
| | (in millions) | | | | | | (in millions) |
| Cash Flow Hedges of Forecasted Debt | | | | | | |
| Southern Company Gas | $ | 200 |
| | 3-month LIBOR | 1.81% | September 2030 | | $ | (23 | ) |
| Cash Flow Hedges of Existing Debt | | | | | | |
| Mississippi Power | 60 |
| | 1-month LIBOR | 0.58% | December 2021 | | — |
|
| Fair Value Hedges of Existing Debt | | | | | | |
| Southern Company parent | 1,500 |
| | 2.35% | 1-month LIBOR + 0.87% | July 2021 | | 23 |
|
| Southern Company | $ | 1,760 |
| | | | | | $ | — |
|
The estimated pre-tax gains (losses) related to interest rate derivatives expected to be reclassified from accumulated OCI to interest expense for the 12-month period ending June 30, 2021 total $(25) million for Southern Company and are immaterial for all other Registrants. Deferred gains and losses related to interest rate derivatives are expected to be amortized into earnings through 2046 for the Southern Company parent entity, 2035 for Alabama Power, 2044 for Georgia Power, 2028 for Mississippi Power, and 2046 for Southern Company Gas.
Foreign Currency Derivatives
Southern Company and certain subsidiaries, including Southern Power, may 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 derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and on the same income statement line as the earnings effect of the hedged transactions, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
At June 30, 2020, the following foreign currency derivatives were outstanding:
|
| | | | | | | | | | | | |
| | Pay Notional | Pay Rate | Receive Notional | Receive Rate | Hedge
Maturity Date | Fair Value Gain (Loss) at June 30, 2020 |
| | (in millions) | | (in millions) | | | (in millions) |
| Cash Flow Hedges of Existing Debt | | | | | |
| Southern Power | $ | 677 |
| 2.95% | € | 600 |
| 1.00% | June 2022 | $ | (18 | ) |
| Southern Power | 564 |
| 3.78% | 500 |
| 1.85% | June 2026 | (31 | ) |
| Total | $ | 1,241 |
| | € | 1,100 |
| | | $ | (49 | ) |
The estimated pre-tax gains (losses) related to Southern Power's foreign currency derivatives expected to be reclassified from accumulated OCI to earnings for the 12-month period ending June 30, 2021 are $(24) million.
Derivative Financial Statement Presentation and Amounts
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas enter into derivative contracts that may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Southern Company and certain subsidiaries also utilize master netting agreements to mitigate exposure to counterparty credit risk. These agreements may contain provisions that permit netting across product lines and against cash collateral. The fair value amounts of derivative assets and liabilities on the balance sheet are presented net to the extent that there are netting arrangements or similar agreements with the counterparties.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
The fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:
|
| | | | | | | | | | | | |
| | As of June 30, 2020 | As of December 31, 2019 |
| 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/Other current liabilities | $ | 19 |
| $ | 64 |
| $ | 3 |
| $ | 70 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 13 |
| 28 |
| 6 |
| 44 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 32 |
| $ | 92 |
| $ | 9 |
| $ | 114 |
|
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 3 |
| $ | 6 |
| $ | 1 |
| $ | 6 |
|
| Interest rate derivatives: | | | | |
| Other current assets/Other current liabilities | 12 |
| 23 |
| 2 |
| 23 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 10 |
| — |
| — |
| 1 |
|
| Foreign currency derivatives: | | | | |
| Other current assets/Other current liabilities | — |
| 24 |
| — |
| 24 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 25 |
| 16 |
| — |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 25 |
| $ | 78 |
| $ | 19 |
| $ | 54 |
|
| Derivatives not designated as hedging instruments | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 361 |
| $ | 367 |
| $ | 461 |
| $ | 358 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 316 |
| 253 |
| 207 |
| 225 |
|
| Total derivatives not designated as hedging instruments | $ | 677 |
| $ | 620 |
| $ | 668 |
| $ | 583 |
|
| Gross amounts recognized | $ | 734 |
| $ | 790 |
| $ | 696 |
| $ | 751 |
|
Gross amounts offset(a) | (520 | ) | (634 | ) | (463 | ) | (562 | ) |
Net amounts recognized in the Balance Sheets(b) | $ | 214 |
| $ | 156 |
| $ | 233 |
| $ | 189 |
|
| | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | |
| | As of June 30, 2020 | As of December 31, 2019 |
| 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/Other current liabilities | $ | 7 |
| $ | 12 |
| $ | 2 |
| $ | 14 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 4 |
| 7 |
| 2 |
| 10 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 11 |
| $ | 19 |
| $ | 4 |
| $ | 24 |
|
| Gross amounts recognized | $ | 11 |
| $ | 19 |
| $ | 4 |
| $ | 24 |
|
| Gross amounts offset | (8 | ) | (8 | ) | (2 | ) | (2 | ) |
| Net amounts recognized in the Balance Sheets | $ | 3 |
| $ | 11 |
| $ | 2 |
| $ | 22 |
|
| | | | | |
| Georgia Power | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 5 |
| $ | 28 |
| $ | 1 |
| $ | 32 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 5 |
| 12 |
| 3 |
| 21 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 10 |
| $ | 40 |
| $ | 4 |
| $ | 53 |
|
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Interest rate derivatives: | | | | |
| Other current assets/Other current liabilities | $ | — |
| $ | — |
| $ | — |
| $ | 17 |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | — |
| $ | — |
| $ | — |
| $ | 17 |
|
| Gross amounts recognized | $ | 10 |
| $ | 40 |
| $ | 4 |
| $ | 70 |
|
| Gross amounts offset | (10 | ) | (10 | ) | (3 | ) | (3 | ) |
| Net amounts recognized in the Balance Sheets | $ | — |
| $ | 30 |
| $ | 1 |
| $ | 67 |
|
| | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | |
| | As of June 30, 2020 | As of December 31, 2019 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| | (in millions) | (in millions) |
| Mississippi Power | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 3 |
| $ | 13 |
| $ | — |
| $ | 15 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 3 |
| 9 |
| 1 |
| 12 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 6 |
| $ | 22 |
| $ | 1 |
| $ | 27 |
|
| Gross amounts recognized | $ | 6 |
| $ | 22 |
| $ | 1 |
| $ | 27 |
|
| Gross amounts offset | (6 | ) | (6 | ) | (1 | ) | (1 | ) |
| Net amounts recognized in the Balance Sheets | $ | — |
| $ | 16 |
| $ | — |
| $ | 26 |
|
| | | | | |
| 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 |
| $ | 1 |
| $ | 2 |
|
| Foreign currency derivatives: | | | | |
| Other current assets/Other current liabilities | — |
| 24 |
| — |
| 24 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 25 |
| 16 |
| — |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 2 |
| $ | 52 |
| $ | 17 |
| $ | 26 |
|
| Derivatives not designated as hedging instruments | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | — |
| $ | — |
| $ | 2 |
| $ | 1 |
|
| Total derivatives not designated as hedging instruments | $ | — |
| $ | — |
| $ | 2 |
| $ | 1 |
|
| Gross amounts recognized | $ | 2 |
| $ | 52 |
| $ | 19 |
| $ | 27 |
|
| Gross amounts offset | (1 | ) | (1 | ) | — |
| — |
|
| Net amounts recognized in the Balance Sheets | $ | 1 |
| $ | 51 |
| $ | 19 |
| $ | 27 |
|
| | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | |
| | As of June 30, 2020 | As of December 31, 2019 |
| 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 |
| $ | 11 |
| $ | — |
| $ | 9 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 1 |
| — |
| — |
| 1 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 5 |
| $ | 11 |
| $ | — |
| $ | 10 |
|
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Energy-related derivatives: | | | | |
| Assets from risk management activities/Liabilities from risk management activities-current | $ | 1 |
| $ | 3 |
| $ | — |
| $ | 4 |
|
| Interest rate derivatives: | | | | |
| Assets from risk management activities/Liabilities from risk management activities-current | — |
| 23 |
| 2 |
| — |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 1 |
| $ | 26 |
| $ | 2 |
| $ | 4 |
|
| Derivatives not designated as hedging instruments | | | | |
| Energy-related derivatives: | | | | |
| Assets from risk management activities/Liabilities from risk management activities-current | $ | 361 |
| $ | 367 |
| $ | 459 |
| $ | 357 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 316 |
| 253 |
| 207 |
| 225 |
|
| Total derivatives not designated as hedging instruments | $ | 677 |
| $ | 620 |
| $ | 666 |
| $ | 582 |
|
| Gross amounts of recognized | $ | 683 |
| $ | 657 |
| $ | 668 |
| $ | 596 |
|
Gross amounts offset(a) | (495 | ) | (609 | ) | (456 | ) | (555 | ) |
Net amounts recognized in the Balance Sheets(b) | $ | 188 |
| $ | 48 |
| $ | 212 |
| $ | 41 |
|
| |
| (a) | Gross amounts offset include cash collateral held on deposit in broker margin accounts of $114 million and $99 million as of June 30, 2020 and December 31, 2019, respectively. |
| |
| (b) | Net amounts of derivative instruments outstanding exclude premium and intrinsic value associated with weather derivatives of $4 million as of December 31, 2019. |
Energy-related derivatives not designated as hedging instruments were immaterial for the traditional electric operating companies at June 30, 2020 and December 31, 2019.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
At June 30, 2020 and December 31, 2019, 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 |
Derivative Category and Balance Sheet Location | Southern Company(*) | Alabama Power | Georgia Power | Mississippi Power | Southern Company Gas(*) |
| | (in millions) |
| At June 30, 2020: | | | | | |
| Energy-related derivatives: | | | | | |
| Other regulatory assets, current | $ | (42 | ) | $ | (8 | ) | $ | (23 | ) | $ | (10 | ) | $ | (1 | ) |
| Other regulatory assets, deferred | (16 | ) | (3 | ) | (7 | ) | (6 | ) | — |
|
| Other regulatory liabilities, current | 10 |
| 3 |
| — |
| — |
| 7 |
|
| Total energy-related derivative gains (losses) | $ | (48 | ) | $ | (8 | ) | $ | (30 | ) | $ | (16 | ) | $ | 6 |
|
| | | | | | |
| At December 31, 2019: | | | | | |
| Energy-related derivatives: | | | | | |
| Other regulatory assets, current | $ | (63 | ) | $ | (14 | ) | $ | (31 | ) | $ | (15 | ) | $ | (3 | ) |
| Other regulatory assets, deferred | (37 | ) | (8 | ) | (18 | ) | (11 | ) | — |
|
| Other regulatory liabilities, current | 6 |
| 2 |
| — |
| — |
| 4 |
|
| Total energy-related derivative gains (losses) | $ | (94 | ) | $ | (20 | ) | $ | (49 | ) | $ | (26 | ) | $ | 1 |
|
| |
| (*) | Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $12 million and $11 million at June 30, 2020 and December 31, 2019, respectively. |
For the three and six months ended June 30, 2020 and 2019, the pre-tax effects of cash flow hedge accounting on accumulated OCI were as follows:
|
| | | | | | | | | | | | |
| Gain (Loss) Recognized in OCI on Derivative | For the Three Months Ended June 30, | For the Six Months Ended June 30, |
| 2020 | 2019 | 2020 | 2019 |
| | (in millions) | (in millions) |
| Southern Company | | | | |
| Energy-related derivatives | $ | (2 | ) | $ | (6 | ) | $ | (6 | ) | $ | (6 | ) |
| Interest rate derivatives | (1 | ) | (37 | ) | (28 | ) | (37 | ) |
| Foreign currency derivatives | 17 |
| (1 | ) | (65 | ) | (39 | ) |
| Total | $ | 14 |
| $ | (44 | ) | $ | (99 | ) | $ | (82 | ) |
| Georgia Power | | | | |
| Interest rate derivatives | $ | — |
| $ | (37 | ) | $ | (3 | ) | $ | (37 | ) |
| Southern Power | | | | |
| Energy-related derivatives | $ | (2 | ) | $ | (2 | ) | $ | (2 | ) | $ | (2 | ) |
| Foreign currency derivatives | $ | 17 |
| $ | (1 | ) | (65 | ) | (39 | ) |
| Total | $ | 15 |
| $ | (3 | ) | $ | (67 | ) | $ | (41 | ) |
| Southern Company Gas | | | | |
| Energy-related derivatives | $ | — |
| $ | (4 | ) | $ | (4 | ) | $ | (4 | ) |
| Interest rate derivatives | (1 | ) | — |
| (25 | ) | — |
|
| Total | $ | (1 | ) | $ | (4 | ) | $ | (29 | ) | $ | (4 | ) |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
For the three and six months ended June 30, 2020 and 2019, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on accumulated OCI were immaterial for the other Registrants.
For the three and six months ended June 30, 2020 and 2019, the pre-tax effects of cash flow and fair value hedge accounting on income were as follows: |
| | | | | | | | | | | | | |
| | Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships | For the Three Months Ended June 30, | For the Six Months Ended June 30, |
| |
| | 2020 | 2019 | 2020 | 2019 |
| | | (in millions) | (in millions) |
| | Southern Company | | | | |
| | Total cost of natural gas | $ | 144 |
| $ | 191 |
| $ | 583 |
| $ | 877 |
|
| | Gain (loss) on energy-related cash flow hedges(a) | (1 | ) | — |
| (8 | ) | — |
|
| | Total depreciation and amortization | 873 |
| 755 |
| 1,730 |
| 1,506 |
|
| | Gain (loss) on energy-related cash flow hedges(a) | (1 | ) | (1 | ) | (2 | ) | (4 | ) |
| | Total interest expense, net of amounts capitalized | (444 | ) | (429 | ) | (900 | ) | (859 | ) |
| | Gain (loss) on interest rate cash flow hedges(a) | (6 | ) | (5 | ) | (13 | ) | (9 | ) |
| | Gain (loss) on foreign currency cash flow hedges(a) | (6 | ) | (6 | ) | (12 | ) | (12 | ) |
| | Gain (loss) on interest rate fair value hedges(b) | 1 |
| 19 |
| 30 |
| 33 |
|
| | Total other income (expense), net | 101 |
| 99 |
| 204 |
| 176 |
|
| | Gain (loss) on foreign currency cash flow hedges(a)(c) | 27 |
| 16 |
| (4 | ) | (8 | ) |
| | Southern Power | | | | |
| | Total depreciation and amortization | $ | 121 |
| $ | 119 |
| $ | 239 |
| $ | 237 |
|
| | Gain (loss) on energy-related cash flow hedges(a) | (1 | ) | (1 | ) | (2 | ) | (4 | ) |
| | Total interest expense, net of amounts capitalized | (38 | ) | (41 | ) | (77 | ) | (84 | ) |
| | Gain (loss) on foreign currency cash flow hedges(a) | (6 | ) | (6 | ) | (12 | ) | (12 | ) |
| | Total other income (expense), net | 1 |
| 40 |
| 4 |
| 41 |
|
| | Gain (loss) on foreign currency cash flow hedges(a)(c) | 27 |
| 16 |
| (4 | ) | (8 | ) |
| |
| (a) | Reclassified from accumulated OCI into earnings. |
| |
| (b) | For fair value hedges, changes in the fair value of the derivative contracts are generally equal to changes in the fair value of the underlying debt and have no material impact on income. |
| |
| (c) | The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes. |
For the three and six months ended June 30, 2020 and 2019, the pre-tax effects of cash flow and fair value hedge accounting on income for energy-related derivatives and interest rate derivatives were immaterial for the traditional electric operating companies and Southern Company Gas.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
As of June 30, 2020 and December 31, 2019, the following amounts were recorded on the balance sheets related to cumulative basis adjustments for fair value hedges:
|
| | | | | | | | | | | | | |
| Carrying Amount of the Hedged Item | | Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item |
| Balance Sheet Location of Hedged Items | As of June 30, 2020 | As of December 31, 2019 |
| As of June 30, 2020 | As of December 31, 2019 |
| (in millions) | | (in millions) |
| Southern Company | | | | | |
| Securities due within one year | $ | — |
| $ | (599 | ) | | $ | — |
| $ | — |
|
| Long-term debt | (1,517 | ) | (1,494 | ) | | (20 | ) | 3 |
|
For the three and six months ended June 30, 2020 and 2019, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income of Southern Company and Southern Company Gas 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 | 2020 | 2019 | | 2020 | 2019 |
| | | (in millions) | | (in millions) |
| Energy-related derivatives: | Natural gas revenues(*) | $ | 14 |
| $ | 50 |
| | $ | 84 |
| $ | 83 |
|
| | Cost of natural gas | 5 |
| (5 | ) | | 13 |
| 3 |
|
| Total derivatives in non-designated hedging relationships | $ | 19 |
| $ | 45 |
| | $ | 97 |
| $ | 86 |
|
| |
| (*) | Excludes immaterial gains (losses) recorded in natural gas revenues associated with weather derivatives for all periods presented. |
For the three and six months ended June 30, 2020 and 2019, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments were immaterial for all other 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.
On October 4, 2017, Mississippi Power executed agreements with its largest retail customer, Chevron, to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038. The agreements grant Chevron a security interest in the co-generation assets located at the refinery that is exercisable upon the occurrence of (i) certain bankruptcy events or (ii) other events of default coupled with specific reductions in steam output at the facility and a downgrade of Mississippi Power's credit rating to below investment grade by two of the three rating agencies.
There are certain contractsderivatives that have required or could require collateral, but not accelerated payment, in the event of avarious credit rating changechanges of certain Southern Company subsidiaries. At June 30, 2020, the Registrants had 0 collateral posted with derivative counterparties to BBB and/or Baa2 or below. These contracts are for physical electricity purchasessatisfy these arrangements.
For the Registrants with interest rate derivatives at June 30, 2020, the fair value of interest rate derivative liabilities with contingent features and sales, fuel transportation and storage, energy price risk management, and transmission. At September 30, 2017, the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, equaled approximately $255 million.
Included in these amounts arewas immaterial. At June 30, 2020, the fair value of energy-related derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were immaterial for all Registrants. The maximum potential collateral requirements arising from the credit-risk-related contingent features for the traditional electric operating companies and Southern Power include certain agreements that could require collateral in the event that Alabama Powerone or Georgia Powermore Southern Company power pool participants has a credit rating change to below investment grade. Following the sale of Gulf Power to NextEra Energy, Gulf Power is continuing to participate in the Southern Company power pool for a defined transition period that, subject to certain potential adjustments, is scheduled to end on January 1, 2024.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally,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, 2020, 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, 2020, cash collateral held on deposit in broker margin accounts was $114 million.
The Registrants are exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Registrants 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. The Registrants have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate their exposure to counterparty credit risk. Prior to entering into a physical transaction, Southern Company Gas assigns physical wholesale counterparties an internal credit rating downgrade could impactand credit limit based on the abilitycounterparties' Moody's, S&P, and Fitch ratings, commercially available credit reports, and audited financial statements. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.
In addition, Southern Company Gas conducts credit evaluations and obtains appropriate internal approvals for the counterparty's line of Mississippi Power to access capital markets, and would be likely to impactcredit before any transaction with the cost atcounterparty is executed. In most cases, the counterparty must have an investment grade rating, which it does so.
On March 1, 2017, Moody's downgraded the senior unsecuredincludes a minimum long-term debt rating of Mississippi PowerBaa3 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 Ba1 from Baa3.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.
On March 24, 2017, S&P revised its consolidated credit rating outlookThe Registrants do not anticipate a material adverse effect on their respective financial statements as a result of counterparty nonperformance.
(K) ACQUISITIONS AND DISPOSITIONS
See Note 15 to the financial statements in Item 8 of the Form 10-K for additional information, including details of assets and liabilities held for sale at December 31, 2019 for Southern Company, Southern Power, and its subsidiaries (including Mississippi Power) from stable to negative.Southern Company Gas. The Registrants had no material assets or liabilities held for sale at June 30, 2020.
Alabama Power
On March 30, 2017, Fitch placedApril 22, 2020 and June 9, 2020, the ratings of Mississippi Power on rating watch negative.
On June 22, 2017, Moody's placedFERC and the ratings of Mississippi Power on review for downgrade. OnAlabama PSC, respectively, approved the Autauga Combined Cycle Acquisition, which is expected to close by September 21, 2017, Moody's revised its rating outlook for Mississippi Power from under review to stable.
Financing Activities
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.
In August 2017, Mississippi Power repaid a $12.5 million short-term bank note.
In September 2017, Mississippi Power issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $150 million bearing interest based on one-month LIBOR. Mississippi Power borrowed $109 million under this promissory note primarily to satisfy its federal income tax obligations for the quarter ending September 30, 2017 and subsequently repaid the promissory note upon receipt of its income tax refund from the U.S. federal government related to the settlement concerning deductible R&E expenditures.2020. See Note (G) to the Condensed Financial Statements(B) under "Section 174 Research and Experimental Deduction" herein"Alabama Power" for additional information.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Mississippi Power plans, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
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, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | |
| Wholesale revenues, non-affiliates | $ | 510 |
| | $ | 387 |
| | $ | 1,293 |
| | $ | 866 |
|
| Wholesale revenues, affiliates | 105 |
| | 110 |
| | 295 |
| | 313 |
|
| Other revenues | 3 |
| | 3 |
| | 9 |
| | 10 |
|
| Total operating revenues | 618 |
| | 500 |
| | 1,597 |
| | 1,189 |
|
| Operating Expenses: | | | | | | | |
| Fuel | 189 |
| | 154 |
| | 460 |
| | 341 |
|
| Purchased power, non-affiliates | 36 |
| | 25 |
| | 90 |
| | 60 |
|
| Purchased power, affiliates | 7 |
| | 8 |
| | 23 |
| | 16 |
|
| Other operations and maintenance | 83 |
| | 81 |
| | 272 |
| | 246 |
|
| Depreciation and amortization | 131 |
| | 93 |
| | 379 |
| | 247 |
|
| Taxes other than income taxes | 13 |
| | 5 |
| | 37 |
| | 17 |
|
| Total operating expenses | 459 |
|
| 366 |
| | 1,261 |
| | 927 |
|
| Operating Income | 159 |
| | 134 |
| | 336 |
| | 262 |
|
| Other Income and (Expense): | | | | | | | |
| Interest expense, net of amounts capitalized | (47 | ) | | (35 | ) | | (144 | ) | | (78 | ) |
| Other income (expense), net | 3 |
| | 2 |
| | 3 |
| | 3 |
|
| Total other income and (expense) | (44 | ) | | (33 | ) | | (141 | ) | | (75 | ) |
| Earnings Before Income Taxes | 115 |
| | 101 |
| | 195 |
| | 187 |
|
| Income taxes (benefit) | (39 | ) | | (102 | ) | | (129 | ) | | (167 | ) |
| Net Income | 154 |
| | 203 |
| | 324 |
| | 354 |
|
| Less: Net income attributable to noncontrolling interests | 30 |
| | 27 |
| | 48 |
| | 39 |
|
| Net Income Attributable to Southern Power | $ | 124 |
| | $ | 176 |
| | $ | 276 |
| | $ | 315 |
|
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) |
| Net Income | $ | 154 |
| | $ | 203 |
| | $ | 324 |
| | $ | 354 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
Changes in fair value, net of tax of
$15, $14, $35, and $(1), respectively | 25 |
| | 23 |
| | 58 |
| | (1 | ) |
Reclassification adjustment for amounts included in net income,
net of tax of $(12), $(1), $(42), and $7, respectively | (20 | ) | | (1 | ) | | (68 | ) | | 13 |
|
| Total other comprehensive income (loss) | 5 |
| | 22 |
| | (10 | ) | | 12 |
|
| Comprehensive Income | 159 |
| | 225 |
| | 314 |
| | 366 |
|
| Less: Comprehensive income attributable to noncontrolling interests | 30 |
| | 27 |
| | 48 |
| | 39 |
|
| Comprehensive Income Attributable to Southern Power | $ | 129 |
| | $ | 198 |
| | $ | 266 |
| | $ | 327 |
|
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, |
| | 2017 | | 2016 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 324 |
| | $ | 354 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 404 |
| | 262 |
|
| Deferred income taxes | 240 |
| | (668 | ) |
| Amortization of investment tax credits | (42 | ) | | (25 | ) |
| Collateral deposits | (1 | ) | | (80 | ) |
| Income taxes receivable, non-current | (42 | ) | | — |
|
| Other, net | (2 | ) | | 19 |
|
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (77 | ) | | (82 | ) |
| -Other current assets | 38 |
| | (15 | ) |
| -Accounts payable | (31 | ) | | 7 |
|
| -Accrued taxes | 79 |
| | 483 |
|
| -Other current liabilities | 5 |
| | 14 |
|
| Net cash provided from operating activities | 895 |
| | 269 |
|
| Investing Activities: | | | |
| Business acquisitions | (1,032 | ) | | (1,134 | ) |
| Property additions | (218 | ) | | (1,702 | ) |
| Change in construction payables | (166 | ) | | (69 | ) |
| Payments pursuant to LTSAs | (99 | ) | | (58 | ) |
| Investment in restricted cash | (16 | ) | | (750 | ) |
| Distribution of restricted cash | 33 |
| | 746 |
|
| Other investing activities | 7 |
| | (41 | ) |
| Net cash used for investing activities | (1,491 | ) | | (3,008 | ) |
| Financing Activities: | | | |
| Increase (decrease) in notes payable, net | (89 | ) | | 692 |
|
| Proceeds — | | | |
| Senior notes | — |
| | 1,531 |
|
| Capital contributions from parent company | — |
| | 800 |
|
| Other long-term debt | 43 |
| | 63 |
|
| Redemptions — Other long-term debt | (4 | ) | | (84 | ) |
| Distributions to noncontrolling interests | (89 | ) | | (22 | ) |
| Capital contributions from noncontrolling interests | 79 |
| | 367 |
|
| Purchase of membership interests from noncontrolling interests | — |
| | (129 | ) |
| Payment of common stock dividends | (238 | ) | | (204 | ) |
| Other financing activities | (27 | ) | | (14 | ) |
| Net cash provided from (used for) financing activities | (325 | ) | | 3,000 |
|
| Net Change in Cash and Cash Equivalents | (921 | ) | | 261 |
|
| Cash and Cash Equivalents at Beginning of Period | 1,099 |
| | 830 |
|
| Cash and Cash Equivalents at End of Period | $ | 178 |
| | $ | 1,091 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
| Interest (net of $7 and $32 capitalized for 2017 and 2016, respectively) | $ | 144 |
| | $ | 49 |
|
| Income taxes, net | (343 | ) | | 71 |
|
| Noncash transactions — Accrued property additions at end of period | 16 |
| | 210 |
|
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, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 178 |
| | $ | 1,099 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 148 |
| | 102 |
|
| Other | | 61 |
| | 34 |
|
| Affiliated | | 74 |
| | 57 |
|
| Fossil fuel stock | | 15 |
| | 15 |
|
| Materials and supplies | | 351 |
| | 337 |
|
| Prepaid income taxes | | 51 |
| | 74 |
|
| Other current assets | | 26 |
| | 39 |
|
| Total current assets | | 904 |
| | 1,757 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 13,734 |
| | 12,728 |
|
| Less: Accumulated provision for depreciation | | 1,823 |
| | 1,484 |
|
| Plant in service, net of depreciation | | 11,911 |
| | 11,244 |
|
| Construction work in progress | | 425 |
| | 398 |
|
| Total property, plant, and equipment | | 12,336 |
| | 11,642 |
|
| Other Property and Investments: | | | | |
Intangible assets, net of amortization of $41 and $22
at September 30, 2017 and December 31, 2016, respectively | | 417 |
| | 436 |
|
| Total other property and investments | | 417 |
| | 436 |
|
| Deferred Charges and Other Assets: | | | | |
| Prepaid LTSAs | | 77 |
| | 101 |
|
| Accumulated deferred income taxes | | 400 |
| | 594 |
|
| Income taxes receivable, non-current | | 53 |
| | 11 |
|
| Other deferred charges and assets — affiliated | | 6 |
| | 13 |
|
| Other deferred charges and assets — non-affiliated | | 455 |
| | 615 |
|
| Total deferred charges and other assets | | 991 |
| | 1,334 |
|
| Total Assets | | $ | 14,648 |
| | $ | 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 September 30, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 864 |
| | $ | 560 |
|
| Notes payable | | 120 |
| | 209 |
|
| Accounts payable — | | | | |
| Affiliated | | 93 |
| | 88 |
|
| Other | | 84 |
| | 278 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 101 |
| | 148 |
|
| Other accrued taxes | | 30 |
| | 7 |
|
| Accrued interest | | 36 |
| | 36 |
|
| Acquisitions payable | | — |
| | 461 |
|
| Contingent consideration | | 15 |
| | 46 |
|
| Other current liabilities | | 58 |
| | 70 |
|
| Total current liabilities | | 1,401 |
| | 1,903 |
|
| Long-term Debt | | 4,946 |
| | 5,068 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 191 |
| | 152 |
|
| Accumulated deferred ITCs | | 1,900 |
| | 1,839 |
|
| Asset retirement obligations | | 76 |
| | 64 |
|
| Other deferred credits and liabilities | | 232 |
| | 304 |
|
| Total deferred credits and other liabilities | | 2,399 |
| | 2,359 |
|
| Total Liabilities | | 8,746 |
| | 9,330 |
|
| Redeemable Noncontrolling Interests | | 59 |
| | 164 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, par value $.01 per share — | | | | |
| Authorized — 1,000,000 shares | | | | |
| Outstanding — 1,000 shares | | — |
| | — |
|
| Paid-in capital | | 3,661 |
| | 3,671 |
|
| Retained earnings | | 762 |
| | 724 |
|
| Accumulated other comprehensive income | | 25 |
| | 35 |
|
| Total common stockholder's equity | | 4,448 |
| | 4,430 |
|
| Noncontrolling interests | | 1,395 |
| | 1,245 |
|
| Total stockholders' equity | | 5,843 |
| | 5,675 |
|
| Total Liabilities and Stockholders' Equity | | $ | 14,648 |
| | $ | 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
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRD QUARTER 2017 vs. THIRD QUARTER 2016
AND
YEAR-TO-DATE 2017 vs. YEAR-TO-DATE 2016
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, and other load-serving entities, as well as commercial and industrial customers. In general, Southern Power has constructed or acquired new generating capacity only after entering into or assuming long-term PPAs for the new facilities.
During the nine months ended September 30, 2017, Southern Power acquired or completed the construction of, and placed in service, approximately 498 MWs of solar and wind facilities. In addition, Southern Power began construction at the recently acquired Cactus Flats wind facility, continued development of its portfolio of wind projects, and continued expansion of the Mankato natural gas facility by 345 MWs of capacity. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information.
Southern Power is considering the sale of up to a one-third equity interest in its solar asset portfolio. The ultimate outcome of this matter cannot be determined at this time.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Southern Power
Asset Acquisitions
During the six months ended June 30, 2017,2020, Southern Power had an average investment coverage ratio of 91% through 2021acquired a controlling interest in the wind facility listed below. Acquisition-related costs were expensed as incurred and 90% through 2026, with an average remaining contract duration of approximately 16 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, including, butwere not limited to, peak season equivalent forced outage rate, contract availability, and net income.
RESULTS OF OPERATIONS
Net Incomematerial.
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(52) | | (29.5) | | $(39) | | (12.4) |
|
| | | | | | | | |
| Project Facility | Resource | Seller | Approximate Nameplate Capacity (MW) | Location | Southern Power Ownership Percentage | COD | PPA Contract Period |
| Beech Ridge II | Wind | Invenergy Renewables LLC | 56 | Greenbrier County, West Virginia | 100% of Class A | (*) | May 2020 | 12 years |
| |
| (*) | In May 2020, Southern Power purchased 100% of the Class A membership interests and now owns the controlling interest in the project, with the Class B member, Invenergy Renewables LLC, owning the noncontrolling interest. |
Net income attributable toIn March 2020, Southern Power for the third quarter 2017 was $124 million comparedentered into an agreement to $176 million for the corresponding periodacquire a controlling membership interest in 2016.an approximately 300-MW wind facility located in South Dakota. The decrease was primarily dueacquisition is subject to decreased income tax benefits from solar ITCsFERC approval and increased interest expense primarily duecertain other customary conditions to a decrease in capitalized interest associated with completing construction of and placing in service solar facilities, partially offset by additional operating income related to new generating facilities.
Net income attributable to Southern Power for year-to-date 2017 was $276 million compared to $315 million for the corresponding period in 2016. The decrease was primarily due to decreased income tax benefits resulting from a reduction in solar ITCs, partially offset by an increase in wind PTCs, and increased interest expense from debt issuances to fund Southern Power's growth strategy and continuous construction program, partially offset by additional operating income from new generating facilities.
For additional information on new generating facilities placed in service during 2016 and 2017, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Acquisitions" and
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
"Construction Projects" of Southern Power in Item 7closing, including commercial operation of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein.
Operating Revenues
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $118 | | 23.6 | | $408 | | 34.3 |
Total operating revenues include PPA capacity revenues,facility, 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 capacity notis expected to occur in late 2020 or early 2021. The facility's output is contracted under a PPA, it may sell power into the wholesale market and, 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 designed to provide recovery of fixed costs plus a return on investment.
Energy 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 energy sales from solar and wind generating facilities are predominantly through2 long-term PPAs that do not have a capacity charge. Customers either purchase the energy output of a dedicated renewable facility through an energy charge or pay a fixed price related to the energy sold to the grid. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, and other factors.
See FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" herein for additional information regarding Southern Power's PPAs.
Details of Southern Power's operating revenues were as follows:
|
| | | | | | | | | | | | | | | |
| | Third Quarter 2017 | | Third Quarter 2016 | | Year-to-Date 2017 | | Year-to-Date 2016 |
| | (in millions) |
| PPA capacity revenues | $ | 169 |
| | $ | 149 |
| | $ | 466 |
| | $ | 406 |
|
| PPA energy revenues | 299 |
| | 247 |
| | 765 |
| | 532 |
|
| Total PPA revenues | 468 |
| | 396 |
| | 1,231 |
| | 938 |
|
| Non-PPA revenues | 147 |
| | 101 |
| | 357 |
| | 241 |
|
| Other revenues | 3 |
| | 3 |
| | 9 |
| | 10 |
|
| Total operating revenues | $ | 618 |
| | $ | 500 |
| | $ | 1,597 |
| | $ | 1,189 |
|
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In the third quarter 2017, total operating revenues were $618 million, reflecting a $118 million, or 24%, increase from the corresponding period in 2016. The increase in operating revenues was primarily due to the following:
PPA capacity revenues increased $20 million, or 13%, primarily due to additional customer capacity requirements and a new PPA related to natural gas facilities.
PPA energy revenues increased $52 million, or 21%, primarily due to a $55 million increase in sales from new solar and wind facilities, partially offset by a $3 million decrease in sales from natural gas PPAs due to a $24 million decrease in volume primarily due to the expiration of a PPA and reduced customer load, partially offset by a $21 million increase in the average cost of fuel.
Non-PPA revenues increased $46 million, or 46%, due to a $58 million increase in the volume of KWHs sold primarily from uncovered natural gas capacity through short-term opportunity sales, offset by a $12 million decrease in the price of energy in the wholesale markets.
For year-to-date 2017, total operating revenues were $1.6 billion, reflecting a $408 million, or 34%, increase from the corresponding period in 2016. The increase in operating revenues was primarily due to the following:
PPA capacity revenues increased $60 million, or 15%, primarily due to additional customer capacity requirements and a new PPA related to natural gas facilities.
PPA energy revenues increased $233 million, or 44%, primarily due to a $188 million increase in sales from new solar and wind facilities and a $35 million increase in sales from natural gas PPAs primarily due to a $69 million increase in the average cost of fuel, partially offset by a $34 million decrease in volume primarily due to the expiration of a PPA and reduced customer load.
Non-PPA revenues increased $116 million, or 48%, due to a $104 million increase in the volume of KWHs sold primarily from uncovered natural gas capacity through short-term opportunity sales, as well as a $12 million increase in the price of energy in the wholesale markets.
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. Details of Southern Power's generation and purchased power were as follows:
|
| | | | | |
| | Third Quarter 2017 | Third Quarter 2016 | | Year-to-Date 2017 | Year-to-Date 2016 |
| | (in billions of KWHs) |
| Generation | 12.5 | 11.1 | | 33.2 | 27.9 |
| Purchased power | 1.2 | 0.9 | | 3.4 | 2.5 |
| Total generation and purchased power | 13.7 | 12.0 | | 36.6 | 30.4 |
| | | | | | |
| Total generation and purchased power, excluding solar, wind, and tolling agreements | 7.2 | 6.7 | | 17.8 | 17.7 |
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.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Purchased power expenses will vary depending on demand, availability, and the cost of generating resources throughout the Southern Company system and other contract resources. Load requirements are submitted to the power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power, an affiliate company, or external parties. Such purchased power costs are generally recovered through PPA revenues.
Details of Southern Power's fuel and purchased power expenses were as follows:
|
| | | | | | | | | | | |
| | Third Quarter 2017
vs.
Third Quarter 2016 | | Year-to-Date 2017
vs.
Year-to-Date 2016 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | 35 |
| | 22.7 | | $ | 119 |
| | 34.9 |
| Purchased power | 10 |
| | 30.3 | | 37 |
| | 48.7 |
| Total fuel and purchased power expenses | $ | 45 |
| | | | $ | 156 |
| | |
In the third quarter 2017, total fuel and purchased power expenses increased $45 million, or 24.1%, compared to the corresponding period in 2016. Fuel expense increased $35 million primarily due to a $29 million increase in the average cost of natural gas per KWH generated and an $8 million increase in the volume of KWHs generated, excluding solar, wind, and tolling agreements. Purchased power expense increased $10 million primarily due to an increase in the volume of KWHs purchased.
For year-to-date 2017, total fuel and purchased power expenses increased $156 million, or 37.4%, compared to the corresponding period in 2016. Fuel expense increased $119 million primarily due to a $139 million increase in the average cost of natural gas per KWH generated, partially offset by a $19 million decrease in the volume of KWHs generated, excluding solar, wind, and tolling agreements. Purchased power expense increased $37 million due to a $28 million increase in the volume of KWHs purchased and a $9 million increase associated with the average cost of purchased power.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $2 | | 2.5 | | $26 | | 10.6 |
In the third quarter 2017, other operations and maintenance expenses were $83 million compared to $81 million for the corresponding period in 2016. The increase was primarily due to a $13 million increase associated with new solar, wind, and gas facilities, partially offset by a $5 million decrease in scheduled outage maintenance expenses and a $5 million decrease in non-outage operations and maintenance expenses.
For year-to-date 2017, other operations and maintenance expenses were $272 million compared to $246 million for the corresponding period in 2016. The increase was primarily due to a $48 million increase associated with new solar, wind, and gas facilities and an $8 million increase associated with employee compensation and expenses in support of Southern Power's overall growth strategy, partially offset by a $22 million decrease in scheduled outage maintenance expenses and an $8 million decrease in non-outage operations and maintenance expenses.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Depreciation and Amortization
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $38 | | 40.9 | | $132 | | 53.4 |
In the third quarter 2017, depreciation and amortization was $131 million compared to $93 million for the corresponding period in 2016. For year-to-date 2017, depreciation and amortization was $379 million compared to $247 million for the corresponding period in 2016. The increases were primarily due to new solar, wind, and gas facilities placed in service.
Taxes Other Than Income Taxes
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $8 | | 160.0 | | $20 | | 117.6 |
In the third quarter 2017, taxes other than income taxes were $13 million compared to $5 million for the corresponding period in 2016. For year-to-date 2017, taxes other than income taxes were $37 million compared to $17 million for the corresponding period in 2016. These increases were primarily due to additional property taxes due to new solar, wind, and gas facilities.
Interest Expense, net of Amounts Capitalized
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $12 | | 34.3 | | $66 | | 84.6 |
In the third quarter 2017, interest expense, net of amounts capitalized was $47 million compared to $35 million for the corresponding period in 2016. The increase was primarily due to an $8 million decrease in capitalized interest associated with completing construction of and placing in service solar facilities and an increase of $3 million in interest expense due to an increase in average outstanding long-term debt, primarily to fund Southern Power's growth strategy and continuous construction program.
For year-to-date 2017, interest expense, net of amounts capitalized was $144 million compared to $78 million for the corresponding period in 2016. The increase was primarily due to an increase of $39 million in interest expense due to an increase in average outstanding long-term debt, primarily to fund Southern Power's growth strategy and continuous construction program, as well as a $25 million decrease in capitalized interest associated with completing construction of and placing in service solar facilities.
Other Income (Expense), Net
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1 | | 50.0 | | $— | | — |
In the third quarter 2017, other income (expense), net was $3 million compared to $2 million for the corresponding period in 2016. Other income (expense), net was $3 million for both year-to-date 2017 and 2016. The changes include increases of $36 million and $152 million from currency losses arising from translation of €1.1 billion euro-denominated fixed-rate notes into U.S. dollars for the third 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.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Income Taxes (Benefit)
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $63 | | 61.8 | | $38 | | 22.8 |
In the third quarter 2017, income tax benefit was $39 million compared to $102 million for the corresponding period in 2016. The decrease was primarily due to a $61 million decrease in income tax benefits from solar ITCs.
For year-to-date 2017, income tax benefit was $129 million compared to $167 million for the corresponding period in 2016. The decrease was primarily due to a $102 million decrease in income tax benefits from solar ITCs, partially offset by a $58 million increase in wind PTCs and a $4 million increase resulting from state apportionment rate changes.
See Note (G) to the Condensed Financial Statements herein for additional 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 and PTCs.
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. 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 Power's consolidated financial statements.
Southern Power is considering the sale of up to a one-third equity interest in its solar asset portfolio. The ultimate outcome of this matter cannot be determined at this time.
Demand for electricity is primarily driven by the pace of economic growth that 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 facilities 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 September 30, 2017, Southern Power's average investment coverage ratio for its generating assets, based on the ratio of investment under contract to total investment using the respective generation facilities' net book value (or expected in-service value for facilities under construction) as the investment amount, was 91% through 2021 and 90% through 2026, with an average remaining contract duration of approximately 16 years.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Southern Power in Item 7 of the Form 10-K for additional information regarding the final effluent guidelines rule.
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 September 18, 2017, the EPA published a final rule establishing a stay of the compliance deadlines for certain effluent limitations and pretreatment standards under the rule.
The ultimate outcome of this matter 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 October 16, 2017, the EPA published a proposed rule to repeal the Clean Power Plan. The EPA has not determined whether or when it will promulgate a replacement rule.
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 related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' and Southern Power's June 30, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
order, or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and Southern Power expect to make a filing within the specified 60 days responding to the FERC's order.
The ultimate outcome of these matters cannot be determined at this time.
Acquisitions
During the nine months ended September 30, 2017, in accordance with Southern Power's overall growth strategy, one of Southern Power's wholly-owned subsidiaries acquired the project discussed below. Acquisition-related costs were expensed as incurred and were not material. See Note (I) to the Condensed Financial Statements under "Southern Power" herein 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.
|
| | | | | | | | | |
| 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 recognized by Southern Power related to the Bethel facility included in Southern Power's 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 as though the acquisition occurred as of the beginning of 2017 and for the comparable 2016 period is not meaningful and has been omitted.
Subsequent to September 30, 2017, Southern Power purchased all of the redeemable noncontrolling interests, representing 10% of the membership interests, in Southern Turner Renewable Energy, LLC and repaid $14 million of notes payable to Turner Renewable Energy, LLC.
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, 2017, in accordance with its overall growth strategy,2020, Southern Power completed construction of and placed in service orthe Reading wind facility, continued construction of the projects set forth inSkookumchuck wind facility, and commenced construction of the following table. Through SeptemberGarland and Tranquillity battery energy storage facilities. Total aggregate construction costs, excluding acquisition costs, are expected to be between $475 million and $545 million for the facilities under construction. At June 30, 2017,2020, total costs of construction incurred for these projects were $494 million, of which $122 million remained in CWIP. Total aggregate construction costs, excluding the acquisition costs, are expected to be between $360$232 million and $415 million for the Mankato and Cactus Flats facilities.are included in CWIP. The ultimate outcome of these matters cannot be determined at this time.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
| | | | | | |
| Project Facility | Resource | Approximate Nameplate Capacity (MW) | Location | Actual/Expected COD | PPA Counterparties | PPA Contract Period |
Projects Completed During the NineSix Months Ended SeptemberJune 30, 20172020 |
East PecosReading(a) | SolarWind | 120200 | Pecos County, TXOsage and Lyon Counties, KS | March 2017May 2020 | Austin Energy | 1512 years |
Lamesa | Solar | 102 | Dawson County, TX | April 2017 | City of Garland, Texas | 15 years |
| | | | | | |
Projects Under Construction as of SeptemberJune 30, 20172020 |
Cactus FlatsSkookumchuck(*)(b)
| Wind | 148136 | Concho County, TXLewis and Thurston Counties, WA | ThirdFourth quarter 20182020 | General Motors, LLC
and
General Mills Operations, LLC | 12 years
and
1520 years |
MankatoGarland Solar Storage(c) | Natural GasBattery energy storage system | 34588 | Mankato, MNKern County, CA | Second quarter 20192021 | Northern States Power Company20 years |
Tranquillity Solar Storage(c) | Battery energy storage system | 72 | Fresno County, CA | Second quarter 2021 | 20 years |
| |
| (a) | In 2018, Southern Power purchased 100% of the membership interests of the Reading facility pursuant to a joint development arrangement. At the time the facility was placed in service, Southern Power recorded an operating lease right-of-use asset and an operating lease liability, each in the amount of $24 million. In June 2020, Southern Power completed a tax equity transaction whereby it received $156 million and now owns 100% of the Class B membership interests. |
| |
| (b) | In October 2019, Southern Power purchased 100% of the membership interests of the Skookumchuck facility pursuant to a joint development arrangement. Southern Power expects to complete a tax equity transaction upon commercial operation and retain the Class B membership interests. Shortly after commercial operation, Southern Power may sell a noncontrolling interest in these Class B membership interests to another partner. The ultimate outcome of these matters cannot be determined at this time. |
| |
| (c) | Prior to commercial operation, Southern Power may enter into one or more partnerships, in which case it would ultimately own less than 100% of the Class B membership interests, but would retain ownership of the controlling interest. The PPAs for these facilities are pending approval from the California Public Utilities Commission. The ultimate outcome of these matters cannot be determined at this time. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Development Projects
Southern Power continues to evaluate and refine the deployment of the remaining wind turbine equipment purchased in 2016 and 2017 to development and construction projects. During the six months ended June 30, 2020, certain wind turbine equipment was sold, resulting in an immaterial gain.
Sales of Natural Gas and Biomass Plants
On January 17, 2020, Southern Power completed the sale of its equity interests in Plant Mankato (including the 385-MW expansion unit completed in May 2019) to a subsidiary of Xcel for a purchase price of approximately $663 million, including final working capital adjustments. The sale resulted in a gain of approximately $39 million ($23 million after tax). The assets and liabilities of Plant Mankato were classified as held for sale on Southern Company's and Southern Power's balance sheets at December 31, 2019.
Plants Nacogdoches (sold in June 2019) and Mankato represented individually significant components of Southern Power; therefore, pre-tax income for these components for the three months ended June 30, 2019 and the six months ended June 30, 2020 and 2019 is presented below:
|
| | | | | | | | | |
| | Three Months Ended June 30, 2019 | Six Months Ended June 30, |
| | 2020 | 2019 |
| | (in millions) |
Southern Power's earnings before income taxes:(*) | | | |
| Plant Nacogdoches | $ | 9 |
| N/A |
| $ | 16 |
|
| Plant Mankato | $ | 6 |
| $ | 2 |
| $ | 8 |
|
| |
| (*) | On July 31, 2017, Southern Power acquired a 100% ownership interestEarnings before income taxes for components reflect the cessation of depreciation and amortization on the long-lived assets being sold upon classification as held for sale in the Cactus Flats facility, which is in the early stages of construction, from RES America Developments, Inc.November 2018 and April 2019 for Plant Mankato and Plant Nacogdoches, respectively. |
Development Projects
In December 2016, as part of Southern Power's renewable development strategy, one of Southern Power's wholly-owned subsidiaries 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 MattersSouthern Company Gas
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters"On March 24, 2020, Southern Company Gas completed the sale of Southern Power in Item 7 of the Form 10-K and Note (G) to the Condensed Financial Statements herein for additional information.
During the third quarter 2017, Southern Power began a legal entity reorganization of various direct and indirect subsidiaries that own and operate solar facilities, including certain subsidiaries owned in partnership with various third parties. Southern Power's ownershipits interests in Pivotal LNG and Atlantic Coast Pipeline to Dominion Modular LNG Holdings, Inc. and Dominion Atlantic Coast Pipeline, LLC, respectively, with aggregate proceeds of $178 million, including working capital adjustments. The preliminary loss associated with the various solar entities and facilities will not be affected by the reorganization. The reorganization is expected to result in estimated tax benefits totaling approximately $40transactions was immaterial. Southern Company Gas may also receive 2 future payments of $5 million that will be recorded in the fourth quarter 2017each, contingent upon certain milestones related to certain changes in state apportionment ratesPivotal LNG being met by Dominion Modular LNG Holdings, Inc. The assets and net operating loss carryforward utilization. The ultimate outcomeliabilities 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 healthPivotal LNG and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
herein, 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 wasAtlantic Coast Pipeline were classified as held for sale at December 31, 2019. See Notes 3 and 7 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 counter lawsuit against Roserock, Array Technologies, Inc., Canadian Solar (USA), Inc., XL, and North American Elite in the U.S. District Court for the Western District of Texas alleging, among other things, breach of contract, and requesting foreclosure of mechanic's liens against Roserock. On July 18, 2017, the U.S. District Court for the Western District of Texas consolidated the two pending lawsuits. Southern Power intends to vigorously pursue and defend these matters, the ultimate outcome of which cannot be determined at this time.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
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, and ITCs.
Recently Issued Accounting Standards
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Southern Power in Item 7 of the Form 10-K for additional information.
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 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. However, given Southern Power's core activities of selling generation capacity and energy to high credit rated customers, Southern Power currently does not expect the new standard to have a significant impact to net income. Southern Power's ongoing evaluation of revenue streams and
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with early adoption permitted. Southern Power is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on Southern Power's financial statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Power in Item 7 of the Form 10-K for additional information. Southern Power's financial condition remained stable at September 30, 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.
Southern Power anticipates utilizing third-party tax equity as one of the financing sources to fund its renewable growth strategy; however, the use of third-party tax equity structures is not expected to have a material impact on future earnings. Subsequent to September 30, 2017, Southern Power secured third-party tax equity funding for the recently acquired Cactus Flats project subject to achieving commercial operation and various other customary conditions to closing. The ultimate outcome of this matter cannot be determined at this time.
Net cash provided from operating activities totaled $895 million for the first nine months of 2017 compared to $269 million for the first nine months of 2016. The increase in net cash provided from operating activities was primarily due to income tax refunds received and an increase in energy sales arising from new solar and wind facilities, partially offset by an increase in interest paid. See FUTURE EARNINGS POTENTIAL – "Income Tax"Other Matters – Bonus Depreciation" of Southern Power in Item 7 of the Form 10-K for additional information. Net cash used for investing activities totaled $1.5 billion for the first nine months of 2017 primarily due to payments for renewable acquisitionsCompany Gas – Gas Pipeline Projects" and the construction of generating facilities. Net cash used for financing activities totaled $325 million for the first nine months of 2017 primarily due to common stock dividend payments, a decrease in notes payable, and distributions to noncontrolling interests, partially offset by capital contributions from 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 nine months of 2017 include a $1.0 billion increase in property, plant,
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
and equipment in-service primarily related to acquisitions and completing construction of and placing in service solar facilities, a $921 million decrease in cash and cash equivalents, and a $461 million decrease in acquisitions payable.
See FUTURE EARNINGS POTENTIAL "Southern Company Gas – "AcquisitionsEquity Method Investments," 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 commitments. Approximately $864 million will be required to repay maturities of long-term debt through September 30, 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. 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, debt maturities, and other purposes 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 September 30, 2017, Southern Power's current liabilities exceeded current assets by $497 million due to long-term debt maturing in the next 12 months, the use of short-term debt as a funding source, and fluctuations in cash needs, due to both seasonality and the stage of acquisitions and construction projects. 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, the debt capital markets, and operating cash flows.
As of September 30, 2017, Southern Power had cash and cash equivalents of approximately $178 million.
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 September 30, 2017.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of commercial paper were as follows:
|
| | | | | | | | | | | | | | | | |
| | Short-term Debt at September 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 | $ | 120 |
| 1.5 | % | | $ | 322 |
| | 1.5 | % | | $ | 416 |
|
| |
(*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2017. |
At September 30, 2017, Southern Power had a committed credit facility (Facility) of $750 million, of which $22 million has been used for letters of credit and $728 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 borrowing ability under this Facility to $750 million from $600 million. Proceeds from the Facility may be used for working capital and general corporate purposes as well as liquidity support for Southern Power's commercial paper program. Subject to applicable market conditions, Southern Power expects to renew or replace the Facility, as needed, prior to expiration. In connection therewith, Southern Power may extend the maturity date and/or increase or decrease the lending commitment thereunder. See Note 6 to the financial statements of Southern Power under "Bank Credit Arrangements"respectively, in Item 8 of the Form 10-K and NoteNotes (C) and (E) to the Condensed Financial Statements under "Bank Credit ArrangementsOther Matters – Southern Company Gas" and "Southern Company Gas," herein for additional information.respectively.
(L) SEGMENT AND RELATED INFORMATION
Southern Company
The Facility, as well asprimary businesses of the Southern Power's term loan agreement, contains a covenant that limitsCompany system are electricity sales by the ratiotraditional electric operating companies and Southern Power and the distribution of debt to capitalization (as definednatural gas by Southern Company Gas. The traditional electric operating companies – Alabama Power, Georgia Power, and Mississippi Power – are vertically integrated utilities providing electric service in 3 Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the Facility)wholesale market. Southern Company Gas distributes natural gas through its natural gas distribution utilities and is involved in several other complementary businesses including gas pipeline investments, wholesale gas services, and gas marketing services.
Southern Company's reportable business segments are the sale of electricity by the traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
gas and contains a cross-default provision that is restricted only to indebtedness ofother complementary products and services by Southern Power. For purposes of this definition, debt excludes any project debt incurredCompany Gas. Revenues from sales by certain subsidiaries of Southern Power to the extent such debt is non-recoursetraditional electric operating companies were $92 million and $178 million for the three and six months ended June 30, 2020, respectively, and $117 million and $204 million for the three and six months ended June 30, 2019, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies were immaterial for all periods presented. Revenues from sales of natural gas from Southern Company Gas to Southern Power were $3 million and capitalization excludes$13 million for the capital stock or other equity attributablethree and six months ended June 30, 2020, respectively, and $16 million and $33 million for the three and six months ended June 30, 2019, respectively. The "All Other" column includes the Southern Company parent entity, which does not allocate operating expenses to such subsidiary. Southern Power is currently in compliance with all covenantsbusiness segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include providing energy solutions to electric utilities and their customers in the Facility.
Southern Power also has a $120 million continuing letterareas of credit facility for standby letters of credit expiringdistributed generation, energy storage and renewables, and energy efficiency, as well as investments in 2019. At September 30, 2017, $111 million has been used for letters of credittelecommunications and $9 million remains unused.
Southern Power's subsidiaries do not borrow under the commercial paper program andleveraged lease projects. All other inter-segment revenues are not parties to, and do not borrow under, the Facility or the continuing letter of credit facility.
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, and transmission.
material.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OFNOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(UNAUDITED)
The maximum potential collateral requirements under these contracts at SeptemberFinancial data for business segments and products and services for the three and six months ended June 30, 2017 were2020 and 2019 was as follows:
|
| | | |
| Credit Ratings | Maximum Potential
Collateral
Requirements |
| | (in millions) |
| At BBB and/or Baa2 | $ | 37 |
|
| At BBB- and/or Baa3 | $ | 398 |
|
At BB+ and/or Ba1(*) | $ | 1,124 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Electric Utilities | | | | |
| | Traditional Electric Operating Companies | Southern Power | Eliminations | Total | Southern Company Gas | All Other | Eliminations | Consolidated |
| | (in millions) |
| Three Months Ended June 30, 2020 | | | | | | | |
| Operating revenues | $ | 3,539 |
| $ | 439 |
| $ | (94 | ) | $ | 3,884 |
| $ | 636 |
| $ | 135 |
| $ | (35 | ) | $ | 4,620 |
|
Segment net income (loss)(a)(b)(c) | 645 |
| 63 |
| — |
| 708 |
| 71 |
| (177 | ) | 10 |
| 612 |
|
| Six Months Ended June 30, 2020 | | | |
|
| | | |
| Operating revenues | $ | 6,946 |
| $ | 814 |
| $ | (181 | ) | $ | 7,579 |
| $ | 1,885 |
| $ | 248 |
| $ | (74 | ) | $ | 9,638 |
|
Segment net income (loss)(a)(b)(c)(d) | 1,287 |
| 138 |
| — |
| 1,425 |
| 346 |
| (299 | ) | 8 |
| 1,480 |
|
| At June 30, 2020 | | | | | | | | |
| Goodwill | $ | — |
| $ | 2 |
| $ | — |
| $ | 2 |
| $ | 5,015 |
| $ | 263 |
| $ | — |
| $ | 5,280 |
|
| Total assets | 83,158 |
| 13,557 |
| (713 | ) | 96,002 |
| 21,500 |
| 3,325 |
| (1,096 | ) | 119,731 |
|
| Three Months Ended June 30, 2019 | | | | | | | |
| Operating revenues | $ | 3,899 |
| $ | 510 |
| $ | (119 | ) | $ | 4,290 |
| $ | 689 |
| $ | 186 |
| $ | (67 | ) | $ | 5,098 |
|
Segment net income (loss)(a)(e)(f) | 782 |
| 174 |
| — |
| 956 |
| 106 |
| (154 | ) | (9 | ) | 899 |
|
| Six Months Ended June 30, 2019 | | | | | | | |
| Operating revenues | $ | 7,343 |
| $ | 953 |
| $ | (211 | ) | $ | 8,085 |
| $ | 2,163 |
| $ | 368 |
| $ | (106 | ) | $ | 10,510 |
|
Segment net income (loss)(a)(e)(f) | 1,346 |
| 230 |
| — |
| 1,576 |
| 376 |
| 1,041 |
| (11 | ) | 2,982 |
|
| At December 31, 2019 | | | | | | | | |
| Goodwill | $ | — |
| $ | 2 |
| $ | — |
| $ | 2 |
| $ | 5,015 |
| $ | 263 |
| $ | — |
| $ | 5,280 |
|
| Total assets | 81,063 |
| 14,300 |
| (713 | ) | 94,650 |
| 21,687 |
| 3,511 |
| (1,148 | ) | 118,700 |
|
| |
| (a) | Attributable to Southern Company. |
| |
| (b) | Segment net income (loss) for the traditional electric operating companies includes a pre-tax charge of $149 million ($111 million after tax) related to Plant Vogtle Units 3 and 4 for the three and six months ended June 30, 2020. See Note (B) under "Georgia Power – Nuclear Construction" for additional information. |
| |
| (c) | Segment net income (loss) for the "All Other" column includes a pre-tax impairment charge of $154 million ($74 million after tax) related to a leveraged lease investment for the three and six months ended June 30, 2020. See Note (C) under "Other Matters – Southern Company" for additional information. |
| |
| (d) | Segment net income (loss) for Southern Power includes a $39 million pre-tax gain ($23 million gain after tax) on the sale of Plant Mankato for the six months ended June 30, 2020. See Note (K) under "Southern Power" for additional information. |
| |
| (e) | Segment net income (loss) for the "All Other" column includes the preliminary pre-tax gain associated with the sale of Gulf Power of $2.5 billion ($1.3 billion after tax) for the six months ended June 30, 2019, of which $(15) million ($(11) million after tax) was recorded in the three months ended June 30, 2019, as well as a goodwill impairment charge of $32 million for the three and six months ended June 30, 2019 in contemplation of the sale of 1 of PowerSecure's business units. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company" for additional information. |
| |
| (f) | Segment net income (loss) for Southern Power includes a $23 million pre-tax gain ($88 million gain after tax) on the sale of Plant Nacogdoches for the three and six months ended June 30, 2019. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power – Sale of Natural Gas and Biomass Plants" for additional information. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Products and Services
|
| | | | | | | | | | | | |
| | Electric Utilities' Revenues |
| | Retail | Wholesale | Other | Total |
| | (in millions) |
| Three Months Ended June 30, 2020 | $ | 3,182 |
| $ | 472 |
| $ | 230 |
| $ | 3,884 |
|
| Three Months Ended June 30, 2019 | 3,540 |
| 542 |
| 208 |
| 4,290 |
|
| Six Months Ended June 30, 2020 | $ | 6,260 |
| $ | 889 |
| $ | 430 |
| $ | 7,579 |
|
| Six Months Ended June 30, 2019 | 6,623 |
| 1,041 |
| 421 |
| 8,085 |
|
|
| | | | | | | | | | | | | | | |
| | Southern Company Gas' Revenues |
| | Gas
Distribution
Operations | Wholesale Gas Services(*) | Gas
Marketing
Services | Other | Total |
| | (in millions) |
| Three Months Ended June 30, 2020 | $ | 583 |
| $ | (19 | ) | $ | 56 |
| $ | 16 |
| $ | 636 |
|
| Three Months Ended June 30, 2019 | 563 |
| 48 |
| 58 |
| 20 |
| 689 |
|
| Six Months Ended June 30, 2020 | $ | 1,596 |
| $ | 32 |
| $ | 233 |
| $ | 24 |
| $ | 1,885 |
|
| Six Months Ended June 30, 2019 | 1,724 |
| 134 |
| 287 |
| 18 |
| 2,163 |
|
| |
| (*) | AnyThe revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. See "Southern Company Gas" herein for additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $38 million.information. |
Southern Company Gas
Southern Company Gas manages its business through 4 reportable segments – gas distribution operations, gas pipeline investments, wholesale gas services, and gas marketing services. 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 these amounts are certain agreements that could require collateral4 states.
Gas pipeline investments consists of joint ventures in natural gas pipeline investments including a 50% interest in SNG, a 20% ownership interest in the event that Alabama Power or Georgia Power hasPennEast Pipeline construction project, a credit rating change50% joint ownership interest in the Dalton Pipeline, and a 5% ownership interest in the Atlantic Coast Pipeline construction project through its sale on March 24, 2020. These natural gas pipelines enable the provision of diverse sources of natural gas supplies to below investment grade. Generally, collateral may be provided by athe customers of Southern Company guaranty, letter of credit, Gas.
Wholesale gas services provides natural gas asset management and/or cash. Additionally, a credit rating downgrade could impact the abilityrelated logistics services for each of Southern PowerCompany 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 marketing services provides natural gas marketing to access capital marketsend-use customers primarily in Georgia and would be likely to impactIllinois through SouthStar.
The all other column includes segments below the cost at which it does so.
In addition, Southern Power has a PPA that could require collateral, but not accelerated payment, inquantitative threshold for separate disclosure, including natural gas storage businesses, fuels operations through the event of a downgradesale 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.
OnCompany Gas' interest in Pivotal LNG on March 24, 2017, S&P revised2020, the investment in Triton through its consolidated credit rating outlooksale on May 29, 2019, and other subsidiaries that fall below the quantitative threshold for separate disclosure. See Notes (E) and (K) under "Southern Company Gas" for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Business segment financial data for the three and its subsidiaries (including Southern Power) from stable to negative.six months ended June 30, 2020 and 2019 was as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Gas Distribution Operations | Gas Pipeline Investments | Wholesale Gas Services(*) | Gas Marketing Services | Total | All Other | Eliminations | Consolidated |
| | (in millions) |
| Three Months Ended June 30, 2020 | | | | | | |
| Operating revenues | $ | 587 |
| $ | 8 |
| $ | (19 | ) | $ | 56 |
| $ | 632 |
| $ | 8 |
| $ | (4 | ) | $ | 636 |
|
| Segment net income (loss) | 74 |
| 21 |
| (23 | ) | 5 |
| 77 |
| (6 | ) | — |
| 71 |
|
| Six Months Ended June 30, 2020 | | | | | | |
| Operating revenues | $ | 1,607 |
| $ | 16 |
| $ | 32 |
| $ | 233 |
| $ | 1,888 |
| $ | 16 |
| $ | (19 | ) | $ | 1,885 |
|
| Segment net income (loss) | 238 |
| 51 |
| — |
| 62 |
| 351 |
| (5 | ) | — |
| 346 |
|
| Total assets at June 30, 2020 | 18,276 |
| 1,617 |
| 637 |
| 1,480 |
| 22,010 |
| 10,645 |
| (11,155 | ) | 21,500 |
|
| Three Months Ended June 30, 2019 | | | | | | |
| Operating revenues | $ | 568 |
| $ | 8 |
| $ | 48 |
| $ | 58 |
| $ | 682 |
| $ | 13 |
| $ | (6 | ) | $ | 689 |
|
| Segment net income (loss) | 58 |
| 25 |
| 23 |
| (3 | ) | 103 |
| 3 |
| — |
| 106 |
|
| Six Months Ended June 30, 2019 | | | | | | | |
| Operating revenues | $ | 1,740 |
| $ | 16 |
| $ | 134 |
| $ | 287 |
| $ | 2,177 |
| $ | 24 |
| $ | (38 | ) | $ | 2,163 |
|
| Segment net income (loss) | 191 |
| 57 |
| 70 |
| 58 |
| 376 |
| — |
| — |
| 376 |
|
| Total assets at December 31, 2019 | 18,204 |
| 1,678 |
| 850 |
| 1,496 |
| 22,228 |
| 10,759 |
| (11,300 | ) | 21,687 |
|
| |
| (*) | 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) |
| Three Months Ended June 30, 2020 | $ | 854 |
| $ | 18 |
| $ | 872 |
| $ | 891 |
| $ | (19 | ) |
| Three Months Ended June 30, 2019 | 1,223 |
| 63 |
| 1,286 |
| 1,238 |
| 48 |
|
| Six Months Ended June 30, 2020 | $ | 2,039 |
| $ | 47 |
| $ | 2,086 |
| $ | 2,054 |
| $ | 32 |
|
| Six Months Ended June 30, 2019 | 3,148 |
| 151 |
| 3,299 |
| 3,165 |
| 134 |
|
In September 2017, Southern Power amended its $60 million aggregate principal amount floating rate bank loan to, among other things, increase the aggregate principal amount to $100 million
Item 2. Management's Discussion and extend the maturity date from September 2017 to October 2018. The additional $40 millionAnalysis of proceeds were used to repay existing indebtednessFinancial Condition and for other general corporate purposes.
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
AND SUBSIDIARY COMPANIES
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Results of Operations.
|
| | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | For the Three Months Ended September 30, | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | | July 1, 2016 through September 30, | | | January 1, 2016 through
June 30, |
| | 2017 | | 2016 | | 2017 | | 2016 | | | 2016 |
| | (in millions) | | | (in millions) |
| Operating Revenues: | | | | | | | | | | |
Natural gas revenues (includes revenue
taxes of $9, $9, $75, $9, and $57 for the
periods presented, respectively) | $ | 532 |
| | $ | 518 |
| | $ | 2,746 |
| | $ | 518 |
| | | $ | 1,841 |
|
| Other revenues | 33 |
| | 25 |
| | 95 |
| | 25 |
| | | 64 |
|
| Total operating revenues | 565 |
| | 543 |
| | 2,841 |
| | 543 |
| | | 1,905 |
|
| Operating Expenses: | | | | | | | | | | |
| Cost of natural gas | 134 |
| | 133 |
| | 1,085 |
| | 133 |
| | | 755 |
|
| Cost of other sales | 7 |
| | 2 |
| | 20 |
| | 2 |
| | | 14 |
|
| Other operations and maintenance | 205 |
| | 216 |
| | 671 |
| | 216 |
| | | 454 |
|
| Depreciation and amortization | 125 |
| | 116 |
| | 370 |
| | 116 |
| | | 206 |
|
| Taxes other than income taxes | 26 |
| | 29 |
| | 140 |
| | 29 |
| | | 99 |
|
| Merger-related expenses | — |
| | 35 |
| | — |
| | 35 |
| | | 56 |
|
| Total operating expenses | 497 |
| | 531 |
| | 2,286 |
| | 531 |
| | | 1,584 |
|
| Operating Income | 68 |
| | 12 |
| | 555 |
| | 12 |
| | | 321 |
|
| Other Income and (Expense): | | | | | | | | | | |
| Earnings from equity method investments | 32 |
| | 29 |
| | 100 |
| | 29 |
| | | 2 |
|
| Interest expense, net of amounts capitalized | (51 | ) | | (39 | ) | | (145 | ) | | (39 | ) | | | (96 | ) |
| Other income (expense), net | 18 |
| | 9 |
| | 26 |
| | 9 |
| | | 5 |
|
| Total other income and (expense) | (1 | ) | | (1 | ) | | (19 | ) | | (1 | ) | | | (89 | ) |
| Earnings Before Income Taxes | 67 |
| | 11 |
| | 536 |
| | 11 |
| | | 232 |
|
| Income taxes | 52 |
| | 7 |
| | 233 |
| | 7 |
| | | 87 |
|
| Net Income | 15 |
| | 4 |
| | 303 |
| | 4 |
| | | 145 |
|
Less: Net income attributable to
noncontrolling interest | — |
| | — |
| | — |
| | — |
| | | 14 |
|
Net Income Attributable to
Southern Company Gas | $ | 15 |
| | $ | 4 |
| | $ | 303 |
| | $ | 4 |
| | | $ | 131 |
|
|
| |
| Page |
| Combined Management's Discussion and Analysis of Financial Condition and Results of Operations | |
| |
| |
| |
| |
| |
| |
| |
| |
| |
| |
| |
The accompanying notesfollowing Management's Discussion and Analysis of Financial Condition and Results of Operations is a combined presentation; however, information contained herein relating to any individual Registrant is filed by such Registrant on its own behalf and each Registrant makes no representation 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 |
| | For the Three Months Ended September 30, | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | | July 1, 2016 through September 30, | | | January 1, 2016 through
June 30, |
| | 2017 | | 2016 | | 2017 | | 2016 | | | 2016 |
| | (in millions) | | | (in millions) |
| Net Income | $ | 15 |
| | $ | 4 |
| | $ | 303 |
| | $ | 4 |
| | | $ | 145 |
|
| Other comprehensive income (loss): | | | | | | | | | | |
| Qualifying hedges: | | | | | | | | | | |
Changes in fair value, net of tax of
$-, $(2), $(2), $(2), and $(23),
respectively | — |
| | (3 | ) | | (3 | ) | | (3 | ) | | | (41 | ) |
Reclassification adjustment for
amounts included in net income,
net of tax of $-, $-, $-, $-, and $-,
respectively | — |
| | — |
| | — |
| | — |
| | | 1 |
|
Pension and other postretirement
benefit plans: | | | | | | | | | | |
Reclassification adjustment for
amounts included in net income,
net of tax of $-, $-, $(1), $-, and $4,
respectively | — |
| | — |
| | — |
| | — |
| | | 5 |
|
| Total other comprehensive income (loss) | — |
| | (3 | ) | | (3 | ) | | (3 | ) | | | (35 | ) |
| Comprehensive Income | 15 |
| | 1 |
| | 300 |
| | 1 |
| | | 110 |
|
Less: Comprehensive income attributable to
noncontrolling interest | — |
| | — |
| | — |
| | — |
| | | 14 |
|
Comprehensive Income Attributable to
Southern Company Gas | $ | 15 |
| | $ | 1 |
| | $ | 300 |
| | $ | 1 |
| | | $ | 96 |
|
The accompanying notes as they relateinformation related to Southern Company Gas are an integral part of these condensed consolidated financial statements.the other Registrants.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | For the Nine Months Ended September 30, | | July 1, 2016 through September 30, | | | January 1, 2016 through
June 30, |
| | 2017 | | 2016 | | | 2016 |
| | (in millions) | | | (in millions) |
| Operating Activities: | | | | | | |
| Net income | $ | 303 |
| | $ | 4 |
| | | $ | 145 |
|
Adjustments to reconcile net income
to net cash provided from operating activities — | | | | | | |
| Depreciation and amortization, total | 370 |
| | 116 |
| | | 206 |
|
| Deferred income taxes | 265 |
| | (30 | ) | | | 8 |
|
| Pension, postretirement, and other employee benefits | (4 | ) | | (123 | ) | | | 5 |
|
| Stock based compensation expense | 25 |
| | 11 |
| | | 20 |
|
| Hedge settlements | — |
| | (35 | ) | | | (26 | ) |
| Mark-to-market adjustments | (32 | ) | | 17 |
| | | 162 |
|
| Other, net | (67 | ) | | (47 | ) | | | (82 | ) |
| Changes in certain current assets and liabilities — | | | | | | |
| -Receivables | 534 |
| | (18 | ) | | | 181 |
|
| -Natural gas for sale, net of temporary LIFO liquidation | — |
| | (222 | ) | | | 273 |
|
| -Prepaid income taxes | (7 | ) | | 1 |
| | | 151 |
|
| -Other current assets | (42 | ) | | (36 | ) | | | 37 |
|
| -Accounts payable | (169 | ) | | 78 |
| | | 43 |
|
| -Accrued taxes | (24 | ) | | (11 | ) | | | 41 |
|
| -Accrued compensation | (11 | ) | | (36 | ) | | | (21 | ) |
| -Other current liabilities | 8 |
| | (11 | ) | | | (30 | ) |
| Net cash provided from (used for) operating activities | 1,149 |
| | (342 | ) | | | 1,113 |
|
| Investing Activities: | | | | | | |
| Property additions | (1,093 | ) | | (287 | ) | | | (509 | ) |
| Cost of removal, net of salvage | (45 | ) | | (21 | ) | | | (32 | ) |
| Change in construction payables, net | 49 |
| | 9 |
| | | (7 | ) |
| Investment in unconsolidated subsidiaries | (128 | ) | | (1,421 | ) | | | (14 | ) |
| Returned investment in unconsolidated subsidiaries | 22 |
| | 2 |
| | | 3 |
|
| Other investing activities | 3 |
| | 3 |
| | | — |
|
| Net cash used for investing activities | (1,192 | ) | | (1,715 | ) | | | (559 | ) |
| Financing Activities: | | | | | | |
| Increase (decrease) in notes payable, net | (323 | ) | | 472 |
| | | (896 | ) |
| Proceeds — | | | | | | |
| First mortgage bonds | 200 |
| | — |
| | | 250 |
|
| Capital contributions from parent company | 79 |
| | 1,089 |
| | | — |
|
| Senior notes | 450 |
| | 900 |
| | | 350 |
|
| Redemptions and repurchases — | | | | | | |
| Medium-term notes | (22 | ) | | — |
| | | — |
|
| First mortgage bonds | — |
| | — |
| | | (125 | ) |
| Senior notes | — |
| | (300 | ) | | | — |
|
| Distributions to noncontrolling interest | — |
| | — |
| | | (19 | ) |
| Payment of common stock dividends | (332 | ) | | (63 | ) | | | (128 | ) |
| Other financing activities | (7 | ) | | (8 | ) | | | 10 |
|
| Net cash provided from (used for) financing activities | 45 |
| | 2,090 |
| | | (558 | ) |
| Net Change in Cash and Cash Equivalents | 2 |
| | 33 |
| | | (4 | ) |
| Cash and Cash Equivalents at Beginning of Period | 19 |
| | 15 |
| | | 19 |
|
| Cash and Cash Equivalents at End of Period | $ | 21 |
| | $ | 48 |
| | | $ | 15 |
|
| Supplemental Cash Flow Information: | | | | | | |
| Cash paid (received) during the period for — | | | | | | |
| Interest (net of $9, $2, and $3 capitalized, respectively) | $ | 146 |
| | $ | 86 |
| | | $ | 119 |
|
| Income taxes, net | 17 |
| | 54 |
| | | (100 | ) |
Noncash transactions —
Accrued property additions at end of period | 112 |
| | 50 |
| | | 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 September 30, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 21 |
| | $ | 19 |
|
| Receivables — | | | | |
| Energy marketing receivables | | 427 |
| | 623 |
|
| Customer accounts receivable | | 221 |
| | 364 |
|
| Unbilled revenues | | 61 |
| | 239 |
|
| Other accounts and notes receivable | | 61 |
| | 76 |
|
| Accumulated provision for uncollectible accounts | | (26 | ) | | (27 | ) |
| Materials and supplies | | 24 |
| | 26 |
|
| Natural gas for sale | | 631 |
| | 631 |
|
| Prepaid expenses | | 103 |
| | 80 |
|
| Assets from risk management activities, net of collateral | | 103 |
| | 128 |
|
| Other regulatory assets, current | | 96 |
| | 81 |
|
| Other current assets | | 25 |
| | 10 |
|
| Total current assets | | 1,747 |
| | 2,250 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 15,383 |
| | 14,508 |
|
| Less: Accumulated depreciation | | 4,567 |
| | 4,439 |
|
| Plant in service, net of depreciation | | 10,816 |
| | 10,069 |
|
| Construction work in progress | | 596 |
| | 496 |
|
| Total property, plant, and equipment | | 11,412 |
| | 10,565 |
|
| Other Property and Investments: | | | | |
| Goodwill | | 5,967 |
| | 5,967 |
|
| Equity investments in unconsolidated subsidiaries | | 1,609 |
| | 1,541 |
|
Other intangible assets, net of amortization of $100 and $34
at September 30, 2017 and December 31, 2016, respectively | | 300 |
| | 366 |
|
| Miscellaneous property and investments | | 21 |
| | 21 |
|
| Total other property and investments | | 7,897 |
| | 7,895 |
|
| Deferred Charges and Other Assets: | | | | |
| Other regulatory assets, deferred | | 944 |
| | 973 |
|
| Other deferred charges and assets | | 190 |
| | 170 |
|
| Total deferred charges and other assets | | 1,134 |
| | 1,143 |
|
| Total Assets | | $ | 22,190 |
| | $ | 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 September 30, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | — |
| | $ | 22 |
|
| Notes payable | | 934 |
| | 1,257 |
|
| Energy marketing trade payables | | 451 |
| | 597 |
|
| Accounts payable | | 368 |
| | 348 |
|
| Customer deposits | | 137 |
| | 153 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | — |
| | 26 |
|
| Other accrued taxes | | 70 |
| | 68 |
|
| Accrued interest | | 66 |
| | 48 |
|
| Accrued compensation | | 46 |
| | 58 |
|
| Liabilities from risk management activities, net of collateral | | 28 |
| | 62 |
|
| Other regulatory liabilities, current | | 126 |
| | 102 |
|
| Accrued environmental remediation, current | | 54 |
| | 69 |
|
| Other current liabilities | | 112 |
| | 108 |
|
| Total current liabilities | | 2,392 |
| | 2,918 |
|
| Long-term Debt | | 5,862 |
| | 5,259 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 2,214 |
| | 1,975 |
|
| Employee benefit obligations | | 431 |
| | 441 |
|
| Other cost of removal obligations | | 1,656 |
| | 1,616 |
|
| Accrued environmental remediation, deferred | | 345 |
| | 357 |
|
| Other regulatory liabilities, deferred | | 35 |
| | 51 |
|
| Other deferred credits and liabilities | | 88 |
| | 127 |
|
| Total deferred credits and other liabilities | | 4,769 |
| | 4,567 |
|
| Total Liabilities | | 13,023 |
| | 12,744 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, par value $0.01 per share — | | | | |
| Authorized — 100 million shares | | | | |
| Outstanding — 100 shares | | — |
| | — |
|
| Paid in capital | | 9,185 |
| | 9,095 |
|
| Accumulated deficit | | (41 | ) | | (12 | ) |
| Accumulated other comprehensive income | | 23 |
| | 26 |
|
| Total common stockholder's equity | | 9,167 |
| | 9,109 |
|
| Total Liabilities and Stockholder's Equity | | $ | 22,190 |
| | $ | 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 servicesa holding company whosethat owns all of the common stock of three traditional electric operating companies (Alabama Power, Georgia Power, and Mississippi Power), as well as Southern Power and Southern Company Gas, and owns other direct and indirect subsidiaries. The primary business isbusinesses of the Southern Company system are electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas through utilities in seven states – Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee, and Maryland.by Southern Company GasGas. Southern Company's reportable segments are the sale of electricity by the traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and its subsidiaries are also involved in severalthe sale of natural gas and other complementary businesses.
products and services by Southern Company Gas has fourGas. Southern Company Gas' reportable segments –are gas distribution operations, gas marketing services,pipeline investments, 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, Acquisition, and Disposition 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.marketing services. See Note (I)(L) to the Condensed Financial Statements herein for additional information relatingon segment reporting. For additional information on the Registrants' primary business activities, see BUSINESS – "The Southern Company System" in Item 1 of the Form 10-K.
The Registrants continue to focus on several key performance indicators. For the Merger.
In September 2016,traditional electric operating companies and Southern Company Gas, paidthese indicators include, but are not limited to, customer satisfaction, plant availability, electric and natural gas system reliability, and execution of major construction projects. For Southern Power, these indicators include, but are not limited to, the equivalent forced outage rate and contract availability to evaluate operating results and help ensure its ability to meet its contractual commitments to customers. In addition, Southern Company and the Subsidiary Registrants focus on earnings per share and net income, respectively, as a key performance indicator.
Recent Developments
COVID-19
During March 2020, COVID-19 was declared a pandemic by the World Health Organization and the Centers for Disease Control and Prevention and has spread globally, including throughout the United States. The Southern Company system provides a critical service to its customers; therefore, it is essential that Southern Company system employees are able to continue to perform their critical duties safely and effectively. The Southern Company system has implemented applicable business continuity plans, including teleworking, canceling non-essential business travel, increasing cleaning frequency at business locations, implementing applicable safety and health guidelines issued by federal and state officials, and establishing protocols for required work on customer premises. To date, these procedures have been effective in maintaining the Southern Company system's critical operations. As a result of the COVID-19 pandemic, there have been economic disruptions in the Registrants' operating territories. The traditional electric operating companies and the natural gas distribution utilities temporarily suspended disconnections for non-payment by customers and waived late fees for certain periods. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters" herein for information regarding deferral of certain incremental COVID-19-related costs, including bad debt, to a regulatory asset by certain of the traditional electric operating companies and the natural gas distribution utilities. In addition, the COVID-19 pandemic has resulted in a reduction in workforce at Plant Vogtle Units 3 and 4, as discussed further herein. Additional information regarding COVID-19 and its potential impacts on the Registrants is provided throughout Management's Discussion and Analysis of Financial Condition and Results of Operations and in Item 1A herein.
Alabama Power
On June 9, 2020, the Alabama PSC approved in part Alabama Power's petition for a certificate of convenience and necessity (CCN) filed in September 2019 to procure additional capacity. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Alabama Power" herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Georgia Power
Plant Vogtle Units 3 and 4 Status
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4 (with electric generating capacity of approximately $1.4 billion1,100 MWs each), in which Georgia Power holds a 45.7% ownership interest.
During the second quarter 2020, approximately $194 million of construction contingency was assigned to the base capital cost forecast, which exceeded the remaining balance of the construction contingency originally established in the second quarter 2018. As a result, Southern Nuclear recommended establishing additional construction contingency, of which Georgia Power's share is $115 million, for potential risks including, among other factors, construction productivity and expected impacts of the COVID-19 pandemic; adding resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement.
After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income of $149 million ($111 million after tax) for the increase in the total project capital cost forecast as of June 30, 2020. As and when these amounts are spent, Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery.
In mid-March 2020, Southern Nuclear began implementing policies and procedures designed to mitigate the risk of transmission of COVID-19 at the construction site. In April 2020, Georgia Power, acting for itself and as agent for the other Vogtle Owners, announced a reduction in workforce at Plant Vogtle Units 3 and 4, which totaled approximately 20% of the then-existing site workforce. This workforce reduction lowered absenteeism, providing an improvement in operational efficiency and allowing for increased social distancing. From the initial peak in April 2020, the number of active cases at the site declined significantly during May and early June, but began increasing again in mid-June and continues to impact productivity levels and pace of activity completion. As a result, overall production improvements have not been achieved at the levels anticipated, contributing to the allocation of, and increase in, construction contingency described above.
To address these issues, in July 2020, Southern Nuclear updated its aggressive site work plan for both Unit 3 and Unit 4. While Southern Nuclear's July 2020 aggressive site work plan extended milestone dates from its February 2020 aggressive site work plan, Georgia Power still expects to achieve the regulatory-approved in-service dates of November 2021 and November 2022 for Plant Vogtle Units 3 and 4, respectively.
The continuing effects of the COVID-19 pandemic could further disrupt or delay construction, testing, supervisory, and support activities at Plant Vogtle Units 3 and 4. Georgia Power's proportionate share of the estimated incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is currently estimated to be between $70 million and $115 million. However, the ultimate impact of the COVID-19 pandemic on the construction schedule and budget for Plant Vogtle Units 3 and 4 cannot be determined at this time.
See FUTURE EARNINGS POTENTIAL – "Construction Programs – Nuclear Construction" herein for additional information.
Mississippi Power
On March 17, 2020, the Mississippi PSC approved a settlement agreement between Mississippi Power and the Mississippi Public Utilities Staff related to Mississippi Power's base rate case filed in November 2019 (Mississippi Power Rate Case Settlement Agreement). Under the terms of the Mississippi Power Rate Case Settlement Agreement, annual retail rates decreased approximately $16.7 million, or 1.85%, effective for the first billing cycle of April 2020. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Mississippi Power – 2019 Base Rate Case" herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Southern Power
During the six months ended June 30, 2020, Southern Power completed construction of and placed in service the 200-MW Reading wind facility, continued construction of the 136-MW Skookumchuck wind facility, and commenced construction of the Garland and Tranquillity battery energy storage facilities. See FUTURE EARNINGS POTENTIAL – "Construction Programs – Southern Power" herein for additional information.
On January 17, 2020, Southern Power completed the sale of its equity interests in Plant Mankato (including the 385-MW expansion unit completed in May 2019) to a subsidiary of Xcel for a purchase price of approximately $663 million, including final working capital adjustments.
In March 2020, Southern Power entered into an agreement to acquire a 50% equitycontrolling membership interest in SNG. an approximately 300-MW wind facility located in South Dakota. The acquisition is subject to FERC approval and certain other customary conditions to closing, including commercial operation of the facility, which is expected to occur in late 2020 or early 2021. The facility's output is contracted under two long-term PPAs. The ultimate outcome of this matter cannot be determined at this time.
On March 31, 2017,May 1, 2020, Southern Company Gas made an additional $50 million contribution to maintain its 50% equityPower purchased a controlling interest in SNG. Southern Company Gas recorded equity investment income of $28 million and $86 millionthe 56-MW Beech Ridge II wind facility located in Greenbrier County, West Virginia from this investment in the successor third quarter and year-to-date 2017, respectively, and $27 million in September 2016.Invenergy Renewables LLC. The facility's output is contracted under a 12-year PPA. See Note (J)(K) 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,At June 30, 2020, Southern Power's average investment coverage ratio for its generating assets, including those owned with various partners, based on the ratio of investment under contract to total investment using the respective generation facilities' net book value (or expected in-service value for facilities under construction) as the investment amount was 94% through 2024 and 92% through 2029, with an average remaining contract duration of approximately 14 years.
Southern Company Gas
On March 24, 2020, Southern Company Gas completed the sale of its purchaseinterests in Pivotal LNG and Atlantic Coast Pipeline with aggregate proceeds of Piedmont's 15% interest in SouthStar, which eliminated the noncontrolling interest associated with SouthStar.$178 million, including working capital adjustments. See Note 4(K) to the financial statements of SouthernCondensed Financial Statements under "Southern Company Gas under "Variable Interest Entities" in Item 8 of the Form 10-KGas" herein for additional information.
On October 15, 2017,June 1, 2020, Virginia Natural Gas filed a general rate case with the Virginia Commission seeking an increase in rates ofapproximately $49.6 million based on a ROE of 10.35% and an equity ratio of 54%. The Virginia Commission is expected to rule on the requested increase in the second quarter 2021.
On July 1, 2020, Atlanta Gas Light filed its 2020 GRAM filing with the Georgia PSC requesting an increase in annual base rates of $37.6 million. Resolution of the 2020 GRAM filing is expected by December 31, 2020, with rates effective January 1, 2021.
See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Southern Company Gas subsidiary, Pivotal Utility Holdings, entered into agreementsGas" herein for the sale of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion. As of September 30, 2017, the net book value of the assets to be disposed of in the sale was approximately $1.5 billion, which includes approximately $0.5 billion of goodwill. The goodwill is not deductible for tax purposes and as a result, a deferred tax liability has not yet been provided for goodwill. Through the completion of the sale,additional information regarding Southern Company Gas intends to invest approximately $0.1 billion in capital expenditures which are required for ordinary business operations. The completion of each sale is subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act; (ii) the receipt of requiredGas' regulatory approvals, including the FERC, the Federal Communications Commission, the New Jersey BPU, and, with respect to the sale of Elkton Gas, the Maryland PSC; and (iii) other customary closing conditions. The sales are expected to be completed by the end of the third quarter 2018.
filings. The ultimate outcome of these matters cannot be determined at this time.
RESULTS OF OPERATIONS
Southern Company
Net Income
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(287) | | (31.9) | | $(1,502) | | (50.4) |
Consolidated net income attributable to Southern Company was $612 million ($0.58 per share) for the second quarter 2020 compared to $899 million ($0.86 per share) for the corresponding period in 2019. The decrease was
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
(Continued)
Operating Metrics
Southern Company Gas continuesprimarily due to focusdecreases in retail revenues associated with milder weather and lower customer usage in the second quarter 2020 compared to the corresponding period in 2019, a $111 million after-tax charge in the second quarter 2020 related to Georgia Power's construction of Plant Vogtle Units 3 and 4, an $88 million after-tax gain on several operating metrics, including Heating Degree Days, customer count,the sale of Plant Nacogdoches in the second quarter 2019, higher depreciation and volumesamortization, and a $74 million after-tax leveraged lease impairment in the second quarter 2020. These decreases to net income were partially offset by increases in retail revenues associated with rates and pricing and lower other operations and maintenance expenses. See Note 15 to the financial statements under "Southern Power" in Item 8 of natural gas sold. Forthe Form 10-K for additional information regarding the disposition of Plant Nacogdoches, Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – "Operating Metrics"the construction of Southern Company Gas in Item 7 of the Form 10-K.
Southern Company Gas measures weatherPlant Vogtle Units 3 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 Illinois4, 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 and Illinois 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 most of the earnings upside.
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
Heating Season is the period from November through March when natural gas usage and operating revenues are generally higher, as more customers are connectedNote (C) to the gas distribution systems and natural gas usage is higher in periods of colder weather. Occasionally inCondensed Financial Statements under "Other Matters – Southern Company" herein for additional information on 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 throughout the year. Seasonality also affects the comparison of certain balance sheet items across quarters, including receivables, unbilled revenues, natural gas for sale, and notes payable. However, these items are comparable when reviewing 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.leveraged lease impairment.
RESULTS OF OPERATIONS
Net Income
|
| | |
Successor |
Third Quarter 2017 vs. Third Quarter 2016 |
(change in millions) | | (% change) |
$11 | | N/M |
N/M - Not meaningful
NetConsolidated net income attributable to Southern Company Gas was $15 million$1.5 billion ($1.40 per share) for year-to-date 2020 compared to $3.0 billion ($2.86 per share) for the thirdcorresponding period in 2019. The decrease was primarily due to the $2.5 billion ($1.3 billion after tax) gain on the sale of Gulf Power recorded in 2019. See Note 15 to the financial statements under "Southern Company" in Item 8 of the Form 10-K for additional information regarding the sale of Gulf Power.
Retail Electric Revenues
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(358) | | (10.1) | | $(363) | | (5.5) |
In the second quarter 20172020, retail electric revenues were $3.2 billion compared to $4$3.5 billion for the corresponding period in 2019. For year-to-date 2020, retail electric revenues were $6.3 billion compared to $6.6 billion for the corresponding period in 2019.
Details of the changes in retail electric revenues were as follows:
|
| | | | | | | | | | | | | |
| | Second Quarter 2020 | | Year-to-Date 2020 |
| | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail electric – prior year | $ | 3,540 |
| | | | $ | 6,623 |
| | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 124 |
| | 3.5 | % | | 267 |
| | 4.0 | % |
| Sales decline | (107 | ) | | (3.0 | ) | | (99 | ) | | (1.5 | ) |
| Weather | (132 | ) | | (3.7 | ) | | (159 | ) | | (2.4 | ) |
| Fuel and other cost recovery | (243 | ) | | (6.9 | ) | | (372 | ) | | (5.6 | ) |
| Retail electric – current year | $ | 3,182 |
| | (10.1 | )% | | $ | 6,260 |
| | (5.5 | )% |
Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2020 when compared to the corresponding periods in 2019 primarily due to an increase in revenue at Georgia Power and Alabama Power related to the recovery of environmental compliance costs and Rate CNP Compliance costs, respectively, as well as the impacts of Georgia Power accruals for customer refunds in the first quarter and year-to-date 2019 related to Tax Reform and the rate pricing effects of decreased customer usage at Georgia Power. Partially offsetting these increases were lower contributions from commercial and industrial customers with variable demand-driven pricing at Georgia Power. Additionally, the year-to-date increase was due to Alabama Power customer bill credits in the first quarter 2019 related to Tax Reform. See Note 2 to the financial statements under "Alabama Power" and "Georgia Power" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Revenues attributable to changes in sales decreased in the second quarter and year-to-date 2020 when compared to the corresponding periods in 2019 largely due to social distancing and shelter-in-place guidelines related to the COVID-19 pandemic. Weather-adjusted residential KWH sales increased 4.7% and 3.8% in the second quarter and year-to-date 2020, respectively, when compared to the corresponding periods in 2019 primarily due to customer growth and an increase in average customer usage, primarily due to the temporary suspension of customer disconnections for nonpayment and shelter-in-place orders. Weather-adjusted commercial KWH sales decreased 11.5% and 6.3% in the second quarter and year-to-date 2020, respectively, when compared to the corresponding periods in 2019 primarily due to lower customer usage resulting from shelter-in-place orders and restrictions on business operations in response to the COVID-19 pandemic. Industrial KWH sales decreased 14.0% and 8.0% in the second quarter and year-to-date 2020, respectively, when compared to the corresponding periods in 2019 as a result of disruptions in supply chain and business operations related to the COVID-19 pandemic and the overall decrease in business activity due to the resulting recession.
Fuel and other cost recovery revenues decreased $243 million and $372 million in the second quarter and year-to-date 2020, respectively, compared to the corresponding periods in 2019 primarily due to decreases in generation and the average cost of fuel and purchased power. 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
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(70) | | (12.9) | | $(152) | | (14.6) |
Wholesale electric revenues consist of revenues from PPAs and short-term opportunity sales. Wholesale electric revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues generally represent the greatest contribution to net income and are designed to provide recovery of fixed costs plus a return on investment. Energy revenues will vary depending on fuel prices, the market prices of wholesale energy compared to the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Energy sales from solar and wind PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or through a fixed price related to the energy. As a result, the ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors. Wholesale electric revenues at Mississippi Power include FERC-regulated municipal and rural association sales under cost-based tariffs as well as market-based sales. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system's variable cost to produce the energy.
In the second quarter 2020, wholesale electric revenues were $472 million compared to $542 million for the corresponding period in 2016. This increase was2019. For year-to-date 2020, wholesale electric revenues were $889 million compared to $1.0 billion for the corresponding period in 2019. These decreases reflect decreases of $46 million and $103 million in energy revenues for the second quarter and year-to-date 2020, respectively, and $24 million and $49 million in capacity revenues for the second quarter and year-to-date 2020, respectively. The decreases in energy revenues include $24 million and $67 million for the second quarter and year-to-date 2020, respectively, from Southern Power, with the remainder from the traditional electric operating companies. These decreases primarily due to $11 million of additional incomeresult from infrastructure replacement programs and base rate increases, net of associated depreciation,lower natural gas prices and a $7 million gain from the settlement of contractor litigation claims, partially offset by $12 million lower net income at wholesale gas services. Also contributing to the increase was $24 million in Merger-related expensesdecrease in the third quarter 2016, partially offset by $23 millionvolume of additional deferred income tax expenseKWHs sold, primarily as a result of milder weather in the third quarter 2017.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
(Continued)
|
| | | | | | | | | | | | | |
| | | Successor | | | Predecessor |
| | | Year-to-Date 2017 | | July 1, 2016 through September 30, 2016 | | | January 1, 2016 through June 30, 2016 |
| | | (in millions) | | (in millions) | | | (in millions) |
Net Income Attributable to
Southern Company Gas | | $ | 303 |
| | $ | 4 |
| | | $ | 131 |
|
Net income attributablethe Southeast U.S. when compared to the corresponding periods in 2019. The decrease in capacity revenues was primarily related to Southern Company Gas for the successor year-to-date 2017 included $28 millionPower's sales of net income from wholesale gas services and $38 million in earnings from the SNG investment, net of related interest expense. Also included in net income for this period was $29 million generated from the continued investment in infrastructure replacement programs and base rate increases, primarily at Atlanta Gas Light effective March 1, 2017, less the associated increases in depreciation. For additional information, see FUTURE EARNINGS POTENTIAL– "Regulatory Matters – Base Rate Cases" herein. These increases were partially offset by $23 million of additional deferred income tax expense.
Net income attributable to Southern Company Gas for the successor period of July 1, 2016 through September 30, 2016 and the predecessor period of January 1, 2016 through June 30, 2016 included $11 million and $42 million, respectively, in net losses from wholesale gas services. The successor period of July 1, 2016 through September 30, 2016 also included $16 million in earnings from the SNG investment, net of related interest expense. Also included in net income for these periods were $24 million and $41 million, respectively, of Merger-related expenses and $14 million of net income attributable to noncontrolling interestPlant Nacogdoches in the predecessor period of January 1, 2016 through June 30, 2016. As a result of purchasing the remaining interest in SouthStar in October 2016, all net income was attributable to Southern Company Gassecond quarter 2019 and Plant Mankato in the successor periods.first quarter 2020. See Note (K) to the Condensed Financial Statements under "Southern Power" herein and Note 15 to the financial statements under "Southern Power – Sales of Natural Gas and Biomass Plants" in Item 8 of the Form 10-K for additional information.
Natural Gas Revenues
|
| | |
| Successor |
| Third Quarter 2017 vs. Third Quarter 2016 |
| (change in millions) | | (% change) |
| $14 | | 2.7 |
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(53) | | (7.7) | | $(278) | | (12.9) |
In the thirdsecond quarter 2017,2020, natural gas revenues were $532$636 million compared to $518$689 million for the corresponding period in 2016.2019. For year-to-date 2020, natural gas revenues were $1.9 billion compared to $2.2 billion for the corresponding period in 2019.
Details of the changes in natural gas revenues were as follows:
| | | | | Third Quarter 2017 | Second Quarter 2020 | | Year-to-Date 2020 |
| | | (in millions) | | (% change) | (in millions) | | (% change) | | (in millions) | | (% change) |
| Natural gas – prior year | | $ | 518 |
| | | |
| Natural gas revenues – prior year | | $ | 689 |
| | | | $ | 2,163 |
| | |
| Estimated change resulting from – | | | | | | | | | | | |
| Infrastructure replacement programs and base rate increases | | 25 |
| | 4.8 | % | |
| Infrastructure replacement programs and base rate changes | | 43 |
| | 6.2 | % | | 119 |
| | 5.5 | % |
| Gas costs and other cost recovery | | 1 |
| | 0.2 |
| (38 | ) | | (5.5 | ) | | (287 | ) | | (13.3 | ) |
| Mark-to-market adjustments at gas marketing services | | 3 |
| | 0.6 |
| |
| Weather | | 3 |
| | 0.4 |
| | (8 | ) | | (0.4 | ) |
| Wholesale gas services | | (16 | ) | | (3.1 | ) | (67 | ) | | (9.7 | ) | | (102 | ) | | (4.7 | ) |
| Other | | 1 |
| | 0.2 |
| 6 |
| | 0.9 |
| | — |
| | — |
|
| Natural gas – current year | | $ | 532 |
| | 2.7 | % | |
| Natural gas revenues – current year | | $ | 636 |
| | (7.7 | )% | | $ | 1,885 |
| | (12.9 | )% |
The increase in natural gas revenue primarily relatesRevenues attributable to gas distribution operations as a result of continued investment in infrastructure replacement programs and increases in base rate revenues,changes at the natural gas distribution utilities increased in the second quarter and year-to-date 2020 compared to the corresponding periods in 2019 primarily due to base rate increases at Nicor Gas and Atlanta Gas Light effective March 1, 2017, as well asand continued investments recovered through infrastructure replacement programs. See Note 2 to the positive impact fromfinancial statements under "Southern Company Gas – Rate Proceedings" in Item 8 of the amortization of assets establishedForm 10-K for additional information.
Revenues attributable to gas costs and other cost recovery decreased in the application of acquisition accounting at gas marketing services. These increases were partially offset by mark-to-
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
market losses from derivative instruments at wholesale gas servicessecond quarter and gas marketing servicesyear-to-date 2020 compared to the corresponding periods in 2019 primarily due to changes inlower natural gas prices and a decrease in commercial activity at wholesale gas services. For information on commercial activity at wholesale gas services, see "Segment Information – Wholesale Gas Services – Change in Commercial Activity" herein.
|
| | | | | | | | | | | | | |
| | | Successor | | | Predecessor |
| | | Year-to-Date 2017 | | July 1, 2016 through September 30, 2016 | | | January 1, 2016 through June 30, 2016 |
| | | (in millions) | | (in millions) | | | (in millions) |
| Natural gas revenues | | $ | 2,746 |
| | $ | 518 |
| | | $ | 1,841 |
|
For the successor year-to-date 2017, natural gas revenues included recovery of $1.1 billion in costdecreased volumes of natural gas and $95 million in net revenues from wholesale gas services, net of $14 million of amortization associated with assets established in the application of acquisition accounting. Also included in natural gas revenues were $69 million in additional revenues generated from gas distribution operations as a result of continued investment in infrastructure replacement programs and increases in base rate revenues, primarily at Atlanta Gas Light effective March 1, 2017, partially offset by a $16 million decrease attributable to warmer-than-normal weather, net of hedging.
For the successor period of July 1, 2016 through September 30, 2016 and the predecessor period of January 1, 2016 through June 30, 2016, natural gas revenues included recovery of $133 million and $755 million, respectively, in cost of natural gas, as well as $8 million and $32 million, respectively, in net losses from wholesale gas services. Also included in natural gas revenues for the predecessor period of January 1, 2016 through June 30, 2016 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.
sold. Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, recoverablegas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from the natural gas distribution utilities.
Revenues attributable to Southern Company Gas' wholesale gas services business decreased in the second quarter and year-to-date 2020 compared to the corresponding periods in 2019 primarily due to decreased commercial activity as a result of warmer weather and a decrease in derivative gains.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Other Revenues
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(4) | | (2.4) | | $(68) | | (19.3) |
In the second quarter 2020, other revenues were $162 million compared to $166 million for the corresponding period in 2019. For year-to-date 2020, other revenues were $284 million compared to $352 million for the corresponding period in 2019. These decreases primarily relate to changes in PowerSecure's business, including the sale of its utility infrastructure services business in June 2019 and the wind-down of a segment of its distributed infrastructure business in the first quarter 2020, partially offset by unregulated sales at Georgia Power largely associated with power delivery construction and maintenance contracts. See Note 15 to the financial statements under "Southern Company" in Item 8 of the Form 10-K for additional information.
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | |
| | Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | (293 | ) | | (32.1) | | $ | (507 | ) | | (28.7) |
| Purchased power | (1 | ) | | (0.5) | | 10 |
| | 2.7 |
| Total fuel and purchased power expenses | $ | (294 | ) | | | | $ | (497 | ) | | |
In the second quarter 2020, total fuel and purchased power expenses were $0.8 billion compared to $1.1 billion for the corresponding period in 2019. The decrease was primarily the result of a $118 million decrease in the average cost of fuel and purchased power and a $176 million net decrease in the volume of KWHs generated and purchased.
For year-to-date 2020, total fuel and purchased power expenses were $1.6 billion compared to $2.1 billion for the corresponding period in 2019. The decrease was primarily the result of a $285 million decrease in the average cost of fuel and purchased power and a $212 million net decrease in the volume of KWHs generated and purchased.
Fuel and purchased power energy transactions at the traditional electric operating companies are generally offset by fuel revenues and do not have a significant impact on net income. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters" 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.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of the Southern Company system's generation and purchased power were as follows:
|
| | | | |
| | Second Quarter 2020 | Second Quarter 2019 | Year-to-Date 2020 | Year-to-Date 2019 |
Total generation (in billions of KWHs) | 41 | 46 | 82 | 90 |
Total purchased power (in billions of KWHs) | 4 | 4 | 9 | 8 |
Sources of generation (percent) — | | | | |
| Gas | 55 | 52 | 54 | 50 |
| Nuclear | 19 | 22 | 19 | 22 |
| Coal | 12 | 16 | 13 | 16 |
| Hydro | 5 | 3 | 6 | 5 |
| Other | 9 | 7 | 8 | 7 |
Cost of fuel, generated (in cents per net KWH)— | | | | |
| Gas | 1.89 | 2.39 | 1.92 | 2.47 |
| Nuclear | 0.78 | 0.80 | 0.78 | 0.80 |
| Coal | 2.96 | 3.04 | 2.92 | 2.98 |
Average cost of fuel, generated (in cents per net KWH) | 1.79 | 2.26 | 1.82 | 2.29 |
Average cost of purchased power (in cents per net KWH)(*) | 4.74 | 4.81 | 4.30 | 4.73 |
| |
| (*) | Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider. |
Fuel
In the second quarter 2020, fuel expense was $621 million compared to $914 million for the corresponding period in 2019. The decrease was primarily due to a 49.3% decrease in the volume of KWHs generated by coal, a 20.9% decrease in the average cost of natural gas per KWH generated, a 2.6% decrease in the average cost of coal per KWH generated, and a 5.2% decrease in the volume of KWHs generated by natural gas.
For year-to-date 2020, fuel expense was $1.3 billion compared to $1.8 billion for the corresponding period in 2019. The decrease was primarily due to a 44.1% decrease in the volume of KWHs generated by coal, a 22.3% decrease in the average cost of natural gas per KWH generated, a 2.0% decrease in the average cost of coal per KWH generated, and a 0.5% decrease in the volume of KWHs generated by natural gas.
Cost of Natural Gas
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(47) | | (24.6) | | $(294) | | (33.5) |
Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from the natural gas distribution utilities. Cost of natural gas at the natural gas distribution utilities represented 86% of total cost of natural gas for both the second quarter and year-to-date 2020.
In the second quarter 2020, cost of natural gas was $144 million compared to $191 million for the corresponding period in 2019. The decrease reflects a 34.9% decrease in natural gas prices in the second quarter 2020 compared to the corresponding period in 2019.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
For year-to-date 2020, cost of natural gas was $583 million compared to $877 million for the corresponding period in 2019. The decrease reflects a 36.6% decrease in natural gas prices compared to 2019 and decreased volumes primarily as a result of warmer weather, as determined by Heating Degree Days, for year-to-date 2020 compared to the corresponding period in 2019.
Cost of Other Sales
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(10) | | (11.9) | | $(74) | | (36.5) |
In the second quarter 2020, cost of other sales was $74 million compared to $84 million for the corresponding period in 2019. For year-to-date 2020, cost of other sales was $129 million compared to $203 million for the corresponding period in 2019. These decreases primarily relate to changes in PowerSecure's business, including the sale of its utility infrastructure services business in June 2019 and the wind-down of a segment of its distributed infrastructure business in the first quarter 2020, partially offset by an increase in expenses related to unregulated sales at Georgia Power largely associated with power delivery construction and maintenance contracts. See Note 15 to the financial statements under "Southern Company" in Item 8 of the Form 10-K for additional information.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(117) | | (8.9) | | $(136) | | (5.2) |
In the second quarter 2020, other operations and maintenance expenses were $1.2 billion compared to $1.3 billion for the corresponding period in 2019. The decrease reflects the impacts of cost containment activities implemented in 2020 to help offset the effects of the recessionary economy resulting from the COVID-19 pandemic, as well as a $32 million goodwill impairment charge in the second quarter 2019 associated with the sale of PowerSecure's utility infrastructure services business unit. The decrease primarily results from decreases of $82 million in scheduled generation outage and maintenance expenses and $17 million in compliance and environmental expenses at the traditional electric operating companies. The decrease also reflects decreases of $14 million in transmission and distribution maintenance expenses, primarily at Alabama Power and Georgia Power, including $11 million of reliability NDR credits at Alabama Power, partially offset by a $46 million increase in storm damage recovery at Georgia Power as authorized in its 2019 ARP.
For year-to-date 2020, other operations and maintenance expenses were $2.5 billion compared to $2.6 billion for the corresponding period in 2019. The decrease reflects the impacts of cost containment activities implemented in 2020 to help offset the effects of the recessionary economy resulting from the COVID-19 pandemic, as well as a $32 million goodwill impairment charge in the second quarter 2019 associated with the sale of PowerSecure's utility infrastructure services business unit. The decrease primarily results from decreases of $111 million in scheduled generation outage and maintenance expenses and $42 million in transmission and distribution expenses at the traditional electric operating companies, including $22 million of reliability NDR credits at Alabama Power, partially offset by a $92 million increase in storm damage recovery at Georgia Power as authorized in its 2019 ARP.
See Note 2 to the financial statements under "Alabama Power – Rate NDR" and " – Rate CNP Compliance" and "Georgia Power – Storm Damage Recovery" and Note 15 to the financial statements under "Southern Company" in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Depreciation and Amortization
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $118 | | 15.6 | | $224 | | 14.9 |
In the second quarter 2020, depreciation and amortization was $873 million compared to $755 million for the corresponding period in 2019. For year-to-date 2020, depreciation and amortization was $1.7 billion compared to $1.5 billion for the corresponding period in 2019. These increases primarily reflect increased amortization of regulatory assets of $63 million and $127 million for the second quarter and year-to-date 2020, respectively, and higher depreciation of $44 million and $89 million for the second quarter and year-to-date 2020, respectively, as authorized in Georgia Power's 2019 ARP. See Note 2 to the financial statements under "Georgia Power – Rate Plans" and " – Integrated Resource Plan" in Item 8 of the Form 10-K for additional information.
Estimated Loss on Plant Vogtle Units 3 and 4
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $149 | | N/M | | $149 | | N/M |
N/M - Not meaningful
In the second quarter 2020, an estimated probable loss of $149 million was recorded at Georgia Power to reflect its revised total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information.
(Gain) Loss on Dispositions, Net
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(8) | | N/M | | $(2,467) | | N/M |
N/M - Not meaningful
For year-to-date 2020, gain on dispositions, net was $39 million compared to $2.5 billion for the corresponding period in 2019. The decrease was primarily due to the $2.5 billion ($1.3 billion after tax) preliminary gain on the sale of Gulf Power recorded in the first quarter 2019. See Note 15 to the financial statements under "Southern Company" in Item 8 of the Form 10-K for additional information.
Interest Expense, Net of Amounts Capitalized
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $15 | | 3.5 | | $41 | | 4.8 |
In the second quarter 2020, interest expense, net of amounts capitalized was $444 million compared to $429 million for the corresponding period in 2019. For year-to-date 2020, interest expense, net of amounts capitalized was $900 million compared to $859 million for the corresponding period in 2019. These increases were primarily due to an increase in average outstanding long-term borrowings primarily at the parent company. Additionally, the year-to-date 2020 increase was due to an increase in average outstanding long-term borrowings primarily at Georgia Power. See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein and Note 8 to the financial statements in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Impairment of Leveraged Lease
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $154 | | N/M | | $154 | | N/M |
N/M - Not meaningful
In the second quarter 2020, an impairment charge of $154 million was recorded related to a leveraged lease investment at Southern Holdings. See Note (C) to the Condensed Financial Statements under "Other Matters – Southern Company" herein for additional information.
Other Income (Expense), Net
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $2 | | 2.0 | | $28 | | 15.9 |
In the second quarter 2020, other income (expense), net was $101 million compared to $99 million for the corresponding period in 2019. For year-to-date 2020, other income (expense), net was $204 million compared to $176 million for the corresponding period in 2019. These increases were primarily related to an increase in non-service cost-related retirement benefits income, partially offset by a gain at Southern Power from a litigation settlement in the second quarter 2019. See Note 3 to the financial statements under "General Litigation Matters – Southern Power" in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein for additional information.
Income Taxes
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(140) | | (96.6) | | $(1,355) | | (90.0) |
In the second quarter 2020, income taxes were $5 million compared to $145 million for the corresponding period in 2019. For year-to-date 2020, income taxes were $150 million compared to $1.5 billion for the corresponding period in 2019. The second quarter 2020 decrease was primarily due to the tax impacts of charges associated with a leveraged lease impairment and the construction of Plant Vogtle Units 3 and 4, as well as the flowback of excess deferred income taxes in 2020 as authorized in Georgia Power's 2019 ARP, partially offset by ITCs recognized upon Southern Power's sale of Plant Nacogdoches in the second quarter 2019. The year-to-date 2020 decrease also reflects the tax impacts of the sale of Gulf Power in 2019. See Notes 2 and 15 to the financial statements under "Georgia Power – Rate Plans – Tax Reform Settlement Agreement" and "Southern Company," respectively, in Item 8 of the Form 10-K and Notes (B), (C), and (G) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction," "Other Matters – Southern Company," and "Effective Tax Rate," respectively, herein for additional information.
Net Income (Loss) Attributable to Noncontrolling Interests
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(24) | | N/M | | $(26) | | N/M |
N/M - Not meaningful
In the second quarter 2020, net income attributable to noncontrolling interests was $5 million compared to $29 million for the corresponding period in 2019. For year-to-date 2020, net loss attributable to noncontrolling interests
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
was $26 million compared to an immaterial amount for the corresponding period in 2019. The changes were primarily due to an allocation of approximately $26 million of income to the noncontrolling interest partner related to a litigation settlement at Southern Power in the second quarter 2019. See Note 3 to the financial statements in Item 8 of the Form 10-K under "General Litigation Matters – Southern Power" for additional information.
Alabama Power
Net Income
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) |
| (% change) |
| (change in millions) |
| (% change) |
| $2 | | 0.7 | | $65 | | 12.7 |
Alabama Power's net income after dividends on preferred stock for the second quarter 2020 was $298 million compared to $296 million for the corresponding period in 2019. This increase was primarily due to a decrease in operations and maintenance expenses and an increase in Rate CNP Compliance-related revenues associated with increased capital investments. These increases to income were partially offset by decreases in retail revenues associated with milder weather in the second quarter 2020 compared to the same period in 2019 and lower customer usage.
Alabama Power's net income after dividends on preferred stock for year-to-date 2020 was $578 million compared to $513 million for the corresponding period in 2019. This increase was primarily due to a decrease in operations and maintenance expenses and an increase in retail revenues associated with the impact of customer bill credits issued in 2019 related to Tax Reform. These increases to income were partially offset by decreases in retail revenues associated with milder weather in the first and second quarters 2020 compared to the same periods in 2019 and lower customer usage. See Note 2 to the financial statements under "Alabama Power – Rate RSE" in Item 8 of the Form 10-K for additional information.
Retail Revenues
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(155) | | (11.2) | | $(165) | | (6.4) |
In the second quarter 2020, retail revenues were $1.22 billion compared to $1.38 billion for the corresponding period in 2019. For year-to-date 2020, retail revenues were $2.43 billion compared to $2.59 billion for the corresponding period in 2019.
Details of the changes in retail revenues were as follows:
|
| | | | | | | | | | | | | |
| | Second Quarter 2020 |
| Year-to-Date 2020 |
| | (in millions) |
| (% change) |
| (in millions) |
| (% change) |
| Retail – prior year | $ | 1,378 |
| | | | $ | 2,592 |
| | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 12 |
| | 0.9 | % | | 63 |
| | 2.4 | % |
| Sales decline | (39 | ) | | (2.8 | ) | | (46 | ) | | (1.8 | ) |
| Weather | (39 | ) | | (2.8 | ) | | (53 | ) | | (2.0 | ) |
| Fuel and other cost recovery | (89 | ) | | (6.5 | ) | | (129 | ) | | (5.0 | ) |
| Retail – current year | $ | 1,223 |
| | (11.2 | )% | | $ | 2,427 |
| | (6.4 | )% |
Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2020 when compared to the corresponding periods in 2019. The second quarter increase was primarily due to an increase in
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Rate CNP Compliance-related revenue. The year-to-date increase was primarily due to customer bill credits issued in the first quarter 2019 related to Tax Reform and Rate CNP Compliance-related revenue.
Revenues attributable to changes in sales decreased in the second quarter and year-to-date 2020 when compared to the corresponding periods in 2019 largely due to social distancing and shelter-in-place guidelines related to the COVID-19 pandemic. Weather-adjusted residential KWH sales increased 4.6% and 3.5% in the second quarter and year-to-date 2020, respectively, when compared to the corresponding periods in 2019 primarily due to customer growth and an increase in average customer usage as a result of shelter-in-place orders and the temporary suspension of customer disconnections. Weather-adjusted commercial KWH sales decreased 12.2% and 7.3% in the second quarter and year-to-date 2020, respectively, when compared to the corresponding periods in 2019 primarily due to lower customer usage resulting from shelter-in-place orders and restrictions on business operations in response to the COVID-19 pandemic. Industrial KWH sales decreased 15.5% and 8.7% in the second quarter and year-to-date 2020, respectively, when compared to the corresponding periods in 2019 as a result of disruptions in supply chain and business operations driven by the COVID-19 pandemic and the overall decrease in business activity due to the resulting recession.
Fuel and other cost recovery revenues decreased in the second quarter and year-to-date 2020 when compared to the corresponding periods in 2019 primarily due to decreases in generation and the average cost of fuel.
Electric rates include provisions to recognize the 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 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.
Wholesale Revenues – Non-Affiliates
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(8) | | (12.9) | | $(12) | | (9.8) |
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale
energy compared to the cost of Alabama Power's and the Southern Company system's generation, demand for
energy within the Southern Company system's service territory, and the availability of the Southern Company
system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by
an increase or decrease in fuel costs and do not affect net income. Short-term opportunity energy sales are also
included in wholesale energy sales to non-affiliates. These opportunity sales are made at market-based rates that
generally provide a margin above Alabama Power's variable cost to produce the energy.
In the second quarter 2020, wholesale revenues from sales to non-affiliates were $54 million compared to $62 million for the corresponding period in 2019. For year-to-date 2020, wholesale revenues from sales to non-affiliates were $111 million compared to $123 million for the corresponding period in 2019. These decreases were primarily due to decreases of 16.0% and 9.8% in the price of energy in the second quarter and year-to-date 2020, respectively, primarily due to lower natural gas prices in 2020 compared to the corresponding periods in 2019. Also contributing to the increase for the second quarter 2020 was a 3.2% decrease in KWH sales as a result of lower market demand.
Wholesale Revenues – Affiliates
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $3 | | 75.0 | | $(37) | | (58.7) |
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 the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
marginal cost and energy purchases are generally offset by energy revenues through Alabama Power's energy cost recovery clause.
For year-to-date 2020, wholesale revenues from sales to affiliates were $26 million compared to $63 million for the corresponding period in 2019. The decrease was primarily due to a 46.6% decrease in KWH sales as a result of decreased coal generation largely due to lower natural gas prices and a 25.9% decrease in the price of energy due to lower natural gas prices in 2020 compared to the corresponding period in 2019.
Other Revenues
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $12 | | 17.4 | | $9 | | 6.3 |
In the second quarter 2020, other revenues were $81 million compared to $69 million for the corresponding period in 2019. This increase was primarily due to an increase in transmission revenues associated with the timing of customer refunds and an increase in unregulated sales of products and services associated with energy efficiency and equipment upgrade projects.
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | | | |
| | Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| | (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| Fuel | $ | (53 | ) | | (21.0 | ) | | $ | (138 | ) | | (25.0 | ) |
| Purchased power – non-affiliates | 2 |
| | 4.3 |
| | 5 |
| | 6.0 |
|
| Purchased power – affiliates | (39 | ) | | (56.5 | ) | | (41 | ) | | (45.6 | ) |
| Total fuel and purchased power expenses | $ | (90 | ) | | | | $ | (174 | ) | | |
In the second quarter 2020, fuel and purchased power expenses were $278 million compared to $368 million for the corresponding period in 2019. The decrease was primarily due to a $77 million decrease in the volume of KWHs generated (excluding hydro) and purchased and a $13 million net decrease in the average cost of generation and purchased power.
For year-to-date 2020, fuel and purchased power expenses were $553 million compared to $727 million for the corresponding period in 2019. The decrease was primarily due to a $140 million decrease in the volume of KWHs generated (excluding hydro) and purchased and a $34 million net decrease in the average cost of generation and purchased power.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Alabama Power's energy cost recovery clause. See Note 2 to the financial statements under "Alabama Power – Rate ECR" in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of Alabama Power's generation and purchased power were as follows:
|
| | | | | | | |
| | Second Quarter 2020 | | Second Quarter 2019 | | Year-to-Date 2020 |
| Year-to-Date 2019 |
Total generation (in billions of KWHs) | 12 | | 12 | | 26 | | 29 |
Total purchased power (in billions of KWHs) | 2 | | 3 | | 3 | | 4 |
Sources of generation (percent) — | | | | | | | |
| Coal | 33 | | 43 | | 33 | | 43 |
| Nuclear | 32 | | 26 | | 30 | | 24 |
| Gas | 24 | | 23 | | 22 | | 21 |
| Hydro | 11 | | 8 | | 15 | | 12 |
Cost of fuel, generated (in cents per net KWH) — | | | | | | | |
| Coal | 2.82 | | 2.86 | | 2.72 | | 2.82 |
| Nuclear | 0.75 | | 0.78 | | 0.75 | | 0.78 |
| Gas | 1.95 | | 2.48 | | 2.07 | | 2.53 |
Average cost of fuel, generated (in cents per net KWH) | 1.85 | | 2.18 | | 1.86 | | 2.19 |
Average cost of purchased power (in cents per net KWH)(*) | 4.29 | | 4.01 | | 4.51 | | 4.45 |
| |
| (*) | Average cost of purchased power includes fuel, energy, and transmission purchased by Alabama Power for tolling agreements where power is generated by the provider. |
Fuel
In the second quarter 2020, fuel expense was $199 million compared to $252 million for the corresponding period in 2019. The decrease was primarily due to a 25.6% decrease in the volume of KWHs generated by coal, a 21.4% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, and increases of 23.5% and 18.9% in the volume of KWHs generated by hydro and nuclear, respectively.
For year-to-date 2020, fuel expense was $415 million compared to $553 million for the corresponding period in 2019. The decrease was primarily due to a 29.6% decrease in the volume of KWHs generated by coal, an 18.2% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, and increases of 11.9% and 11.0% in the volume of KWHs generated by nuclear and hydro, respectively.
Purchased Power – Affiliates
In the second quarter 2020, purchased power expense from affiliates was $30 million compared to $69 million for the corresponding period in 2019. For year-to-date 2020, purchased power expense from affiliates was $49 million compared to $90 million for the corresponding period in 2019. The second quarter and year-to-date 2020 decreases were primarily due to reductions of 50.8% and 43.7%, respectively, in the amount of energy purchased due to milder weather during 2020 as compared to 2019 and decreases of 10.7% and 4.3%, respectively, in the average cost of purchased power per KWH as a result of lower natural gas prices in 2020 compared to the corresponding periods in 2019.
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.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Other Operations and Maintenance Expenses
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(60) | | (14.9) | | $(122) | | (15.0) |
In the second quarter 2020, other operations and maintenance expenses were $342 million compared to $402 million for the corresponding period in 2019. For year-to-date 2020, other operations and maintenance expenses were $690 million compared to $812 million for the corresponding period in 2019. These decreases reflect the impacts of cost containment activities implemented to help offset the effects of the recessionary economy resulting from the COVID-19 pandemic. The decreases primarily result from $43 million and $78 million decreases in generation expenses associated with scheduled outages and CNP Compliance-related expenses for the second quarter and year-to-date 2020, respectively, as well as $10 million and $29 million decreases in transmission and distribution maintenance expenses primarily related to reliability NDR credits for the second quarter and year-to-date 2020, respectively. Also contributing to the year-to-date 2020 decrease was a $12 million increase in nuclear property insurance refunds.
See Note 2 to the financial statements under "Alabama Power – Rate NDR" and " – Rate CNP Compliance" in Item 8 of the Form 10-K for additional information.
Other Income (Expense), Net
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $15 | | 136.4 | | $23 | | 92.0 |
In the second quarter 2020, other income (expense), net was $26 million compared to $11 million for the corresponding period in 2019. For year-to-date 2020, other income (expense), net was $48 million compared to $25 million for the corresponding period in 2019. These increases were primarily due to an increase in non-service cost-related retirement benefits income. See Note (H) to the Condensed Financial Statements herein for additional information.
Income Taxes
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $4 | | 4.5 | | $26 | | 17.2 |
For year-to-date 2020, income taxes were $177 million compared to $151 million for the corresponding period in 2019. This increase was primarily due to higher pre-tax earnings.
Georgia Power
Net Income
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(140) | | (31.3) | | $(121) | | (15.9) |
Georgia Power's net income for the second quarter 2020 was $308 million compared to $448 million for the corresponding period in 2019. For year-to-date 2020, net income was $638 million compared to $759 million for the corresponding period in 2019. These decreases were primarily due to a $111 million after-tax charge in the second quarter 2020 related to the construction of Plant Vogtle Units 3 and 4 and impacts of the 2019 ARP effective January
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
1, 2020, including higher depreciation and amortization, largely offset by increased retail rates and lower income tax expense. Also contributing to the decreases were lower retail revenues associated with milder weather as compared to the corresponding periods in 2019 and decreased customer usage resulting from the COVID-19 pandemic, partially offset by related cost containment activities. See Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information on the construction of Plant Vogtle Units 3 and 4 and Note 2 to the financial statements under "Georgia Power" in Item 8 of the Form 10-K for additional information on the 2019 ARP.
Retail Revenues
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(186) | | (9.6) | | $(179) | | (5.0) |
In the second quarter 2020, retail revenues were $1.76 billion compared to $1.95 billion for the corresponding period in 2019. For year-to-date 2020, retail revenues were $3.44 billion compared to $3.61 billion for the corresponding period in 2019.
Details of the changes in retail revenues were as follows:
|
| | | | | | | | | | | | | |
| | Second Quarter 2020 | | Year-to-Date 2020 |
| | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | $ | 1,946 |
| | | | $ | 3,614 |
| | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 116 |
| | 5.9 | % | | 209 |
| | 5.8 | % |
| Sales decline | (63 | ) | | (3.2 | ) | | (47 | ) | | (1.3 | ) |
| Weather | (88 | ) | | (4.5 | ) | | (107 | ) | | (3.0 | ) |
| Fuel cost recovery | (151 | ) | | (7.8 | ) | | (234 | ) | | (6.5 | ) |
| Retail – current year | $ | 1,760 |
| | (9.6 | )% | | $ | 3,435 |
| | (5.0 | )% |
Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2020, when compared to the corresponding periods in 2019. These increases were primarily due to an increase in revenue recognized under the ECCR tariff effective January 1, 2020 as authorized in the 2019 ARP, the impacts of accruals in 2019 for customer refunds related to Tax Reform, and the rate pricing effects of decreased customer usage in 2020. Partially offsetting these increases were lower contributions from commercial and industrial customers with variable demand-driven pricing. See Note 2 to the financial statements under "Georgia Power" 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 2020 when compared to the corresponding periods in 2019 largely due to social distancing and shelter-in-place guidelines related to the COVID-19 pandemic. Weather-adjusted residential KWH sales increased 4.7% and 4.1% in the second quarter and year-to-date 2020, respectively, when compared to corresponding periods in 2019 due to customer growth and an increase in average customer usage, primarily due to the temporary suspension of customer disconnections for nonpayment and shelter-in-place orders. Weather-adjusted commercial KWH sales decreased 11.3% and 5.8% in the second quarter and year-to-date 2020, respectively, when compared to the corresponding periods in 2019 primarily due to lower customer usage resulting from shelter-in-place orders and restrictions on business operations in response to the COVID-19 pandemic. Weather-adjusted industrial KWH sales decreased 13.4% and 8.4% in the second quarter and year-to-date 2020, respectively, when compared to the corresponding periods in 2019 as a result of disruptions in supply chain and business operations related to the COVID-19 pandemic and the overall decrease in business activity due to the resulting recession.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues decreased in the second quarter and year-to-date 2020 when compared to the corresponding periods in 2019 due to lower fuel and purchased power costs. Electric rates include provisions to periodically 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 – "Regulatory Matters – Georgia Power – Fuel Cost Recovery" in Item 7 of the Form 10-K for additional information.
Wholesale Revenues
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(11) | | (30.6) | | $(16) | | (23.9) |
Wholesale revenues from sales to non-affiliates consist of PPAs and short-term opportunity sales. Wholesale revenues from PPAs have both capacity and energy components. Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amounts billable under the contract terms and provide for recovery of fixed costs and a return on investment. Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Georgia Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above Georgia Power's variable cost of energy.
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 costs.
In the second quarter 2020, wholesale revenues were $25 million compared to $36 million for the corresponding period in 2019. For year-to-date 2020, wholesale revenues were $51 million compared to $67 million for the corresponding period in 2019. These decreases were primarily due to lower market demand largely resulting from the expiration of a non-affiliate PPA and lower energy prices.
Other Revenues
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $8 | | 5.9 | | $(2) | | (0.7) |
In the second quarter 2020, other revenues were $143 million compared to $135 million for the corresponding period in 2019. The increase was primarily due to an increase of $14 million in unregulated sales associated with power delivery construction and maintenance contracts, partially offset by a decrease of $7 million in pole attachment revenues.
For year-to-date 2020, other revenues were $268 million compared to $270 million for the corresponding period in 2019. The decrease was primarily due to a $13 million decrease in pole attachment revenues and an $8 million decrease in retail customer fees largely resulting from the temporary suspension of customer disconnections and late fees related to the COVID-19 pandemic, substantially offset by an increase of $20 million in unregulated sales associated with power delivery construction and maintenance contracts and outdoor lighting.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | | | |
| | Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | (164 | ) | | (42.1 | ) | | $ | (231 | ) | | (33.5 | ) |
| Purchased power – non-affiliates | 9 |
| | 7.3 |
| | 20 |
| | 8.3 |
|
| Purchased power – affiliates | (12 | ) | | (9.0 | ) | | (59 | ) | | (19.0 | ) |
| Total fuel and purchased power expenses | $ | (167 | ) | | | | $ | (270 | ) | | |
In the second quarter 2020, total fuel and purchased power expenses were $481 million compared to $648 million for the corresponding period in 2019. For year-to-date 2020, total fuel and purchased power expenses were $971 million compared to $1.24 billion for the corresponding period in 2019. These decreases were due to decreases of $101 million and $193 million related to the average cost of fuel and purchased power and net decreases of $66 million and $77 million related to the volume of KWHs generated and purchased in second quarter and year-to-date 2020, respectively.
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 – "Regulatory Matters – Georgia Power – Fuel Cost Recovery" 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 2020 | | Second Quarter 2019 | | Year-to-Date 2020 | | Year-to-Date 2019 |
Total generation (in billions of KWHs) | 13 | | 16 | | 25 | | 29 |
Total purchased power (in billions of KWHs) | 8 | | 6 | | 16 | | 15 |
Sources of generation (percent) — | | | | | | | |
| Gas | 56 | | 45 | | 57 | | 47 |
| Nuclear | 32 | | 26 | | 30 | | 26 |
| Coal | 7 | | 26 | | 7 | | 23 |
| Hydro and other | 5 | | 3 | | 6 | | 4 |
Cost of fuel, generated (in cents per net KWH) — | | | | | | | |
| Gas | 2.11 | | 2.48 | | 2.11 | | 2.53 |
| Nuclear | 0.81 | | 0.81 | | 0.80 | | 0.81 |
| Coal | 3.37 | | 3.18 | | 3.60 | | 3.20 |
Average cost of fuel, generated (in cents per net KWH) | 1.76 | | 2.23 | | 1.82 | | 2.22 |
Average cost of purchased power (in cents per net KWH)(*) | 3.58 | | 4.59 | | 3.36 | | 4.23 |
| |
| (*) | 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 2020, fuel expense was $226 million compared to $390 million for the corresponding period in 2019. For year-to-date 2020, fuel expense was $458 million compared to $689 million for the corresponding period in 2019. The decreases for the second quarter and year-to-date 2020 were primarily due to decreases of 21.1% and 18.0%, respectively, in the average cost of fuel primarily related to lower cost of natural gas and decreases of 9.2% and 6.9%, respectively, in the volume of KWHs generated largely due to lower customer demand.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Purchased Power – Non-Affiliates
In the second quarter 2020, purchased power expense from non-affiliates was $133 million compared to $124 million for the corresponding period in 2019. For year-to-date 2020, purchased power expense from non-affiliates was $262 million compared to $242 million for the corresponding period in 2019. The increases for the second quarter and year-to-date 2020 were primarily due to increases of 11.0% and 24.6%, respectively, in the volume of KWHs purchased primarily due to the availability of lower cost market resources, largely offset by decreases of 6.0% and 12.4%, respectively, in the average cost per KWH purchased primarily due to lower energy prices.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the second quarter 2020, purchased power expense from affiliates was $122 million compared to $134 million for the corresponding period in 2019. For year-to-date 2020, purchased power expense from affiliates was $251 million compared to $310 million for the corresponding period in 2019. The decreases for the second quarter and year-to-date 2020 were primarily due to decreases of 32.8% and 29.0%, respectively, in the average cost per KWH purchased primarily resulting from lower energy prices and the expiration of a PPA. Partially offsetting the decrease in the second quarter 2020 was a 10.4% increase in the volume of KWHs purchased as Georgia Power units generally dispatched at a higher cost than other Southern Company system resources.
Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $— | | — | | $15 | | 1.6 |
In the second quarter 2020 and 2019, other operations and maintenance expenses were $463 million. Increases of $46 million in storm damage recovery as authorized in the 2019 ARP and $10 million in expenses from unregulated sales associated with power delivery construction and maintenance contracts were substantially offset by decreases of $22 million associated with generation maintenance and scheduled outages, $8 million associated with generation environmental projects, $7 million in customer accounts and sales costs, and $7 million in transmission-related expenses. These decreases reflect the impacts of cost containment activities implemented to help offset the effects of the recessionary economy resulting from the COVID-19 pandemic. Also contributing to the offset was a decrease of $8 million related to an adjustment in 2019 for FERC fees following the conclusion of a multi-year audit of headwater benefits associated with hydro facilities.
For year-to-date 2020, other operations and maintenance expenses were $928 million compared to $913 million for the corresponding period in 2019. The increase was primarily due to increases of $92 million in storm damage recovery as authorized in the 2019 ARP and $9 million in expenses from unregulated sales associated with power delivery construction and maintenance contracts, partially offset by decreases of $26 million associated with generation maintenance and scheduled outages, $18 million in distribution- and transmission-related expenses, and $9 million associated with generation environmental projects. These decreases reflect the impacts of cost containment activities implemented to help offset the effects of the recessionary economy resulting from the COVID-19 pandemic. Other expense reductions include a decrease of $15 million related to an adjustment in 2019 for FERC fees following the conclusion of a multi-year audit of headwater benefits associated with hydro facilities and an $11 million increase in nuclear property insurance refunds.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
See Note 2 to the financial statements under "Georgia Power – Storm Damage Recovery" in Item 8 of the Form 10-K for additional information.
Depreciation and Amortization
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $110 | | 45.1 | | $224 | | 46.4 |
In the second quarter 2020, depreciation and amortization was $354 million compared to $244 million for the corresponding period in 2019. For year-to-date 2020, depreciation and amortization was $707 million compared to $483 million for the corresponding period in 2019. These increases primarily reflect increased amortization of regulatory assets of $63 million and $127 million for the second quarter and year-to-date 2020, respectively, and higher depreciation of $44 million and $89 million for the second quarter and year-to-date 2020, respectively, as authorized in the 2019 ARP. See Note 2 to the financial statements under "Georgia Power – Rate Plans" and " – Integrated Resource Plan" in Item 8 of the Form 10-K for additional information.
Estimated Loss on Plant Vogtle Units 3 and 4
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $149 | | N/M | | $149 | | N/M |
N/M - Not meaningful
In the second quarter 2020, an estimated probable loss of $149 million was recorded to reflect Georgia Power's revised total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information.
Interest Expense, Net of Amounts Capitalized
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $— | | — | | $15 | | 7.5 |
In the second quarter 2020 and 2019, interest expense, net of amounts capitalized was $105 million. For year-to-date 2020, interest expense, net of amounts capitalized was $216 million compared to $201 million for the corresponding period in 2019. The increase for year-to-date 2020 was primarily due to a $25 million increase in interest expense associated with an increase in average outstanding long-term borrowings, partially offset by an $11 million increase in amounts capitalized in connection with the construction of Plant Vogtle Units 3 and 4. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings and Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
Other Income (Expense), Net
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $16 | | 45.7 | | $26 | | 33.8 |
In the second quarter 2020, other income (expense), net was $51 million compared to $35 million for the corresponding period in 2019. For year-to-date 2020, other income (expense), net was $103 million compared to $77 million for the corresponding period in 2019. The second quarter and year-to-date 2020 increases were
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
primarily due to increases of $11 million and $21 million, respectively, in non-service cost-related retirement benefits income and increases in AFUDC equity of $5 million and $9 million, respectively, primarily associated with the construction of Plant Vogtle Units 3 and 4. See Note (H) to the Condensed Financial Statements herein for additional information on retirement benefits and Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
Income Taxes
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(118) | | (91.5) | | $(184) | | (87.2) |
In the second quarter 2020, income taxes were $11 million compared to $129 million for the corresponding period in 2019. For year-to-date 2020, income taxes were $27 million compared to $211 million for the corresponding period in 2019. These decreases were primarily due to the flowback of excess deferred income taxes in 2020 as authorized in the 2019 ARP and lower pre-tax earnings primarily due to the second quarter 2020 charge associated with the construction of Plant Vogtle Units 3 and 4. See Note (B) under "Nuclear Construction" and Note (G) to the Condensed Financial Statements herein and Note 2 to the financial statements under "Georgia Power – Rate Plans – Tax Reform Settlement Agreement" in Item 8 of the Form 10-K for additional information.
Mississippi Power
Net Income
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $2 | | 5.4 | | $(3) | | (4.1) |
Mississippi Power's net income for the second quarter 2020 was $39 million compared to $37 million for the corresponding period in 2019. The increase was primarily due to a decrease in amortization associated with ECO Plan regulatory assets and a decrease in scheduled generation outage costs, partially offset by a decrease in base rates that became effective for the first billing cycle of April 2020 and a decrease in revenues due to the COVID-19 pandemic.
For year-to-date 2020, net income was $71 million compared to $74 million for the corresponding period in 2019. The decrease was primarily due to a decrease in base rates that became effective for the first billing cycle of April 2020, a decrease in revenues due to the COVID-19 pandemic, and an increase in scheduled generation outage costs, partially offset by a decrease in amortization associated with ECO Plan regulatory assets.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Mississippi Power – 2019 Base Rate Case" herein and Note 2 to the financial statements under "Mississippi Power – Environmental Compliance Overview Plan" in Item 8 of the Form 10-K for additional information.
Retail Revenues
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(16) | | (7.4) | | $(20) | | (4.8) |
In the second quarter 2020, retail revenues were $199 million compared to $215 million for the corresponding period in 2019. For year-to-date 2020, retail revenues were $398 million compared to $418 million for the corresponding period in 2019.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of the changes in retail revenues were as follows:
|
| | | | | | | | | | | | | |
| | Second Quarter 2020 | | Year-to-Date 2020 |
| | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | $ | 215 |
| | | | $ | 418 |
| | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | (4 | ) | | (1.9 | )% | | (5 | ) | | (1.2 | )% |
| Sales decline | (5 | ) | | (2.3 | ) | | (7 | ) | | (1.7 | ) |
| Weather | (4 | ) | | (1.9 | ) | | 1 |
| | 0.2 |
|
| Fuel and other cost recovery | (3 | ) | | (1.3 | ) | | (9 | ) | | (2.1 | ) |
| Retail – current year | $ | 199 |
| | (7.4 | )% | | $ | 398 |
| | (4.8 | )% |
Revenues associated with changes in rates and pricing decreased in the second quarter and year-to-date 2020 when compared to the corresponding periods in 2019 primarily due to decreases in PEP and ECO Plan rates that became effective for the first billing cycle of April 2020, partially offset by revenue associated with a tolling arrangement. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Mississippi Power – 2019 Base Rate Case" herein for additional information.
Revenues attributable to changes in sales decreased in the second quarter and year-to-date 2020 when compared to the corresponding periods in 2019 largely due to lower overall customer usage resulting from shelter-in-place orders and restrictions on business operations in response to the COVID-19 pandemic.
Weather-adjusted residential KWH sales increased 5.4% and 2.3% in the second quarter and year-to-date 2020, respectively, primarily due to customer growth and an increase in average customer usage as a result of shelter-in-place orders and the temporary suspension of customer disconnections. Weather-adjusted commercial KWH sales decreased 11.6% and 7.9% in the second quarter and year-to-date 2020, respectively, primarily due to lower customer usage resulting from shelter-in-place orders and restrictions on business operations, including the temporary closure of casinos, in response to the COVID-19 pandemic. Industrial KWH sales decreased 7.0% and 1.3% in the second quarter and year-to-date 2020, respectively, as a result of disruptions in supply chain and business operations driven by the COVID-19 pandemic and the overall decrease in business activity due to the resulting recession.
Fuel and other cost recovery revenues decreased in the second quarter and year-to-date 2020 when compared to the corresponding periods in 2019 primarily as a result of lower recoverable fuel costs. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power's service territory. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income.
Wholesale Revenues – Non-Affiliates
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(5) | | (8.8) | | $(11) | | (9.6) |
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Mississippi Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. In addition, Mississippi Power provides service under long-term contracts with rural electric cooperative associations
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
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 – "Regulatory Matters – Mississippi Power" in Item 7 of the Form 10-K for additional information.
In the second quarter 2020, wholesale revenues from sales to non-affiliates were $52 million compared to $57 million for the corresponding period in 2019. For year-to-date 2020, wholesale revenues from sales to non-affiliates were $103 million compared to $114 million for the corresponding period in 2019. These decreases were primarily due to decreases in revenue from MRA customers as a result of lower fuel costs and milder weather, as well as fewer opportunity sales.
Wholesale Revenues – Affiliates
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(12) | | (32.4) | | $(11) | | (19.0) |
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.
In the second quarter 2020, wholesale revenues from sales to affiliates were $25 million compared to $37 million for the corresponding period in 2019. For year-to-date 2020, wholesale revenues from sales to affiliates were $47 million compared to $58 million for the corresponding period in 2019. These decreases were primarily due to decreases of $18 million and $26 million in the second quarter and year-to-date 2020, respectively, associated with lower natural gas prices, partially offset by increases of $6 million and $14 million in the second quarter and year-to-date 2020, respectively, associated with higher KWH sales due to the dispatch of Mississippi Power's lower cost generation resources to serve the Southern Company system's territorial load.
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | |
| | Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | (22 | ) | | (21.0) | | $ | (36 | ) | | (18.2) |
| Purchased power | 1 |
| | 16.7 | | 3 |
| | 33.3 |
| Total fuel and purchased power expenses | $ | (21 | ) | | | | $ | (33 | ) | | |
In the second quarter 2020, total fuel and purchased power expenses were $90 million compared to $111 million for the corresponding period in 2019. The decrease was primarily due to a $20 million decrease related to the cost of fuel primarily due to the lower average cost of natural gas.
For year-to-date 2020, total fuel and purchased power expenses were $174 million compared to $207 million for the corresponding period in 2019. The decrease was primarily due to a $42 million decrease related to the cost of fuel and purchased power primarily due to the lower average cost of natural gas, partially offset by a $9 million increase associated with the volume of KWHs generated and purchased.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Mississippi Power's fuel cost recovery clause.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of Mississippi Power's generation and purchased power were as follows:
|
| | | | | | | |
| | Second Quarter 2020 | | Second Quarter 2019 | | Year-to-Date 2020 | | Year-to-Date 2019 |
Total generation (in millions of KWHs) | 4,484 | | 4,621 | | 8,651 | | 8,570 |
Total purchased power (in millions of KWHs) | 208 | | 152 | | 396 | | 243 |
Sources of generation (percent) – | | | | | | | |
| Coal | 4 | | 8 | | 4 | | 6 |
| Gas | 96 | | 92 | | 96 | | 94 |
Cost of fuel, generated (in cents per net KWH) – | | | | | | | |
| Coal | 3.82 | | 3.92 | | 4.02 | | 4.06 |
| Gas | 1.88 | | 2.29 | | 1.92 | | 2.37 |
Average cost of fuel, generated (in cents per net KWH) | 1.97 | | 2.43 | | 2.00 | | 2.48 |
Average cost of purchased power (in cents per net KWH) | 3.27 | | 3.78 | | 2.97 | | 3.76 |
Fuel
In the second quarter 2020, fuel expense was $83 million compared to $105 million for the corresponding period in 2019. This decrease was due to a 19.0% decrease in the average cost of fuel per KWH generated and a 2.6% decrease in the volume of KWHs generated.
For year-to-date 2020, fuel expense was $162 million compared to $198 million for the corresponding period in 2019. This decrease was due to a 19.5% decrease in the average cost of fuel per KWH generated, partially offset by a 1.8% increase in the volume of KWHs generated.
Purchased Power
In the second quarter 2020, purchased power expense was $7 million compared to $6 million for the corresponding period in 2019. For year-to-date 2020, purchased power expense was $12 million compared to $9 million for the corresponding period in 2019. These increases were primarily the result of 36.3% and 63.2% increases in the volume of KWHs purchased in the second quarter and year-to-date 2020, respectively, largely offset by 13.5% and 20.9% decreases in the average cost per KWH purchased in the second quarter and year-to-date 2020, respectively.
Energy purchases 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. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(5) | | (6.9) | | $9 | | 6.8 |
In the second quarter 2020, other operations and maintenance expenses were $67 million compared to $72 million for the corresponding period in 2019. The decrease was primarily due to a decrease of $5 million in scheduled generation outage costs.
For year-to-date 2020, other operations and maintenance expenses were $142 million compared to $133 million for the corresponding period in 2019. The increase was primarily due to increases of $5 million in scheduled generation outage costs, $3 million in vegetation management expenses, and $2 million in certain employee compensation expenses previously deferred in 2019.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Depreciation and Amortization
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(2) | | (4.2) | | $(7) | | (7.4) |
In the second quarter 2020, depreciation and amortization was $46 million compared to $48 million for the corresponding period in 2019. For year-to-date 2020, depreciation and amortization was $88 million compared to $95 million for the corresponding period in 2019. These decreases were related to decreases in amortization of $8 million and $14 million in the second quarter and year-to-date 2020, respectively, primarily as a result of the ECO Plan regulatory assets being fully amortized in 2019, partially offset by amortization of a regulatory asset associated with an ARO. These decreases were partially offset by increases in depreciation of $6 million and $7 million in the second quarter and year-to-date 2020, respectively, primarily related to additional plant in service and an increase in depreciation rates in accordance with the Mississippi Power Rate Case Settlement Agreement. See Note (B) to the Condensed Financial Statements under "Mississippi Power – 2019 Base Rate Case" herein and Note 2 to the financial statements under "Mississippi Power – Environmental Compliance Overview Plan" in Item 8 of the Form 10-K for additional information.
Income Taxes
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(3) | | (60.0) | | $(4) | | (33.3) |
In the second quarter 2020, income taxes were $2 million compared to $5 million for the corresponding period in 2019. For year-to-date 2020, income taxes were $8 million compared to $12 million for the corresponding period in 2019. These decreases were primarily due to a decrease of $3 million in both the second quarter and year-to-date 2020 associated with the flowback of excess deferred income taxes as a result of the Mississippi Power Rate Case Settlement Agreement. See Note (G) to the Condensed Financial Statements herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Southern Power
Net Income Attributable to Southern Power
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(111) | | (63.8) | | $(92) | | (40.0) |
Net income attributable to Southern Power for the second quarter 2020 was $63 million compared to $174 million for the corresponding period in 2019. The decrease was primarily due to the gain on the sale of Plant Nacogdoches in the second quarter 2019 of $88 million after tax. In addition, the decrease was due to reduced net income related to the dispositions of Plant Nacogdoches in 2019 and Plant Mankato in the first quarter 2020. The decrease also reflects net gains in the second quarter 2019 totaling $22 million from the Roserock solar facility litigation settlement and sales of wind equipment.
Net income attributable to Southern Power for year-to-date 2020 was $138 million compared to $230 million for the corresponding period in 2019. The decrease was primarily due to the gain on the sale of Plant Nacogdoches in the second quarter 2019 of $88 million after tax, partially offset by the gain on sale of Plant Mankato in the first quarter 2020 of $23 million after tax. In addition, the decrease was due to reduced net income related to the dispositions of Plant Nacogdoches and Plant Mankato. The decrease also reflects net gains in the second quarter 2019 totaling $22 million from the Roserock solar facility litigation settlement and sales of wind equipment.
See Note (K) to the Condensed Financial Statements under "Southern Power" herein and Note 15 to the financial statements under "Southern Power" in Item 8 of the Form 10-K for additional information.
Operating Revenues
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(71) | | (13.9) | | $(139) | | (14.6) |
Total operating revenues include PPA capacity revenues, which are derived primarily from long-term contracts involving natural gas facilities and a biomass generating facility (through the second quarter 2019 sale of Plant Nacogdoches), and PPA energy revenues from Southern Power's generation facilities. To the extent Southern Power has capacity not contracted under a PPA, it may sell power into an accessible wholesale market, or, to the extent those generation assets are part of the FERC-approved IIC, it may sell power into the Southern Company power pool.
Natural Gas and Biomass Capacity and Energy Revenue
Capacity revenues generally represent the greatest contribution to operating income and are designed to provide recovery of fixed costs plus a return on investment.
Energy is generally sold at variable cost or is indexed to published natural 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 energy sales from solar and wind generating facilities are predominantly through long-term PPAs that do not have capacity revenue. Customers either purchase the energy output of a dedicated renewable facility through an energy charge or pay a fixed price related to the energy generated from the respective facility and sold to
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
the grid. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors.
See FUTURE EARNINGS POTENTIAL – "Southern Power's Power Sales Agreements" herein for additional information regarding Southern Power's PPAs.
Operating Revenues Details
Details of Southern Power's operating revenues were as follows:
|
| | | | | | | | | | | | | | | |
| | Second Quarter 2020 | | Second Quarter 2019 | | Year-to-Date 2020 | | Year-to-Date 2019 |
| | (in millions) |
| PPA capacity revenues | $ | 92 |
| | $ | 125 |
| | $ | 181 |
| | $ | 252 |
|
| PPA energy revenues | 270 |
| | 291 |
| | 475 |
| | 518 |
|
| Total PPA revenues | 362 |
| | 416 |
| | 656 |
| | 770 |
|
| Non-PPA revenues | 73 |
| | 91 |
| | 151 |
| | 177 |
|
| Other revenues | 4 |
| | 3 |
| | 7 |
| | 6 |
|
| Total operating revenues | $ | 439 |
| | $ | 510 |
| | $ | 814 |
| | $ | 953 |
|
In the second quarter 2020, total operating revenues were $439 million, reflecting a $71 million, or 14%, decrease from the corresponding period in 2019. The decrease in operating revenues was primarily due to the following:
PPA capacity revenues decreased $33 million, or 26%, primarily due to decreases of $22 million related to the dispositions of Plant Nacogdoches in the second quarter 2019 and Plant Mankato in the first quarter 2020 and $10 million from the contractual expiration of an affiliate natural gas PPA.
PPA energy revenues decreased $21 million, or 7%, due to a $46 million decrease in sales from natural gas facilities resulting from a $25 million decrease in the volume of KWHs sold due to reduced demand and a $21 million decrease in the average cost of fuel and purchased power. This decrease was partially offset by a $13 million increase in sales primarily driven by the volume of KWHs generated by solar and wind facilities and a $12 million increase in sales from a fuel cell project acquired in late 2019.
Non-PPA revenues decreased $18 million, or 20%, due to a $40 million decrease in the market price of energy, partially offset by a $23 million increase in the volume of KWHs sold through short-term sales.
For year-to-date 2020, total operating revenues were $814 million, reflecting a $139 million, or 15%, decrease from the corresponding period in 2019. The decrease in operating revenues was primarily due to the following:
PPA capacity revenues decreased $71 million, or 28%, primarily due to decreases of $45 million related to the dispositions of Plant Nacogdoches in the second quarter 2019 and Plant Mankato in the first quarter 2020 and $24 million from the contractual expiration of an affiliate natural gas PPA.
PPA energy revenues decreased $43 million, or 8%, due to an $86 million decrease in sales from natural gas facilities resulting from a $49 million decrease in the price of fuel and purchased power and a $37 million decrease in the volume of KWHs sold due to reduced demand. This decrease was partially offset by increases of $23 million in sales primarily driven by the volume of KWHs generated by solar and wind facilities and $20 million in sales from a fuel cell project acquired in late 2019.
Non-PPA revenues decreased $26 million, or 15%, due to a $74 million decrease in the market price of energy, partially offset by a $48 million increase in the volume of KWHs sold through short-term sales.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Fuel and Purchased Power Expenses
Details of Southern Power's generation and purchased power were as follows:
|
| | | | | |
| | Second Quarter 2020 | Second Quarter 2019 | | Year-to-Date 2020 | Year-to-Date 2019 |
| | (in billions of KWHs) |
| Generation | 11.3 | 11.7 | | 22.0 | 21.9 |
| Purchased power | 0.9 | 1.0 | | 1.5 | 1.8 |
| Total generation and purchased power | 12.2 | 12.7 | | 23.5 | 23.7 |
| | | | | | |
| Total generation and purchased power, excluding solar, wind, and tolling agreements | 7.4 | 7.1 | | 14.5 | 13.7 |
Southern Power's PPAs for natural gas 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 Southern Company power pool for capacity owned directly by Southern 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 Southern Company power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power, an affiliate company, or external parties. Such purchased power costs are generally recovered through PPA revenues.
Details of Southern Power's fuel and purchased power expenses were as follows:
|
| | | | | | | | | | | |
| | Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | (37 | ) | | (26.6) | | $ | (75 | ) | | (26.4) |
| Purchased power | (14 | ) | | (43.8) | | (23 | ) | | (41.8) |
| Total fuel and purchased power expenses | $ | (51 | ) | | | | $ | (98 | ) | | |
In the second quarter 2020, total fuel and purchased power expenses decreased $51 million, or 30%, compared to the corresponding period in 2019. Fuel expense decreased $37 million due to a $46 million decrease in the average cost of fuel per KWH generated, partially offset by a $9 million increase associated with the volume of KWHs generated. Purchased power expense decreased $14 million due to a $9 million decrease associated with the average cost of purchased power and a $5 million decrease associated with the volume of KWHs purchased.
For year-to-date 2020, total fuel and purchased power expenses decreased $98 million, or 29%, compared to the corresponding period in 2019. Fuel expense decreased $75 million due to a $98 million decrease in the average cost of fuel per KWH generated, partially offset by a $23 million increase associated with the volume of KWHs generated. Purchased power expense decreased $23 million due to a $16 million decrease associated with the average cost of purchased power and a $7 million decrease associated with the volume of KWHs purchased.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
(Gain) Loss on Dispositions, Net
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $23 | | N/M | | $(16) | | N/M |
N/M - Not meaningful
In the second quarter 2020, loss on dispositions, net was immaterial compared to a gain on dispositions, net of $23 million for the corresponding period in 2019. For year-to-date 2020, gain on dispositions, net was $39 million compared to $23 million for the corresponding period in 2019. The changes were due to the sale of Plant Mankato in the first quarter 2020, which resulted in a $39 million gain, and the sale of Plant Nacogdoches in the second quarter 2019, which resulted in a $23 million gain. See Note (K) to the Condensed Financial Statements herein and Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power – Sales of Natural Gas and Biomass Plants" for additional information.
Other Income (Expense), Net |
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(39) | | (97.5) | | $(37) | | (90.2) |
In the second quarter 2020, other income (expense), net was $1 million compared to $40 million for the corresponding period in 2019. For year-to-date 2020, other income (expense), net was $4 million compared to $41 million for the corresponding period in 2019. The decreases were primarily due to a $36 million gain arising from the Roserock solar facility litigation settlement in the second quarter 2019. See Note 3 to the financial statements in Item 8 of the Form 10-K under "General Litigation Matters – Southern Power" for additional information.
Income Taxes (Benefit)
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $57 | | 111.8 | | $73 | | 121.7 |
In the second quarter 2020, income tax expense was $6 million compared to a $51 million benefit for the corresponding period in 2019. For year-to-date 2020, income tax expense was $13 million compared to a $60 million benefit for the corresponding period in 2019. The changes were primarily due to a $75 million income tax benefit in 2019 resulting from ITCs recognized upon the sale of Plant Nacogdoches, partially offset by a decrease in income tax expense as a result of lower pre-tax earnings. See Notes (G) and (K) to the Condensed Financial Statements herein for additional information.
Net Income (Loss) Attributable to Noncontrolling Interests
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(24) | | N/M | | $(26) | | N/M |
In the second quarter 2020, net income attributable to noncontrolling interests was $5 million compared to $29 million for the corresponding period in 2019. For year-to-date 2020, net loss attributable to noncontrolling interests was $26 million compared to an immaterial amount for the corresponding period in 2019. The changes were primarily due to an allocation of approximately $26 million of income to the noncontrolling interest partner related to the Roserock solar facility litigation settlement in the second quarter 2019. See Note 3 to the financial statements in Item 8 of the Form 10-K under "General Litigation Matters – Southern Power" for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Southern Company Gas
Operating Metrics
Southern Company Gas continues to focus on several operating metrics, including Heating Degree Days, customer count, and volumes of natural gas sold.
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. Southern Company Gas has various regulatory mechanisms, such as weather and revenue normalization and straight-fixed-variable rate design, which limit its exposure to weather changes within typical ranges in each of its utility's respective service territory, including Nicor Gas following the approval of a revenue decoupling mechanism for residential customers in its base rate case that concluded in 2019. Southern Company Gas also utilizes weather hedges to limit the negative income impacts in the event of warmer-than-normal weather.
The number of customers served by gas distribution operations and gas marketing services can be impacted by natural gas prices, economic conditions, and competition from alternative fuels. Gas distribution operations and gas marketing services' customers are primarily located in Georgia, Illinois, and Ohio.
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 Heating Season, natural gas usage and operating revenues are generally higher as more customers are connected to the gas distribution systems and natural gas usage is higher in periods of colder weather. Occasionally in the summer, wholesale gas services' operating revenues are impacted due to peak usage by power generators in response to summer energy demands. Southern Company Gas' base operating expenses, excluding cost of natural gas, bad debt expense, and certain incentive compensation costs, are incurred relatively evenly throughout the year. Seasonality also affects the comparison of certain balance sheet items across quarters, including receivables, unbilled revenues, natural gas for sale, and notes payable. However, these items are comparable when reviewing Southern Company Gas' annual results. Thus, Southern Company Gas' operating results for the interim periods presented are not necessarily indicative of annual results and can vary significantly from quarter to quarter.
Net Income
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(35) | | (33.0) | | $(30) | | (8.0) |
In the second quarter 2020, net income was $71 million compared to $106 million for the corresponding period in 2019. This decrease was primarily due to a $46 million decrease at wholesale gas services primarily due to reduced natural gas price volatility compared to the prior year and a $7 million gain from the sale of Triton in 2019, partially offset by a $16 million increase at gas distribution operations primarily due to base rate increases for Nicor Gas and Atlanta Gas Light and continued investment in infrastructure replacement programs, partially offset by reduced flowback of excess deferred income taxes at Atlanta Gas Light in 2020.
For year-to-date 2020, net income was $346 million compared to $376 million for the corresponding period in 2019. This decrease in net income was primarily due to a $70 million decrease at wholesale gas services primarily due to reduced natural gas price volatility compared to the prior year and a $7 million gain from the sale of Triton in 2019, partially offset by a $47 million increase at gas distribution operations primarily due to base rate increases for Nicor Gas and Atlanta Gas Light and continued investment in infrastructure replacement programs, partially offset by reduced flowback of excess deferred income taxes at Atlanta Gas Light in 2020.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
See Note 2 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Natural Gas Revenues, including Alternative Revenue Programs
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(53) | | (7.7) | | $(278) | | (12.9) |
In the second quarter 2020, natural gas revenues, including alternative revenue programs, were $636 million compared to $689 million for the corresponding period in 2019. For year-to-date 2020, natural gas revenues, including alternative revenue programs, were $1.9 billion compared to $2.2 billion for the corresponding period in 2019.
Details of the changes in natural gas revenues, including alternative revenue programs, were as follows:
|
| | | | | | | | | | | | | |
| | Second Quarter 2020 | | Year-to-Date 2020 |
| | (in millions) | | (% change) | | (in millions) | | (% change) |
| Natural gas revenues – prior year | $ | 689 |
|
|
|
| $ | 2,163 |
|
|
|
|
| Estimated change resulting from – | | | | | | | |
| Infrastructure replacement programs and base rate changes | 43 |
|
| 6.2 | % |
| 119 |
|
| 5.5 | % |
| Gas costs and other cost recovery | (38 | ) |
| (5.5 | ) |
| (287 | ) |
| (13.3 | ) |
| Weather | 3 |
|
| 0.4 |
|
| (8 | ) |
| (0.4 | ) |
| Wholesale gas services | (67 | ) |
| (9.7 | ) |
| (102 | ) |
| (4.7 | ) |
| Other | 6 |
|
| 0.9 |
|
| — |
|
| — |
|
| Natural gas revenues – current year | $ | 636 |
| | (7.7 | )% | | $ | 1,885 |
| | (12.9 | )% |
Revenues from infrastructure replacement programs and base rate changes increased in the second quarter and year-to-date 2020 compared to the corresponding periods in 2019 primarily due to base rate increases at Nicor Gas and Atlanta Gas Light and continued investments recovered through infrastructure replacement programs. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" in Item 8 of the Form 10-K for additional information.
Revenues associated with gas costs and other cost recovery decreased in the second quarter and year-to-date 2020 compared to the corresponding periods in 2019 primarily due to lower natural gas prices and decreased volumes of natural gas sold. Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations. See "Cost of Natural Gas" herein for additional information. Revenue impacts from weather and customer growth are described further below.
Revenues from wholesale gas services decreased in the second quarter and year-to-date 2020 compared to the corresponding periods in 2019 primarily due to decreased commercial activity as a result of warmer weather and a decrease in derivative gains. See "Segment Information – Wholesale Gas Services" herein for additional information.
Southern Company Gas hedged the majority of its exposure to warmer-than-normal weather in Illinois for gas distribution operations and in Illinois and Georgia for gas marketing services. During Heating Season, natural gas usage and operating revenues are generally higher. Weather typically does not have a significant net income impact other than during the non-HeatingHeating 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.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
|
| | | | | | | | | | | | | | | |
| | | Year-to-Date | | 2017
vs.
2016 | | 2017
vs.
normal |
| | | Normal(a) | | 2017 | | 2016 | | (warmer) | | (warmer) |
Illinois(b) | | 3,817 |
| | 3,146 |
| | 3,353 |
| | (6.2 | )% | | (17.6 | )% |
| Georgia | | 1,631 |
| | 1,008 |
| | 1,449 |
| | (30.4 | )% | | (38.2 | )% |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Second Quarter | | 2020
vs.
normal | 2020
vs.
2019 | | Year-to-Date | | 2020 vs. normal | 2020 vs. 2019 |
| | Normal(a) | 2020 | 2019 | | colder | colder | | Normal(a) | 2020 | 2019 | | (warmer) | (warmer) |
| | (in thousands) | | | | | (in thousands) | | | |
Illinois(b) | 631 |
| 736 |
| 659 |
| | 16.6 | % | 11.7 | % | | 3,684 |
| 3,495 |
| 3,956 |
| | (5.1 | )% | (11.7 | )% |
| Georgia | 114 |
| 188 |
| 86 |
| | 64.9 | % | 118.6 | % | | 1,529 |
| 1,279 |
| 1,298 |
| | (16.4 | )% | (1.5 | )% |
| |
| (a) | Normal represents the 10-year average from January 1, 20072010 through SeptemberJune 30, 20162019 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 thein Illinois Commissionare expected to have a limited financial impact beginning in 2020. In October 2019, Nicor Gas' 2009Gas received approval for a volume balancing adjustment, a revenue decoupling mechanism for residential customers that provides a monthly benchmark level of revenue per rate case is 3,580class for the first nine months from 1998 through 2007.recovery. |
For the third quarters 2017 and 2016, the weather-related pre-tax income impact was immaterial.
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 $6 million ($3 million after tax) and $7 million ($5 million after tax) for year-to-date 2017 and 2016, respectively. Southern Company Gas also hedged its exposure at gas marketing services to warmer-than-normal weather in Georgia and Illinois;
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
therefore, the weather-related negative pre-tax income impact on gas marketing services was limited to $10 million ($6 million after tax) for year-to-date 2017 and there was no impact for year-to-date 2016.
The following table provides the number of customers served by Southern Company Gas at SeptemberJune 30, 20172020 and 2016:2019:
| | | | September 30, | | | June 30, | | |
| | 2017 | | 2016 | | 2017 vs. 2016 | 2020 | | 2019 | | 2020 vs. 2019 |
| | (in thousands, except market share %) | | (% change) | (in thousands, except market share %) | | (% change) |
| Gas distribution operations | 4,555 |
| | 4,522 |
| | 0.7 | % | 4,275 |
| | 4,231 |
| | 1.0 | % |
| Gas marketing services | | | | | | | | | | |
Energy customers(*) | 756 |
| | 626 |
| | 20.8 | % | 671 |
| | 622 |
| | 7.9 | % |
| Market share of energy customers in Georgia | 28.8 | % | | 29.4 | % | | | 29.0 | % | | 28.8 | % | |
|
|
| Service contracts | 1,183 |
| | 1,189 |
| | (0.5 | )% | |
| |
| (*) | Includes approximately 140,000Gas marketing services' customers are primarily located in Georgia, Ohio, and Illinois. Also included as of SeptemberJune 30, 2017 that2020 were approximately 50,000 customers in Ohio contracted through an annual auction process to serve for 12 months beginning April 1, 2017.2020. |
Southern Company Gas anticipates overall customer growth trends atin gas distribution operations to continue as it expects continued improvement in the new housing market and low natural gas prices.
Gas marketing services' market share in Georgia decreased at September 30, 2017 compared to the corresponding period in 2016 as a result of a highly competitive marketing environment, which Southern Company Gas expectsuses a variety of targeted marketing programs to continue for the foreseeable future. Southern Company Gas will continue efforts at gas marketing services to enter into targeted markets and expand its energyattract new customers and service contracts.to retain existing customers.
Cost of Natural Gas
|
| | |
| Successor |
| Third Quarter 2017 vs. Third Quarter 2016 |
| (change in millions) | | (% change) |
| $1 | | 0.8 |
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(47) | | (24.6) | | $(294) | | (33.5) |
In the third quarter 2017, cost ofExcluding Atlanta Gas Light, which does not sell natural gas was $134 million compared to $133 million for the corresponding period in 2016. This increase reflected 7% higherend-use customers, natural gas prices during the third quarter 2017 compared to the corresponding period in 2016, partially offset by lower demand for natural gas.
|
| | | | | | | | | | | | | |
| | | Successor | | | Predecessor |
| | | Year-to-Date 2017 | | July 1, 2016 through September 30, 2016 | | | January 1, 2016 through June 30, 2016 |
| | | (in millions) | | (in millions) | | | (in millions) |
| Cost of natural gas | | $ | 1,085 |
| | $ | 133 |
| | | $ | 755 |
|
Cost of natural gas primarily reflected an increase of 38% in natural gas prices during the 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, recoverablegas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations. Cost of natural gas at gas distribution operations represented approximately 79%86% of total cost of natural gas for both the second quarter and year-to-date 2017 and will be recovered in this manner. For additional information, see2020. See MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – "Cost"Southern Company Gas – Cost of Natural Gas" of Southern Company Gas in Item 7 of the Form 10-K and "Natural Gas Revenues, including Alternative Revenue Programs" herein.herein for additional information.
In the second quarter 2020, cost of natural gas was $144 million compared to $191 million for the corresponding period in 2019. This decrease reflects a 34.9% decrease in natural gas prices in the second quarter 2020 compared to the corresponding period in 2019.
For year-to-date 2020, cost of natural gas was $583 million compared to $877 million for the corresponding period in 2019. This decrease reflects a 36.6% decrease in natural gas prices compared to 2019 and decreased volumes primarily as a result of warmer weather for year-to-date 2020 compared to the corresponding period in 2019.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
(Continued)
The following table details the volumes of natural gas sold during all periods presented.
| | | | Third Quarter | | 2017
vs.
2016 | | Year-to-Date | | 2017
vs.
2016 | Second Quarter | 2020 vs. 2019 | | Year-to-Date | 2020 vs. 2019 |
| | 2017 | | 2016 | | % Change | | 2017 | | 2016 | | % Change | 2020 | 2019 | | 2020 | 2019 |
Gas distribution operations
(mmBtu in millions) | | | | | | | | | | | | Gas distribution operations (mmBtu in millions) | | | |
| Firm | 73 |
| | 71 |
| | 2.8 | % | | 438 |
| | 467 |
| | (6.2 | )% | 100 |
| 99 |
| 1.0 | % | | 357 |
| 396 |
| (9.8 | )% |
| Interruptible | 22 |
| | 22 |
| | — | % | | 71 |
| | 71 |
| | — | % | 21 |
| 22 |
| (4.5 | ) | | 45 |
| 46 |
| (2.2 | ) |
| Total | 95 |
| | 93 |
| | 2.2 | % | | 509 |
| | 538 |
| | (5.4 | )% | 121 |
| 121 |
| — | % | | 402 |
| 442 |
| (9.0 | )% |
Wholesale gas services (mmBtu in millions/day) | | Wholesale gas services (mmBtu in millions/day) | | | |
| Daily physical sales | | 6.4 |
| 5.7 |
| 12.3 | % | | 6.6 |
| 6.3 |
| 4.8 | % |
Gas marketing services
(mmBtu in millions) | | | | | | | | | | | | Gas marketing services (mmBtu in millions) | |
| | |
|
| Firm: | | | | | | | | | | | | |
|
| | |
|
|
| Georgia | 3 |
| | 3 |
| | — | % | | 11 |
| | 25 |
| | (56.0 | )% | 4 |
| 4 |
| — | % | | 18 |
| 19 |
| (5.3 | )% |
| Illinois | 1 |
| | 1 |
| | — | % | | 4 |
| | 8 |
| | (50.0 | )% | 1 |
| 2 |
| (50.0 | ) | | 6 |
| 8 |
| (25.0 | ) |
| Other emerging markets | 2 |
| | 2 |
| | — | % | | 7 |
| | 9 |
| | (22.2 | )% | |
| Interruptible: | | | | | | | | | | | | |
| Large commercial and industrial | 3 |
| | 3 |
| | — | % | | 8 |
| | 10 |
| | (20.0 | )% | |
| Other | | 3 |
| 2 |
| 50.0 |
| | 7 |
| 10 |
| (30.0 | ) |
| Interruptible large commercial and industrial | | 3 |
| 3 |
| — |
| | 7 |
| 7 |
| — |
|
| Total | 9 |
| | 9 |
| | — | % | | 30 |
| | 52 |
| | (42.3 | )% | 11 |
| 11 |
| — | % | | 38 |
| 44 |
| (13.6 | )% |
Wholesale gas services
(mmBtu in millions/day) | | | | | | | | | | | | |
| Daily physical sales | 6.3 |
| | 7.6 |
| | (17.1 | )% | | 6.4 |
| | 7.6 |
| | (15.8 | )% | |
Other Operations and Maintenance Expenses
|
| | |
| Successor |
| Third Quarter 2017 vs. Third Quarter 2016 |
| (change in millions) | | (% change) |
| $(11) | | (5.1) |
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $21 | | 10.6 | | $46 | | 10.6 |
In the thirdsecond quarter 2017,2020, other operations and maintenance expenses were $205$220 million compared to $216$199 million for the corresponding period in 2016. The decrease was primarily related to $8 million of expenses associated with certain benefit arrangements recorded in 2016, $2 million lower marketing expenses at gas marketing services, and a $3 million decrease in other employee benefit and incentive costs. |
| | | | | | | | | | | | | |
| | | Successor | | | Predecessor |
| | | Year-to-Date 2017 | | July 1, 2016 through September 30, 2016 | | | January 1, 2016 through June 30, 2016 |
| | | (in millions) | | (in millions) | | | (in millions) |
| Other operations and maintenance | | $ | 671 |
| | $ | 216 |
| | | $ | 454 |
|
Other operations and maintenance expenses for the successor2019. For year-to-date 2017 reflected increased compensation expenses due to timing, partially offset by low bad debt expense. For all periods presented,2020, other operations and maintenance expenses primarily includes professional services, including pipeline compliance and maintenance and legal services, as well as compensation and benefit costs.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Depreciation and Amortization
|
| | |
| Successor |
| Third Quarter 2017 vs. Third Quarter 2016 |
| (change in millions) | | (% change) |
| $9 | | 7.8 |
In the third quarter 2017, depreciation and amortization was $125were $479 million compared to $116$433 million for the corresponding period in 2016. The increase was2019. These increases were primarily due to $7 millionincreases in additional depreciation at gas distribution operations associated with additional plant in servicecompensation and benefit expenses and expenses passed through directly to customers primarily related to continued investment in infrastructure replacement programs.
|
| | | | | | | | | | | | | |
| | | Successor | | | Predecessor |
| | | Year-to-Date 2017 | | July 1, 2016 through September 30, 2016 | | | January 1, 2016 through June 30, 2016 |
| | | (in millions) | | (in millions) | | | (in millions) |
| Depreciation and amortization | | $ | 370 |
| | $ | 116 |
| | | $ | 206 |
|
Depreciationbad debt and amortizationpipeline compliance and maintenance activities. See Note (H) to the Condensed Financial Statements herein for the successor year-to-date 2017 included $29 million of additional amortization of intangible assets established in the application of acquisition accounting primarily at gas marketing services, $21 million in additional depreciation at gas distribution operations due to additional assets placed in service primarily related to continued investment in infrastructure replacement programs, and $7 million from the acceleration of depreciation relating to certain assets.information.
Taxes Other Than Income Taxes
|
| | |
| Successor |
| Third Quarter 2017 vs. Third Quarter 2016 |
| (change in millions) | | (% change) |
| $(3) | | (10.3) |
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1 | | 2.2 | | $(10) | | (7.8) |
In the third quarter 2017,For year-to-date 2020, taxes other than income taxes were $26$118 million compared to $29$128 million for the corresponding period in 2016.2019. The decrease primarily reflects establishingrelates to a regulatory asset related to Nicor Gas' invested capital tax. For additional information, see FUTURE EARNINGS POTENTIAL– "Regulatory Matters – Riders" herein.
|
| | | | | | | | | | | | | |
| | | Successor | | | Predecessor |
| | | Year-to-Date 2017 | | July 1, 2016 through September 30, 2016 | | | January 1, 2016 through June 30, 2016 |
| | | (in millions) | | (in millions) | | | (in millions) |
| Taxes other than income taxes | | $ | 140 |
| | $ | 29 |
| | | $ | 99 |
|
Taxes other than income taxesdecrease in the successor periods reflected increased revenue-based taxes due to higherrevenue tax expenses as a result of lower natural gas revenues at gas distribution operations during the successor periods.
Nicor Gas. These revenue tax expenses are passed through directly to customers and have no impact on net income.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
(Continued)
Earnings from Equity Method Investments
|
| | |
| Successor |
| Third Quarter 2017 vs. Third Quarter 2016 |
| (change in millions) | | (% change) |
| $3 | | 10.3 |
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(1) | | (3.2) | | $(8) | | (10.0) |
In the third quarter 2017,For year-to-date 2020, earnings from equity method investments were $32$72 million compared to $29$80 million for the corresponding period in 2016.2019. The increase wasdecrease primarily duerelates to higher earnings fromlower income at SNG, PennEastthe sale of Atlantic Coast Pipeline and Horizon Pipeline.
|
| | | | | | | | | | | | | |
| | | Successor | | | Predecessor |
| | | Year-to-Date 2017 | | July 1, 2016 through September 30, 2016 | | | January 1, 2016 through June 30, 2016 |
| | | (in millions) | | (in millions) | | | (in millions) |
| Earnings from equity method investments | | $ | 100 |
| | $ | 29 |
| | | $ | 2 |
|
Earnings from equity method investments in the successor year-to-date 2017 consistedfirst quarter 2020, and the sale of $86 millionTriton in earnings from SNG and $14 million in earnings from all other investments.
the second quarter 2019. 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)(E) to the Condensed Financial Statements under "Southern Company Gas – Equity Method Investments" herein for additional information.
Other Income (Expense), Net
|
| | |
| Successor |
| Third Quarter 2017 vs. Third Quarter 2016 |
| (change in millions) | | (% change) |
| $9 | | 100.0 |
|
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $6 | | 100.0 | | $11 | | 110.0 |
In the thirdsecond quarter 2017,2020, other income (expense), net was $18$12 million compared to $9$6 million for the corresponding period in 2016. The increase2019. For year-to-date 2020, other income (expense), net was primarily due to a $14 million gain from the settlement of contractor litigation claims.
|
| | | | | | | | | | | | | |
| | | Successor | | | Predecessor |
| | | Year-to-Date 2017 | | July 1, 2016 through September 30, 2016 | | | January 1, 2016 through June 30, 2016 |
| | | (in millions) | | (in millions) | | | (in millions) |
| Other income (expense), net | | $ | 26 |
| | $ | 9 |
| | | $ | 5 |
|
The successor year-to-date 2017 reflects a $16 million gain from the settlement of contractor litigation claims. The successor period of July 1, 2016 through September 30, 2016 and the predecessor period of January 1, 2016 through June 30, 2016 primarily represent the tax gross-up on contributions in aid of construction and AFUDC.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Interest Expense, Net of Amounts Capitalized
|
| | |
| Successor |
| Third Quarter 2017 vs. Third Quarter 2016 |
| (change in millions) | | (% change) |
| $12 | | 30.8 |
In the third quarter 2017, interest expense, net of amounts capitalized was $51$21 million compared to $39$10 million for the corresponding period in 2016. The increase was2019. These increases were primarily due to increases in non-service cost-related retirement benefits income. See Note (H) to the Condensed Financial Statements herein for additional interest expense on new debt issuances.
|
| | | | | | | | | | | | | |
| | | Successor | | | Predecessor |
| | | Year-to-Date 2017 | | July 1, 2016 through September 30, 2016 | | | January 1, 2016 through June 30, 2016 |
| | | (in millions) | | (in millions) | | | (in millions) |
| Interest expense, net of amounts capitalized | | $ | 145 |
| | $ | 39 |
| | | $ | 96 |
|
The successor year-to-date 2017 and the period of July 1, 2016 through September 30, 2016 reflect additional interest expense on new debt issuances, partially offset by reductions of $29 million and $9 million, respectively, resulting from the fair value adjustment of long-term debt in acquisition accounting.information.
Income Taxes
|
| | |
Successor |
Third Quarter 2017 vs. Third Quarter 2016 |
(change in millions) | | (% change) |
$45 | | N/M |
N/M - Not meaningful |
| | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $10 | | 166.7 | | $12 | | 14.5 |
In the thirdsecond quarter 2017,2020, income taxes were $52$16 million compared to $7$6 million for the corresponding period in 2016. The increase reflects $232019. For year-to-date 2020, income taxes were $95 million compared to $83 million for the corresponding period in 2019. These increases were primarily due to a decrease in the flowback of additionalexcess deferred income tax expense associated with State of Illinois tax legislation enacted duringtaxes at Atlanta Gas Light as authorized by the third quarter 2017Georgia PSC and the allocationreversal of newa federal income tax apportionment factorsvaluation allowance in several states forconnection with the inclusionsale of Southern Company Gas into the consolidated Southern Company state tax filings, as well as higherTriton in 2019, partially offset by lower pre-tax earnings. See FUTURE EARNINGS POTENTIAL herein for additional information.
|
| | | | | | | | | | | | | |
| | | Successor | | | Predecessor |
| | | Year-to-Date 2017 | | July 1, 2016 through September 30, 2016 | | | January 1, 2016 through June 30, 2016 |
| | | (in millions) | | (in millions) | | | (in millions) |
| Income taxes | | $ | 233 |
| | $ | 7 |
| | | $ | 87 |
|
The successor year-to-date 2017 income taxes reflect $23 million of additional deferred income tax expense associated with State of Illinois tax legislation andNote (G) to the allocation of new tax apportionment factors, as well as increased income taxes from higher pre-tax earnings. See FUTURE EARNINGS POTENTIALCondensed Financial Statements herein for additional information.
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
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(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 third quarters 2017 and 2016 and the successor 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 third quarters 2017 and 2016 and the successor year-to-date 2017 is useful as it allows for a measure of comparability to other companies with different capital and legal structures, which accordingly may be subject to different interest rates and effective tax rates. The applicable reconciliations of net income to consolidated EBIT and segment EBIT are provided herein.
Adjusted operating margin is a non-GAAP measure that is calculated as operating revenues minusless cost of natural gas, cost of other sales, and revenue tax expense. Adjusted operating margin excludes other operations and maintenance expenses, depreciation and amortization, and 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 base rate changes, infrastructure replacement programs and capital projects, and 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,pipeline investments, wholesale gas services, and gas midstream operationsmarketing services allows it to focus on a direct measure of adjusted operating marginperformance before overhead costs. The applicable reconciliation of operating income to adjusted operating margin is provided herein.
EBIT and adjustedAdjusted operating margin should not be considered alternativesan alternative to, or a more meaningful indicatorsindicator 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.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Detailed variance explanations of Southern Company Gas' financial performance are provided herein.
Reconciliations of operating income to adjusted operating margin are as follows:
| | | | | Successor | | | Predecessor | | | | | | | | | | | |
| | | Third Quarter 2017 | | Third Quarter 2016 | | Year-to-Date 2017 | | July 1, 2016 through September 30, 2016 | | | January 1, 2016 through
June 30,
2016 | Second Quarter 2020 | Second Quarter 2019 | | Year-to-Date 2020 | Year-to-Date 2019 |
| | | (in millions) | | | (in millions) | (in millions) |
| Operating Income | | $ | 68 |
| | $ | 12 |
| | $ | 555 |
| | $ | 12 |
| | | $ | 321 |
| $ | 102 |
| $ | 134 |
| | $ | 462 |
| $ | 487 |
|
Other operating expenses(a) | | 356 |
| | 396 |
| | 1,181 |
| | 396 |
| | | 815 |
| 390 |
| 364 |
| | 840 |
| 799 |
|
Revenue taxes(b) | | (8 | ) | | (8 | ) | | (74 | ) | | (8 | ) | | | (56 | ) | (22 | ) | (22 | ) | | (67 | ) | (76 | ) |
| Adjusted Operating Margin | | $ | 416 |
| | $ | 400 |
| | $ | 1,662 |
| | $ | 400 |
| | | $ | 1,080 |
| $ | 470 |
| $ | 476 |
| | $ | 1,235 |
| $ | 1,210 |
|
| |
| (a) | Includes other operations and maintenance, depreciation and amortization, and taxes other than income taxes, and Merger-related expenses.taxes. |
| |
| (b) | Nicor Gas' revenue tax expenses, which are passed through directly to customers. |
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
(Continued)
Segment Information
Adjusted operating margin, operating expenses, and net income for each segment are provided in the table below. See Note (L) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
|
| | | | | | | | | | | | | | | | | | | | | |
| | | Successor | | | Predecessor |
| | | Third Quarter 2017 | | Third Quarter 2016 | | Year-to-Date 2017 | | July 1, 2016 through September 30, 2016 | | | January 1, 2016
through
June 30,
2016 |
| | | (in millions) | | | (in millions) |
Consolidated Net Income Attributable
to Southern Company Gas | | $ | 15 |
| | $ | 4 |
| | $ | 303 |
| | $ | 4 |
| | | $ | 131 |
|
Net income attributable to
noncontrolling interest (*) | | | | — |
| | — |
| | — |
| | | 14 |
|
| Income taxes | | 52 |
| | 7 |
| | 233 |
| | 7 |
| | | 87 |
|
Interest expense, net of amounts
capitalized | | 51 |
| | 39 |
| | 145 |
| | 39 |
| | | 96 |
|
| EBIT | | $ | 118 |
| | $ | 50 |
| | $ | 681 |
| | $ | 50 |
| | | $ | 328 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Second Quarter 2020 | | Second Quarter 2019 |
| | Adjusted Operating Margin(*) | | Operating Expenses(*) | | Net Income (Loss) | | Adjusted Operating Margin(*) | | Operating Expenses(*) | | Net Income (Loss)(b) |
| | (in millions) | | (in millions) |
| Gas distribution operations | $ | 441 |
| | $ | 314 |
| | $ | 74 |
| | $ | 394 |
| | $ | 287 |
| | $ | 58 |
|
| Gas pipeline investments | 8 |
| | 3 |
| | 21 |
| | 8 |
| | 3 |
| | 25 |
|
| Wholesale gas services | (19 | ) | | 11 |
| | (23 | ) | | 41 |
| | 10 |
| | 23 |
|
| Gas marketing services | 35 |
| | 28 |
| | 5 |
| | 27 |
| | 31 |
| | (3 | ) |
| All other | 7 |
| | 14 |
| | (6 | ) | | 7 |
| | 12 |
| | 3 |
|
| Intercompany eliminations | (2 | ) | | (2 | ) | | — |
| | (1 | ) | | (1 | ) | | — |
|
| Consolidated | $ | 470 |
| | $ | 368 |
| | $ | 71 |
| | $ | 476 |
| | $ | 342 |
| | $ | 106 |
|
| |
| (*) | 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. |
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 |
| | Third Quarter 2017 |
| Third Quarter 2016 |
| Adjusted Operating |
| Operating |
| Net Income |
| Adjusted Operating |
| Operating |
| Net Income |
| Margin(*) |
| Expenses(*) |
| (Loss) |
| Margin(*) |
| Expenses(*) |
| (Loss) |
| (in millions) |
| (in millions) |
| Gas distribution operations | $ | 379 |
|
| $ | 271 |
|
| $ | 52 |
|
| $ | 353 |
|
| $ | 284 |
|
| $ | 27 |
|
| Gas marketing services | 51 |
|
| 48 |
|
| 1 |
|
| 45 |
|
| 51 |
|
| (4 | ) |
| Wholesale gas services | (25 | ) |
| 11 |
|
| (23 | ) |
| (8 | ) |
| 10 |
|
| (11 | ) |
| Gas midstream operations | 12 |
|
| 13 |
|
| 14 |
|
| 9 |
|
| 13 |
|
| 14 |
|
| All other | 2 |
|
| 8 |
|
| (29 | ) |
| 2 |
|
| 31 |
|
| (22 | ) |
| Intercompany eliminations | (3 | ) |
| (3 | ) |
| — |
|
| (1 | ) |
| (1 | ) |
| — |
|
| Consolidated | $ | 416 |
|
| $ | 348 |
|
| $ | 15 |
|
| $ | 400 |
|
| $ | 388 |
|
| $ | 4 |
|
| |
(*) | Operating margin and operating expenses are adjusted for Nicor Gas' revenue tax expenses, which are passed through directly to customers. |
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Year-to-Date 2017 | | July 1, 2016 through
September 30, 2016 | | | January 1, 2016 through
June 30, 2016 |
| | Adjusted Operating | | Operating | | Net Income | | Adjusted Operating | | Operating | | Net Income | | | Adjusted Operating | | Operating | | |
| | Margin(*) | | Expenses(*) | | (Loss) | | Margin(*) | | Expenses(*) | | (Loss) | | | Margin(*) | | Expenses(*) | | EBIT |
| | (in millions) | | | (in millions) |
Gas distribution
operations | $ | 1,329 |
| | $ | 866 |
| | $ | 223 |
| | $ | 353 |
| | $ | 284 |
| | $ | 27 |
| | | $ | 911 |
| | $ | 560 |
| | $ | 353 |
|
Gas marketing
services | 213 |
| | 149 |
| | 36 |
| | 45 |
| | 51 |
| | (4 | ) | | | 190 |
| | 81 |
| | 109 |
|
Wholesale gas
services | 93 |
| | 40 |
| | 28 |
| | (8 | ) | | 10 |
| | (11 | ) | | | (36 | ) | | 33 |
| | (68 | ) |
Gas midstream
operations | 28 |
| | 38 |
| | 38 |
| | 9 |
| | 13 |
| | 14 |
| | | 15 |
| | 24 |
| | (6 | ) |
| All other | 7 |
| | 22 |
| | (22 | ) | | 2 |
| | 31 |
| | (22 | ) | | | 4 |
| | 65 |
| | (60 | ) |
Intercompany
eliminations | (8 | ) | | (8 | ) | | — |
| | (1 | ) | | (1 | ) | | — |
| | | (4 | ) | | (4 | ) | | — |
|
| Consolidated | $ | 1,662 |
| | $ | 1,107 |
| | $ | 303 |
| | $ | 400 |
| | $ | 388 |
| | $ | 4 |
| | | $ | 1,080 |
| | $ | 759 |
| | $ | 328 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Year-to-Date 2020 | | Year-to-Date 2019 |
| | Adjusted Operating Margin(*) | | Operating Expenses(*) | | Net Income (Loss) | | Adjusted Operating Margin(*) | | Operating Expenses(*) | | Net Income (Loss) |
| | (in millions) | | (in millions) |
| Gas distribution operations | $ | 1,036 |
| | $ | 654 |
| | $ | 238 |
| | $ | 918 |
| | $ | 601 |
| | $ | 191 |
|
| Gas pipeline investments | 16 |
| | 6 |
| | 51 |
| | 16 |
| | 6 |
| | 57 |
|
| Wholesale gas services | 31 |
| | 28 |
| | — |
| | 125 |
| | 29 |
| | 70 |
|
| Gas marketing services | 142 |
| | 58 |
| | 62 |
| | 142 |
| | 62 |
| | 58 |
|
| All other | 13 |
| | 30 |
| | (5 | ) | | 13 |
| | 29 |
| | — |
|
| Intercompany eliminations | (3 | ) | | (3 | ) | | — |
| | (4 | ) | | (4 | ) | | — |
|
| Consolidated | $ | 1,235 |
| | $ | 773 |
| | $ | 346 |
| | $ | 1,210 |
| | $ | 723 |
| | $ | 376 |
|
| |
| (*) | OperatingAdjusted 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. These agencies approve natural gas rates designed to provide Southern Company Gas with the opportunity to generate revenues to recover the cost of natural gas delivered to its customers and its fixed and variable costs, including depreciation, interest expense, operations and maintenance, taxes, and overhead costs, and to earn a reasonable return on its investments.
With the exception of Atlanta Gas Light, Southern Company Gas' second largest utility that operates in a deregulated natural gas market and has a straight-fixed-variable rate design that minimizes the variability of its revenues based on consumption, the earnings of the natural gas distribution utilities can be affected by customer consumption patterns that are a function of weather conditions, price levels for natural gas, and general economic conditions that may impact customers' ability to pay for natural gas consumed. Southern Company Gas has various weatherregulatory and other mechanisms, such as weather and revenue normalization mechanisms and weather derivative
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
instruments, that limit its exposure to changes in customer consumption, including weather changes within typical ranges in its natural gas distribution utilities' service territories.
Successor Third Quarter 2017 vs. Third Quarter 2016
In the thirdsecond quarter 2017,2020, net income was $52increased $16 million, or 27.6%, compared to $27 million for the corresponding period in 2016.2019. The increase in net income relates to an increase of $26$47 million in adjusted operating margin, a decrease of $13 million in operating expenses, and an increase of $11 million in other income (expense), net. The change in net income also includes an increase of $7 million in interest expense, net of amounts capitalized, and an increase of $18 million in income tax expense. The increase in adjusted operating margin primarily reflects $24 million in additional revenue from the continued investment in infrastructure replacement programs and base rate increases for Nicor Gas and Atlanta Gas Light and continued investments recovered through infrastructure replacement programs. The $27 million increase in operating expenses includes increased medical and retirement benefit expenses, higher expenses passed through directly to customers, primarily related to bad debt and pipeline compliance and maintenance activities, and higher depreciation primarily due to additional assets placed in service. The $6 million increase in other income is primarily due to an increase in non-service cost-related retirement benefits income. Income tax expense increased $11 million primarily due to higher pre-tax earnings and a decrease in the flowback of excess deferred income taxes at Atlanta Gas Light effective March 1, 2017.as authorized by the Georgia PSC.
For year-to-date 2020, net income increased $47 million or 24.6%, compared to the corresponding period in 2019. The decrease$118 million increase in adjusted operating margin primarily reflects base rate increases for Nicor Gas and Atlanta Gas Light and continued investments recovered through infrastructure replacement programs, partially offset by warmer weather, net of weather normalization mechanisms. The $53 million increase in operating expenses primarily reflects $18 million in rate credits providedincludes increased medical and retirement benefit expenses, higher expenses passed through directly to customers, of Elizabethtown Gas in 2016 as a condition of the Merger, partially offset by $7 million inprimarily related to bad debt and pipeline compliance and maintenance activities, and additional depreciation primarily due to continued investmentadditional assets placed in infrastructure programs.service. The $12 million increase in other income (expense), netis primarily reflects a $14 million gain from the settlement of contractor litigation claims in 2017. Thedue to an increase in interest expense includes the impact of intercompany promissory notes executed in December 2016 and the issuance of first mortgage bonds at Nicor Gas on August 10, 2017.non-service cost-related retirement benefits income. The $31 million increase in income tax expense relatesis primarily due to higher pre-tax earnings.earnings and a decrease in the flowback of excess deferred income taxes at Atlanta Gas Light as authorized by the Georgia PSC.
Successor Year-to-Date 2017See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein for additional information.
NetGas Pipeline Investments
Gas pipeline investments consists primarily of joint ventures in natural gas pipeline investments including SNG, PennEast Pipeline, Dalton Pipeline, and Atlantic Coast Pipeline (until its sale on March 24, 2020). See Notes (E) and (K) to the Condensed Financial Statements under "Southern Company Gas" herein and Note 7 to the financial statements in Item 8 of the Form 10-K for additional information.
In the second quarter and year-to-date 2020, net income decreased $4 million, or 16.0%, and $6 million, or 10.5%, respectively, compared to the corresponding periods in 2019. These decreases primarily relate to lower earnings at SNG.
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 $223factors. 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.
In the second quarter 2020, net income decreased $46 million, includes $1.3 billionor 200.0%, compared to the corresponding period in 2019. This decrease primarily relates to a $60 million decrease in adjusted operating margin, $866partially offset by a $15 million decrease in income tax expense due to lower pre-tax earnings.
For year-to-date 2020, net income decreased $70 million, or 100.0%, compared to the corresponding period in 2019. This decrease primarily relates to a $94 million decrease in adjusted operating margin and a $1 million decrease in operating expenses, and $23partially offset by a $22 million decrease in other income (expense), net, which resulted in EBIT of $486 million. Net income also includes
tax expense due to lower pre-tax earnings.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
(Continued)
$119 million in interest expense, netDetails of amounts capitalized and $144 million in income tax expense. Adjusted operating margin reflects $69 million in additional revenue from continued investment in infrastructure replacement programs and base rate increases, primarily at Atlanta Gas Light effective March 1, 2017. Also includedthe changes in adjusted operating margin was increased customer growth, partially offset by a $6 million negativeare provided in the table below.
|
| | | | | | | | | | | | | |
| | Second Quarter 2020 | Second Quarter 2019 | | Year-to-Date 2020 | Year-to-Date 2019 |
| | (in millions) |
| Commercial activity recognized | $ | (33 | ) | $ | (1 | ) | | $ | (42 | ) | $ | 37 |
|
| Gain (loss) on storage derivatives | (5 | ) | 2 |
| | (11 | ) | 5 |
|
| Gain on transportation and forward commodity derivatives | 19 |
| 48 |
| | 85 |
| 77 |
|
| LOCOM adjustments, net of current period recoveries | — |
| (6 | ) | | — |
| (8 | ) |
| Purchase accounting adjustments to fair value inventory and contracts | — |
| (2 | ) | | (1 | ) | 14 |
|
| Adjusted operating margin | $ | (19 | ) | $ | 41 |
| | $ | 31 |
| $ | 125 |
|
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. The decrease in commercial activity in the second quarter and year-to-date 2020 compared to the corresponding periods in 2019 was primarily due to warmer-than-normal weather netconditions.
Change in Storage and Transportation Derivatives
Volatility in the natural gas market arises from a number of hedging. Operating expenses reflectfactors, 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 $21 million increasesignificant 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. Forward storage or time spreads applicable to the locations of wholesale gas services' specific storage positions in depreciation2020 resulted in storage derivative losses. Transportation and forward commodity derivative gains in 2020 are primarily the result of narrowing transportation spreads due to supply constraints and increases in natural gas supply, 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 additional assets placedthe transportation portfolio of wholesale gas services are presented in service,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 increased compensation expense, legal expenses,other variable fuel, withdrawal, receipt, and pipeline compliancedelivery charges, and maintenance activities. Other income (expense), net reflects a $16 million gain fromexclude estimated profit sharing under asset management agreements. Further, the settlementamounts that are realizable in future periods are based on the inventory withdrawal schedule, planned physical flow of contractor litigation claims. Interest expense reflectsnatural gas between the impact of intercompany promissory notes executed in December 2016transportation receipt and the issuance of first mortgage bondsdelivery points, and forward natural gas prices at Nicor Gas on August 10, 2017.
Successor Period of July 1, 2016 through September 30, 2016
Net income of $27 million includes $353 million in adjusted operating margin, $284 million in operating expenses, including $18 million in rate credits provided to customers, and $6 million in other income (expense), net, which resulted in EBIT of $75 million. Net income also includes $32 million in interest expense and $16 million in income tax expense.
Predecessor Period of January 1, 2016 through June 30, 20162020. 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.
EBIT
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
|
| | | | | | | | | | |
| | Storage withdrawal schedule | | |
| | Total storage(a) | | Expected net operating gains(b) | | Physical transportation transactions – expected net operating losses(c) |
| | (in mmBtu in millions) | | (in millions) | | (in millions) |
| 2020 | 15 |
| | $ | 6 |
| | $ | (12 | ) |
| 2021 and thereafter | 33 |
| | 34 |
| | (73 | ) |
| Total at June 30, 2020 | 48 |
| | $ | 40 |
| | $ | (85 | ) |
| |
| (a) | At June 30, 2020, the WACOG of wholesale gas services' expected natural gas withdrawals from storage was $1.68 per mmBtu. |
| |
| (b) | 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. |
| |
| (c) | Represents the transportation derivative gains and (losses) that will be settled during the period and the physical transportation transactions that offset the derivative gains and losses 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" 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 impactItem 7 of warmer-than-normal weather, net of hedging. Operating expenses reflect depreciation associated with additional assets placed in service.the Form 10-K.
Gas Marketing ServicesChange in Storage and Transportation Derivatives
Gas marketing services consists of several businesses that provide energy-related products and services toVolatility in the natural gas markets, including warranty sales. Gas marketing services is weather sensitive and usesmarket arises from a varietynumber of hedging strategies,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. Forward storage or time spreads applicable to the locations of wholesale gas services' specific storage positions in 2020 resulted in storage derivative instrumentslosses. Transportation and other risk management tools,forward commodity derivative gains in 2020 are primarily the result of narrowing transportation spreads due to partially mitigate potential weather impacts. Operating expensessupply constraints and increases in natural gas supply, which impacted forward prices at natural gas receipt and delivery points, primarily reflect employee costs, marketing, and bad debt expenses.
Successor Third Quarter 2017 vs. Third Quarter 2016
In the third quarter 2017, net income was $1 million compared to a net loss of $4 million for the corresponding period in 2016. The increase in net income primarily relates to a $6 million increase in adjusted operating margin and a $3 million decrease in operating expenses. The change in net income also includes increases of $1 million and $3 million in interest expense and income tax expense, respectively. Adjusted operating margin primarily reflects a $3 million decrease in unrealized hedge losses, net of recoveries, and a $4 million increase from the elimination of deferred revenue in the third quarter 2016Northeast 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 applicationtransportation portfolio of acquisition accounting. Operating expenses reflect decreased amortization of intangible assets establishedwholesale gas services are presented in the applicationfollowing table, along with the net operating revenues expected at the time of acquisition accounting.
Successor Year-to-Date 2017
Net incomewithdrawal from storage and the physical flow of $36 million includes $213 millionnatural 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, and exclude estimated profit sharing under asset management agreements. Further, the amounts that are realizable in adjusted operating marginfuture periods are based on the inventory withdrawal schedule, planned physical flow of natural gas between the transportation receipt and $149 million in operating expenses,delivery points, and forward natural gas prices at June 30, 2020. A portion of wholesale gas services' storage inventory and transportation capacity is economically hedged with futures contracts, which resulted in EBIT of $64 million. Net income also includes $4 million in interest expense and $24 million in income tax expense. Adjusted operating margin reflects a $10 million negative impact of warmer-than-normal weather, net of hedging, and $7 million in unrealized hedge losses, net of recoveries. Operating expenses include $30 million in additional amortization of intangible assets establishedresults in the applicationrealization of acquisition accounting.
Successor Period of July 1, 2016 through September 30, 2016
Net loss of $4 million includes $45 million in adjustedsubstantially fixed net operating margin and $51 million in operating expenses, which resulted in a loss before interest and taxes of $6 million. Also included in net loss is $2 million in income tax benefit.
revenues.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
(Continued)
|
| | | | | | | | | | |
| | Storage withdrawal schedule | | |
| | Total storage(a) | | Expected net operating gains(b) | | Physical transportation transactions – expected net operating losses(c) |
| | (in mmBtu in millions) | | (in millions) | | (in millions) |
| 2020 | 15 |
| | $ | 6 |
| | $ | (12 | ) |
| 2021 and thereafter | 33 |
| | 34 |
| | (73 | ) |
| Total at June 30, 2020 | 48 |
| | $ | 40 |
| | $ | (85 | ) |
| |
| (a) | At June 30, 2020, the WACOG of wholesale gas services' expected natural gas withdrawals from storage was $1.68 per mmBtu. |
| |
| (b) | 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. |
| |
| (c) | Represents the transportation derivative gains and (losses) that will be settled during the period and the physical transportation transactions that offset the derivative gains and losses previously recognized. |
The unrealized storage and transportation derivative gains do not change the underlying economic value of January 1, 2016 through June 30, 2016
EBIT of $109 million includes $190 million in adjusted operating margin and $81 million in operating expenses. Adjusted operating margin reflects $9 million in unrealized hedge gains. 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 positionedservices' storage and transportation positions and will be reversed when the business to generate positive economic earningsrelated transactions occur and are recognized. For more information 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 valueservices' energy marketing and generate stronger results. Operating expenses primarily reflect employee compensation and benefits.
Successor Third Quarter 2017 vs. Third Quarter 2016
In the third quarter 2017, net loss was $23 million compared to a net loss of $11 million for the corresponding period in 2016. The increase in net loss relates primarily to a $17 million decrease in adjusted operating margin, partially offset by an increase of $8 million in income tax benefit due to higher losses. The decrease in adjusted gross margin includes $22 million in additional mark-to-market losses and a $7 million decrease in gains from commercial activity, partially offset by a $12 million positive impact from the amortization of liabilities recorded in the application of acquisition accounting.
Successor Year-to-Date 2017
Net income of $28 million includes $93 million in adjusted operating margin and $40 million in operating expenses, which resulted in EBIT of $53 million. Net income also includes $5 million in interest expense and $20 million in income tax expense.
Successor Period of July 1, 2016 through September 30, 2016
Net loss of $11 million includes $(8) million in adjusted operating margin and $10 million in operating expenses, which resulted in a loss before interest and taxes of $17 million. Also included in net loss is $1 million in interest expense and $7 million in income tax benefit.
Predecessor Period of January 1, 2016 through June 30, 2016
Loss before interest and taxes of $68 million includes $(36) million in adjusted operating margin, $33 million in operating expenses, and $1 million in other income (expense), net.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
risk management activities, see MANAGEMENT'S DISCUSSION AND ANALYSIS OF
– FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following table illustratesLIQUIDITY – "Market Price Risk" in Item 7 of the components of wholesale gas services' adjusted operating margin for the periods presented.Form 10-K.
|
| | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Third Quarter 2017 | | Third Quarter 2016 | | Year-to-Date 2017 | | July 1, 2016 through September 30, 2016 | | | January 1, 2016
through
June 30,
2016 |
| | (in millions) | | | (in millions) |
| Commercial activity recognized | $ | 3 |
| | $ | 10 |
| | $ | 80 |
| | 10 |
| | | $ | 34 |
|
| Gain (loss) on storage derivatives | 4 |
| | 11 |
| | 13 |
| | 11 |
| | | (38 | ) |
Gain (loss) on transportation and forward
commodity derivatives | (22 | ) | | (7 | ) | | 14 |
| | (7 | ) | | | (31 | ) |
LOCOM adjustments, net of current period
recoveries | — |
| | — |
| | — |
| | — |
| | | (1 | ) |
| Purchase accounting adjustments | (10 | ) | | (22 | ) | | (14 | ) | | (22 | ) | | | — |
|
| Adjusted Operating Margin | $ | (25 | ) | | $ | (8 | ) | | $ | 93 |
| | $ | (8 | ) | | | $ | (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 nine months of 2017, forwardForward storage or time spreads applicable to the locations of wholesale gas services' specific storage positions in 2020 resulted in storage derivative gains.losses. Transportation and forward commodity derivative gains in 2020 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
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
charges, but are net of theand exclude 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 SeptemberJune 30, 2017.2020. 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.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
|
| | | | | | | | | | |
| | Storage withdrawal schedule | | |
| | Total storage
(WACOG $2.67) | | Expected net operating gains(a) | | Physical transportation transactions – expected net operating gains (losses)(b) |
| | (in mmBtu in millions) | | (in millions) | | (in millions) |
| 2017 | 22.0 |
| | $ | 4 |
| | $ | (13 | ) |
| 2018 and thereafter | 40.0 |
| | 17 |
| | 28 |
|
| Total at September 30, 2017 | 62.0 |
| | $ | 21 |
| | $ | 15 |
|
|
| | | | | | | | | | |
| | Storage withdrawal schedule | | |
| | Total storage(a) | | Expected net operating gains(b) | | Physical transportation transactions – expected net operating losses(c) |
| | (in mmBtu in millions) | | (in millions) | | (in millions) |
| 2020 | 15 |
| | $ | 6 |
| | $ | (12 | ) |
| 2021 and thereafter | 33 |
| | 34 |
| | (73 | ) |
| Total at June 30, 2020 | 48 |
| | $ | 40 |
| | $ | (85 | ) |
| |
| (a) | At June 30, 2020, the WACOG of wholesale gas services' expected natural gas withdrawals from storage was $1.68 per mmBtu. |
| |
| (b) | 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)(c) | Represents the periods associated with the transportation derivative gains during which the derivativesand (losses) that will be settled during the period and the physical transportation transactions will occur that offset the derivative gains and losses 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 OperationsMarketing Services
Gas midstream operations consists primarilymarketing services provides energy-related products and services to natural gas markets and participants in customer choice programs that were approved in various states to increase competition. These programs allow customers to choose their natural gas supplier while the local distribution utility continues to provide distribution and transportation services. Gas marketing services is weather sensitive and uses a variety of gas pipeline investments, with storagehedging strategies, such as weather derivative instruments and fuels also aggregated into this segment. Gas pipeline investments include SNG, Horizon Pipeline, Atlantic Coast Pipeline, PennEast Pipeline, Dalton Pipeline, and Magnolia Enterprise Holdings, Inc. See Note (J)other risk management tools, 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 Third Quarter 2017 vs. Third Quarter 2016partially mitigate potential weather impacts.
In both the thirdsecond quarter 2017 and2020, net income increased $8 million compared to the corresponding period in 2016 net income was $14 million. Net income reflects a $32019. This increase primarily relates to an $8 million increase in adjusted operating margin, which primarily reflects recovery of prior period hedge losses, and a $4 million increase in earnings from equity method investments at SNG, PennEast Pipeline, and Horizon Pipeline. The change in net income also includes a $9 million increase in interest expense, net of amounts capitalized and a $2$3 million decrease in income taxes. The increase in interest expense includes the impact of intercompany promissory notes executed in December 2016.
Successor Year-to-Date 2017
Net income of $38 million includes $28 million in adjusted operating margin, $38 million in operating expenses, $97 million in earnings from equity method investments, consisting primarily of earnings from equity method investments at SNG, andpartially offset by a $3 million in other income (expense), net, which resulted in EBIT of $90 million. Also included in net income are $25 million in interest expense and $27 millionincrease in income tax expense.
Successor Period of July 1, 2016 through September 30, 2016
NetFor year-to-date 2020, net income of $14increased $4 million includes $9compared to the corresponding period in 2019. This increase primarily relates to a $4 million in adjusted operating margin, $13 milliondecrease in operating expenses, $28 million in earnings from equity method investments, consisting primarily of earnings from equity method
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
investments at SNG, and $1 million in other income (expense), net, which resulted in EBIT of $25 million. Also included in net income is $11 million in income tax expense.
Predecessor Period of January 1, 2016 through June 30, 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.expenses.
All Other
All other includes natural gas storage businesses, fuels operations through the sale of Southern Company Gas' interest in Pivotal LNG on March 24, 2020, the investment in Triton through its sale on May 29, 2019, AGL Services Company, and Southern Company Gas Capital, as well as various corporate operating expenses that are not allocated to the reportable segments and interest income (expense) associated with affiliate financing arrangements.
Successor Third Quarter 2017 vs. Third Quarter 2016 See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information on the sale of its interest in Pivotal LNG.
In the thirdsecond quarter 2017,2020, net loss was $29income decreased $9 million compared to $22 million in the corresponding period in 2016. The increase in net loss2019. This decrease primarily reflects a $23$2 million decreaseincrease in operating expenses and a decrease of $2$12 million increase in income taxes, partially offset by a $7 million increase in other income (expense), net. Net(expenses). The increase in other income (expenses) was primarily due to a pre-tax loss also reflectedon the sale of Triton in 2019. The increase in income taxes reflects the reversal of a $6federal income tax valuation allowance in connection with the sale of Triton in 2019.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
For year-to-date 2020, net income decreased $5 million compared to the corresponding period in 2019. This decrease includes a $2 million increase in interest expense, net of amounts capitalized, and ana $6 million increase of $34 million in income taxes. The decreasetaxes related to the reversal of a federal income tax valuation allowance in operating expenses reflects a $35 million decreaseconnection with the sale of Triton in Merger-related expenses,2019, partially offset by a $10$4 million increase in other operations and maintenance expenses andincome (expenses) primarily due to a $3 million increase frompre-tax loss on the accelerationsale of depreciation relating to certain assets. Interest expense decreased as a result of intercompany promissory notes executedTriton in December 2016. The increase in income taxes primarily reflects additional deferred income tax expenses associated with State of Illinois tax legislation enacted during the third quarter 2017, as well as the allocation of new tax apportionment factors in several states for the inclusion of Southern Company Gas into the consolidated Southern Company state tax filings.2019.
Successor Year-to-Date 2017, Successor Period of July 1, 2016 through September 30, 2016, and Predecessor Period of January 1, 2016 through June 30, 2016
For the successor period of July 1, 2016 through September 30, 2016 and the predecessor period of January 1, 2016 through June 30, 2016, Merger-related expenses were $35 million and $56 million, respectively. There were no Merger-related expenses during the successor year-to-date 2017. In the successor year-to-date 2017, depreciation and amortization includes $7 million from the acceleration of depreciation relating to certain assets. Interest expense, net of amounts capitalized was $8 million, $6 million, and $34 million, respectively, in the successor year-to-date 2017, the successor period of July 1, 2016 through September 30, 2016, and the predecessor period of January 1, 2016 through June 30, 2016. Income taxes were $18 million in the successor year-to-date 2017 and income tax benefit was $11 million and $35 million, respectively, in the successor period of July 1, 2016 through September 30, 2016 and the predecessor period of January 1, 2016 through June 30, 2016. In the successor year-to-date 2017, income taxes reflect $23 million of additional deferred income tax expense associated with State of Illinois tax legislation enacted during the third quarter 2017 and the allocation of new tax apportionment factors in several states for the inclusion of Southern Company Gas into the consolidated Southern Company state tax filings.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Segment Reconciliations
Reconciliations of consolidated net income attributable to Southern Company Gas to EBIT for the successor third quarter and year-to-date 2017, and operating income to adjusted operating margin for all periods presented,the second quarter and year-to-date 2020 and 2019 are reflected in the following tables. See Note (K)(L) to the Condensed Financial Statements herein for additional information. |
| | | | | | | | | | | | | | | | | | | | | |
| Successor |
| Third Quarter 2017 |
| Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services | Gas Midstream Operations | All Other | Intercompany Elimination | Consolidated |
| (in millions) |
Consolidated Net Income
(Loss) | $ | 52 |
| $ | 1 |
| $ | (23 | ) | $ | 14 |
| $ | (29 | ) | $ | — |
| $ | 15 |
|
| Income taxes (benefit) | 34 |
| 1 |
| (15 | ) | 9 |
| 23 |
| — |
| 52 |
|
Interest expense, net of
amounts capitalized | 39 |
| 1 |
| 2 |
| 9 |
| — |
| — |
| 51 |
|
| EBIT | $ | 125 |
| $ | 3 |
| $ | (36 | ) | $ | 32 |
| $ | (6 | ) | $ | — |
| $ | 118 |
|
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | Successor |
| | | Third Quarter 2016 |
| | | Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services | Gas Midstream Operations | All Other | Intercompany Elimination | Consolidated |
| | | (in millions) |
Consolidated Net Income
(Loss) | | $ | 27 |
| $ | (4 | ) | $ | (11 | ) | $ | 14 |
| $ | (22 | ) | $ | — |
| $ | 4 |
|
| Income taxes (benefit) | | 16 |
| (2 | ) | (7 | ) | 11 |
| (11 | ) | — |
| 7 |
|
Interest expense, net of
amounts capitalized | | 32 |
| — |
| 1 |
| — |
| 6 |
| — |
| 39 |
|
| EBIT | | $ | 75 |
| $ | (6 | ) | $ | (17 | ) | $ | 25 |
| $ | (27 | ) | $ | — |
| $ | 50 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2020 |
| Gas Distribution Operations | Gas Pipeline Investments | Wholesale Gas Services | Gas Marketing Services | All Other | Intercompany Elimination | Consolidated |
| (in millions) |
| Operating Income (Loss) | $ | 127 |
| $ | 5 |
| $ | (30 | ) | $ | 7 |
| $ | (7 | ) | $ | — |
| $ | 102 |
|
Other operating expenses(a) | 336 |
| 3 |
| 11 |
| 28 |
| 14 |
| (2 | ) | 390 |
|
Revenue tax expense(b) | (22 | ) | — |
| — |
| — |
| — |
| — |
| (22 | ) |
| Adjusted Operating Margin | $ | 441 |
| $ | 8 |
| $ | (19 | ) | $ | 35 |
| $ | 7 |
| $ | (2 | ) | $ | 470 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| | 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
(Loss) | $ | 223 |
| $ | 36 |
| $ | 28 |
| $ | 38 |
| $ | (22 | ) | $ | — |
| $ | 303 |
|
| Income taxes | 144 |
| 24 |
| 20 |
| 27 |
| 18 |
| — |
| 233 |
|
Interest expense, net of
amounts capitalized | 119 |
| 4 |
| 5 |
| 25 |
| (8 | ) | — |
| 145 |
|
| EBIT | $ | 486 |
| $ | 64 |
| $ | 53 |
| $ | 90 |
| $ | (12 | ) | $ | — |
| $ | 681 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| | Second Quarter 2019 |
| | Gas Distribution Operations | Gas Pipeline Investments | Wholesale Gas Services | Gas Marketing Services | All Other | Intercompany Elimination | Consolidated |
| | (in millions) |
| Operating Income (Loss) | $ | 107 |
| $ | 5 |
| $ | 31 |
| $ | (4 | ) | $ | (5 | ) | $ | — |
| $ | 134 |
|
Other operating expenses(a) | 309 |
| 3 |
| 10 |
| 31 |
| 12 |
| (1 | ) | 364 |
|
Revenue tax expense(b) | (22 | ) | — |
| — |
| — |
| — |
| — |
| (22 | ) |
| Adjusted Operating Margin | $ | 394 |
| $ | 8 |
| $ | 41 |
| $ | 27 |
| $ | 7 |
| $ | (1 | ) | $ | 476 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| | Year-to-Date 2020 |
| | Gas Distribution Operations | Gas Pipeline Investments | Wholesale Gas Services | Gas Marketing Services | All Other | Intercompany Elimination | Consolidated |
| | (in millions) |
| Operating Income (Loss) | $ | 382 |
| $ | 10 |
| $ | 3 |
| $ | 84 |
| $ | (17 | ) | $ | — |
| $ | 462 |
|
Other operating expenses(a) | 721 |
| 6 |
| 28 |
| 58 |
| 30 |
| (3 | ) | 840 |
|
Revenue tax expense(b) | (67 | ) | — |
| — |
| — |
| — |
| — |
| (67 | ) |
| Adjusted Operating Margin | $ | 1,036 |
| $ | 16 |
| $ | 31 |
| $ | 142 |
| $ | 13 |
| $ | (3 | ) | $ | 1,235 |
|
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
(Continued)
|
| | | | | | | | | | | | | | | | | | | | | |
| Successor |
| Third Quarter 2017 |
| Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services | Gas Midstream Operations | All Other | Intercompany Elimination | Consolidated |
| (in millions) |
| Operating Income (Loss) | $ | 108 |
| $ | 3 |
| $ | (36 | ) | $ | (1 | ) | $ | (6 | ) | $ | — |
| $ | 68 |
|
Other operating expenses(a) | 279 |
| 48 |
| 11 |
| 13 |
| 8 |
| (3 | ) | 356 |
|
Revenue tax expense(b) | (8 | ) | — |
| — |
| — |
| — |
| — |
| (8 | ) |
Adjusted Operating
Margin | $ | 379 |
| $ | 51 |
| $ | (25 | ) | $ | 12 |
| $ | 2 |
| $ | (3 | ) | $ | 416 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| | Successor |
| | Third Quarter 2016 |
| | Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services | Gas Midstream Operations | All Other | Intercompany Elimination | Consolidated |
| | (in millions) |
| Operating Income (Loss) | $ | 69 |
| $ | (6 | ) | $ | (18 | ) | $ | (4 | ) | $ | (29 | ) | $ | — |
| $ | 12 |
|
Other operating expenses(a) | 292 |
| 51 |
| 10 |
| 13 |
| 31 |
| (1 | ) | 396 |
|
Revenue tax expense(b) | (8 | ) | — |
| — |
| — |
| — |
| — |
| (8 | ) |
Adjusted Operating
Margin | $ | 353 |
| $ | 45 |
| $ | (8 | ) | $ | 9 |
| $ | 2 |
| $ | (1 | ) | $ | 400 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| | 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) | $ | 463 |
| $ | 64 |
| $ | 53 |
| $ | (10 | ) | $ | (15 | ) | $ | — |
| $ | 555 |
|
Other operating expenses(a) | 940 |
| 149 |
| 40 |
| 38 |
| 22 |
| (8 | ) | 1,181 |
|
Revenue tax expense(b) | (74 | ) | — |
| — |
| — |
| — |
| — |
| (74 | ) |
Adjusted Operating
Margin | $ | 1,329 |
| $ | 213 |
| $ | 93 |
| $ | 28 |
| $ | 7 |
| $ | (8 | ) | $ | 1,662 |
|
| | | | Predecessor | | | | | | | | | | | | | | | |
| | January 1, 2016 through June 30, 2016 | Year-to-Date 2019 |
| | Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services | Gas Midstream Operations | All Other | Intercompany Elimination | Consolidated | Gas Distribution Operations | Gas Pipeline Investments | Wholesale Gas Services | Gas Marketing Services | All Other | Intercompany Elimination | Consolidated |
| | (in millions) | (in millions) |
| Operating Income (Loss) | $ | 351 |
| $ | 109 |
| $ | (69 | ) | $ | (9 | ) | $ | (61 | ) | $ | — |
| $ | 321 |
| $ | 317 |
| $ | 10 |
| $ | 96 |
| $ | 80 |
| $ | (16 | ) | $ | — |
| $ | 487 |
|
Other operating expenses(a) | 616 |
| 81 |
| 33 |
| 24 |
| 65 |
| (4 | ) | 815 |
| 677 |
| 6 |
| 29 |
| 62 |
| 29 |
| (4 | ) | 799 |
|
Revenue tax expense(b) | (56 | ) | — |
| — |
| — |
| — |
| — |
| (56 | ) | (76 | ) | — |
| — |
| — |
| — |
| — |
| (76 | ) |
| Adjusted Operating Margin | $ | 911 |
| $ | 190 |
| $ | (36 | ) | $ | 15 |
| $ | 4 |
| $ | (4 | ) | $ | 1,080 |
| $ | 918 |
| $ | 16 |
| $ | 125 |
| $ | 142 |
| $ | 13 |
| $ | (4 | ) | $ | 1,210 |
|
| |
| (a) | Includes other operations and maintenance, depreciation and amortization, and taxes other than income taxes, and Merger-related expenses.taxes. |
| |
| (b) | Nicor Gas' revenue tax expenses, which are passed through directly to customers. |
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FUTURE EARNINGS POTENTIAL
TheEach Registrant's results of operations discussed above are not necessarily indicative of Southern Company Gas'its future earnings potential. Recent disposition activities described under "Acquisitions and Dispositions" herein, in Note (K) to the Condensed Financial Statements herein, and in Note 15 to the financial statements in Item 8 of the Form 10-K will impact future earnings for the applicable Registrants. The level of Southern Company Gas'the Registrants' future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Registrants' primary businesses of selling electricity and/or distributing natural gas, as described further herein.
For the traditional electric operating companies, these factors include the ability to maintain constructive regulatory environments that allow for the timely recovery of prudently-incurred costs during a time of increasing costs, continued customer growth, and the trend of reduced electricity usage per customer, especially in residential and commercial markets. Other major factors include completing construction of Plant Vogtle Units 3 and 4 and related cost recovery proceedings for Georgia Power and the ability to prevail against legal challenges associated with the Kemper County energy facility for Mississippi Power.
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 and increasing volumes of electronic commerce transactions, which could contribute to a net reduction in customer usage.
Global and U.S. economic conditions have been significantly affected by a series of demand and supply shocks that have caused a global and national economic recession. Most prominently, the COVID-19 pandemic has negatively impacted global supply chains and global demand for goods and services and public policy responses of social distancing and closing non-essential businesses have further restricted economic activity. The drivers, speed, and depth of this economic contraction are unprecedented and have reduced energy demand across the Southern Company system's service territory, primarily in the commercial and industrial classes. The negative impacts, which started in late-March 2020, of the COVID-19 pandemic and related recession on the Southern Company system's retail electric sales began to improve in the middle of May 2020; however, retail electric sales through the end of the second quarter 2020 continued to be approximately 3% to 4% lower than levels projected prior to the COVID-19 pandemic. Recovery is expected to continue for the remainder of 2020 and into 2021, but responses to the COVID-19 pandemic by both customers and government could significantly affect the pace of recovery. The ultimate extent of the negative impact on revenues depends on the depth and duration of the economic contraction in the Southern Company system's service territory and cannot be determined at this time. See RESULTS OF OPERATIONS herein for information on COVID-19-related impacts on energy demand in the Southern Company system's service territory during the first six months of 2020.
Alabama Power continues to temporarily suspend disconnections for non-payment by customers and waive late fees as a result of the COVID-19 pandemic. In addition, the traditional electric operating companies have established installment payment plans to allow customers to repay past due accounts over a period of time. See "Regulatory Matters" herein for additional information on the status of disconnections and the deferral of costs resulting from
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
the COVID-19 pandemic at Georgia Power, Mississippi Power, and the natural gas distribution utilities. The ultimate outcome of these matters cannot be determined at this time.
The level of future earnings for Southern Power's competitive wholesale electric business depends on numerous factors including Southern Power's ability to execute its growth strategy through the development or acquisition of renewable facilities and other energy projects while containing costs, as well as regulatory matters, creditworthiness of customers, total electric generating capacity available in Southern Power's market areas, and Southern Power's ability to successfully remarket capacity as current contracts expire. In addition, renewable portfolio standards, transmission constraints, cost of generation from units within the Southern Company power pool, and operational limitations could influence Southern Power's future earnings.
The level of future earnings for Southern Company Gas' primary business of distributing natural gas distribution and its complementary businesses in the gas marketing services,pipeline investments, wholesale gas services, and gas midstream operations sectors.marketing services sectors depends on numerous factors. These factors include Southern Company Gas'the natural gas distribution utilities' ability to maintain a constructive regulatory environmentenvironments that allowsallow for the timely recovery of prudently-incurred costs, the completion and subsequent operation of ongoing infrastructure and other construction projects, creditworthiness of customers, and Southern Company Gas' ability to optimize its transportation and storage positions and its ability to re-contract storage rates at favorable prices. Future earnings in the near term will depend, in part, upon maintaining and growing sales and customers which are subject to a number of factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of natural gas, the price elasticity of demand, and the rate of economic growth or decline in Southern Company Gas' service territories. Demand for natural gas is primarily driven by the pace of economic growth that 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 repealed its non-combination tax rule and increased the effective corporate income tax rate from 5.25% to 7.0% (making the total corporate tax rate 9.5% when combined with the 2.5% personal property replacement tax) effective July 1, 2017. In addition to increasing taxes on future earnings, this legislation required Southern Company Gas to increase accumulated deferred income tax liabilities by $24 million during the third quarter 2017 to reflect these changes, $15 million of which was expensed and $9 million was recorded as a regulatory asset. In addition, during the third quarter 2017, Southern Company calculated new apportionment factors in several states to include Southern Company Gas in its consolidated tax filings, which resulted in $8 million of additional deferred income tax expenses.
On October 15, 2017, Southern Company Gas subsidiary, Pivotal Utility Holdings, entered into agreements for the sale of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. The execution of the asset purchase agreements triggered an interim assessment of goodwill, which is currently being performed with the assistance of a third-party valuation specialist. The preliminary results of this valuation indicate that the estimated fair values of the reporting units with goodwill exceed their carrying amounts and are not at risk of impairment. See OVERVIEW – "Merger, Acquisition, and Disposition Activities" and Note (I) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information on the sales.
Volatilityvolatility of natural gas prices has a significantan impact on Southern Company Gas' customer rates, its long-term competitive position against other energy sources, and the ability of itsSouthern Company Gas' gas marketing services and wholesale gas services segmentsbusinesses 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,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 further delayed or not built, volatility could increase. See "Construction Programs" herein for additional information on permitting challenges experienced by the PennEast Pipeline. 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,In addition, if the COVID-19 pandemic results in a continued economic conditions continue to improve, including the new housing market, thedownturn for a sustained period, demand for natural gas may increase, which may causedecrease, resulting in further downward pressure on natural gas prices to rise and drive higherlower volatility in the natural gas markets on a longer-term basis.
Earnings for both the electricity and natural gas businesses are subject to a variety of other factors. These factors include weather, competition, developing new and maintaining existing energy contracts and associated load requirements with wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the prices of electricity and natural gas, and the price elasticity of demand. Demand for electricity and natural gas in the Registrants' service territories is primarily driven by the pace of economic growth or decline that may be affected by changes in regional and global economic conditions, which may impact future earnings.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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. In addition, Southern Power and Southern Company Gas regularly consider and evaluate joint development arrangements as well as acquisitions and dispositions of businesses and assets as part of their business strategies.
For additional information relating to these issues, see "Risk Factors"RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL in Item 7 of the Form 10-K and RISK FACTORS in Item 1A herein.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Acquisitions and Dispositions
See Note 15 to the financial statements in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements herein for additional information.
Alabama Power
On April 22, 2020 and June 9, 2020, the FERC and the Alabama PSC, respectively, approved the Autauga Combined Cycle Acquisition, which is expected to close by September 1, 2020. See "Regulatory Matters – Alabama Power" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.
Southern Power
On January 17, 2020, Southern Power completed the sale of its equity interests in Plant Mankato (including the 385-MW expansion unit completed in May 2019) to a subsidiary of Xcel for a purchase price of approximately $663 million, including final working capital adjustments. The sale resulted in a gain of approximately $39 million ($23 million after tax). Pre-tax income for Plant Mankato was immaterial for the six months ended June 30, 2020 and the three and six months ended June 30, 2019.
In March 2020, Southern Power entered into an agreement to acquire a controlling membership interest in an approximately 300-MW wind facility located in South Dakota. The acquisition is subject to FERC approval and certain other customary conditions to closing, including commercial operation of the facility, which is expected to occur in late 2020 or early 2021. The facility's output is contracted under two long-term PPAs. The ultimate outcome of this matter cannot be determined at this time.
On May 1, 2020, Southern Power purchased a controlling interest in the 56-MW Beech Ridge II wind facility located in Greenbrier County, West Virginia from Invenergy Renewables LLC. The facility's output is contracted under a 12-year PPA. See Note (K) to the Condensed Financial Statements herein for additional information.
Southern Power continues to evaluate and refine the deployment of the remaining wind turbine equipment purchased in 2016 and 2017 to development and construction projects. During the six months ended June 30, 2020, certain wind turbine equipment was sold, resulting in an immaterial gain.
Southern Company Gas
On March 24, 2020, Southern Company Gas completed the sale of its interests in Item 1APivotal LNG and Atlantic Coast Pipeline to Dominion Modular LNG Holdings, Inc. and Dominion Atlantic Coast Pipeline, LLC, respectively, with aggregate proceeds of $178 million, including working capital adjustments. The preliminary loss associated with the Form 10-K.transactions was immaterial. Southern Company Gas may also receive two future payments of $5 million each, contingent upon certain milestones related to Pivotal LNG being met by Dominion Modular LNG Holdings, Inc. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" 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. 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 Matters –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"Remediation" in Item 8 of the Form 10-K, as well as Note (C) to the Condensed Financial Statements under "Environmental Remediation" herein, for additional information.
Natural Gas StorageEnvironmental Laws and Regulations
A wholly-owned subsidiaryCoal Combustion Residuals
In June 2020, Alabama Power recorded an increase of Southern Company Gas ownsapproximately $462 million to its AROs related to the CCR Rule and operatesthe related state rule primarily due to management's completion of a natural gas storage facility consisting of two salt dome caverns in Louisiana. Periodic integrity tests are required in accordance with rules offeasibility study and the Louisiana Department of Natural Resources (LDNR). In August 2017, in connection with an ongoing integrity project, updated seismic mapping indicatedrelated cost estimates during the proximity ofsecond quarter 2020 for one of the cavernsits ash ponds. Alabama Power's increase also reflects costs
Table of ContentsIndex to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. At September 30, 2017, the facility's property, plant, and equipment had a net book value of $111 million, of which the cavern itself represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including the results of ongoing third-party technical engineering reviews, testing, and compliance with an order from the LDNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining a core sample to determine the composition of the sheath surrounding the edge of the salt dome. Early retirement of the cavern could trigger impairment of other long-lived assets Financial Statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
associated with the natural gas storage facility.addition of a water treatment system to the design of another ash pond. The additional estimated costs to close these ash ponds under the planned closure-in-place methodology primarily relate to inputs from contractor bids, design revisions, and changes in the expected volume of ash handling.
The traditional electric operating companies expect to continue updating their cost estimates and ARO liabilities periodically as additional information related to ash pond closure methodologies, schedules, and/or costs becomes available. Additionally, the closure designs and plans in the States of Alabama and Georgia are subject to approval by environmental regulatory agencies. Absent continued recovery of ARO costs through regulated rates, results of operations, cash flows, and financial condition for Southern Company and the traditional electric operating companies could be materially impacted. See Note (B) to the Condensed Financial Statements under "Georgia Power – Integrated Resource Plan" herein for additional information. The ultimate outcome of this matterthese matters cannot be determined at this time, but could have a material impact on Southern Company Gas' financial statements.
FERC Matters
time. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Southern Company Gas in Item 7 and Note 46 to the financial statements of Southern Company Gas in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information regarding the Dalton Pipeline project.information.
On August 1, 2017, the Dalton Pipeline was placed in service as authorized by the FERC and transportation service for customers commenced.
On October 13, 2017, the Atlantic Coast Pipeline project received FERC approval.Regulatory Matters
See Note 32 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.information.
Nicor Gas has establishedAlabama 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.
Petition for Certificate of Convenience and Necessity
On June 9, 2020, the Alabama PSC approved in part Alabama Power's petition for a variable tax cost adjustment rider,CCN which authorizes Alabama Power to (i) construct an approximately 720-MW combined cycle facility at Alabama Power's Plant Barry (Plant Barry Unit 8), which is expected to be placed in service by the end of 2023, (ii) complete the Autauga Combined Cycle Acquisition, which was approved by the Illinois Commission effective July 16, 2017. This rider providesFERC on April 22, 2020 and is expected to close by September 1, 2020, (iii) purchase approximately 240 MWs of combined cycle generation under a long-term PPA expected to begin later in 2020 and (iv) pursue up to approximately 200 MWs of certain demand-side management and distributed energy resource programs.
The Alabama PSC authorized the recovery of actual costs for the construction of Plant Barry Unit 8 up to 5% above the estimated in-service cost of $652 million. In so doing, it recognized the potential for developments that could cause the project costs to exceed the capped amount, in which case Alabama Power would provide documentation to the Alabama PSC to explain and justify potential recovery of the invested capital tax imposed on Nicor Gasadditional costs.
The Alabama PSC further directed that the proposed solar generation of approximately 400 MWs, coupled with battery energy storage systems (solar/battery systems), be evaluated under an existing Renewable Generation Certificate issued by the Alabama PSC in September 2015.
Alabama Power expects to recover all approved costs associated with the CCN through existing rate mechanisms as outlined in Note 2 to the financial statements in Item 8 of the Form 10-K. The Alabama PSC's approval in part of the CCN will be followed by a written order which is subject to any rehearing request or judicial appeal filed within 30 days of the date of such order.
The ultimate outcome of these matters cannot be determined at this time.
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 an annual true-up and reconciliation mechanism based on amounts approved in prioralternate rate cases. Accordingly, this rider will not have a significant effect on Southern Company Gas' net income.
plan, which includes traditional base tariffs, Demand-Side Management tariffs, the
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION
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(Continued)
Natural GasEnvironmental Compliance Cost Recovery tariff, and Municipal Franchise Fee tariffs. In addition, financing costs on certified construction costs 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.
Deferral of Incremental COVID-19 Costs
On April 7, 2020 and June 2, 2020, in response to the COVID-19 pandemic, the Georgia PSC approved orders directing Georgia Power to continue its previous, voluntary suspension of customer disconnections through July 14, 2020 and to defer the resulting incremental bad debt as a regulatory asset. On June 16, 2020 and July 7, 2020, the Georgia PSC approved orders establishing a methodology for identifying incremental bad debt and allowing the deferral of other incremental costs associated with the COVID-19 pandemic. The period over which such costs will be recovered is expected to be determined in Georgia Power's next base rate case. At June 30, 2020, the incremental costs deferred totaled approximately $34 million. The ultimate outcome of this matter cannot be determined at this time.
Integrated Resource Plan
On March 5, 2020, the Sierra Club filed a petition for judicial review in the Superior Court of Fulton County to appeal the Georgia PSC's decision in the 2019 ARP allowing Georgia Power to recover compliance costs for CCR AROs. Georgia Power intervened in the appeal on June 22, 2020. The ultimate outcome of this matter cannot be determined at this time.
Fuel Cost Recovery
On May 28, 2020, the Georgia PSC approved a stipulation agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors to lower total fuel billings by approximately $740 million over a two-year period effective June 1, 2020. In addition, Georgia Power will further lower fuel billings by approximately $44 million under an interim fuel rider effective June 1, 2020 through September 30, 2020. Georgia Power continues to be allowed to adjust its fuel cost recovery rates under an interim fuel rider prior to its next fuel case if the under or over recovered fuel balance exceeds $200 million. Georgia Power is scheduled to file its next fuel case no later than February 28, 2023.
Mississippi Power
Mississippi Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Mississippi PSC. Mississippi Power's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased power, ad valorem taxes, property damage, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are expected to be recovered through Mississippi Power's base rates.
2019 Base Rate Case
On March 17, 2020, the Mississippi PSC approved the Mississippi Power Rate Case Settlement Agreement between Mississippi Power and the Mississippi Public Utilities Staff related to Mississippi Power's base rate case filed in November 2019.
Under the terms of the Mississippi Power Rate Case Settlement Agreement, annual retail rates decreased approximately $16.7 million, or 1.85%, effective for the first billing cycle of April 2020, based on a test year period of January 1, 2020 through December 31, 2020, a 53% average equity ratio, an allowed maximum actual equity ratio of 55% by the end of 2020, and a 7.57% return on investment.
Additionally, the approved Mississippi Power Rate Case Settlement Agreement: (i) established common amortization periods of four years for regulatory assets and three years for regulatory liabilities included in the approved revenue requirement, including those related to unprotected deferred income taxes; (ii) established new depreciation rates reflecting an annual increase in depreciation of approximately $10 million; and (iii) excluded
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
certain compensation costs totaling approximately $3.9 million. It also eliminated separate rates for costs associated with Plant Ratcliffe and energy efficiency initiatives and includes such costs in the PEP, ECO Plan, and ad valorem tax adjustment factor, as applicable. In accordance with the previous order of the Mississippi PSC suspending the operation of PEP and the ECO Plan for 2018 through 2020, Mississippi Power plans to resume PEP proceedings and ECO Plan filings for 2021.
Performance Evaluation Plan
On July 24, 2020, the Mississippi PSC approved Mississippi Power's July 14, 2020 filing of its PEP compliance rate clause reflecting revisions agreed to in the Mississippi Power Rate Case Settlement Agreement. These revisions include, among other things, changing the filing date for the annual PEP rate filing from November of the immediately preceding year to March of the current year, utilizing a historic test year adjusted for "known and measurable" changes, using discounted cash flow and regression formulas to determine base return on equity, and moving all embedded ad valorem property taxes currently collected in PEP to the ad valorem tax adjustment clause.
Deferral of Incremental COVID-19 Costs
On April 14, 2020 and May 12, 2020, in order to mitigate the economic impact of the COVID-19 pandemic on customers, the Mississippi PSC approved orders directing Mississippi Power to continue its previous, voluntary suspension of customer disconnections through May 25, 2020 and to defer as a regulatory asset all necessary and reasonable incremental costs or expenses to plan, prepare, stage, or react to protect and keep safe its employees and customers, and to reliably operate its utility system during the COVID-19 pandemic. The period over which such costs will be recovered is expected to be determined in a future PEP filing. At June 30, 2020, the incremental costs deferred totaled approximately $2 million. The ultimate outcome of this matter cannot be determined at this time.
Municipal and Rural Associations Tariff
On June 25, 2020, the FERC accepted Mississippi Power's April 27, 2020 request for an increase in wholesale base revenues under the MRA tariff as agreed upon in a settlement agreement reached with its wholesale customers. The MRA settlement agreement resulted in a $2 million annual increase in base rates effective June 1, 2020.
Southern Company Gas has established
The natural gas cost recoverydistribution utilities are subject to regulation and oversight by their respective state regulatory agencies for the rates approvedcharged to their customers and other matters. With the exception of Atlanta Gas Light, which does not sell natural gas to end-use customers, the natural gas distribution utilities are authorized by the relevant state regulatory agencies in the states in which it serves.they serve to use natural gas cost recovery mechanisms that adjust rates to reflect changes in the wholesale cost of natural gas and ensure recovery of all costs prudently incurred in purchasing natural gas for customers. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on Southern Company Gas' revenues or net income, but will affect cash flows. In addition to natural gas cost recovery mechanisms, there are other cost recovery mechanisms, such as regulatory riders, which vary by utility but allow recovery of certain costs, such as those related to infrastructure replacement programs, as well as environmental remediation, energy efficiency plans, and bad debt.
Base Rate Cases
Settled Base Rate Cases
On February 21, 2017,The natural gas distribution utilities have various regulatory mechanisms to recover bad debt expense, which will mitigate potential increases in bad debt expense as a result of the Georgia PSC approvedCOVID-19 pandemic. Nicor Gas fully recovers its bad debt expenses, both the Georgia Rate Adjustment Mechanism (GRAM)gas and a $20 million increasenon-gas portions, through its purchased gas adjustment mechanism and separate bad debt rider. Virginia Natural Gas and Chattanooga Gas recover the gas portion of bad debt expense through their purchased gas adjustment mechanisms and the non-gas portion of bad debt expense through their base rates in annual base rate revenues foraccordance with established benchmarks. 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 byhave material bad debt expense because its receivables are from Marketers, rather than end-use customers. Its tariff allows it to obtain credit security support from the Georgia PSC under Atlanta Gas Light's STRIDE program, which include the Integrated Vintage Plastic Replacement Program and Integrated System Reinforcement Program, will continue under GRAM and the recoveryMarketers in an amount equal to at least two times their estimated highest bill.
Pursuant to the GRAM approval, Atlanta Gas Light and the staff of the Georgia PSC agreed to a variation to the Integrated Customer Growth Program that was formerly part of Atlanta Gas Light's STRIDE program. As a result, a new tariff was created, effective October 10, 2017, to provide $15 million annually for Atlanta Gas Light to commit to strategic economic development projects.
Beginning with the next rate adjustment inMANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Rate Proceedings
On 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, Elizabethtown2020, Virginia Natural Gas filed a general base rate case with the New Jersey BPU requesting a $19 millionVirginia Commission seeking an increase in annual base rate revenues.rates of$49.6 million primarily to recover investments and increased costs associated with infrastructure, technology, and workforce development. The requested increase wasis based on a projected 12-month test year ending March 31, 2017 andbeginning November 1, 2020, a ROE of 10.25%10.35%, and an equity ratio of 54%. 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 isRate adjustments are expected to result in a $3 million annual reduction of depreciation. See OVERVIEW – "Merger, Acquisition, and Disposition Activities" and Note (I)be effective November 1, 2020, subject to the Condensed Financial Statements under "Southern Company Gas" herein for information on the proposed sale of Elizabethtown Gas.
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.refund. The requested increase is based on a 2018 projected test year and a ROE of 10.7%. The IllinoisVirginia Commission is expected to rule on the requested increase in the second quarter 2021.
On July 1, 2020, Atlanta Gas Light filed its 2020 GRAM filing with the Georgia PSC. The filing requests an annual base rate increase of $37.6 million based on the projected 12-month period beginning January 1, 2021, which does not exceed the 5% limitation established by the Georgia PSC in its December 2017, after which rate adjustments will be effective.
On March 31, 2017, Virginia Natural2019 approval of Atlanta Gas filed aLight's general base rate case with the Virginia Commission requesting a $44 million increase in annual base rate revenues. The requested increase was based on a projected 12-month test year beginning September 1, 2017 and a ROE of 10.25%. The requested increase included $13 million related to the recovery of investments under the Steps to Advance Virginia's Energy (SAVE) program. On October 3, 2017, Virginia Natural Gas entered into a proposed stipulation with the Staffcase. Resolution of the Virginia Commission, the Office of the Attorney General, Division of Consumer Counsel, and the Virginia Industrial Gas Users' Association resolving all related issues. The proposed stipulation includes a $34 million increase in annual base rate revenues, including $13 million related to the recovery of investments under the SAVE program. An authorized ROE range of 9.0% to 10.0% with a midpoint of 9.5% will be used to determine the revenue requirement in any2020 GRAM filing other than for a
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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change in base rates. The Virginia Commission is expected to rule on the proposed stipulation in the fourth quarter 2017. Rate adjustments based on the proposed stipulation becameby December 31, 2020, with rates effective SeptemberJanuary 1, 2017, subject to refund.
On October 23, 2017, Florida City Gas filed a general base rate case with the Florida PSC requesting a $19 million increase in annual base rate revenues. The requested increase is based on a 2018 projected test year and a ROE of 11.25%2021. The requested increase includes $3 million related to the recovery of investments under the Safety, Access, and Facility Enhancement (SAFE) program. Additionally, Florida City Gas requested interim rates of $5 million to be effective in January 2018, subject to refund. The Florida PSC is expected to rule on the requested increase in mid-2018.
The ultimate outcome of these pending base rate casesmatters cannot be determined at this time.
Regulatory Infrastructure ProgramsDeferral of Incremental COVID-19 Costs
Southern CompanyAtlanta Gas is engagedLight
On April 30, 2020, in various infrastructure programs that update or expandresponse to the COVID-19 pandemic, the Georgia PSC approved orders directing Atlanta Gas Light to continue its gas distribution systemsprevious, voluntary suspension of customer disconnections. On June 22, 2020, the Georgia PSC ordered Atlanta Gas Light to improve reliability and ensureresume customer disconnections beginning July 1, 2020, with exceptions for customers still covered by a shelter-in-place order. The orders provide the safetyMarketers, including SouthStar, with a mechanism to receive credits from Atlanta Gas Light for the base rates it charged to the Marketers of non-paying customers during the suspension. Atlanta Gas Light expects to recover these credits through the annual revenue true-up process within its utility infrastructure, and recovers in2021 GRAM filing, which would impact rates its investment and a return associated with these infrastructure programs.effective January 1, 2022. The ultimate outcome of this matter cannot be determined at this time.
Nicor Gas
On March 18, 2020, the Illinois Commission issued an order directing utilities to cease disconnections for non-payment and to suspend the imposition of late payment fees or penalties until the Governor of Illinois announces the end of the COVID-19 state of emergency. In 2014,response to this order, on March 27, 2020, Nicor Gas and other utilities in Illinois filed their plans seeking cost recovery and more flexible credit and collection plans.
On June 18, 2020, the Illinois Commission approved Nicor Gas' nine-year regulatory infrastructure program, Investing in Illinois. Under this program, Nicor Gas placed into service $178 million of qualifying assets duringa stipulation pursuant to which the first nine months of 2017.
Atlanta Gas Light
Atlanta Gas Light's STRIDE program,utilities will provide more flexible credit and collection procedures to assist customers with financial hardship and which started in 2009, consists of three individual programs that update and expand gas distribution systems and LNG facilities as well as improve system reliability to meet operational flexibility and customer growth. Through the programs under STRIDE, Atlanta Gas Light invested $127 million during the first nine months of 2017. Theauthorizes a special purpose rider for recovery of and return on current and future capital investments under the STRIDE program are included in the annual base rate revenue adjustment under GRAM.
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. Subsequently, the proposed capital investmentsfollowing COVID-19 pandemic-related impacts: incremental costs directly associated with the extensionCOVID-19 pandemic, net of i-SRP were included in the 2017 annual base rate revenue under GRAM approved byoffset for COVID-19 pandemic-related credits received, foregone late fees, foregone reconnection charges, and the Georgia PSCcosts associated with a bill payment assistance program. The special purpose rider is proposed to be effective on February 21, 2017.
See "Base Rate Cases" herein for additional information.
Elizabethtown Gas
In 2013, the New Jersey BPU approved the extensionOctober 1, 2020 and continue over a 24-month period. At June 30, 2020, Nicor Gas' related regulatory asset was $12 million. The ultimate outcome of Elizabethtown Gas' Aging Infrastructure Replacement program, under which Elizabethtown Gas invested $16 million during the first nine months of 2017. Effective July 1, 2017, investments under this program are being recovered through base rate revenues.matter cannot be determined at this time.
Virginia Natural Gas
In March 2016,response to the COVID-19 pandemic, the Virginia Commission approved an extension to the SAVE program, under whichissued orders requiring Virginia Natural Gas invested $21 million duringto suspend disconnections beginning on March 16, 2020 and also to suspend late payment and reconnection fees beginning on April 9, 2020, both of which continue in effect through August 31, 2020. On April 29, 2020, the first nine monthsVirginia Commission authorized Virginia Natural Gas to defer the following COVID-19 pandemic-related costs as a regulatory asset: incremental uncollectible expense incurred, suspended late fees, suspended reconnection charges, carrying costs, and other incremental prudently incurred costs associated with the COVID-19 pandemic. Specific recovery of 2017.
Florida City Gas
The Florida PSC approved Florida City Gas' SAFE programthe amounts deferred in 2015. Under the program, Florida City Gas invested $9 million during the first nine months of 2017.
Other Matters
Southern Company Gas is involveda regulatory asset will be addressed in various other matters being litigated and regulatory matters that could affecta future earnings. In addition, Southern Company Gas is subject to certain claims and legal actions arising in the
rate proceeding. At June 30,
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
(Continued)
ordinary course of business.2020, Virginia Natural Gas' related regulatory asset was $1 million. The ultimate outcome of such pending or potential litigation or regulatory mattersthis matter cannot be predicteddetermined 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.time.
ACCOUNTING POLICIESConstruction Programs
Application of Critical Accounting PoliciesOverview
The Subsidiary Registrants are engaged in continuous construction programs to accommodate existing and Estimates
estimated future loads on their respective systems. The Southern Company Gas preparessystem intends to continue its financial statementsstrategy of developing and constructing new electric generating facilities, expanding and improving the electric transmission and electric and natural gas distribution systems, and undertaking projects to comply with environmental laws and regulations.
For the traditional electric operating companies, major generation construction projects are subject to state PSC approval 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
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Southern Company Gas in Item 7 of the Form 10-K for additional information.
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 revenueorder to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements.retail rates. The majority oflargest construction project currently underway in the Southern Company Gas' revenue, including energy provided to customers,system 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 managementPlant Vogtle Units 3 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
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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. Southern Company Gas is evaluating the standard and expects to early adopt ASU 2017-04 effective January 1, 2018.
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. 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.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with early adoption permitted. Southern Company Gas is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on Southern Company Gas' financial statements.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FINANCIAL CONDITION AND LIQUIDITY
Overview
4. 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 third quarter and year-to-date 2017, the successor period of July 1, 2016 through September 30, 2016, and the predecessor period of January 1, 2016 through June 30, 2016. See OVERVIEW – "Merger, Acquisition, and Disposition Activities" and Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company GasNuclear Construction" herein for additional information.
Southern Company Gas' financial condition remained stable at September 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, Also see Note 2 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 September 30, 2017, the amount of subsidiary retained earnings and net income available to dividend totaled $752 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 (used for) operating activities totaled $1.1 billion for the successor first nine months of 2017, $(342) million for the successor period of July 1, 2016 through September 30, 2016, and $1.1 billion for the predecessor period of January 1, 2016 through June 30, 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 $1.2 billion for the successor first nine 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 $1.7 billion for the successor period of July 1, 2016 through September 30, 2016 and $559 million for the predecessor period of January 1, 2016 through June 30, 2016 primarily due to gross property additions related to capital expenditures for infrastructure replacement programs at gas distribution operations and the acquisition of Southern Company Gas' ownership interest in SNG in September 2016.
Net cash provided from financing activities totaled $45 million for the successor first nine months of 2017, primarily due to proceeds from debt issuances and capital contributions from Southern Company, partially offset by net repayments of commercial paper borrowings and common stock dividend payments to Southern Company. Net cash provided from (used for) financing activities totaled $2.1 billion for the successor period of July 1, 2016 through September 30, 2016 and $(558) million for the predecessor period of January 1, 2016 through June 30, 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. The successor period of July 1, 2016 through September 30, 2016 also includes capital contributions from Southern Company to fund the investment in SNG. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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Significant balance sheet changes at September 30, 2017 include an increase of $847 million in total property, plant, and equipment primarily due to capital expenditures for infrastructure replacement programs, an increase in long-term debt of $603 million primarily due to $450 million of senior notes and $200 million of first mortgage bonds at Nicor Gas issued in May 2017 and August 2017, respectively, and a decrease of $323 million in notes payable related primarily to net repayments of commercial paper borrowings at Nicor Gas. Other significant balance sheet changes include an increase of $239 million in accumulated deferred income taxes, primarily as a result of tax depreciation related to infrastructure assets placed in service as well as the impact of State of Illinois tax legislation, and decreases of $196 million and $146 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. There are no scheduled maturities of long-term debt through September 30, 2018. See "Sources of Capital" herein for additional information.
The regulatory infrastructure programs and other construction programs are subject to periodic review and revision, and actual costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in FERC rules and regulations; state regulatory approvals; changes in legislation; the cost and efficiency of labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. See Note 3 to the consolidated financial statements of Southern Company Gas in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Alabama Power" for information regarding additional factors that may impact infrastructure investment expenditures.Alabama Power's construction of Plant Barry Unit 8.
Sources of Capital
While Southern Company Gas plans to obtain the funds to meet itsPower generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future capital needs through operating cash flows, short-term debt borrowings under its commercial paper programs, external securities issuances,earnings. See "Southern Power" herein, "Acquisitions and equity contributions fromDispositions – 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 September 30, 2017, Southern Company Gas' current liabilities exceeded current assets by $645 million primarily as a result of $934 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.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
At September 30, 2017, Southern Company Gas had approximately $21 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2017 were as follows:
|
| | | | | | | | |
| Company | | Expires 2022 | | Unused |
| | | (millions) |
| Southern Company Gas Capital | | $ | 1,200 |
| | $ | 1,161 |
|
| Nicor Gas | | 700 |
| | 700 |
|
| Total | | $ | 1,900 |
| | $ | 1,861 |
|
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-KPower" herein, and Note (E)(K) to the Condensed Financial Statements under "Bank Credit ArrangementsSouthern Power" herein, for additional information.
In May 2017, Southern Company Gas Capital and Nicor Gas terminated their existing credit arrangements for $1.3 billion and $700 million, respectively, which were to mature in 2017 and 2018, and entered into a new multi-year credit arrangement (Facility) currently allocated for $1.2 billion and $700 million, respectively, with a maturity date of 2022, as reflected in the table above. Pursuant to the Facility, the allocations may be adjusted.
The Facility contains a covenant that limits the ratio of debt to capitalization (as defined in each facility) to a maximum of 70% for each of 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 September 30, 2017, both companies were in compliance with such covenant. The Facility does not contain a material adverse change clause at the time of borrowings.
Subject to applicable market conditions, the applicable company expects to renew or replace the Facility as needed, prior to expiration. In connection therewith, the applicable company may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
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 commercial paper borrowings were as follows:
|
| | | | | | | | | | | | | | | | | |
| | Commercial Paper at September 30, 2017 | | Commercial Paper 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 | $ | 836 |
| | 1.5 | % | | $ | 680 |
| | 1.5 | % | | $ | 838 |
|
| Nicor Gas | 98 |
| | 1.3 |
| | 40 |
| | 1.3 |
| | 120 |
|
| Total | $ | 934 |
| | 1.5 | % | | $ | 720 |
| | 1.5 | % | | |
| |
(*) | Average and maximum amounts are based upon daily balances during the successor three-month period ended September 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.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 September 30, 2017 were $12 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 September 30, 2017, the non-principal components totaled $523 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 December 2016, Southern Company Gas executed intercompany promissory notes to further allocate interest expense to its reportable segments that previously remained in the "all other" segment. These intercompany promissory notes allow Southern Company Gas to calculate net income, which is its performance measure subsequent to the Merger, at the segment level that incorporates the full impact of interest costs.
In May 2017, Southern Company Gas Capital issued $450 million aggregate principal amount of Series 2017A 4.40% Senior Notes due May 30, 2047. The proceeds were used to repay Southern Company Gas' short-term indebtedness and for general corporate purposes.
In July 2017, Atlanta Gas Light Company repaid at maturity $22 million of Series C medium-term notes.
In July 2017, Nicor Gas agreed to issue $400 million aggregate principal amount of first mortgage bonds in a private placement. On August 10, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.03% Series due August 10, 2027 and $100 million aggregate principal amount of First Mortgage Bonds 3.62% Series due August 10, 2037. The proceeds were used to repay short-term indebtedness incurred under the Nicor Gas commercial paper program and for other working capital needs. The remaining $200 million is expected to be issued in 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 third 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.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 |
| | | Third Quarter | | Third Quarter | | Year-to-Date | | July 1, 2016 through September 30, 2016 | | | January 1, 2016
through
June 30,
2016 |
| | | 2017 | | 2016 | | 2017 | | | |
| | | (in millions) | | | (in millions) |
Contracts outstanding at beginning of period,
assets (liabilities), net | | $ | 51 |
| | $ | (54 | ) | | $ | 12 |
| | $ | (54 | ) | | | $ | 75 |
|
| Contracts realized or otherwise settled | | (6 | ) | | (3 | ) | | (22 | ) | | (3 | ) | | | (77 | ) |
Current period changes(a) | | (16 | ) | | — |
| | 39 |
| | — |
| | | (82 | ) |
Contracts outstanding at the end of period,
assets (liabilities), net | | 29 |
| | (57 | ) | | 29 |
| | (57 | ) | | | (84 | ) |
| Netting of cash collateral | | 76 |
| | 111 |
| | 76 |
| | 111 |
| | | 120 |
|
Cash collateral and net fair value of contracts
outstanding at end of period(b) | | $ | 105 |
| | $ | 54 |
| | $ | 105 |
| | $ | 54 |
| | | $ | 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 $13 million at September 30, 2017 and $7 million at September 30, 2016. |
The maturities of Southern Company Gas' energy-related derivative contracts at September 30, 2017 were as follows:
|
| | | | | | | | | | | | | | | |
| | | | Fair Value Measurements |
| | | | Successor – September 30, 2017 |
| | Total
Fair Value | | Maturity |
| | | Year 1 | | Years 2 & 3 | | Years 4 and thereafter |
| | (in millions) |
Level 1(a) | $ | (35 | ) | | $ | (10 | ) | | $ | (20 | ) | | $ | (5 | ) |
Level 2(b) | 64 |
| | 12 |
| | 45 |
| | 7 |
|
Fair value of contracts outstanding at end of period(c) | $ | 29 |
| | $ | 2 |
| | $ | 25 |
| | $ | 2 |
|
| |
(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 $76 million at September 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, 2016 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended September 30, 2017 and 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 for the three and nine months ended September 30, 2017 and the three months ended September 30, 2016, as well as its financial condition as of September 30, 2017 and December 31, 2016, are reflected within Southern Company's consolidated amounts in these accompanying notes herein. The equity method is used for entities in which Southern Company has significant influence but does not control, including Southern Company Gas' investment in 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" 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' 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
See Note 115 to the financial statements of the registrants under "Recently Issued Accounting Standards" in Item 8 of the Form 10-K for additional information.
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 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. Southern Company and Southern Company Gas are evaluating the standard and expect to early adopt ASU 2017-04 effective January 1, 2018.
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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company's, the traditional electric operating companies', and 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's, the traditional electric operating companies', or Southern Company Gas' financial statements.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with early adoption permitted. The registrants are evaluating the standard and expect to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on the registrants' financial statements.
Affiliate Transactions
Prior to the completion of Southern Company Gas' acquisition of its 50% equity interest in SNG, SCS (as agent for Alabama Power, Georgia Power, and Southern Power) and Southern Company Gas had entered into long-term interstate natural gas transportation agreements with SNG. The interstate transportation service provided to 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 nine months ended September 30, 2017, transportation costs under these agreements for Alabama Power, Georgia Power, Southern Power, and Southern Company Gas were approximately $8 million, $77 million, $19 million, and $24 million, respectively. For the period subsequent to Southern Company Gas' investment in SNG through September 30, 2016, transportation costs under these agreements for Alabama Power, Georgia Power, Southern Power, and Southern Company Gas were approximately $1 million, $8 million, $2 million, and $4 million, respectively.
SCS, as agent for Georgia Power and Southern Power, has agreements with certain subsidiaries of Southern Company Gas to purchase natural gas. For the nine months ended September 30, 2017, natural gas purchases made by Georgia Power and Southern Power from Southern Company Gas' subsidiaries were approximately $18 million and $94 million, respectively. For the period subsequent to Southern Company's acquisition of Southern Company Gas through September 30, 2016, natural gas purchases made by Georgia Power and Southern Power from Southern Company Gas' subsidiaries were approximately $7 million and $2 million, respectively.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Goodwill and Other Intangible Assets
At September 30, 2017 and December 31, 2016, goodwill was as follows:
|
| | | | | | |
| | Goodwill |
| | At September 30, 2017 | At December 31, 2016 |
| | (in millions) |
| Southern Company | $ | 6,267 |
| $ | 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 each year, or more frequently if impairment indicators arise.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Other intangible assets were as follows:
|
| | | | | | | | | | | | | | | | | | | |
| | At September 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 |
| $ | (70 | ) | $ | 218 |
| | $ | 268 |
| $ | (32 | ) | $ | 236 |
|
| Trade names | 159 |
| (15 | ) | 144 |
| | 158 |
| (5 | ) | 153 |
|
| Storage and transportation contracts | 64 |
| (27 | ) | 37 |
| | 64 |
| (2 | ) | 62 |
|
| PPA fair value adjustments | 456 |
| (41 | ) | 415 |
| | 456 |
| (22 | ) | 434 |
|
| Other | 16 |
| (3 | ) | 13 |
| | 11 |
| (1 | ) | 10 |
|
| Total other intangible assets subject to amortization | $ | 983 |
| $ | (156 | ) | $ | 827 |
|
| $ | 957 |
| $ | (62 | ) | $ | 895 |
|
| Other intangible assets not subject to amortization: | | | | | | | |
| Federal Communications Commission licenses | $ | 75 |
| $ | — |
| $ | 75 |
| | $ | 75 |
| $ | — |
| $ | 75 |
|
| Total other intangible assets | $ | 1,058 |
| $ | (156 | ) | $ | 902 |
| | $ | 1,032 |
| $ | (62 | ) | $ | 970 |
|
| | | | | | | | |
| Southern Power | | | | | | | |
| Other intangible assets subject to amortization: | | | | | | | |
| PPA fair value adjustments | $ | 456 |
| $ | (41 | ) | $ | 415 |
| | $ | 456 |
| $ | (22 | ) | $ | 434 |
|
| | | | | | | | |
| Southern Company Gas | | | | | | | |
| Other intangible assets subject to amortization: | | | | | | | |
| Gas marketing services | | | | | | | |
| Customer relationships | $ | 221 |
| $ | (65 | ) | $ | 156 |
| | $ | 221 |
| $ | (30 | ) | $ | 191 |
|
| Trade names | 115 |
| (8 | ) | 107 |
| | 115 |
| (2 | ) | 113 |
|
| Wholesale gas services | | | | | | | |
| Storage and transportation contracts | 64 |
| (27 | ) | 37 |
| | 64 |
| (2 | ) | 62 |
|
| Total other intangible assets subject to amortization | $ | 400 |
| $ | (100 | ) | $ | 300 |
| | $ | 400 |
| $ | (34 | ) | $ | 366 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Amortization associated with other intangible assets was as follows:
|
| | | | | | |
| | Three Months Ended | Nine Months Ended |
| | September 30, 2017 |
| | (in millions) |
| Southern Company | $ | 29 |
| $ | 94 |
|
| Southern Power | $ | 6 |
| $ | 19 |
|
| Southern Company Gas | $ | 20 |
| $ | 66 |
|
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 regardingabout costs relating to Southern Power's PPA fair value adjustments related to its business acquisitions. Also see Note (I) under "Southern Company– Acquisition of PowerSecure" 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 and 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 eventsacquisitions 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 property damage reserve to approximately $40 million. As of September 30, 2017, Gulf Power's property damage reserve totaled approximately $39 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 WACOG basis.
Nicor Gas' natural gas inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated. Southern Company Gas had no inventory decrement at September 30, 2017. 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 or Southern Company Gas' net income.
Natural gas inventories for Southern Company Gas' non-utility businesses are carried at the lower of weighted average cost or current market price, with cost determined on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value. 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
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, 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, to which the plaintiffs filed an opposition on September 11, 2017.
On February 27, 2017, Jean Vineyard filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the defendants caused Southern Company to make false or misleading statements regarding the Kemper 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 and, on May 31, 2017, Judy Mesirov filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. Each complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with theinvolve construction of the Kemper IGCC. Each 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. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. On August 15, 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia and the court deferred the consolidated case until 30 days after certain further action in the purported securities class action complaint discussed above.
Southern Company believes these legal challenges have no merit; however, an adverse outcome in any of these proceedings could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, the ultimate outcome of which cannot be determined at this time.
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 filed a petition for writ of certiorari with the Georgia Supreme Court, which was granted on August 28, 2017. A decision from the Georgia Supreme Court is not expected until 2018. 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 generatingrenewable 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 counter lawsuit against Roserock, Array Technologies, Inc., Canadian Solar (USA), Inc., XL, and North American Elite in the U.S. District Court for the Western District of Texas alleging, among other things, breach of contract, and requesting foreclosure of mechanic's liens against Roserock. On July 18, 2017, the U.S. District Court for the Western District of Texas consolidated the two pending lawsuits. Southern Power intends to vigorously pursue and defend these matters, the ultimate outcome of which cannot be determined at this time.facilities.
Southern Company Gas
Nicor Gas and Nicor Energy Services Company, wholly-owned subsidiaries of Southern Company Gas, and Nicor Inc. were defendants is engaged in a putative class action initially filed in 2011 in the state court in Cook County, Illinois. The plaintiffs purportedvarious infrastructure improvement programs designed 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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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'supdate or Southern Company Gas' financial statements.
Environmental Matters
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 andexpand 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.
Georgia Power's environmental remediation liability was $26 million and $17 million as of September 30, 2017 and December 31, 2016, respectively. Georgia Power has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected.
Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $53 million and $44 million as of September 30, 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 Power's substations. The schedule for completion of the remediation projects is subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power's environmental cost recovery clause; therefore, these liabilities have no impact on net income.
Southern Company Gas' environmental remediation liability was $399 million and $426 million as of September 30, 2017 and December 31, 2016, respectively, based on the estimated cost of environmental investigation and remediation associated with known current and former manufactured gas plant operating sites. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the applicable state regulatory agenciessystems of the natural gas distribution utilities with the exception of one site representing $5 million of the total accrued remediation costs.
The final outcome of these matters cannot be determined at this time. However, the final disposition of these matters is not expected to have a material impact on the financial statements of Southern Company, Georgia Power, Gulf Power, or Southern Company Gas.
Natural Gas Storage
A wholly-owned subsidiary of Southern Company Gas ownsimprove reliability and operates ameet operational flexibility and growth. The natural gas storage facility consisting of two salt dome caverns in Louisiana. Periodic integrity tests are required in accordance with rules of the Louisiana Department of Natural Resources (LDNR). In August 2017, in connection with an ongoing integrity project, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimumdistribution utilities recover their investment and could result in Southern Company Gas retiring the cavern early. At September 30, 2017, the facility's property, plant, and equipment had a net book value of $111 million, of which the cavern itself represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including the results of ongoing third-party technical engineering reviews, testing, and compliance with an order from the LDNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining a core sample to determine the composition of the sheath surrounding the edge of the salt dome. Early retirement of the cavern could trigger impairment of other long-lived assetsreturn associated with the natural gas storage
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
facility. The ultimate outcome of this matter cannot be determined at this time, but could have a significant impact on Southern Company's financial statements and a material impact on Southernthese infrastructure programs through their regulated rates. See "Southern Company Gas' financial statements.
Nuclear Fuel Disposal Costs
See Note 3 to the financial statements of Southern Company, Alabama Power, and Georgia Power under "Nuclear Fuel Disposal Costs" in Item 8 of the Form 10-KGas" herein for additional information regarding legal remedies pursued by Alabama Powerinfrastructure improvement programs at the natural gas distribution utilities and Georgia Power against the U.S. government for its partial breach of contract relating to the disposal of spent nuclear fuelPennEast Pipeline construction project.
See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and high level radioactive waste generated at each company's nuclear plants.
On October 10, 2017, Alabama Power and Georgia Power filed additional lawsuits against the U.S. government in the Court of Federal Claims for the costs of continuing to store spent nuclear fuel at Plant Farley, Plant Hatch, and Plant Vogtle Units 1 and 2 for the period from January 1, 2015 through December 31, 2017. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of September 30, 2017 for any potential recoveries from the additional lawsuits. The final outcome of these matters cannot be determined at this time; however, no material impact on Southern Company's, Alabama Power's, or Georgia Power's net income is expected.
FERC Matters
Municipal and Rural Associations Tariff
See Note 3 to the financial statements of Mississippi Power under "FERC Matters" in Item 8 of the Form 10-K for additional information regarding a settlement agreement entered into by Mississippi Power regarding the establishment of a regulatory asset for Kemper IGCC-related costs. See "Integrated Coal Gasification Combined CycleContractual Obligations" herein for information regarding the Kemper IGCC.
In March 2016, Mississippi Power reached a settlement agreement with its wholesale customers, which was subsequently approved by the FERC, for an increase in wholesale base revenues under the MRA cost-based electric tariff, primarily as a result of placing scrubbers for Plant Daniel Units 1 and 2 in service in 2015. The settlement agreement became effective for services rendered beginning May 1, 2016, resulting in an estimated annual revenue increase of $7 million under the MRA cost-based electric tariff. Additionally, under the settlement agreement, the tariff customers agreed to similar regulatory treatment for MRA tariff ratemaking as the treatment approved for retail ratemaking through an order issued by the Mississippi PSC in December 2015 (In-Service Asset Rate Order). This regulatory treatment primarily includes (i) recovery of the 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 totaled approximately $22 million through the suspension of Kemper 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 September 30, 2017, the amount of over-recovered wholesale MRA fuel costs included in the balance sheets was $3 million compared to $13 million at December 31, 2016. Over-recovered wholesale MB fuel costs included in the balance sheets were immaterial at September 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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Market-Based Rate Authority
See 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 under "FERC Matters" in Item 8 of the Form 10-K for additional information regarding the traditional electric operating companies' and Southern Power's market power proceeding and amendment toRegistrants' capital requirements for their market-rate tariff.construction programs.
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 related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' and Southern Power's June 30, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order, or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and Southern Power expect to make a filing within the specified 60 days responding to the FERC's order.
The ultimate outcome of these matters cannot be determined at this time.
Regulatory Matters
Alabama Power
See Note 3 to the financial statements of Southern Company and Alabama Power under "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,
2017 | December 31,
2016 |
|
| (in millions) |
| Rate CNP Compliance | Deferred over recovered regulatory clause revenues | $ | 9 |
| $ | — |
|
Rate CNP Compliance(*) | Deferred under recovered regulatory clause revenues | — |
| 9 |
|
| Rate CNP PPA | Deferred under recovered regulatory clause revenues | 17 |
| 142 |
|
Retail Energy Cost Recovery(*) | Other regulatory liabilities, current | — |
| 76 |
|
| Natural Disaster Reserve | Other regulatory liabilities, deferred | 51 |
| 69 |
|
| |
(*) | 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 and $11 million of its under recovered balance for Retail Energy Cost Recovery to a deferred regulatory asset account. |
Georgia Power
Rate Plans
See Note 3 to the financial statements of Southern Company and Georgia Power under "Regulatory Matters – Georgia Power – Rate Plans" and "Retail Regulatory Matters – Rate Plans," respectively, in Item 8 of the Form 10-K for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 "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" 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" in Item 8 of the Form 10-K for additional information regarding fuel cost recovery.
Integrated Resource Plan
See Note 3 to the financial statements of Southern Company and Georgia Power under "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.
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.
Fuel Cost Recovery
See Note 3 to the financial statements of Southern Company and Georgia Power under "Regulatory Matters – Georgia Power – Fuel Cost Recovery" and "Retail Regulatory Matters – Fuel Cost Recovery," respectively, in Item 8 of the Form 10-K for additional information.
As of September 30, 2017, Georgia Power's under recovered fuel balance totaled $100 million and is included in current assets and other deferred charges and assets on Southern Company's and Georgia Power's condensed balance sheets. As of December 31, 2016, Georgia Power's over recovered fuel balance totaled $84 million and is included in other current liabilities on Southern Company's and Georgia Power's 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
Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, for incremental operating and maintenance costs of damage from major storms to its transmission and distribution facilities. During September 2017, Hurricane Irma caused significant damage to Georgia Power's transmission and distribution facilities. The total amount of incremental restoration costs related to this hurricane is estimated to be approximately $150 million. As of September 30, 2017, Georgia Power had deferred approximately $145 million in a regulatory asset related to storm damage. As of September 30, 2017, the total balance in Georgia Power's regulatory asset related to storm damage was $360 million. The rate of storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case required to be filed by July 1, 2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's or Georgia Power's financial statements. See Note 3 to the financial statements of Southern Company under "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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Nuclear Construction
See Note 32 to the financial statements of Southern Company and Georgia Power under "Regulatory Matters – Georgia"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)the joint ownership agreements and related funding agreement, VCM reports, and the NCCR tariff, and the Contractor Settlement Agreement.
Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcytariff.
In 2008,2009, the 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 sharePSC certified construction of Plant Vogtle Units 3 and 4, isin which Georgia Power holds a 45.7%.
The ownership interest. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 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 Contractorcontinued under the Vogtle 3 and 4 Agreement, which was 40% of the contracta substantially fixed price (approximately $1.7 billion based on Georgia Power's ownership interest).
Onagreement. In 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
In connection 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 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. The Interim Assessment Agreement, as amended, expired on July 27, 2017.
Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor, including Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, 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 September 30, 2017, of the Vogtle Owners for the removal of subcontractor liens and payment of other EPC Contractor pre-petition accounts payable to total approximately $386 million, of which $340 million had been paid or accrued as of September 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $176 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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations, which will reduce CWIP, 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 October 2, 2017, Georgia Power received the first installment of the Guarantee Obligations of $300 million from Toshiba, of which Georgia Power's proportionate share was $137 million. Georgia Power is considering potential options with respect to its right to future payments under the Guarantee Settlement Agreement and its claims against the EPC Contractor in the EPC Contractor's bankruptcy proceeding, including a potential sale of those payment rights and bankruptcy claims. Any such transaction cannot be assured and would be subject to DOE consents and related approvals under the Loan Guarantee Agreement and related agreements.
On August 10, 2017, Toshiba released its financial results for the quarter ended June 30, 2017, which reflected a negative shareholders' equity balance of approximately $4.5 billion as of June 30, 2017. Toshiba previously 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,filing, 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 onseveral transitional arrangements to allow construction to continue. In 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.
Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into the Vogtle Services Agreement, whereby Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a construction completion agreement (Bechtel Agreement) with Bechtel Power Corporation (Bechtel), whereby Bechteltime and materials cost basis. The Vogtle Services Agreement provides that it will serve ascontinue until the primary contractor for the remaining construction activities forstart-up and testing of Plant Vogtle Units 3 and 4. Facility design4 are complete and engineering remainselectricity is generated and
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
sold from both units. The Vogtle Services Agreement is terminable by the responsibility ofVogtle Owners upon 30 days' written notice.
In October 2017, Georgia Power, acting for itself and as agent for the EPC Contractor underother Vogtle Owners, executed the Services Agreement. The Bechtel Agreement, is a cost reimbursable plus fee arrangement, whereby Bechtel will beis reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. Pursuant
See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for information on the Amended and Restated Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
Cost and Schedule
Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 by the expected in-service dates of November 2021 and November 2022, respectively, is as follows:
|
| | | |
| | (in billions) |
Base project capital cost forecast(a)(b) | $ | 8.4 |
|
| Construction contingency estimate | 0.1 |
|
Total project capital cost forecast(a)(b) | 8.5 |
|
Net investment as of June 30, 2020(b) | (6.6 | ) |
Remaining estimate to complete(a) | $ | 1.9 |
|
| |
| (a) | Excludes financing costs expected to be capitalized through AFUDC of approximately $260 million, of which $52 million had been accrued through June 30, 2020. |
| |
| (b) | Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds. |
Georgia Power is required to obtain the DOE's approval of the Bechtel Agreement prior to obtaining any further advances under the Loan Guarantee Agreement.
In connection with the recommendation to continue withestimates that its financing costs for construction of Plant Vogtle Units 3 and 4 (described below)will total approximately $3.0 billion, of which $2.4 billion had been incurred through June 30, 2020.
As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of engineering support, commodity installation, system turnovers, and workforce statistics.
During the second quarter 2020, approximately $194 million of construction contingency was assigned to the base capital cost forecast for cost risks including, among other things, construction productivity, including the April 2020 reduction in workforce designed to mitigate impacts of the COVID-19 pandemic described below, field support, subcontracts, engineering resources, and procurement. The second quarter 2020 assignment of contingency exceeded the remaining balance of the $366 million construction contingency originally established in the second quarter 2018 by approximately $34 million. Through June 30, 2020, assignments of contingency for cost risks also have included, among other factors, construction productivity; craft labor incentives; adding resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement. As a result of these factors, Southern Nuclear recommended establishing additional construction contingency, of which Georgia Power's share is approximately $115 million, for further potential risks including, among other factors, construction productivity and expected impacts of the COVID-19
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
pandemic; adding resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement.
After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income of $149 million ($111 million after tax) for the increase in the total project capital cost forecast as of June 30, 2020. As and when these amounts are spent, Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery.
In April 2019, Southern Nuclear established aggressive target values for monthly construction production and system turnover activities as part of a strategy to maintain and, where possible, build margin to the regulatory-approved in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4. Through early 2020, the project faced challenges with the April 2019 aggressive strategy targets including, but not limited to, electrical and pipefitting labor productivity and work package closure rates, which resulted in a backlog of activities and completion percentages below the April 2019 aggressive strategy targets.
In February 2020, Southern Nuclear updated its cost and schedule forecast, which, at that time, did not change the total project capital cost forecast and confirmed the expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4. This update included initiatives to improve productivity while refining and extending system turnover plans and certain near-term milestone dates. Other milestone dates did not change. Achievement of the February 2020 aggressive site work plan relied on meeting increased monthly production and activity target values during 2020.
In mid-March 2020, Southern Nuclear began implementing policies and procedures designed to mitigate the risk of transmission of COVID-19 at the construction site, including worker distancing measures, isolating individuals who have tested positive for COVID-19, are showing symptoms consistent with COVID-19, are being tested for COVID-19, or have been in close contact with such persons, requiring self-quarantine, and adopting additional precautionary measures.
In April 2020, Georgia Power, acting for itself and as agent for the other Vogtle Owners, announced a reduction in workforce at Plant Vogtle Units 3 and 4, which totaled approximately 20% of the then-existing site workforce. This reduction in workforce was a mitigation action intended to address the impact of the COVID-19 pandemic on the Plant Vogtle Units 3 and 4 workforce and construction site, including challenges with labor productivity that were exacerbated by the impact of the COVID-19 pandemic. The April 2020 workforce reduction was intended to provide operational efficiencies by increasing productivity of the remaining workforce and reducing workforce fatigue and absenteeism. Further, it was also intended to allow for increased social distancing by the workforce and facilitate compliance with the recommendations from the Centers for Disease Control and Prevention. The April 2020 workforce reduction did reduce absenteeism, providing an improvement in operational efficiency and allowing for increased social distancing. From the initial peak in April 2020, the number of active cases at the site declined significantly during May and early June, but began increasing again in mid-June and continues to impact productivity levels and pace of activity completion. As a result of these factors, overall production improvements have not been achieved at the levels anticipated, contributing to the allocation of, and increase in, construction contingency described above. Through mid-July 2020, Unit 3 mechanical, electrical, and subcontract activities continued to build a backlog to Southern Nuclear's February 2020 aggressive site work plan.
To address these issues, in July 2020, Southern Nuclear updated its aggressive site work plan for both Unit 3 and Unit 4. To meet the targets in the July 2020 aggressive site work plan, absenteeism rates must continue to normalize and overall construction productivity and production levels, including subcontractors, must significantly improve and be sustained above pre-pandemic levels. In addition, appropriate levels of craft laborers, particularly electrical and pipefitter craft labor, must be added and maintained. While Southern Nuclear's July 2020 aggressive site work plan extended milestone dates from the February 2020 aggressive site work plan, Georgia Power still expects to achieve the regulatory-approved in-service dates of November 2021 and November 2022 for Plant Vogtle Units 3
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
and 4, respectively. Southern Nuclear and Georgia Power continue to believe that pursuit of an aggressive site work plan is an appropriate strategy to achieve completion of the units by their regulatory-approved in-service dates.
As construction, including subcontract work, continues and testing and system turnover activities increase, challenges with management of contractors and vendors; subcontractor performance; supervision of craft labor and related productivity, particularly in the installation of electrical, mechanical, and instrumentation and controls commodities, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, installation, system turnover, and the initial testing and start-up, including any required engineering changes or any remediation related thereto, of plant systems, structures, or components (some of which are based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale), any of which may require additional labor and/or materials; or other issues could arise and change the projected schedule and estimated cost.
In addition, the continuing effects of the COVID-19 pandemic could further disrupt or delay construction, testing, supervisory, and support activities at Plant Vogtle Units 3 and 4. Georgia Power's proportionate share of the estimated incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is currently estimated to be between $70 million and $115 million, which is included in the total project capital cost forecast and assumes (i) absenteeism rates continue to normalize and (ii) the intended productivity efficiencies and production targets assumed in Southern Nuclear's July 2020 aggressive site work plan are realized in the coming months. However, the ultimate impact of the COVID-19 pandemic on the construction schedule and budget for Plant Vogtle Units 3 and 4 cannot be determined at this time.
There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel, may arise, which may result in additional license amendments or require other resolution. As part of the aggressive site work plan, in January 2020, Southern Nuclear notified the NRC of its intent to load fuel in 2020. On May 11, 2020, the Blue Ridge Environmental Defense League filed a petition with the NRC that challenges a license amendment request. On June 15, 2020, the NRC issued an appealable order rejecting Nuclear Watch South's April 20, 2020 petition requesting a hearing and challenging the closure of certain ITAAC. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.
The ultimate outcome of these matters cannot be determined at this time. However, any extension of the regulatory-approved project schedule is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $10 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.
Joint Owner Contracts
In November 2017, the Vogtle Owners agreed on a term sheetentered into an amendment to amend the existingtheir joint ownership agreements for Plant Vogtle Units 3 and 4 to provide for, among other conditions, additional Vogtle Owner approval requirements. UnderEffective in August 2018, the term sheet,Vogtle Owners further amended the joint ownership agreements to clarify and provide procedures for certain provisions of the joint ownership agreements related to adverse events that require the vote of the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including (i) the bankruptcy of Toshiba or a material breach by Toshiba of the Guarantee Settlement Agreement; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3(as amended, and 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report by more than $1 billion or extension of the project schedule contained in the seventeenth VCM report by more than one year. In addition, under the term sheet, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Services Agreement or agreementstogether with the primary construction contractor or Southern Nuclear.November 2017 amendment, the Vogtle Joint Ownership Agreements). The Vogtle
The term sheet
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Joint Ownership Agreements also confirmsconfirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.
As a result of an increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs in conjunction with the nineteenth VCM report in 2018, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. In September 2018, the Vogtle Owners unanimously voted to continue construction of Plant Vogtle Units 3 and 4.
Amendments to the Vogtle Joint Ownership Agreements
In connection with the vote to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and MEAG Power's wholly-owned subsidiaries MEAG Power SPVJ, LLC (MEAG SPVJ), MEAG Power SPVM, LLC (MEAG SPVM), and MEAG Power SPVP, LLC (MEAG SPVP) to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners, including additional amendments to the Vogtle Joint Ownership Agreements and the purchase of PTCs from the other Vogtle Owners at pre-established prices, and (ii) a term sheet (MEAG Term Sheet) with MEAG Power and MEAG SPVJ to provide up to $300 million of funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. In January 2019, Georgia Power, MEAG Power, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. In February 2019, Georgia Power, the other Vogtle Owners, and MEAG Power's wholly-owned subsidiaries MEAG SPVJ, MEAG SPVM, and MEAG SPVP entered into certain amendments to the Vogtle Joint Ownership Agreements to implement the provisions of the Vogtle Owner Term Sheet (Global Amendments).
As previously disclosed, pursuant to the Global Amendments: (i) each Vogtle Owner must pay its proportionate share of qualifying construction costs for Plant Vogtle Units 3 and 4 based on its ownership percentage up to the estimated cost at completion (EAC) for Plant Vogtle Units 3 and 4 which formed the basis of Georgia Power's forecast of $8.4 billion in the nineteenth VCM plus $800 million; (ii) Georgia Power will be responsible for 55.7% of actual qualifying construction costs between $800 million and $1.6 billion over the EAC in the nineteenth VCM (resulting in $80 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests; and (iii) Georgia Power will be responsible for 65.7% of qualifying construction costs between $1.6 billion and $2.1 billion over the EAC in the nineteenth VCM (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests. If the EAC is revised and exceeds the EAC in the nineteenth VCM by more than $2.1 billion, each of the other Vogtle Owners will have a one-time option at the time the project budget forecast is so revised to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100% of such Vogtle Owner's remaining share of total construction costs in excess of the EAC in the nineteenth VCM plus $2.1 billion.
In addition, pursuant to the Global Amendments, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including, among other events: (i) the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power's public announcement of its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 or the Georgia PSC determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Vogtle Owners pursuant to the Global Amendments described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Georgia PSC for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates; and (iv) an incremental extension of one year or more over the most recently approved schedule.
The ultimate outcome of these matters cannot be determined at this time.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
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.Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by includingup to the related CWIP accounts in rate base during the construction period. Ascertified capital cost of September$4.418 billion. At June 30, 2017,2020, Georgia Power had recovered approximately $1.5$2.4 billion of financing costs. Financing costs related to capital costs above $4.418 billion are being recognized through AFUDC and are expected to be recovered through retail rates over the life of Plant Vogtle Units 3 and 4; however, Georgia Power expectswill not record AFUDC related to file on November 1, 2017any capital costs in excess of the total deemed reasonable by the Georgia PSC (currently $7.3 billion) and not requested for rate recovery. In December 2019, the Georgia PSC approved Georgia Power's request to increasedecrease the NCCR tariff by approximately $90$62 million annually, effective January 1, 2018, pending2020.
Georgia Power is required to file semi-annual VCM reports with the Georgia PSC approval.by February 28 and August 31 of each year. In 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.
On December 20,In 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) Georgia Power's seventeenth VCM report and modified the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following prudence matters:regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report willshould be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement iswas 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$5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, and (c)(b) Georgia Power would have the burden to show that any capital costs above $5.68 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the Revised Forecast are reasonable and prudent. Underimpact of payments received under the terms of the Vogtle CostGuarantee Settlement Agreement and related customer refunds) was found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the certified in-service capitalrevised cost for purposes of calculatingforecast does not represent a cost cap and that prudence decisions on cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the 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(a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016. For purposes of the AFUDC calculation,2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE on costs between $4.418 billion and $5.440 billionin no case will also be 10.00% and the ROE on any amounts above $5.440 billion would beless than Georgia Power's average cost of long-term debt. Ifdebt); (viii) reduced the Georgia PSC adjusts Georgia
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Power's ROE rate setting point in a rate case prior toused for AFUDC equity for Plant Vogtle Units 3 and 4 being placed intofrom 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail rate base thenrates would be adjusted to include carrying costs on those capital costs deemed prudent in 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. IfVogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not placed in servicecommercially operational by December 31, 2020, then (i)June 1, 2021 and June 1, 2022, respectively, the ROE for purposes of calculatingused to calculate the NCCR tariff will be further reduced an additional 300by 10 basis points or $8 million pereach 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(but not lower than Georgia Power's average cost of long-term debt.debt) until the respective Unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $75 million in 2019 and are estimated to have negative earnings impacts of approximately $145 million, $255 million, and $200 million in 2020, 2021, and 2022, respectively. In its January 11, 2018 order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
In February 2018, Georgia Interfaith Power & Light, Inc. (GIPL) and Partnership for Southern Equity, Inc. (PSE) filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. In March 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's decision and denial of Georgia Watch's motion for reconsideration. In December 2018, the Fulton County Superior Court granted Georgia Power's motion to dismiss the two appeals. In January 2019, GIPL, PSE, and Georgia Watch filed an appeal of this decision with the Georgia Court of Appeals. In October 2019, the Georgia Court of Appeals issued an opinion affirming the Fulton County Superior Court's ruling that the Georgia PSC's January 11, 2018 order was not a final, appealable decision. In addition, the Georgia Court of Appeals remanded the case to the Fulton County Superior Court to clarify its ruling as to whether the petitioners showed that review of the Georgia PSC's final order would not provide them an adequate remedy. On April 21, 2020, the Fulton County Superior Court granted Georgia Power's motion to dismiss the two appeals. The petitioners filed a notice of appeal of the dismissal on May 20, 2020. Georgia Power believes the petitions have no merit; however, an adverse outcome in the litigation combined with subsequent adverse action by the Georgia PSC could have a material impact on Southern Company's and Georgia Power's results of operations, financial condition, and liquidity.
The Georgia PSC has approved sixteen21 VCM reports covering the periods through December 31, 2016,June 30, 2019, including total construction capital costs incurred which through that date totaled $3.9 billion.of $6.7 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds). On August 18, 2020, the Georgia Power filed its seventeenthPSC is scheduled to vote on Georgia Power's twenty-second VCM report, covering the period from January 1 through June 30, 2017, requestingwhich requested approval of $542$674 million of construction capital costs incurred during that period,from July 1, 2019 through December 31, 2019.
Georgia Power expects to file its twenty-third VCM report with the Georgia PSC onby August 31, 2017.2020, which will reflect the revised capital cost forecast discussed above and request approval of $701 million of construction capital costs incurred from January 1, 2020 through June 30, 2020.
In the seventeenth VCM report, Georgia Power recommended that construction of Plant Vogtle Units 3See RISK FACTORS in Item 1A herein and 4 be continued, with Southern Nuclear serving as project manager. Georgia Power believes that the most reasonable schedule for completing Plant Vogtle Units 3 and 4 is by November 2021 for Unit 3 and by November 2022 for Unit 4. Georgia Power's recommendation to go forward with completion of Vogtle Units 3 and 4 is based on the following assumptions about the regulatory treatment of this recommendation, if the recommendation to go forward is adopted by the Georgia PSC: (i) that pursuant to Georgia law, the Georgia PSC in the seventeenth VCM proceeding approvesForm 10-K for a discussion of certain risks associated with the new costlicensing, construction, and schedule forecast and findsoperation of nuclear generating units, including potential impacts that it iscould result from a reasonable basis for going forward, and that if the Georgia PSC disapproves all or part of the proposed cost and schedule revisions, Georgia Power may cancel Plant Vogtle Units 3 and 4 and recover its actual investment in Plant Vogtle Units 3 and 4; (ii) that the Vogtle Cost Settlement Agreement remains in full force and effect, including Georgia Power retaining the burden of proving all capital costs above $5.680 billion were prudent; (iii) that while the Georgia PSC will make no prudence findingmajor incident at a nuclear facility anywhere in the seventeenth VCM proceeding, nor will the certified amount be amended consistent with the Vogtle Cost Settlement Agreement, the Georgia PSC recognizes that the certified amount is not a cap, and all costs that are approved and presumed or shown to be prudently incurred will be recoverable by Georgia Power; (iv) that Georgia Power is not a guarantor of the Toshiba Guarantee, and the failure of Toshiba to pay the Toshiba Guarantee, the failure of the U.S. Congress to extend the PTCs for Plant Vogtle Units 3 and 4, or the failure of the DOE to extend the Loan Guarantee Agreement with Georgia Power to reflect the increased capital amounts, will not reduce the amount of investment Georgia Power is otherwise allowed to collect; and (v) that as conditions change and assumptions are either proven or disproven, Georgia Power and the Georgia PSC may reconsider the decision to go forward. The Georgia PSC is expected to make a decision on these matters by February 6, 2018.world.
The ultimate outcome of these matters cannot be determined at this time.
Revised Cost and ScheduleGeorgia Power's approximate proportionate shareSouthern Power
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Construction Programs – Southern Power" in Item 7 of the remaining estimated cost to complete Plant Vogtle Units 3Form 10-K and 4 is as follows:FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information.
|
| | | |
| | (in billions) |
| Estimated cost to complete | $ | 4.2 |
|
| CWIP as of September 30, 2017 | 4.6 |
|
| Guarantee Obligations | (1.7 | ) |
| Estimated capital costs | $ | 7.1 |
|
| Vogtle Cost Settlement Agreement Revised Forecast | (5.7 | ) |
| Estimated net additional capital costs | $ | 1.4 |
|
Georgia Power's estimated financing costs duringDuring the six months ended June 30, 2020, Southern Power completed construction period total approximately $3.4 billion, of which approximately $1.5 billion had been incurred through September 30, 2017.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Georgia Power's cancellation cost estimate results indicate that its proportionate shareand placed in service the Reading wind facility, continued construction of the estimatedSkookumchuck wind facility, and commenced construction of the Garland and Tranquillity battery energy storage facilities. Total aggregate construction costs, excluding acquisition costs, are expected to cancel both units is approximately $350 million. As a result, as of Septemberbe between $475 million and $545 million for the facilities under construction. At June 30, 2017,2020, total estimated costs subject to evaluation by Georgia Power and the Georgia PSC in the event of a cancellation decision are as follows:
|
| | | |
| | Cancellation Cost Estimate |
| | (in billions) |
| CWIP as of September 30, 2017 | $ | 4.6 |
|
| Financing costs collected, net of tax | 1.5 |
|
Cancellation costs(*) | 0.4 |
|
| Guarantee Obligations | (1.7 | ) |
| Estimated net cancellation cost | $ | 4.8 |
|
| |
(*) | 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 incurred for these projects were $232 million and rate recovery.
are included in CWIP. The ultimate outcome of these matters cannot be determined at this time.
Other MattersAs of September 30, 2017, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through the Loan Guarantee Agreement and a multi-advance credit facility among Georgia Power, the DOE, and the FFB, which provides for borrowings of up to $3.46 billion, subject to the satisfaction of certain conditions. On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to the financial statements
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
|
| | | | | | |
| Project Facility | Resource | Approximate Nameplate Capacity (MW) | Location | Actual/Expected COD | PPA Counterparties | PPA Contract Period |
| Projects Completed During the Six Months Ended June 30, 2020 | |
Reading(a) | Wind | 200 | Osage and Lyon Counties, KS | May 2020 | Royal Caribbean Cruises LTD | 12 years |
| Projects Under Construction as of June 30, 2020 | | |
Skookumchuck(b) | Wind | 136 | Lewis and Thurston Counties, WA | Fourth quarter 2020 | Puget Sound Energy | 20 years |
Garland Solar Storage(c) | Battery energy storage system | 88 | Kern County, CA | Second quarter 2021 | Southern California Edison | 20 years |
Tranquillity Solar Storage(c) | Battery energy storage system | 72 | Fresno County, CA | Second quarter 2021 | Southern California Edison | 20 years |
| |
| (a) | In 2018, Southern Power purchased 100% of the membership interests of the Reading facility pursuant to a joint development arrangement. At the time the facility was placed in service, Southern Power recorded an operating lease right-of-use asset and an operating lease liability, each in the amount of $24 million. In June 2020, Southern Power completed a tax equity transaction whereby it received $156 million and now owns 100% of the Class B membership interests. |
| |
| (b) | In October 2019, Southern Power purchased 100% of the membership interests of the Skookumchuck facility pursuant to a joint development arrangement. Southern Power expects to complete a tax equity transaction upon commercial operation and retain the Class B membership interests. Shortly after commercial operation, Southern Power may sell a noncontrolling interest in these Class B membership interests to another partner. The ultimate outcome of these matters cannot be determined at this time. |
| |
| (c) | Prior to commercial operation, Southern Power may enter into one or more partnerships, in which case it would ultimately own less than 100% of the Class B membership interests, but would retain ownership of the controlling interest. The PPAs for these facilities are pending approval from the California Public Utilities Commission. The ultimate outcome of these matters cannot be determined at this time. |
Southern Company and Georgia Power under "DOE Loan Guarantee Borrowings"Gas
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Construction Programs – Southern Company Gas" in Item 8 of the Form 10-K and Note (E) under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
The IRS has allocated PTCs to Plant Vogtle Units 3 and 4 which require that the 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 while 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 while 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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
While construction continues, the risk remains that challenges with management of contractors, subcontractors, and vendors, 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.
Gulf Power
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 87 of the Form 10-K for additional information regarding Gulf Power'sinformation.
Infrastructure Replacement Programs and Capital Projects
In addition to capital expenditures recovered through base rates and charges for service to retail customers.
Retail Base Rate Cases
See Note 3 to the financial statements of Southern Company and Gulf Power under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" and "Retail Regulatory Matters – Retail Base Rate Cases," respectively, in Item 8by each of the Form 10-Knatural gas distribution utilities, Nicor Gas and Virginia Natural Gas have separate rate riders that provide timely recovery of capital expenditures for additional information.
In 2013, the Florida PSC approved a 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 could 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. Through June 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 three intervenors with respect to Gulf Power's request to increase retail base rates. Among the terms of the 2017 Rate Case Settlement Agreement, Gulf Power increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consisted of a $62.0 million increase in annual base revenues less an annual 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%), 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), which was recordedspecific infrastructure replacement programs. Infrastructure expenditures incurred under these programs in the first quarter 2017. The remaining issuessix months of 2020 were as follows:
|
| | | | |
| Utility | Program | Year-to-Date 2020 |
| | | (in millions) |
| Nicor Gas | Investing in Illinois | $ | 158 |
|
| Virginia Natural Gas | Steps to Advance Virginia's Energy (SAVE) | 25 |
|
| Total | | $ | 183 |
|
In December 2019, Virginia Natural Gas filed an application with the Virginia Commission for a 24.1-mile header improvement project to improve resiliency and increase the supply of natural gas delivered to energy suppliers, including Virginia Natural Gas. On June 26, 2020, the Virginia Commission issued an order requiring Virginia Natural Gas to submit additional information by December 31, 2020 related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates have been resolved as a resultfinancing plans 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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Cost Recovery Clauses
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K for additional information regarding Gulf Power's recovery of retail costs through various regulatory clauses and accounting orders. Gulf Power has four regulatory clauses which are approved by the Florida PSC. The balance of each regulatory clause recoveryproject's primary customer before ruling on the balance sheet follows:
|
| | | | | | | |
| Regulatory Clause | Balance Sheet Line Item | September 30,
2017 | December 31,
2016 |
|
| (in millions) |
| Fuel Cost Recovery | Under recovered regulatory clause revenues | $ | 13 |
| $ | — |
|
| Fuel Cost Recovery | Other regulatory liabilities, current | — |
| 15 |
|
| Purchased Power Capacity Recovery | Under recovered regulatory clause revenues | 1 |
| — |
|
| Environmental Cost Recovery | Other regulatory liabilities, current | 1 |
| — |
|
| Environmental Cost Recovery | Under recovered regulatory clause revenues | — |
| 13 |
|
| Energy Conservation Cost Recovery | Under recovered regulatory clause revenues | 1 |
| 4 |
|
As discussed previously, the 2017 Rate Case Settlement Agreement resolved the remaining issues related to Gulf Power's inclusion of certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 in the environmental cost recovery clause and no adjustment to the environmental cost recovery clause rate approved by the Florida PSC in November 2016 was made.
On October 25, 2017, the Florida PSC approved Gulf Power's annual rate clause request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2018. The net effect of the approved changes is a $63 million increase in annual revenues effective in January 2018, the majority of which will be offset by related expense increases.
Mississippi Power
Performance Evaluation Plan
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Performance Evaluation Plan" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's base rates.
On March 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.December 2019 application. The ultimate outcome of this matter cannot be determined at this time.
Energy Efficiency
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
See Note 32 to the financial statements of Mississippi Power under "Retail Regulatory Matters "Southern Company Gas – Energy Efficiency"Infrastructure Replacement Programs and Capital Projects" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's energy efficiency programs.information.
Pipeline Construction Projects
On July 6, 2017,March 24, 2020, Southern Company Gas completed 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 withsale of its interest in Atlantic Coast Pipeline. See Note (K) to the first billing cycleCondensed Financial Statements under "Southern Company Gas" herein for August 2017.
Environmental Compliance Overview Planadditional information.
On May 4, 2017,February 20, 2020, the Mississippi PSCFERC approved Mississippi Power's ECO Plan filinga two-year extension for 2017,PennEast Pipeline to complete the project by January 19, 2022.
In September 2019, an appellate court ruled that the PennEast Pipeline does not have federal eminent domain authority over lands in which a state has property rights interests. On June 29, 2020, the U.S. Supreme Court requested the maximum 2% annual increase in revenues, approximately $18 million, primarilyU.S. Solicitor General to provide an opinion on PennEast Pipeline's petition for a writ of certiorari seeking its review of the appellate court's decision.
Expected project costs related to the Plant Daniel Units 1
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
and 2 scrubbers placed in service in 2015.PennEast Pipeline for Southern Company Gas total approximately $300 million, excluding financing costs. The rates became effective with the first billing cycle for June 2017. Approximately $26 million of related revenue requirements in excessultimate outcome of the 2% maximum was deferred for inclusionPennEast Pipeline construction project cannot be determined at this time; however, any work delays, whether caused by judicial or regulatory action, abnormal weather, or other conditions, may result in the 2018 filing.additional cost or schedule modifications or, ultimately, in project cancellation, any of which could result in impairment of Southern Company Gas' investment and could have a significant impact on Southern Company's financial statements and a material impact on Southern Company Gas' financial statements.
Fuel Cost Recovery
See NoteNotes 3 and 7 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements herein under "Southern Company Gas" for additional information.
Southern Power's Power Sales Agreements
See BUSINESS – "The Southern Company System – Southern Power" in Item 1 of the Form 10-K and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Southern Power's Power Sales Agreements" in Item 7 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.
During the first quarter 2020, Southern Power received $15 million from Pacific Gas & Electric Company (PG&E) in accordance with a November 2019 bankruptcy court order granting payment of certain transmission interconnections. PG&E emerged from bankruptcy on July 1, 2020 and Southern Power's PPAs and transmission interconnection agreements continue in effect unchanged.
Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" in Item 7 of the Form 10-K and Note (G) to the Condensed Financial Statements herein for additional information.
On March 18, 2020 and March 27, 2020, respectively, the Families First Coronavirus Response Act and the Coronavirus Aid, Relief, and Economic Security Act were signed into law. Both acts include provisions intended to provide stability and support for individuals and businesses in response to the COVID-19 pandemic. Southern Company continues to evaluate these provisions, including those related to payroll tax deferrals and employee retention credits; however, they are not expected to have a material impact on the Registrants' financial statements.
On March 20, 2020 and April 9, 2020, the Treasury Department and the Internal Revenue Service issued Notices 2020-18 and 2020-23, respectively, providing relief to taxpayers by postponing to July 15, 2020 a variety of tax form filings and payment obligations that were due before July 15, 2020. Associated interest, additions to tax, and penalties for late filing or late payment were also suspended until July 16, 2020. These provisions had a modest
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
positive impact on the Registrants' liquidity. However, Southern Power's expected utilization of tax credits in the first half of 2020 was delayed until July 15, 2020.
General Litigation Matters
The Registrants are involved in various other matters being litigated and regulatory matters that could affect future earnings. The ultimate outcome of such pending or potential litigation or regulatory matters against each Registrant and any subsidiaries cannot be determined at this time; however, for current proceedings not specifically reported herein or in Notes (B) and (C) 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 such Registrant's financial statements. See Notes (B) and (C) to the Condensed Financial Statements for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
The Registrants believe the pending legal challenges discussed below have no merit; however, the ultimate outcome of these matters cannot be determined at this time.
Southern Company
In January 2017, a securities class action complaint was filed in the U.S. District Court for the Northern District of Georgia 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 names as defendants Southern Company, certain of its current and former officers, and certain former Mississippi Power officers and alleges that the defendants made materially false and misleading statements regarding the Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. In 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. Also in 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition. In 2018, the court issued an order dismissing certain claims against certain officers of Southern Company and Mississippi Power and dismissing the allegations related to a number of the statements that plaintiffs challenged as being false or misleading. In 2018, the court denied the defendants' motion for reconsideration and also denied a motion to certify the issue for interlocutory appeal. In the third quarter 2019, the court certified the plaintiffs' proposed class and the defendants filed a petition for interlocutory appeal of the class certification order with the U.S. Court of Appeals for the Eleventh Circuit. In December 2019, the U.S. District Court for the Northern District of Georgia entered an order staying all deadlines in the case pending mediation. The stay automatically expired on March 31, 2020; however, in light of the COVID-19 pandemic, the U.S. District Court for the Northern District of Georgia vacated all existing discovery deadlines until June 15, 2020. On June 30, 2020, the court entered a revised scheduling order, which resumed discovery and set out remaining case deadlines.
In February 2017, Jean Vineyard and Judy Mesirov each filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its current and former officers, and certain former Mississippi Power officers. In 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. In 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the securities class action.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, Georgia that names as defendants Southern Company, certain of its directors, certain of its current and former 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 County energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. 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. In 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the securities class action. In August 2019, the court granted a motion filed by the plaintiff in July 2019 to substitute a new named plaintiff, Martin J. Kobuck, in place of Helen E. Piper Survivor's Trust.
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 retail fuel cost recovery.collection in rates of amounts for municipal franchise fees (which fees are paid to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state law claims. This case has been ruled upon and appealed numerous times over the last several years. In one recent appeal, the Georgia Supreme Court remanded the case and noted that the trial court could refer the matter to the Georgia PSC to interpret its tariffs. Following a motion by Georgia Power, in February 2019, the Superior Court of Fulton County ordered the parties to submit petitions to the Georgia PSC for a declaratory ruling and also conditionally certified the proposed class. In March 2019, Georgia Power and the plaintiffs filed petitions with the Georgia PSC seeking confirmation of the proper application of the municipal franchise fee schedule pursuant to the Georgia PSC's orders. Also in March 2019, Georgia Power appealed the class certification decision to the Georgia Court of Appeals. In October 2019, the Georgia PSC issued an order that found Georgia Power has appropriately implemented the municipal franchise fee schedule. On March 11, 2020, the Georgia Court of Appeals vacated the Superior Court of Fulton County's February 2019 order granting conditional class certification. The Court of Appeals remanded the case to the Superior Court of Fulton County for further proceedings. The amount of any possible losses cannot be calculated at this time because, among other factors, it is unknown whether a class will be certified, the ultimate composition of any class, and whether any losses would be subject to recovery from any municipalities.
At September 30, 2017,On July 29, 2020, a group of individual plaintiffs filed a complaint in the Superior Court of Fulton County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater, surface water, and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages, a medical monitoring fund, and injunctive relief.
Mississippi Power
In May 2018, Southern Company and Mississippi Power received a notice of dispute and arbitration demand filed by Martin Product Sales, LLC (Martin) based on two agreements, both related to Kemper IGCC byproducts for which Mississippi Power provided termination notices in 2017. Martin alleges breach of contract, breach of good faith and fair dealing, fraud and misrepresentation, and civil conspiracy and makes a claim for damages in the amount of over-recovered retail fuelapproximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest. A portion of the claim for damages was on behalf of Martin Transport, Inc. (Martin Transport), an affiliate of Martin. In May 2019, the arbitration panel denied Mississippi Power's and Southern Company's motions to dismiss. In September 2019, Martin Transport filed a separate complaint against Mississippi Power in the Circuit Court of Kemper County, Mississippi alleging claims of fraud, negligent misrepresentation, promissory estoppel, and equitable estoppel, each arising out of the same alleged facts and circumstances that underlie Martin's arbitration demand. Martin Transport seeks compensatory damages of $5 million and punitive damages of $50 million. In November 2019, Martin Transport's claim was combined with the Martin arbitration case and the
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
separate court case was dismissed. In December 2019, Southern Company and Mississippi Power each filed motions for summary judgment on all claims. On February 17, 2020, the arbitration panel granted Southern Company's motion and dismissed Southern Company from the arbitration. On March 12, 2020, the arbitration panel denied Mississippi Power's motions for summary judgment. An adverse outcome in this proceeding could have a material impact on Southern Company's and Mississippi Power's financial statements.
In November 2018, Ray C. Turnage and 10 other individual plaintiffs filed a putative class action complaint against Mississippi Power and the three then-serving members of the Mississippi PSC in the U.S. District Court for the Southern District of Mississippi. Mississippi Power received Mississippi PSC approval in 2013 to charge a mirror CWIP rate premised upon including in its rate base pre-construction and construction costs for the Kemper IGCC prior to placing the Kemper IGCC into service. The Mississippi Supreme Court reversed that approval and ordered Mississippi Power to refund the amounts paid by customers under the previously-approved mirror CWIP rate. The plaintiffs allege that the initial approval process, and the amount approved, were improper. They also allege that Mississippi Power underpaid customers by up to $23.5 million in the refund process by applying an incorrect interest rate. The plaintiffs seek to recover, on behalf of themselves and their putative class, actual damages, punitive damages, pre-judgment interest, post-judgment interest, attorney's fees, and costs. In response to Mississippi Power and the Mississippi PSC each filing a motion to dismiss, the plaintiffs filed an amended complaint in March 2019. The amended complaint included four additional plaintiffs and additional claims for gross negligence, reckless conduct, and intentional wrongdoing. Mississippi Power and the Mississippi PSC have each filed a motion to dismiss the amended complaint. On March 27, 2020, the Mississippi PSC's motion to dismiss was granted. Also on March 27, 2020, the plaintiffs filed a motion seeking to name the new members of the Mississippi PSC, the Mississippi Development Authority, and Southern Company as additional defendants and add a cause of action against all defendants based on a dormant commerce clause theory under the U.S. Constitution. On April 9, 2020 and April 10, 2020, Mississippi Power and the Mississippi PSC, respectively, filed responses opposing the motion for leave to file a second amended complaint. On May 26, 2020, Mississippi Power's motion to dismiss the first amended complaint filed in 2019 was granted. On July 6, 2020, the plaintiffs filed a motion for revision of the court's decision. The plaintiffs' motion for leave to file a second amended complaint also remains pending before the court. An adverse outcome in this proceeding could have a material impact on Mississippi Power's condensed balance sheet was $2 million compared to $37 million at December 31, 2016.
Ad Valorem Tax Adjustmentfinancial statements.
See Note 32 to the financial statements of Mississippiunder "Mississippi Power under "Retail Regulatory Matters – Ad Valorem Tax Adjustment" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's ad valorem tax adjustments.
On July 6, 2017, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment factor filing for 2017, which included an annual rate increase of 0.85%, or $8 million in annual retail revenues, primarily due to increased assessments.
Southern Company Gas
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 based on amounts approved in prior rate cases. 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's or Southern Company Gas' revenues or net income, but will affect cash flows.
Base Rate Cases
See Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters – Base Rate Cases"Kemper County Energy Facility" in Item 8 of the Form 10-K for additional information.
On February 21, 2017,Other Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" in Item 7 of the Georgia PSC approvedForm 10-K for additional information.
Southern Company
See Notes 1 and 3 under "Leveraged Leases" and "Other Matters – Southern Company," respectively, in Item 8 of the Georgia Rate Adjustment Mechanism (GRAM)Form 10-K for discussion of challenges associated with a leveraged lease agreement with a subsidiary of Southern Holdings. While all required lease payments through June 30, 2020 have been paid in full, the operational and remarketing risks and the resulting cash liquidity challenges persist and significant concerns continue regarding the lessee's ability to make the remaining required semi-annual lease payments to the Southern Holdings subsidiary through the term of the lease.
In its annual impairment analysis of the expected residual value of the generation assets and the overall collectability of the related lease receivable, Southern Company uses multiple scenarios of long-term market energy prices to estimate the cash flows expected to be received from remarketing the generation assets following the expiration of the existing PPA in 2032 and the residual value of the generation assets at the end of the lease in 2047. Southern Company received the latest annual forecasts of natural gas prices during the second quarter 2020 and considered the significant decline in forecasted prices to be an indicator of potential impairment that required an interim impairment assessment. Accordingly, consistent with prior years, Southern Company evaluated the
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
recoverability of the lease receivable and the expected residual value of the generation assets under various natural gas price scenarios. Based on the current forecasts of energy prices in the years following the expiration of the existing PPA, Southern Company concluded that it is no longer probable that any of the associated rental payments will be received, because it is no longer probable the generation assets will be successfully remarketed and continue to operate after that date. During the second quarter 2020, Southern Company revised the estimated cash flows to be received under the leveraged lease to reflect this conclusion, which resulted in a full impairment of the lease investment and a $20pre-tax charge to earnings of $154 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 and Integrated System Reinforcement 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.($74 million after tax).
PursuantIf any future lease payment due prior to the GRAM approval, Atlanta Gas Light and the staffexpiration of the Georgia PSC agreedassociated PPA is not paid in full, the Southern Holdings subsidiary may be unable to a variationmake its corresponding payment to the Integrated Customer Growth Program that was formerly part of Atlanta Gas Light's STRIDE program. As a result, a
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
new tariff was created, effective October 10, 2017, to provide $15 million annually for Atlanta Gas Light to commit to strategic economic development projects.
Beginning with the next rate adjustment in June 2018, Atlanta Gas Light's recoveryholders of the previously unrecovered Pipeline Replacement Program revenue through 2014,underlying non-recourse debt related to the generation assets. Failure to make the required payment to the debtholders could represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the generation assets, in effect terminating the lease. As the full amount of the lease investment has been charged against earnings 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 is2020, termination would not be expected to result in additional charges. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments and meet its obligations associated with a $3 million annual reductionfuture closure or retirement of depreciation. the generation assets and associated properties, including the dry ash landfill.
Mississippi Power
Kemper County Energy Facility
See Note (I) under "Southern Company Gas" for information on the proposed sale of Elizabethtown Gas.
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 in December 2017, 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 was based on a projected 12-month test year beginning September 1, 2017 and a ROE of 10.25%. The requested increase included $13 million related to the recovery of investments under the Steps to Advance Virginia's Energy (SAVE) program. On October 3, 2017, Virginia Natural Gas entered into a proposed stipulation with the Staff of the Virginia Commission, the Office of the Attorney General, Division of Consumer Counsel, and the Virginia Industrial Gas Users' Association resolving all related issues. The proposed stipulation includes a $34 million increase in annual base rate revenues, including $13 million related to the recovery of investments under the SAVE program. An authorized ROE range of 9.0% to 10.0% with a midpoint of 9.5% will be used to determine the revenue requirement in any filing, other than for a change in base rates. The Virginia Commission is expected to rule on the proposed stipulation in the fourth quarter 2017. Rate adjustments based on the proposed stipulation became effective September 1, 2017, subject to refund.
On October 23, 2017, Florida City Gas filed a general base rate case with the Florida PSC requesting a $19 million increase in annual base rate revenues. The requested increase is based on a 2018 projected test year and a ROE of 11.25%. The requested increase includes $3 million related to the recovery of investments under the Safety, Access, and Facility Enhancement (SAFE) program. Additionally, Florida City Gas requested interim rates of $5 million to be effective in January 2018, subject to refund. The Florida PSC is expected to rule on the requested increase in mid-2018.
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. See Note 32 to the financial statements of Southern Company and Southern Company Gas under "Regulatory Matters"Mississippi Power – Southern Company Gas – Regulatory Infrastructure Programs" and "Regulatory Matters – Regulatory Infrastructure Programs," respectively,Kemper County Energy Facility" in Item 8 of the Form 10-K for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 $178 million of qualifying assets during the first nine 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 LNG facilities as well as improve system reliability to meet operational flexibility and customer growth. Through the programs under STRIDE, Atlanta Gas Light invested $127 million during the first nine months of 2017. The recovery of and return on current and future capital investments under the STRIDE program are included in the annual base rate revenue adjustment under GRAM.
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. Subsequently, the proposed capital investments associated with the extension of i-SRP were included in the 2017 annual base rate revenue under GRAM 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 $16 million during the first nine months of 2017. Effective July 1, 2017, investments under this program are being recovered through base rate revenues.
Virginia Natural Gas
In March 2016, the Virginia Commission approved an extension to the SAVE program, under which Virginia Natural Gas invested $21 million during the first nine months of 2017.
Florida City Gas
The Florida PSC approved Florida City Gas' SAFE program in 2015. Under the program, Florida City Gas invested $9 million during the first nine months of 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 was designed to utilize IGCC technology with an expected output capacity of 582 MWs and to be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper IGCC, Mississippi Power constructed approximately 61 miles of CO2 pipeline infrastructure for the 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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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.
The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO2, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast has decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations has 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 (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). 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.
Mississippi Power's Kemper IGCC 2010 project estimate totaled $2.97 billion, which included capped costs of $2.4 billion. At the time of project suspension in June 2017, 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 for the Kemper IGCC (Additional DOE Grants).
Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate above the cost cap for the Kemper IGCC of $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.
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 IGCC Settlement Docket, 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 third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
costs and contract termination 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 $34 million ($21 million after tax) for the third quarter 2017 and $3.2 billion ($2.2 billion after tax) for the nine months ended September 30, 2017.
As of September 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. The Kemper combined cycle balances as presented in the condensed balance sheet at September 30, 2017 include $1.1 billion in property, plant, and equipment, net of $80 million in accumulated depreciation; $15 million in materials and supplies; $10 million in other deferred charges and assets; and $113 million in regulatory assets, net of accumulated amortization of $63 million, of which $21 million is included in other regulatory assets, current and $92 million in other regulatory assets, deferred.
Rate Recovery of Kemper IGCC Costs
Given the variety of potential scenarios and the uncertainty of the outcome of future regulatory proceedings with the Mississippi PSC (and any subsequent related legal challenges), the ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, cannot now be determined 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.
Kemper 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.
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 reached and filed a settlement agreement on August 21, 2017 with certain parties (not including the Mississippi Public Utilities Staff (MPUS)), which it believes met the conditions of the Kemper Settlement Order. The settlement agreement provides for an annual revenue requirement of $126 million for Kemper IGCC-related costs, which would (i) be effective January 1, 2018, (ii) represent no rate increase for customers, and (iii) include no recovery for the costs associated with the gasifier portion of the Kemper IGCC in 2018 or at any future date. In addition, under the settlement agreement, the CPCN for the Kemper IGCC would be modified to limit the Kemper County energy facility to natural gas combined cycle operation and Mississippi Power would, in the future, file a reserve margin plan with the Mississippi PSC. The Mississippi PSC issued a scheduling order, as amended on October 5, 2017, noting Mississippi Power and the MPUS had failed to reach a joint stipulation and ordering a full hearing. The Mississippi PSC is expected to rule on an order resolving this matter in January 2018.
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 IGCC Settlement Docket, 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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
associated with the gasification portions of the plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred.
As of September 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 Cooperative Energy. 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 was to be 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 was to be 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 utilize this information in connection with the ultimate 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. The 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 to address this matter in connection with the Kemper IGCC Settlement Docket.
2015 Rate Case
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 MPUS regarding the Kemper IGCC assets that were commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The In-Service Asset Rate Order also included a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets. 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 Cooperative Energy but reserved Mississippi Power's right to seek recovery in a future proceeding. See "Termination of Proposed Sale of Undivided Interest" herein for additional information.
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 September 30, 2017, the balance associated with these regulatory assets was $113 million, of which $21 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, for the May 31, 2016 and 2017 calculations. At September 30, 2017, Mississippi Power's related regulatory liability 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. At September 30, 2017, the related regulatory liability totaled $7 million.
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 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 (construction cost increase demonstrated to produce efficiencies that result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 was placed in service, based on a mirror CWIP methodology (Mirror CWIP rate).
On February 12, 2015, the Mississippi Supreme Court reversed the 2013 MPSC Rate Order and, 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, along with associated carrying costs of $29 million.
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 continued to record AFUDC on the Kemper IGCC. Between the original May 2014 estimated in-service date and the June 2017 project suspension date, Mississippi Power recorded $494 million of AFUDC on the Kemper IGCC subject to the $2.88 billion cost cap and Cost Cap Exception amounts, of which $460 million related to the gasification portions of the Kemper IGCC.
Mississippi Power expects the Mississippi PSC to address this matter in connection with the Kemper IGCC Settlement Docket.
Lignite Mine and CO2 Pipeline Facilities
In conjunction with the Kemper IGCC, Mississippi Power owns the lignite mine and equipment and 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 responsible for the mining operations through the end of the mine reclamation. As the mining permit holder, Liberty Fuels Company, LLC has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. In additionactivities related to the obligationlignite mine and equipment and mineral reserves located around the Kemper County energy facility site. As a result of the abandonment of the Kemper IGCC, final mine reclamation began in 2018 and is expected to fund the reclamation activities, Mississippi Power provides working capital supportbe substantially completed in 2020, with monitoring expected to Liberty Fuelscontinue through cash advances for capital purchases, payroll, and other operating expenses. During the suspension period, these costs are approximately $2 million per month and are being recognized in income as incurred.2027. See Note 16 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.
Dismantlement of the abandoned gasifier-related assets and site restoration activities are expected to be completed in 2025. The additional pre-tax period costs associated with dismantlement and site restoration activities, including related costs for compliance and safety, ARO accretion, and property taxes, are estimated to total $5 million for the remainder of 2020, $16 million in 2021, and $11 million to $13 million annually in 2022 through 2025. In addition, closure costs for the mine and gasifier-related assets, currently estimated at up to $6 million pre-tax (excluding dismantlement costs, net of salvage), may be incurred during the remainder of 2020.
In December 2019, Mississippi Power constructed 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%transferred ownership of the CO2 captured frompipeline to an unrelated gas pipeline company, with no resulting impact on income. In conjunction with the transfer of the CO2 pipeline, the parties agreed to enter into a 15-year firm transportation agreement, which is expected to be signed by the end of 2020, providing for the conversion by the pipeline company of the CO2 pipeline to a natural gas pipeline to be used for the delivery of natural gas to Plant Ratcliffe. The agreement will be treated as a finance lease for accounting purposes upon commencement.
In 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the $387 million of grants received for the Kemper IGCC and Treetop would purchase 30%County energy facility. Mississippi Power expects to close out the DOE contract in 2020. In connection with the DOE closeout discussions, in April 2019, the Civil Division of the CO2 captured fromDepartment of Justice informed Southern Company and Mississippi Power of an investigation related to 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. Denbury has the right to terminate the contract at any time because Mississippi Power did not place the Kemper IGCC in service by July 1, 2017.
County energy facility. The ultimate outcome of these mattersthis matter cannot be determined at this time.
Termination of Proposed Sale of Undivided Interest
In 2010 and as amended in 2012, Mississippi Power and Cooperative Energy (formerly known as SMEPA) entered into an agreement whereby Cooperative Energy agreed to purchase a 15% undivided interest in the Kemper IGCC. On May 20, 2015, Cooperative Energy notified Mississippi Power of its termination of the agreement. Mississippi Power previously received a total of $275 million of deposits from Cooperative Energy that were required to be returned to Cooperative Energy with interest. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to Cooperative Energy. 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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 of an appeal.
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 moved to compel arbitration pursuant to the terms of the CO2 contract, which the court granted on May 4, 2017. On June 28, 2017, Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a claim for arbitration requesting $500 million in damages.
Southern Company and Mississippi Power believe these legal challenges have no merit;time; however, an adverse outcome in these proceedingsit could have a material impact on Southern Company's and Mississippi Power's resultsfinancial statements.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Plant Daniel
In conjunction with Southern Company andCompany's sale of Gulf Power, Mississippi Power will vigorously defend themselvesand Gulf Power agreed to seek a restructuring of their 50% undivided ownership interests in these matters,Plant Daniel such that each of them would, after the restructuring, own 100% of a generating unit. On April 24, 2020, Mississippi Power and Gulf Power amended the terms of the agreement to extend the deadline from May 1, 2020 to August 1, 2020 for Mississippi Power to notify Gulf Power of which generating unit it has selected for 100% ownership. Mississippi Power and Gulf Power are continuing negotiations on a mutually acceptable revised operating agreement for Plant Daniel and, as a result, the parties have agreed not to select a specific unit on August 1, 2020. The impacts of operating the units on an individual basis continue to be evaluated by Mississippi Power and any transfer of ownership would be subject to approval by the FERC 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 or implement credits, refunds, or rebates to customers 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 Experimental Deduction" for additional information on bonus depreciation, investment tax credits, and the Section 174 research and experimental deduction.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Bonus Depreciation
All projected tax benefits previously received for bonus depreciation related to the Kemper IGCC were repaid in connection with third quarter 2017 estimated tax payments. If the suspension of the Kemper IGCC start-up activities ultimately results in an abandonment for income tax purposes, the related deduction would be claimed in the year of the abandonment. See Note (G) for additional information. The ultimate outcome of this matter cannot be determined at this time.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Experimental DeductionEstimates
Southern Company, on behalf of Mississippi Power, has reflected deductions for research and experimental (R&E) expenditures relatedThe Registrants prepare their financial statements in accordance with GAAP. Significant accounting policies are described in the notes to the Kemper IGCCfinancial statements in its federal income tax calculations since 2013Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on the Registrants' results of operations and filed amended federal income tax returnsrelated 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" in Item 7 of the Form 10-K for 2008 through 2013 to also include such deductions. In December 2016, a complete discussion of the Registrants' critical accounting policies and estimates.
Estimated Cost, Schedule, and Rate Recovery for the Construction of Plant Vogtle Units 3 and 4
(Southern Company and Georgia Power)
In the IRS reachedsecond quarter 2018, Georgia Power revised its base capital cost forecast and contingency to complete construction and start-up of Plant Vogtle Units 3 and 4 to $8.0 billion and $0.4 billion, respectively, for a proposed settlement,total project capital cost forecast of $8.4 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds). Through the second quarter 2020, assignment of construction contingency to the base capital cost forecast exceeded the amount originally established in the second quarter 2018 by approximately $34 million. As a result, Southern Nuclear recommended establishing additional construction contingency, of which was approvedGeorgia Power's share is $115 million.
After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018 and a total pre-tax charge to income of $149 million ($111 million after tax) in the second quarter 2020.
In July 2020, Southern Nuclear updated its aggressive site work plan for both Unit 3 and Unit 4. To meet the targets in the July 2020 aggressive site work plan, absenteeism rates must continue to normalize and overall construction productivity and production levels, including subcontractors, must significantly improve and be sustained above pre-pandemic levels. In addition, appropriate levels of craft laborers, particularly electrical and pipefitter craft labor, must be added and maintained. While Southern Nuclear's July 2020 aggressive site work plan extended milestone dates from the February 2020 aggressive site work plan, Georgia Power still expects to achieve the regulatory-approved in-service dates of November 2021 and November 2022 for Plant Vogtle Units 3 and 4, respectively. The continuing effects of the COVID-19 pandemic and other factors could further disrupt or delay construction, testing, supervisory, and support activities at Plant Vogtle Units 3 and 4.
The ultimate impact of these matters on September 8, 2017 by the U.S. Congress Joint Committee on Taxation, resolving a methodologyconstruction schedule and budget for these deductions.Plant Vogtle Units 3 and 4 cannot be determined at this time. See Note (G)(B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information.
NOTES TO THE CONDENSED
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL STATEMENTS:CONDITION
AND RESULTS OF OPERATIONS (Continued)
(UNAUDITED)
| |
(C) | FAIR VALUE MEASUREMENTS |
As of September 30, 2017, assets and liabilities measured at fair value on a recurring basis duringRecently Issued Accounting Standards
On March 12, 2020, the period, together with their associated levelFASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the fairEffects of Reference Rate Reform on Financial Reporting (ASU 2020-04) providing temporary guidance to ease the potential burden in accounting for reference rate reform primarily resulting from the discontinuation of LIBOR, which is currently expected to occur on December 31, 2021. The amendments in ASU 2020-04 are elective and apply to all entities that have contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued. The new guidance provides the following optional expedients: (i) simplifies accounting analyses under current GAAP for contract modifications; (ii) simplifies the assessment of hedge effectiveness and allows hedging relationships affected by reference rate reform to continue; and (iii) allows a one-time election to sell or transfer debt securities classified as held to maturity that reference a rate affected by reference rate reform. An entity may elect to apply the amendments prospectively from March 12, 2020 through December 31, 2022 by accounting topic.
The Registrants currently reference LIBOR for certain debt and hedging arrangements. Contract language has been, or is expected to be, incorporated into each of these agreements to address the transition to an alternative rate for agreements that will be in place at the transition date. While existing effective hedging relationships are expected to continue, the Registrants are continuing to evaluate the provisions of ASU 2020–04 and the impacts of transitioning to an alternative rate. The ultimate outcome of the transition cannot be determined at this time, but is not expected to have a material impact on the Registrants' financial statements. See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein and Note (J) to the Condensed Financial Statements under "Interest Rate Derivatives" herein for additional information.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" in Item 7 of the Form 10-K for additional information. The financial condition of each Registrant remained stable at June 30, 2020. The Registrants have maintained adequate access to capital throughout 2020, including during periods of volatility in the financial markets. This volatility began to constrain access across the Southern Company system to commercial paper during certain periods. As a precautionary measure, in the first quarter 2020, Southern Company, Georgia Power, Mississippi Power, and Southern Company Gas increased their outstanding short-term debt while also increasing cash and cash equivalents by taking actions such as entering into new bank term loans, entering into and funding new committed and uncommitted credit facilities, funding existing uncommitted credit facilities, and issuing commercial paper with longer-date maturities when available. No material changes occurred in the terms of the applicable Registrants' bank credit arrangements or their interest expense on short-term debt as a result of these actions.
The Registrants have experienced no material counterparty credit losses as a result of the volatility in the financial markets. The Registrants intend to continue to monitor their access to short-term and long-term capital markets as well as their bank credit arrangements to meet future capital and liquidity needs. The impact on future financing costs as a result of continued financial market volatility cannot be determined at this time. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein and Note (K) to the Condensed Financial Statements herein for additional information.
At the end of the second quarter 2020, the market price of Southern Company's common stock was $51.85 per share (based on the closing price as reported on the NYSE) and the book value hierarchy, were as follows:was $26.20 per share, representing a market-to-book ratio of 198%, compared to $63.70, $26.11, and 244%, respectively, at the end of 2019. Southern Company's common stock dividend for the second quarter 2020 was $0.64 per share compared to $0.62 per share in the second quarter 2019.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Analysis of Cash Flows
Net cash flows provided from (used for) operating, investing, and financing activities for the six months ended June 30, 2020 and 2019 are presented in the following table:
|
| | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using: | | |
| As of September 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) | $ | 231 |
| | $ | 184 |
| | $ | — |
| | $ | — |
| | $ | 415 |
|
| Interest rate derivatives | — |
| | 5 |
| | — |
| | — |
| | 5 |
|
| Foreign currency derivatives | — |
| | 103 |
| | — |
| | — |
| | 103 |
|
Nuclear decommissioning trusts(c) | 752 |
| | 1,004 |
| | — |
| | 26 |
| | 1,782 |
|
| Cash equivalents | 1,271 |
| | — |
| | — |
| | — |
| | 1,271 |
|
| Other investments | 9 |
| | — |
| | 1 |
| | — |
| | 10 |
|
| Total | $ | 2,263 |
| | $ | 1,296 |
| | $ | 1 |
| | $ | 26 |
| | $ | 3,586 |
|
| Liabilities: | | | | | | | | | |
Energy-related derivatives(a)(b) | $ | 265 |
| | $ | 146 |
| | $ | — |
| | $ | — |
| | $ | 411 |
|
| Interest rate derivatives | — |
| | 24 |
| | — |
| | — |
| | 24 |
|
| Foreign currency derivatives | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
| Contingent consideration | — |
| | — |
| | 20 |
| | — |
| | 20 |
|
| Total | $ | 265 |
| | $ | 193 |
| | $ | 20 |
| | $ | — |
| | $ | 478 |
|
| | | | | | | | | | |
| Alabama Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 9 |
| | $ | — |
| | $ | — |
| | $ | 9 |
|
Nuclear decommissioning trusts:(d) | | | | | | | | |
|
|
| Domestic equity | 422 |
| | 81 |
| | — |
| | — |
| | 503 |
|
| Foreign equity | 60 |
| | 57 |
| | — |
| | — |
| | 117 |
|
| U.S. Treasury and government agency securities | — |
| | 27 |
| | — |
| | — |
| | 27 |
|
| Corporate bonds | 19 |
| | 150 |
| | — |
| | — |
| | 169 |
|
| Mortgage and asset backed securities | — |
| | 18 |
| | — |
| | — |
| | 18 |
|
| Private Equity | — |
| | — |
| | — |
| | 26 |
| | 26 |
|
| Other | — |
| | 8 |
| | — |
| | — |
| | 8 |
|
| Cash equivalents | 808 |
| | — |
| | — |
| | — |
| | 808 |
|
| Total | $ | 1,309 |
| | $ | 350 |
| | $ | — |
| | $ | 26 |
| | $ | 1,685 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 7 |
| | $ | — |
| | $ | — |
| | $ | 7 |
|
|
| | | | | | | | | | | | | | | | | | |
Net cash provided from (used for): | Southern Company | Alabama Power | Georgia
Power | Mississippi Power | Southern Power | Southern Company Gas |
| | (in millions) |
| Six Months Ended June 30, 2020 | | | | | | |
| Operating activities | $ | 2,847 |
| $ | 674 |
| $ | 1,124 |
| $ | 71 |
| $ | 195 |
| $ | 1,046 |
|
| Investing activities | (2,655 | ) | (783 | ) | (1,659 | ) | (145 | ) | 490 |
| (570 | ) |
| Financing activities | (285 | ) | 116 |
| 869 |
| (178 | ) | (808 | ) | (401 | ) |
| | | | | | | |
| Six Months Ended June 30, 2019 | | | | | | |
| Operating activities | $ | 2,513 |
| 695 |
| $ | 1,112 |
| $ | 60 |
| $ | 719 |
| $ | 931 |
|
| Investing activities | 1,002 |
| (1,002 | ) | (1,834 | ) | (128 | ) | 254 |
| (586 | ) |
| Financing activities | (3,648 | ) | 617 |
| 620 |
| (26 | ) | (784 | ) | (355 | ) |
Fluctuations in cash flows from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using: | | |
| As of September 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 | $ | — |
| | $ | 18 |
| | $ | — |
| | $ | — |
| | $ | 18 |
|
| Interest rate derivatives | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Nuclear decommissioning trusts:(d) (e) | | | | | | | | | |
| Domestic equity | 235 |
| | 1 |
| | — |
| | — |
| | 236 |
|
| Foreign equity | — |
| | 156 |
| | — |
| | — |
| | 156 |
|
| U.S. Treasury and government agency securities | — |
| | 225 |
| | — |
| | — |
| | 225 |
|
| Municipal bonds | — |
| | 64 |
| | — |
| | — |
| | 64 |
|
| Corporate bonds | — |
| | 160 |
| | — |
| | — |
| | 160 |
|
| Mortgage and asset backed securities | — |
| | 38 |
| | — |
| | — |
| | 38 |
|
| Other | 16 |
| | 19 |
| | — |
| | — |
| | 35 |
|
| Cash equivalents | 112 |
| | — |
| | — |
| | — |
| | 112 |
|
| Total | $ | 363 |
| | $ | 682 |
| | $ | — |
| | $ | — |
| | $ | 1,045 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 11 |
| | $ | — |
| | $ | — |
| | $ | 11 |
|
| Interest rate derivatives | — |
| | 3 |
| | — |
| | — |
| | 3 |
|
| Total | $ | — |
| | $ | 14 |
| | $ | — |
| | $ | — |
| | $ | 14 |
|
| | | | | | | | | | |
| Gulf Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Cash equivalents | $ | 21 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 21 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 22 |
| | $ | — |
| | $ | — |
| | $ | 22 |
|
| | | | | | | | | | |
| Mississippi Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 3 |
|
| Interest rate derivatives | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
| Cash equivalents | 209 |
| | — |
| | — |
| | — |
| | 209 |
|
| Total | $ | 209 |
| | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | 214 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 7 |
| | $ | — |
| | $ | — |
| | $ | 7 |
|
| | | | | | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using: | | |
| As of September 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 Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 9 |
| | $ | — |
| | $ | — |
| | $ | 9 |
|
| Foreign currency derivatives | — |
| | 103 |
| | — |
| | — |
| | 103 |
|
| Cash equivalents | 90 |
| | — |
| | — |
| | — |
| | 90 |
|
| Total | $ | 90 |
| | $ | 112 |
| | $ | — |
| | $ | — |
| | $ | 202 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | 4 |
|
| Foreign currency derivatives | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
| Contingent consideration | — |
| | — |
| | 20 |
| | — |
| | 20 |
|
| Total | $ | — |
|
| $ | 27 |
|
| $ | 20 |
|
| $ | — |
|
| $ | 47 |
|
| | | | | | | | | | |
| Southern Company Gas | | | | | | | | | |
| Assets: | | | | | | | | | |
Energy-related derivatives(a)(b) | $ | 231 |
| | $ | 145 |
| | $ | — |
| | $ | — |
| | $ | 376 |
|
| Liabilities: | | | | | | | | | |
Energy-related derivatives(a)(b) | $ | 265 |
| | $ | 95 |
| | $ | — |
| | $ | — |
| | $ | 360 |
|
| |
(a) | Excludes $13 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value. |
| |
(b) | Excludes cash collateral of $76 million. |
| |
(c) | For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table. |
| |
(d) | Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. |
| |
(e) | Includes the investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of September 30, 2017, approximately $66 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
Net cash provided from operating activities increased $0.3 billion for the six months ended June 30, 2020 as compared to the corresponding period in 2019 primarily due to the timing of vendor payments and income tax payments, as well as increased fuel cost recovery, partially offset by the timing of receivable collections and customer bill credits issued in 2020 by 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 interestPower. See FUTURE EARNINGS POTENTIAL – "Tax Matters" herein and dividends and excluding the funds' expenses, increased by $50 million and $168 million, respectively, for the three and nine months ended September 30, 2017, and by $49 million and $116 million, respectively, for the three and nine months ended September 30, 2016. Alabama Power recorded increases in fair value of $25 million and $87 million, respectively, for the three and nine months ended September 30, 2017 and $26 million and $66 million, respectively, for the three and nine months ended September 30, 2016 as a change in regulatory liabilities related to its AROs. Georgia Power recorded increases in fair value of $25 million and $81 million, respectively, for the three and nine months ended September 30, 2017 and $23 million and $50 million, respectively, for the three and nine months ended September 30, 2016 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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The fair value of cross-currency swaps reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and discount rates. The interest rate derivatives and cross-currency swaps are categorized as LevelNote 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,under "Alabama Power" and Georgia Power under "Nuclear Decommissioning""Georgia Power" 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 make generation-based paymentsThe net cash used for investing activities for the six months ended June 30, 2020 was primarily due to the seller over a period rangingSubsidiary Registrants' construction programs, partially offset by proceeds from 10the sale transactions described in Note (K) to 30 years, beginning at the commercial operation date. Condensed Financial Statements herein.
The obligation is categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputsnet cash used for financing activities for the forecasted facility generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate, and is evaluated periodically. The fair value of contingent consideration reflects the net present value of expectedsix months ended June 30, 2020 was primarily due to common stock dividend payments and any periodic change arisingnet repayments of short-term bank debt and commercial paper, partially offset by net issuances of long-term debt.
Alabama Power
Net cash provided from forecasted generation is expected to be immaterial.
"Other investments" include investments that are not traded in the open market. The fair value of these investments has been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan executions.
As of September 30, 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, 2017: | Fair Value | | Unfunded Commitments | | Redemption Frequency | | Redemption Notice Period |
| | (in millions) | | | | |
| Southern Company | $ | 26 |
| | $ | 24 |
| | Not Applicable | | Not Applicable |
| Alabama Power | $ | 26 |
| | $ | 24 |
| | Not Applicable | | Not Applicable |
Private equity funds include a fund-of-funds that invests in high-quality private equity funds across several market sectors, funds that invest in real estate assets, and a fund that acquires companies to create resale value. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated. Liquidations are expected to occur at various times over the next 10 years.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
As of September 30, 2017, other financial instruments for which the carrying amount did not equal fair value were as follows:
|
| | | | | | | |
| | Carrying Amount | | Fair Value |
| | (in millions) |
| Long-term debt, including securities due within one year: | | | |
| Southern Company | $ | 47,269 |
| | $ | 49,348 |
|
| Alabama Power | $ | 7,404 |
| | $ | 8,031 |
|
| Georgia Power | $ | 11,713 |
| | $ | 12,237 |
|
| Gulf Power | $ | 1,292 |
| | $ | 1,352 |
|
| Mississippi Power | $ | 2,123 |
| | $ | 2,117 |
|
| Southern Power | $ | 5,810 |
| | $ | 5,916 |
|
| Southern Company Gas | $ | 5,862 |
| | $ | 6,230 |
|
The fair values are determined using Level 2 measurements and are based on quoted market pricesoperating activities decreased $21 million for the same or similar issues or onsix months ended June 30, 2020 as compared to the current rates availablecorresponding period in 2019 primarily due to Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas.
Earnings per Share
For Southern Company,Rate RSE customer refunds, partially offset by the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under the stock option and performance share plans.timing of income tax payments. See Note 82 to the financial statements under "Alabama Power – Rate RSE" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Tax Matters" herein for additional information.
The net cash used for investing activities for the six months ended June 30, 2020 was primarily due to gross property additions.
The net cash provided from financing activities for the six months ended June 30, 2020 was primarily due to capital contributions from Southern Company, partially offset by common stock dividend payments.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Georgia Power
Net cash provided from operating activities increased $12 million for the six months ended June 30, 2020 as compared to the corresponding period in 2019 primarily due to the timing of income tax payments and increased fuel cost recovery, partially offset by customer bill credits issued in 2020 associated with Tax Reform and 2018 earnings in excess of the allowed retail ROE range. See FUTURE EARNINGS POTENTIAL – "Tax Matters" herein and Note 2 to the financial statements under "Georgia Power – Rate Plans" in Item 8 of the Form 10-K for additional information.
The net cash used for investing activities for the six months ended June 30, 2020 was primarily due to gross property additions, including approximately $690 million related to the construction of Plant Vogtle Units 3 and 4. See FUTURE EARNINGS POTENTIAL – "Construction Programs – Nuclear Construction" herein for additional information on construction of Plant Vogtle Units 3 and 4.
The net cash provided from financing activities for the six months ended June 30, 2020 was primarily due to issuances of senior notes, borrowings from the FFB for construction of Plant Vogtle Units 3 and 4, capital contributions from Southern Company, and short-term borrowings, partially offset by the redemption and maturity of senior notes and common stock optiondividend payments.
Mississippi Power
Net cash provided from operating activities increased $11 million for the six months ended June 30, 2020 as compared to the corresponding period in 2019 primarily due to the timing of income tax payments.
The net cash used for investing activities for the six months ended June 30, 2020 was primarily due to gross property additions.
The net cash used for financing activities for the six months ended June 30, 2020 was primarily due to the redemption of senior notes and performance share plans. The effecta return of both stock optionscapital to Southern Company, partially offset by debt issuances and performance share award units was determined usingcapital contributions from Southern Company.
Southern Power
Net cash provided from operating activities decreased $524 million for the treasury stock method. Shares usedsix months ended June 30, 2020 as compared to compute diluted earnings per share were as follows:
|
| | | | | | | | |
| | Three Months Ended September 30, 2017 | Three Months Ended September 30, 2016 | Nine Months Ended September 30, 2017 | Nine Months Ended September 30, 2016 |
| | (in millions) |
| As reported shares | 1,003 |
| 968 |
| 998 |
| 940 |
|
| Effect of options and performance share award units | 7 |
| 7 |
| 7 |
| 5 |
|
| Diluted shares | 1,010 |
| 975 |
| 1,005 |
| 945 |
|
Stock options and performance share award units that were not includedthe corresponding period in 2019 primarily due to the delay in utilization of tax credits in the diluted earnings per share calculation because they were anti-dilutive were immaterialfirst half of 2020 compared to the utilization of $427 million in income tax credits in the first half of 2019. See FUTURE EARNINGS POTENTIAL – "Tax Matters" herein for additional information.
The net cash provided from investing activities for the three and ninesix months ended SeptemberJune 30, 20172020 was primarily due to proceeds from the disposition of Plant Mankato, partially offset by the acquisition of the Beech Ridge II wind facility and 2016.ongoing construction activities. See Note (K) to the Condensed Financial Statement under "Southern Power" herein for additional information.
The net cash used for financing activities for the six months ended June 30, 2020 was primarily due to net repayments of short-term bank debt and commercial paper, the repayment of senior notes at maturity, distributions to non-controlling interests, and common stock dividend payments, partially offset by contributions from non-controlling interests.
Southern Company Gas
Net cash provided from operating activities increased $115 million for the six months ended June 30, 2020 as compared to the corresponding period in 2019 primarily due to the timing of vendor payments and income tax payments, partially offset by the timing of customer receivable collections and an increase in the use of stored natural gas at lower prices.
The net cash used for investing activities for the six months ended June 30, 2020 was primarily due to utility capital expenditures and infrastructure investments recovered through replacement programs at gas distribution operations and capital contributed to equity method investments, partially offset by proceeds from the sale of interests in
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL STATEMENTS:CONDITION
AND RESULTS OF OPERATIONS (Continued)
(UNAUDITED)
Pivotal LNG and Atlantic Coast Pipeline. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
The net cash used for financing activities for the six months ended June 30, 2020 was primarily due to net repayments of short-term borrowings and common stock dividend payments, partially offset by capital contributions from Southern Company.
Significant Balance Sheet Changes
Southern Company
Significant balance sheet changes for the six months ended June 30, 2020 included:
an increase of $1.9 billion in Stockholders' Equitytotal property, plant, and equipment primarily related to the Subsidiary Registrants' construction programs;
an increase of $1.9 billion in long-term debt (including amounts due within one year) related to new issuances;
a decrease of $0.9 billion in notes payable related to net repayments of short-term bank debt and commercial paper;
a decrease of $0.8 billion in assets held for sale related to the completion of Southern Power's sale of Plant Mankato and Southern Company Gas' sale of its interests in Pivotal LNG and Atlantic Coast Pipeline;
increases of $0.5 billion in both AROs and regulatory assets associated with AROs primarily related to cost estimate updates at Alabama Power for certain of its ash pond facilities; and
an increase of $0.4 billion in accumulated deferred income taxes related to the expected utilization of tax credits in 2020.
See FUTURE EARNINGS POTENTIAL – "Tax Matters" herein, "Financing Activities" herein, and Notes (A) and (K) to the Condensed Financial Statements herein for additional information.
Alabama Power
Significant balance sheet changes for the six months ended June 30, 2020 included:
an increase of $715 million in common stockholder's equity primarily due to capital contributions from Southern Company;
increases of $436 million and $472 million in AROs and regulatory assets associated with AROs, respectively, primarily related to cost estimate updates for certain ash pond facilities; and
an increase of $408 million in total property, plant, and equipment primarily related to the construction of distribution and transmission facilities and the installation of equipment to comply with environmental standards.
See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Georgia Power
Significant balance sheet changes for the six months ended June 30, 2020 included:
an increase of $1.3 billion in total property, plant, and equipment primarily related to the construction of generation, transmission, and distribution facilities, partially offset by a $149 million decrease due to a charge related to the construction of Plant Vogtle Units 3 and 4;
an increase of $1.1 billion in long-term debt (including securities due within one year) primarily due to a net increase in outstanding senior notes and borrowings from the FFB for construction of Plant Vogtle Units 3 and 4; and
an increase of $0.4 billion in common stockholder's equity primarily due to capital contributions from Southern Company.
See "Financing Activities – Georgia Power" herein and Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information.
Mississippi Power
Significant balance sheet changes for the six months ended June 30, 2020 included:
a decrease of $252 million in cash and cash equivalents and a decrease of $185 million in long-term debt (including amounts due within one year) primarily related to the repayment of senior notes at maturity;
an increase of $72 million in common stockholder's equity primarily due to a capital contribution from Southern Company;
a decrease of $42 million in deferred credits related to income taxes due to reclassifying certain amounts to other regulatory liabilities, current for the expected flowback of excess deferred income taxes; and
an increase of $38 million in total property, plant, and equipment primarily related to the installation of equipment to comply with environmental standards and the construction of transmission and distribution facilities.
See "Financing Activities – Mississippi Power" herein for additional information.
Southern Power
Significant balance sheet changes for the six months ended June 30, 2020 included:
a decrease of $618 million in assets held for sale (of which $17 million related to current assets) due to completion of the sale of Plant Mankato;
a decrease of $457 million in notes payable due to net repayments of short-term bank debt and commercial paper;
an increase of $366 million in prepaid income taxes and a decrease of $395 million in accumulated deferred income tax assets primarily related to the expected utilization of tax credits in 2020;
an increase of $364 million in property, plant, and equipment in service and a decrease of $201 million in construction work in progress primarily due to wind facilities being acquired or placed in service; and
a decrease of $299 million in securities due within one year primarily related to the maturity of senior notes.
See FUTURE EARNINGS POTENTIAL – "Tax Matters" herein, "Financing Activities – Southern Power" herein, and Note (K) to the Condensed Financial Statements herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Southern Company Gas
Significant balance sheet changes for the six months ended June 30, 2020 included:
an increase of $477 million in total property, plant, and equipment primarily due to utility capital expenditures and infrastructure investments recovered through replacement programs;
a decrease of $321 million in notes payable due to net repayments of short-term borrowings;
an increase of $263 million in common stockholder's equity primarily from net income and capital contributions from Southern Company, partially offset by dividends paid to Southern Company;
a decrease of $197 million in natural gas for sale due to the use of stored natural gas;
a decrease of $171 million in assets held for sale due to the completed sale of interests in Pivotal LNG and Atlantic Coast Pipeline;
decreases of $155 million and $158 million in energy marketing receivables and payables, respectively, due to lower natural gas prices and volumes of natural gas sold; and
a decrease of $126 million in unbilled revenues due to seasonality.
See "Financing Activities – Southern Company Gas" herein and Note (K) to the Condensed Financial Statements herein for additional information.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements" and "Contractual Obligations" in Item 7 of the Form 10-K for a description of the Registrants' capital requirements and contractual obligations. 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 |
| | Issued | Treasury | | Noncontrolling Interests(*) |
| | (in thousands) | | (in millions) |
| Balance at December 31, 2016 | 991,213 |
| (819 | ) | | $ | 24,758 |
| $ | 609 |
| $ | 1,245 |
| $ | 26,612 |
|
| Consolidated net income attributable to Southern Company | — |
| — |
| | 347 |
| — |
| — |
| 347 |
|
| Other comprehensive income (loss) | — |
| — |
| | (2 | ) | — |
| — |
| (2 | ) |
| Stock issued | 13,308 |
| — |
| | 613 |
| — |
| — |
| 613 |
|
| Stock-based compensation | — |
| — |
| | 97 |
| — |
| — |
| 97 |
|
| Cash dividends on common stock | — |
| — |
| | (1,716 | ) | — |
| — |
| (1,716 | ) |
| Preference stock redemption | — |
| — |
| | — |
| (150 | ) | — |
| (150 | ) |
| Contributions from noncontrolling interests | — |
| — |
| | — |
| — |
| 77 |
| 77 |
|
| Distributions to noncontrolling interests | — |
| — |
| | — |
| — |
| (87 | ) | (87 | ) |
| Net income attributable to noncontrolling interests | — |
| — |
| | — |
| — |
| 45 |
| 45 |
|
| Reclassification from redeemable noncontrolling interests | — |
| — |
| | — |
| — |
| 114 |
| 114 |
|
| Other | — |
| (75 | ) | | (15 | ) | 3 |
| 1 |
| (11 | ) |
| Balance at September 30, 2017 | 1,004,521 |
| (894 | ) | | $ | 24,082 |
| $ | 462 |
| $ | 1,395 |
| $ | 25,939 |
|
| | | | | | | | |
| Balance at December 31, 2015 | 915,073 |
| (3,352 | ) | | $ | 20,592 |
| $ | 609 |
| $ | 781 |
| $ | 21,982 |
|
| Consolidated net income attributable to Southern Company | — |
| — |
| | 2,251 |
| — |
| — |
| 2,251 |
|
| Other comprehensive income (loss) | — |
| — |
| | (95 | ) | — |
| — |
| (95 | ) |
| Stock issued | 65,725 |
| 2,599 |
| | 3,265 |
| — |
| — |
| 3,265 |
|
| Stock-based compensation | — |
| — |
| | 94 |
| — |
| — |
| 94 |
|
| Cash dividends on common stock | — |
| — |
| | (1,553 | ) | — |
| — |
| (1,553 | ) |
| Contributions from noncontrolling interests | — |
| — |
| | — |
| — |
| 357 |
| 357 |
|
| Distributions to noncontrolling interests | — |
| — |
| | — |
| — |
| (21 | ) | (21 | ) |
| Purchase of membership interests from noncontrolling interests | — |
| — |
| | — |
| — |
| (129 | ) | (129 | ) |
| Net income attributable to noncontrolling interests | — |
| — |
| | — |
| — |
| 36 |
| 36 |
|
| Other | — |
| (46 | ) | | (7 | ) | — |
| — |
| (7 | ) |
| Balance at September 30, 2016 | 980,798 |
| (799 | ) | | $ | 24,547 |
| $ | 609 |
| $ | 1,024 |
| $ | 26,180 |
|
| |
(*) | Related 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 September 30, 2017, Mississippi Power's current liabilities exceeded current assets by approximately $769 million primarily due to approximately $935 million that will be required through September 30, 2018 to fundprovides the applicable Registrants' maturities of long-term debt through June 30, 2021:
|
| | | | | | | | | | | | | | | |
| At June 30, 2020: | Southern Company | Alabama Power | Georgia
Power | Southern Power | Southern Company Gas |
| | (in millions) |
| Securities due within one year | $ | 1,596 |
| $ | 496 |
| $ | 536 |
| $ | 525 |
| $ | 31 |
|
See "Sources of Capital" and $4 million"Financing Activities" herein for additional information.
The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to 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; abnormal weather; delays in construction due to judicial or regulatory action; storm impacts; and the cost of capital. The continued COVID-19 pandemic could also impair the ability to develop, construct, and operate facilities, as discussed further in Item 1A herein. In addition, there can be no assurance that costs related to capital expenditures will be requiredfully recovered. Additionally, Southern Power's planned expenditures for plant acquisitions may vary due 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 facilitiesmarket opportunities and $50 million of fixed rate pollution control revenue bonds that are requiredSouthern Power's ability 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 6execute its growth strategy. See Note 15 to the financial statements of Mississippi Power under "Recently Issued Accounting Standards" and "Going Concern," respectively,"Southern Power" in Item 8 of the Form 10-K and Note (B)(K) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle.Southern Power" herein for additional information regarding Southern Power's plant acquisitions and construction projects.
DOE Loan Guarantee Borrowings
The construction program of Georgia Power also includes Plant Vogtle Units 3 and 4, which includes components based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale and which may be subject to additional revised cost estimates during construction. See Note 62 to the financial statements of Southern Company and Georgiaunder "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K, Note (B) to the
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein, and Item 1A herein for additional information regarding Georgia Power's 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).
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-to-complete and cancellation cost assessments prepared as a result of the bankruptcy of the EPC Contractor (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 byadditional factors that may impact construction expenditures.
As a result of the DOE (togethersecond quarter 2020 increase in Alabama Power's AROs discussed under FUTURE EARNINGS POTENTIAL – "Environmental Matters" herein, Alabama Power's costs through 2024 associated with closure and monitoring of ash ponds and landfills in accordance with the Services AgreementCCR Rule and the IP Licenses, the Replacement EPC Arrangements),related state rule are currently estimated to be approximately $263 million for 2020, $247 million for 2021, $301 million for 2022, $330 million for 2023, 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$326 million 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 advances2024. These costs 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 Georgiareflected in Alabama Power's ownership interest in Plant Vogtle Units 3 and 4 other than permitted liens, evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act of 1931, as amended, and certification from the DOE's consulting engineer that proceeds of the advances are used to reimburse Eligible Project Costs.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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.
On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion of additional guaranteed loans under the Loan Guarantee Agreement. Final approval and issuance of these additional loan guarantees by the DOE cannot be assuredARO liabilities and are subjectbased on closure-in-place for all of its ash ponds. These anticipated costs are likely to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals,change, and satisfaction of other conditions.
could change materially, as assumptions and details pertaining to closure are refined and compliance activities continue. See Note (B) under "RegulatoryFUTURE EARNINGS POTENTIAL – "Environmental Matters – Georgia PowerEnvironmental Laws and Regulations – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.
Bank Credit Arrangements
Bank credit arrangements provide liquidity support to the registrants' commercial paper borrowings and the traditional electric operating companies' pollution control revenue bonds. The amount of variable rate pollution control revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of September 30, 2017 was approximately $1.5 billion (comprised of approximately $854 million at Alabama Power, $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 September 30, 2017, the traditional electric operating companies had approximately $699 million (comprised of approximately $509 million at Georgia Power, $140 million at Gulf Power, and $50 million at Mississippi Power) of pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to September 30, 2017, $40 million of these pollution control revenue bonds of Georgia Power which were in an index rate mode were remarketed to the public in a long-term fixed rate mode. See Note 6 to the financial statements of each registrant under "Bank Credit Arrangements"Coal Combustion Residuals" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements herein for additional information.
Sources of Capital
Southern Company intends to meet its future capital needs through operating cash flows, borrowings from financial institutions, and debt and equity issuances in the capital markets. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings. Southern Company does not expect to issue any equity in the capital markets through 2024.
The Subsidiary Registrants plan to obtain the funds to meet their future capital needs from sources similar to those they used in the past, which were primarily from operating cash flows, external securities issuances, borrowings from financial institutions, and equity contributions from Southern Company. In addition, Georgia Power plans to utilize borrowings from the FFB (as discussed further in Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K) and Southern Power plans to utilize tax equity partnership contributions (as discussed further herein).
The traditional electric operating companies and the natural gas distribution utilities have experienced a reduction in operating cash flows as a result of the temporary suspension of disconnections for non-payment by customers resulting from the COVID-19 pandemic and the related overall economic contraction. The U.S. House of Representatives has passed the Heroes Act, which would prohibit creditors, including utilities, from collecting consumer debts that are or become past-due, imposing late fees, or disconnecting customers for nonpayment. If the Heroes Act becomes law, its restrictions would apply until 120 days after the end of the presidential declared emergency related to the COVID-19 pandemic. While the reduction in operating cash flows is expected to continue while disconnections for non-payment are suspended, the ultimate extent of the negative impact on the Registrants' liquidity depends on the duration of the COVID-19 pandemic and the timing of economic recovery and cannot be determined at this time. The Registrants intend to continue to monitor their access to short-term and long-term capital markets as well as their bank credit arrangements to meet future capital and liquidity needs. See Note (B) to the Condensed Financial Statements herein for information regarding suspended disconnections for non-payment by the traditional electric operating companies and the natural gas distribution utilities.
The amount, type, and timing of any financings in 2020, as well as in subsequent years, will be contingent on investment opportunities and the Registrants' capital requirements and will depend upon prevailing market conditions, regulatory approvals (for the Subsidiary Registrants), and other factors. See "Financing ActivitiesCapital Requirements and Contractual Obligations" herein for additional information. Also see "Overview" herein for information on volatility in the financial markets that has occurred at certain periods during 2020 as a result of the COVID-19 pandemic.
Southern Power utilizes tax equity partnerships as one of its financing sources, where the tax partner takes significantly all of the federal tax benefits. These tax equity partnerships are consolidated in Southern Power's financial statements and are accounted for using HLBV methodology to allocate partnership gains and losses. In June 2020, Southern Power obtained tax equity funding for the Reading wind project and received proceeds of $156 million. In addition, during the first six months of 2020, Southern Power received tax equity funding totaling $16
NOTES TO THE CONDENSED
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL STATEMENTS:CONDITION
AND RESULTS OF OPERATIONS (Continued)
(UNAUDITED)
million from existing partnerships. See Note 1 to the financial statements under "General" in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements under "Southern Power" 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. At June 30, 2020, the amount of subsidiary retained earnings restricted to dividend totaled $1.1 billion. This restriction did not impact Southern Company Gas' ability to meet its cash obligations, nor does management expect such restriction to materially impact Southern Company Gas' ability to meet its currently anticipated cash obligations.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" in Item 7 of the Form 10-K for additional information.
The Registrants' current liabilities frequently exceed their 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. The following table outlinesshows the amount by which current liabilities exceeded current assets at June 30, 2020 for the applicable Registrants:
|
| | | | | | | | | | | | |
| At June 30, 2020 | Southern Company | Georgia
Power | Mississippi Power | Southern Company Gas |
| | (in millions) |
| Current liabilities in excess of current assets | $ | 265 |
| $ | 1,132 |
| $ | 70 |
| $ | 209 |
|
The Registrants believe the need for working capital can be adequately met by utilizing operating cash flows, as well as commercial paper, lines of credit, and short-term bank notes, as market conditions permit. In addition, under certain circumstances, the Subsidiary Registrants may utilize equity contributions and/or loans from Southern Company.
Bank Credit Arrangements
At June 30, 2020, the Registrants' unused committed credit arrangements by companywith banks were as of September 30, 2017: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 | — |
| 35 |
| — |
| 500 |
| 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 | 100 |
| — |
| — |
| — |
| — |
| | 100 |
| | 100 |
| | — |
| | — |
| | — |
| | 100 |
|
Southern Power Company(b) | — |
| — |
| — |
| — |
| 750 |
| | 750 |
| | 728 |
| | — |
| | — |
| | — |
| | — |
|
Southern Company Gas(c) | — |
| — |
| — |
| — |
| 1,900 |
| | 1,900 |
| | 1,861 |
| | — |
| | — |
| | — |
| | — |
|
| Other | — |
| 30 |
| — |
| — |
| — |
| | 30 |
| | 30 |
| | 20 |
| | — |
| | 20 |
| | 10 |
|
| Southern Company Consolidated | $ | 130 |
| $ | 260 |
| $ | 25 |
| $ | 530 |
| $ | 7,200 |
| | $ | 8,145 |
| | $ | 8,066 |
| | $ | 65 |
| | $ | — |
| | $ | 20 |
| | $ | 185 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| At June 30, 2020 | Southern Company parent | Alabama Power | Georgia
Power | Mississippi Power | Southern Power(a) | Southern Company Gas(b) | SEGCO | Southern Company |
| | (in millions) |
| Unused committed credit | $ | 1,999 |
| $ | 1,328 |
| $ | 1,733 |
| $ | 250 |
| $ | 590 |
| $ | 1,745 |
| $ | 30 |
| $ | 7,675 |
|
| |
| (a) | RepresentsAt June 30, 2020, Southern Power also had two continuing letters of credit facilities for standby letters of credit, of which $79 million was unused. Southern Power's subsidiaries are not parties to its bank credit arrangement or to the Southern Company parent entity.letter of credit facilities. |
| |
| (b) | Does not include Southern Power's $120Includes $1.245 billion and $500 million continuing letter of credit facility for standby letters of credit expiring in 2019, of which $111 million has been used for letters of credit and $9 million remains unused atSeptember 30, 2017.
|
| |
(c) | 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 whichand Nicor Gas, is the borrower and which is restricted for working capital needs of Nicor Gas.
respectively. |
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. Pursuant to the new multi-year credit arrangement, the allocations may be adjusted. In September 2017, Alabama Power amended its $500 million multi-year credit arrangement, which, among other things, extended the maturity date from 2018 to 2020.
Subject to applicable market conditions, Southern Companythe Registrants, Nicor Gas, and its subsidiariesSEGCO expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Companythe Registrants, Nicor Gas, and its subsidiariesSEGCO may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the unused credit with banks is allocated to provide liquidity support to the revenue bonds of the traditional electric operating companies and the commercial paper programs of the Registrants, Nicor Gas, and SEGCO. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support at June 30, 2020 was approximately $1.4 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia Power, and $34 million at Mississippi Power). In addition, at June 30, 2020, Georgia Power had approximately $257 million of fixed rate revenue bonds outstanding that are required to be remarketed within the next 12 months.
NOTES TO THE CONDENSEDSee Note 8 to the financial statements under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL STATEMENTS:CONDITION
AND RESULTS OF OPERATIONS (Continued)
(UNAUDITED)
Short-term Borrowings
The Registrants, Nicor Gas, and SEGCO make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Southern Power's subsidiaries are not issuers or obligors under its commercial paper program. Commercial paper and short-term bank term loans are included in notes payable in the balance sheets. Details of the Registrants' short-term borrowings were as follows:
|
| | | | | | | | | | | | | | | | | |
| | Short-term Debt at June 30, 2020 | | 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) |
| Southern Company | $ | 1,185 |
| | 1.2 | % | | $ | 1,317 |
| | 1.6 | % | | $ | 1,738 |
|
| Alabama Power | — |
| | — |
| | 42 |
| | 1.3 |
| | 105 |
|
| Georgia Power | 465 |
| | 1.5 |
| | 443 |
| | 1.6 |
| | 478 |
|
| Mississippi Power | 4 |
| | 0.3 |
| | 26 |
| | 1.9 |
| | 40 |
|
| Southern Power | 92 |
| | 0.3 |
| | 68 |
| | 0.5 |
| | 252 |
|
| Southern Company Gas: | | | | | | | | | |
| Southern Company Gas Capital | $ | 290 |
| | 1.1 | % | | $ | 332 |
| | 1.6 | % | | $ | 482 |
|
| Nicor Gas | 39 |
| | 0.2 |
| | 25 |
| | 1.4 |
| | 104 |
|
| Southern Company Gas Total | $ | 329 |
| | 1.0 | % | | $ | 357 |
| | 1.6 | % | | |
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2020. |
Financing Activities
The following table outlines the Registrants' long-term debt financing activities for Southern Company and its subsidiaries for the first ninesix months of 2017:2020:
| | | | | | | | | | | | | | Senior Notes | | Revenue Bonds | | Other Long-Term Debt |
| 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) | Issuances | | Maturities, Redemptions, and Repurchases | | Issuances/ Remarketings | | Maturities, Redemptions, and Repurchases | | Issuances | | Redemptions and Maturities(*) |
| | (in millions) | (in millions) |
Southern Company(b) | $ | 300 |
| | $ | 400 |
| | $ | — |
| | $ | 500 |
| | $ | 400 |
| |
| Southern Company parent | | $ | 1,000 |
| | $ | 600 |
| | $ | — |
| | $ | — |
| | $ | 1,000 |
| | $ | — |
|
| Alabama Power | 550 |
| | 200 |
| | 36 |
| | — |
| | — |
| — |
| | — |
| | 87 |
| | 87 |
| | — |
| | — |
|
| Georgia Power | 1,350 |
| | 450 |
| | 65 |
| | 370 |
| | 13 |
| 1,500 |
| | 950 |
| | 53 |
| | 148 |
| | 519 |
| | 35 |
|
| Gulf Power | 300 |
| | 85 |
| | — |
| | 6 |
| | — |
| |
| Mississippi Power | — |
| | — |
| | — |
| | 40 |
| | 893 |
| — |
| | 275 |
| | 34 |
| | 41 |
| | 100 |
| | — |
|
| Southern Power | — |
| | — |
| | — |
| | 43 |
| | 4 |
| — |
| | 300 |
| | — |
| | — |
| | — |
| | — |
|
Southern Company Gas(c) | 450 |
| | — |
| | — |
| | 200 |
| | 22 |
| |
| Other | — |
| | — |
| | — |
| | — |
| | 12 |
| — |
| | — |
| | — |
| | — |
| | — |
| | 8 |
|
Elimination(d) | — |
| | — |
| | — |
| | (40 | ) | | (599 | ) | |
| Southern Company Consolidated | $ | 2,950 |
| | $ | 1,135 |
| | $ | 101 |
| | $ | 1,119 |
| | $ | 745 |
| |
| Southern Company | | $ | 2,500 |
| | $ | 2,125 |
| | $ | 174 |
| | $ | 276 |
| | $ | 1,619 |
| | $ | 43 |
|
| |
(a)(*) | Includes reductions in capitalfinance 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 Capitalfinance leases and, guaranteed by the Southern Company Gas parent entity. Other long-term debt issued represents first mortgage bonds issued by Nicor Gas.
|
| |
(d) | Includes intercompany loans from Southern Company to Mississippifor Georgia Power, and reductions in affiliate capital lease obligations at Georgia Power. These transactions are eliminated in Southern Company's Consolidated Financial Statements.principal amortization payments for FFB borrowings. |
Southern CompanyIn June 2017, Southern Company issued $500 million aggregate principal amount
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Except as otherwise described herein, the Registrants used the proceeds of Series 2017A 5.325% Junior Subordinated Notes due June 21, 2057debt issuances for their redemptions and $300 million aggregate principal amount of Series 2017A Floating Rate Senior Notes due September 30, 2020, which bear interest at a floating rate based on three-month LIBOR. The proceeds were usedmaturities shown in the table above, to repay short-term indebtedness, and for other general corporate purposes.purposes, including working capital. The Subsidiary Registrants also used the proceeds for their construction programs.
Also in June 2017,In addition to any financings that may be necessary to meet capital requirements and contractual obligations, the Registrants 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.
Southern Company
During the first six months of 2020, Southern Company entered into two $100issued approximately 2.9 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $59 million.
In January 2020, Southern Company issued $1.0 billion 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.of Series 2020A 4.95% Junior Subordinated Notes due January 30, 2080.
In August 2017,March 2020, Southern Company borrowed $250 million pursuant to ana short-term uncommitted bank credit arrangement, which bearsbearing interest at a rate agreed upon by Southern Company and the bank from time to time and is payable on no less than 30 days' demand, following specified notice by the bank. The proceeds were used for working capital and other general corporate purposes.In April 2020, Southern Company repaid $50 million of the $250 million borrowed.
Also in March 2020, Southern Company entered into a $75 million short-term floating rate bank loan bearing interest based on one-month LIBOR.
In April 2020, Southern Company issued $1.0 billion aggregate principal amount of Series 2020A 3.70% Senior Notes due April 30, 2030.
In May 2020, Southern Company redeemed all $600 million aggregate principal amount of its Series 2015A 2.750% Senior Notes due June 15, 2020.
Alabama Power
In March 2017,2020, Alabama Power purchased and held approximately $87 million aggregate principal amount of The Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Plant Barry Project), Series 2007-A, which were remarketed to the public in June 2020.
Georgia Power
In January 2020, Georgia Power issued $550$700 million aggregate principal amount of Series 2020A 2.10% Senior Notes due July 30, 2023, $500 million aggregate principal amount of Series 2017A 2.45%2020B 3.70% Senior Notes due MarchJanuary 30, 2022. The proceeds were used to repay Alabama Power's short-term indebtedness2050, and for general corporate purposes, including Alabama Power's continuous construction program.an additional $300 million aggregate principal amount of Series 2019B 2.65% Senior Notes due September 15, 2029.
In September 2017, Alabama Power issued 10 million shares ($250 million aggregate stated capital) of 5.00% Class A Preferred Stock, Cumulative, Par Value $1 Per Share (Stated Capital $25 Per Share). The proceeds were used in
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
October 2017 to redeem all 2 million shares ($50 million aggregate stated capital) of Alabama Power's 6.50% Series Preference Stock, 6 million shares ($150 million aggregate stated capital) of Alabama Power's 6.45% Series Preference Stock, and 1.52 million shares ($38 million aggregate stated capital) of Alabama Power's 5.83% Class A Preferred Stock and for other general corporate purposes, including Alabama Power's continuous construction program.
Georgia Power
In March 2017,February 2020, Georgia Power issued $450redeemed all $500 million aggregate principal amount of its Series 2017A2017C 2.00% Senior Notes due March 30,September 8, 2020.
Also in February 2020, and $400 million aggregate principal amount of Series 2017B 3.25% Senior Notes due March 30, 2027. The proceeds were used to repay a portion of Georgia Power's short-term indebtedness and for general corporate purposes, including Georgia Power's continuous construction program.
In April 2017, Georgia Power purchased and held $27approximately $28 million, $49 million, and $18 million aggregate principal amountamounts of Development Authority of BurkeMonroe County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant VogtleScherer Project), FifthSecond Series 1995. Subsequent2006, First Series 2012, and First Series 2013, respectively, which may be remarketed to September 30, 2017,the public at a later date.
In March 2020, Georgia Power repaid at maturity $450 million aggregate principal amount of its Series 2017A 2.00% Senior Notes.
Also in March 2020, Georgia Power purchased and subsequently remarketed these bonds to the public.public approximately $53 million of pollution control revenue bonds.
In June 2017,Also in March 2020, Georgia Power entered into threeextended one of its $125 million short-term floating rate bank loans in aggregate principal amounts of $50 million, $150 million, and $100 million, with maturity dates of December 1, 2017, May 31, 2018, and June 28, 2018, respectively,to a long-term term loan, which bear interest based on one-month LIBOR. Alsomatures in June 2017, Georgia Power2021, and borrowed $500$200 million pursuant to ana $250 million short-term uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Georgia Power and the bank
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
from time to time and is payable on no less than 30 days' demand, following specified notice by the bank. In April 2020, Georgia Power borrowed the remaining $50 million pursuant to this bank credit arrangement.
In June 2020, Georgia Power extended its other $125 million short-term floating rate bank loan, which matures in December 2020.
Also in June 2020, Georgia Power made additional borrowings under the FFB Credit Facilities in an aggregate principal amount of $519 million at an interest rate of 1.652% through the final maturity date of February 20, 2044. The proceeds from these bank loans were used to repay a portionreimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4. During the six months ended June 30, 2020, Georgia Power's existing indebtedness andPower made principal amortization payments of $32 million under the FFB Credit Facilities. At June 30, 2020, the outstanding principal balance under the FFB Credit Facilities was $4.3 billion. See Note 8 to the financial statements under "Long-Term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for working capital and other general corporate purposes, including Georgia Power's continuous construction program.additional information.
Mississippi Power
In August 2017, GeorgiaFebruary 2020, Mississippi Power repaid $250entered into $60 million of the $500 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement. Also in August 2017, Georgia Power amended its $100and $15 million floating rate bank loanterm loans, which mature in December 2021 and January 2022, respectively, each bearing interest based on one-month LIBOR.
In March 2020, Mississippi Power entered into a $125 million revolving credit arrangement that matures in March 2023 and borrowed $40 million (short term) and $25 million (long term) pursuant to extend the arrangement, each bearing interest based on one-month LIBOR. In May 2020, Mississippi Power repaid the $40 million short-term portion.
In March 2020, Mississippi Power repaid at maturity date from June 28, 2018 to October 26, 2018.
Also in August 2017, Georgia Power issued $500the remaining $275 million aggregate principal amount of its Series 2017C 2.00%2018A Floating Rate Senior Notes due September 8, 2020. The proceeds were used to repay Georgia Power's $50 million floating rate bank loan due December 1, 2017 and outstanding commercial paper borrowings and for general corporate purposes.Notes.
Also in August 2017, GeorgiaIn April 2020, Mississippi Power purchased and held $38approximately $11 million, $14 million, and $9 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution ControlMississippi Business Finance Corporation Solid Waste Disposal Facilities Revenue Bonds, (GeorgiaSeries 1995 (Mississippi Power Company Plant Bowen Project), FirstSolid Waste Disposal Facilities Revenue Refunding Bonds, Series 1997. Subsequent to September 30, 2017, Georgia1998 (Mississippi Power Company Project), and Revenue Bonds, Series 1999 (Mississippi Power Company Project), respectively, which were remarketed these bonds to the public.public in May 2020.
In September 2017, GeorgiaAlso in April 2020, Mississippi Power issued $270redeemed approximately $7 million aggregate principal amount of The Industrial Development Board of the City of Eutaw, Alabama Pollution Control Revenue Refunding Bonds, Series 2017A 5.00% Junior Subordinated Notes1992 (Mississippi Power Greene County Plant Project) due OctoberDecember 1, 2077. The proceeds were used2020.
Southern Power
In February 2020, Southern Power repaid its $100 million short-term floating rate bank loan entered into in October 2017 to redeem all 1.8 million shares ($45December 2019.
In June 2020, Southern Power repaid at maturity $300 million aggregate liquidation amount)principal amount of Georgia Power's 6.125%its Series Class A Preferred Stock and 2.25 million shares ($225 million aggregate liquidation amount) of Georgia Power's 6.50% Series 2007A Preference Stock.2015B 2.375% Senior Notes.
Southern Company Gas
In March 2017, Gulf Power extended the maturity of2020, Southern Company Gas Capital, as borrower, and Southern Company Gas, as guarantor, entered into a $100$150 million short-term floating rate bank loan bearing interest based on one-month LIBOR from April 2017 to October 2017 and subsequently repaid the loanLIBOR.
Also in May 2017.
In May 2017, Gulf Power issued $300 million aggregate principal amount of Series 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 15, 2017; to repay outstanding commercial paper borrowings; to repay a $100 million short-term floating rate bank loan, as discussed above; and to redeem, in June 2017, 550,000 shares ($55 million aggregate liquidation amount) of 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,
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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.
In August 2017, Mississippi Power repaid a $12.5 million short-term bank note.
In September 2017, Mississippi Power issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $150 million bearing interest based on one-month LIBOR. Mississippi Power borrowed $109 million under this promissory note primarily to satisfy its federal income tax obligations for the quarter ending September 30, 2017 and subsequently repaid the promissory note upon receipt of its income tax refund from the U.S. federal government related to the settlement concerning deductible R&E expenditures. See Note (G) under "Section 174 Research and Experimental Deduction" for additional information.
Southern Power
In September 2017, Southern Power amended its $60 million aggregate principal amount floating rate bank loan to, among other things, increase the aggregate principal amount to $100 million and extend the maturity date from September 2017 to October 2018. The additional $40 million of proceeds were used to repay existing indebtedness and for other general corporate purposes.
Southern Company Gas
In May 2017,2020, Southern Company Gas Capital issued $450borrowed approximately $95 million aggregate principal amount of Series 2017A 4.40% Senior Notes due May 30, 2047. The proceeds were usedpursuant to repay Southern Company Gas'a short-term indebtedness and for general corporate purposes.
In July 2017, Nicor Gas agreed to issue $400 million aggregate principal amount of first mortgage bonds in a private placement. On August 10, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.03% Series due August 10, 2027 and $100 million aggregate principal amount of First Mortgage Bonds 3.62% Series due August 10, 2037. The proceeds were used to repay short-term indebtedness incurred under the Nicor Gas commercial paper program and for other working capital needs. The remaining $200 million is expected to be issued in November 2017.
Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees atuncommitted bank credit arrangement, guaranteed by 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 (ERISA). No mandatory contributions to the Southern Company qualified pension plan are anticipated for the year ending December 31, 2017. Southern Company also provides certain defined benefit pension plans forbearing interest at 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 requiredrate agreed upon by their respective regulatory commissions.
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. This qualified pension plan is funded in accordance with requirements of ERISA. No mandatory contributions to the Southern Company Gas qualified pension plan 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 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 nine months ended September 30, 2017 and 2016 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, 2017 | | | | | | | | | |
| Service cost | $ | 73 |
| | $ | 15 |
| | $ | 19 |
| | $ | 3 |
| | $ | 4 |
|
| Interest cost | 114 |
| | 25 |
| | 34 |
| | 5 |
| | 5 |
|
| Expected return on plan assets | (224 | ) | | (49 | ) | | (71 | ) | | (10 | ) | | (9 | ) |
| Amortization: | | | | | | | | | |
| Prior service costs | 3 |
| | 1 |
| | — |
| | — |
| | — |
|
| Net (gain)/loss | 41 |
| | 10 |
| | 15 |
| | 2 |
| | 1 |
|
| Net periodic pension cost (income) | $ | 7 |
| | $ | 2 |
| | $ | (3 | ) | | $ | — |
| | $ | 1 |
|
| Nine Months Ended September 30, 2017 | | | | | | | | | |
| Service cost | $ | 220 |
| | $ | 47 |
| | $ | 56 |
| | $ | 10 |
| | $ | 11 |
|
| Interest cost | 341 |
| | 73 |
| | 103 |
| | 15 |
| | 15 |
|
| Expected return on plan assets | (673 | ) | | (147 | ) | | (212 | ) | | (29 | ) | | (29 | ) |
| Amortization: | | | | | | | | | |
| Prior service costs | 9 |
| | 2 |
| | 2 |
| | — |
| | 1 |
|
| Net (gain)/loss | 122 |
| | 31 |
| | 43 |
| | 5 |
| | 5 |
|
| Net periodic pension cost (income) | $ | 19 |
| | $ | 6 |
| | $ | (8 | ) | | $ | 1 |
| | $ | 3 |
|
| 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 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | |
| Pension Plans | Southern Company Gas |
| | (in millions) |
| Successor – Three Months Ended September 30, 2017 | |
| Service cost | $ | 6 |
|
| Interest cost | 10 |
|
| Expected return on plan assets | (18 | ) |
| Amortization of net (gain)/loss | 5 |
|
| Net periodic pension cost | $ | 3 |
|
| Successor – Nine Months Ended September 30, 2017 | |
| Service cost | $ | 17 |
|
| Interest cost | 30 |
|
| Expected return on plan assets | (53 | ) |
| Amortization: | |
| Prior service costs | (1 | ) |
| Net (gain)/loss | 15 |
|
| Net periodic pension cost | $ | 8 |
|
| Successor – July 1, 2016 through September 30, 2016 | |
| Service cost | $ | 7 |
|
| Interest cost | 10 |
|
| Expected return on plan assets | (17 | ) |
| Amortization of regulatory asset | 6 |
|
| Net periodic pension cost | $ | 6 |
|
| | |
| | |
| Predecessor – January 1, 2016 through June 30, 2016 | |
| Service cost | $ | 13 |
|
| Interest cost | 21 |
|
| Expected return on plan assets | (33 | ) |
| Amortization: | |
| Prior service costs | (1 | ) |
| Net (gain)/loss | 13 |
|
| 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 September 30, 2017 | | | | | | | | | |
| Service cost | $ | 6 |
| | $ | 1 |
| | $ | 2 |
| | $ | — |
| | $ | — |
|
| Interest cost | 19 |
| | 4 |
| | 6 |
| | 1 |
| | 1 |
|
| Expected return on plan assets | (16 | ) | | (5 | ) | | (6 | ) | | — |
| | — |
|
| Amortization: | | | | | | | | | |
| Prior service costs | 2 |
| | 1 |
| | — |
| | — |
| | — |
|
| Net (gain)/loss | 3 |
| | — |
| | 3 |
| | — |
| | — |
|
| Net periodic postretirement benefit cost | $ | 14 |
| | $ | 1 |
| | $ | 5 |
| | $ | 1 |
| | $ | 1 |
|
| Nine Months Ended September 30, 2017 | | | | | | | | | |
| Service cost | $ | 18 |
| | $ | 4 |
| | $ | 5 |
| | $ | 1 |
| | $ | 1 |
|
| Interest cost | 59 |
| | 13 |
| | 21 |
| | 2 |
| | 3 |
|
| Expected return on plan assets | (49 | ) | | (19 | ) | | (18 | ) | | (1 | ) | | (1 | ) |
| Amortization: | | | | | | | | | |
| Prior service costs | 5 |
| | 3 |
| | 1 |
| | — |
| | — |
|
| Net (gain)/loss | 10 |
| | 1 |
| | 6 |
| | — |
| | — |
|
| Net periodic postretirement benefit cost | $ | 43 |
| | $ | 2 |
| | $ | 15 |
| | $ | 2 |
| | $ | 3 |
|
| Three Months Ended September 30, 2016 | | | | | | | | | |
| Service cost | $ | 6 |
| | $ | 1 |
| | $ | 2 |
| | $ | — |
| | $ | — |
|
| Interest cost | 20 |
| | 5 |
| | 7 |
| | 1 |
| | — |
|
| Expected return on plan assets | (16 | ) | | (6 | ) | | (6 | ) | | — |
| | — |
|
| Amortization: | | | | | | | | | |
| Prior service costs | 1 |
| | 1 |
| | — |
| | — |
| | — |
|
| Net (gain)/loss | 5 |
| | — |
| | 3 |
| | — |
| | 1 |
|
| Net periodic postretirement benefit cost | $ | 16 |
| | $ | 1 |
| | $ | 6 |
| | $ | 1 |
| | $ | 1 |
|
| Nine Months Ended September 30, 2016 | | | | | | | | | |
| Service cost | $ | 17 |
| | $ | 4 |
| | $ | 5 |
| | $ | 1 |
| | $ | 1 |
|
| Interest cost | 55 |
| | 14 |
| | 22 |
| | 2 |
| | 2 |
|
| Expected return on plan assets | (44 | ) | | (19 | ) | | (17 | ) | | (1 | ) | | (1 | ) |
| Amortization: | | | | | | | | | |
| Prior service costs | 4 |
| | 3 |
| | 1 |
| | — |
| | — |
|
| Net (gain)/loss | 12 |
| | 1 |
| | 7 |
| | — |
| | 1 |
|
| Net periodic postretirement benefit cost | $ | 44 |
| | $ | 3 |
| | $ | 18 |
| | $ | 2 |
| | $ | 3 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | |
| Postretirement Benefits | Southern Company Gas |
| | (in millions) |
| Successor – Three Months Ended September 30, 2017 | |
| Service cost | $ | 1 |
|
| Interest cost | 3 |
|
| Expected return on plan assets | (2 | ) |
| Amortization: | |
| Prior service costs | (1 | ) |
| Net (gain)/loss | 1 |
|
| Net periodic postretirement benefit cost | $ | 2 |
|
| Successor – Nine Months Ended September 30, 2017 | |
| Service cost | $ | 2 |
|
| Interest cost | 8 |
|
| Expected return on plan assets | (5 | ) |
| Amortization: | |
| Prior service costs | (2 | ) |
| Net (gain)/loss | 3 |
|
| Net periodic postretirement benefit cost | $ | 6 |
|
| Successor – July 1, 2016 through September 30, 2016 | |
| Service cost | $ | 1 |
|
| Interest cost | 2 |
|
| Expected return on plan assets | (2 | ) |
| Amortization of regulatory asset | 1 |
|
| Net periodic postretirement benefit cost | $ | 2 |
|
| | |
| | |
| Predecessor – January 1, 2016 through 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
Tax Credit Carryforwards
Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) totaling $1.9 billion as of September 30, 2017 compared to $1.8 billion as of December 31, 2016.
The federal ITC carryforwards begin expiring in 2032 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 acquisition of 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 September 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 |
| | 64 |
|
| Balance at September 30, 2017 | $ | 46 |
| | $ | 19 |
| | $ | 82 |
|
Southern Company had valuation allowances, net of the federal benefit, of $82 million at September 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 rate was 42.6% for the nine months ended September 30, 2017 compared to 28.3% for the corresponding period in 2016. The effective tax rate increase was primarily due to the estimated probable losses on the Kemper IGCC, net of the non-deductible AFUDC equity portion. Other factors include a decrease in tax benefits from solar ITCs and an increase in state valuation allowances, partially offset by an increase in tax benefits from wind PTCs.
Southern Company recognizes PTCs when wind energy is generated and sold (using the prescribed KWH rate in applicable federal and state statutes), which may differ significantly from amounts computed on a quarterly basis using an overall estimated annual effective income tax rate. Southern Company 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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Mississippi Power
Mississippi Power's effective tax (benefit) rate was (30.3)% for the nine months ended September 30, 2017 compared to (282.8)% for the corresponding period in 2016. The effective tax rate increase was primarily due to the estimated probable losses on the Kemper IGCC, net of the non-deductible AFUDC equity portionCapital and the related state valuation allowances.
Southern Power
Southern Power's effective tax (benefit) rate was (66.5)% for the nine months ended September 30, 2017 comparedbank from time to (88.9)% for the corresponding period in 2016. The effective tax rate increase was primarily due to a decrease in tax benefits from solar ITCs, partially offset by additional wind PTCstime and state apportionment rate changes.
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 computedpayable on a quarterly basis using an overall estimated annual effective income tax rate. Southern Power uses this method of recognition since the amount of PTCs can be significantly impacted by wind generation. This method can significantly affect the effective income tax rate for the period depending on the amount of pretax income.
During the third quarter 2017, Southern Power began a legal entity reorganization of various direct and indirect subsidiaries that own and operate solar facilities, including certain subsidiaries owned in partnership with various third parties. Southern Power's ownership interests in the various solar entities and facilities will not be affecteddemand, following specified notice by the reorganization. The reorganization is expected to result in estimated tax benefits totaling approximately $40 million that will be recorded in the fourth quarter 2017 related to certain changes in state apportionment rates and net operating loss carryforward utilization. The ultimate outcome of this matter cannot be determined at this time.
Southern Company Gas
Southern Company Gas' effective tax rate was 43.4% for the successor nine months ended September 30, 2017 compared to 60.3% for the successor period of July 1, 2016 through September 30, 2016 and 37.6% for the predecessor period of January 1, 2016 through June 30, 2016. The effective tax rate for the successor year-to-date 2017 was impacted by State of Illinois tax legislation enacted during July 2017, the allocation of new tax apportionment factors in several states for the inclusion of Southern Company Gas into the consolidated Southern Company state tax filings, and higher pre-tax earnings. The effective tax rates for the periods in 2016 were impacted by the non-deductibility of certain Merger-related expenses. The effective tax rate for the successor period of July 1, 2016 through September 30, 2016 was also impacted by nondeductible expenses associated with certain compensation costs.
Unrecognized Tax Benefits
See Note 5 to the financial statements of each registrant under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K for additional information.
Changes during the nine months ended September 30, 2017 for unrecognized tax benefits were as follows:
|
| | | | | | | | | | | |
| | Mississippi Power | | Southern Power | | Southern Company |
| | (in millions) |
| Unrecognized tax benefits as of December 31, 2016 | $ | 465 |
| | $ | 17 |
| | $ | 484 |
|
| Tax positions from current periods | 2 |
| | — |
| | 9 |
|
| Tax positions from prior periods | (175 | ) | | (17 | ) | | (186 | ) |
| Reductions due to settlements | (290 | ) | | — |
| | (290 | ) |
| Balance as of September 30, 2017 | $ | 2 |
| | $ | — |
| | $ | 17 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
The tax positions from current and prior periods primarily relate to state tax benefits, deductions for R&E expenditures, and charitable contribution carryforwards that were impacted as a result of the settlement of R&E expenditures associated with the Kemper IGCC, as well as federal income tax benefits from deferred ITCs. See "Section 174 Research and Experimental Deduction" herein for additional information. These amounts are presented on a gross basis without considering the related federal or state income tax impact.
The impact on the effective tax rate, if recognized, is as follows:
|
| | | | | | | | | | | |
| | As of September 30, 2017 | | As of December 31, 2016 |
| | Mississippi Power | | Southern Company | | Southern Company |
| | (in millions) |
| Tax positions impacting the effective tax rate | $ | 2 |
| | $ | 17 |
| | $ | 20 |
|
| Tax positions not impacting the effective tax rate | — |
| | — |
| | 464 |
|
| Balance of unrecognized tax benefits | $ | 2 |
| | $ | 17 |
| | $ | 484 |
|
The tax positions impacting the effective tax rate primarily relate to state tax benefits and charitable contribution carryforwards that were impacted as a result of the settlement of R&E expenditures associated with the Kemper IGCC. See "Section 174 Research and Experimental Deduction" herein for additional information.
Accrued interest for all tax positions was immaterial for all periods presented.
All of the registrants classify interest on tax uncertainties as interest expense. None of the registrants accrued any penalties on uncertain tax positions.
It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2016. Southern Company is a participant in the Compliance Assurance Process of the IRS. However, the pre-Merger Southern Company Gas 2014, 2015, and June 30, 2016 federal tax returns are currently under audit. The audits for Southern Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2011.
Section 174 Research and Experimental Deduction
Southern Company has reflected deductions for R&E expenditures related to the Kemper 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, which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation (JCT), resolving a methodology for these deductions. As a result of the JCT approval, Southern Company recognized $176 million of previously unrecognized tax benefits and reversed $36 million of associated accrued interest. 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 in the year an abandonment is determined. The ultimate outcome of this matter cannot be determined at this time.bank.
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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Southern Company Gas' wholesale gas operations use various contracts in its commercial activities that generally meet the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note (C) for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. The cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with classification of the hedged interest or principal, respectively.
Energy-Related Derivatives
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas enter into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies and the natural gas distribution utilities have limited exposure to market volatility in energy-related commodity prices. Each of the traditional electric operating companies and certain of the natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs, implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. The Florida PSC extended the moratorium on Gulf Power's fuel-hedging program until January 1, 2021 in connection with the 2017 Rate Case Settlement Agreement. The moratorium does not have an impact on the recovery of existing hedges entered into under the previously-approved hedging program. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in energy-related commodity prices because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted capacity is used to sell electricity. Southern Company Gas retains exposure to price changes that can, in a volatile energy market, be material and can adversely affect its results of operations.
Southern Company Gas also enters into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in the statements of income.
Energy-related derivative contracts are accounted for under one of three methods:
Regulatory Hedges — Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the traditional electric operating companies' and the natural gas distribution utilities' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses.
Cash Flow Hedges — Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings.
Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric and natural gas industries. When an energy-related
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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.Credit Rating Risk
At September 30, 2017, the net volume of energy-related derivative contracts for natural gas positions for the Southern Company system, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows:
|
| | | | | |
| | Net Purchased mmBtu | | Longest Hedge Date | | Longest Non-Hedge Date |
| | (in millions) | | | | |
Southern Company(*) | 463 | | 2021 | | 2024 |
| Alabama Power | 66 | | 2020 | | — |
| Georgia Power | 159 | | 2021 | | — |
| Gulf Power | 28 | | 2020 | | — |
| Mississippi Power | 44 | | 2021 | | — |
| Southern Power | 13 | | 2018 | | — |
Southern Company Gas(*) | 153 | | 2020 | | 2024 |
| |
(*) | Southern Company's and Southern Company Gas' derivative instruments include both long and short natural gas positions. A long position is a contract to purchase natural gas and a short position is a contract to sell natural gas. Southern Company Gas' volume represents the net of long natural gas positions of 3.3 billion mmBtu and short natural gas positions of 3.1 billion mmBtu as of September 30, 2017, which is also included in Southern Company's total volume. |
In addition to the volumes discussed above, the traditional electric operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 34 million mmBtu for Southern Company, 11 million mmbtu for Georgia Power and Southern Power, 5 million mmbtu for Alabama Power, 3 million mmBtu for Gulf Power, and 4 million mmBtu for Mississippi Power.
For cash flow hedges of energy-related derivatives, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending September 30, 2018 are $5 million for Southern Power and immaterial for all other registrants.
Interest Rate Derivatives
Southern Company and certain subsidiaries may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings, providing an offset, with any difference representing ineffectiveness. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
At September 30, 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, 2017 |
| | (in millions) | | | | | | (in millions) |
| Cash Flow Hedges of Existing Debt | | | | | | |
| Mississippi Power | $ | 900 |
| | 1-month
LIBOR | 0.79% | March 2018 | | $ | 2 |
|
| Fair Value Hedges of Existing Debt | | | | | | |
Southern Company(*) | 300 |
| | 2.75% | 3-month
LIBOR + 0.92% | June 2020 | | — |
|
Southern Company(*) | 1,500 |
| | 2.35% | 1-month
LIBOR + 0.87% | July 2021 | | (19 | ) |
| 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 | | — |
|
| Southern Company Consolidated | $ | 3,650 |
| | | | | | $ | (19 | ) |
| |
(*) | Represents the Southern Company parent entity. |
The estimated pre-tax gains (losses) related to interest rate derivatives expected to be reclassified from accumulated OCI to interest expense for the next 12-month period ending September 30, 2018 are $(19) million for Southern Company and immaterial for all other registrants. Southern Company and certain subsidiaries have deferred gains and losses expected to be amortized into earnings through 2046.
Foreign Currency Derivatives
Southern Company and certain subsidiaries may also enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time that the hedged transactions affect earnings, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Any ineffectiveness is recorded directly to earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
At September 30, 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, 2017 |
| (in millions) | | (in millions) | | | (in millions) |
| Cash Flow Hedges of Existing Debt | | | | | |
| Southern Power | $ | 677 |
| 2.95% | € | 600 |
| 1.00% | June 2022 | $ | 42 |
|
| Southern Power | 564 |
| 3.78% | 500 |
| 1.85% | June 2026 | 38 |
|
| Total | $ | 1,241 |
| | € | 1,100 |
| | | $ | 80 |
|
The estimated pre-tax gains (losses) related to foreign currency derivatives that will be reclassified from accumulated OCI to earnings for the next 12-month period ending September 30, 2018 are $(23) million for Southern Company and Southern Power.
Derivative Financial Statement Presentation and Amounts
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas enter into derivative contracts that may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Southern Company and certain subsidiaries also utilize master netting agreements to mitigate exposure to counterparty credit risk. These agreements may contain provisions that permit netting across product lines and against cash collateral. The fair value amounts of derivative assets and liabilities on the balance sheet are presented net to the extent that there are netting arrangements or similar agreements with the counterparties.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
The fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:
|
| | | | | | | | | | | | |
| | As of September 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/Other current liabilities | $ | 21 |
| $ | 25 |
| $ | 73 |
| $ | 27 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 13 |
| 23 |
| 25 |
| 33 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 34 |
| $ | 48 |
| $ | 98 |
| $ | 60 |
|
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 8 |
| $ | 6 |
| $ | 23 |
| $ | 7 |
|
| Interest rate derivatives: | | | | |
| Other current assets/Other current liabilities | 5 |
| 1 |
| 12 |
| 1 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 23 |
| 1 |
| 28 |
|
| Foreign currency derivatives: | | | | |
| Other current assets/Other current liabilities | — |
| 23 |
| — |
| 25 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 103 |
| — |
| — |
| 33 |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 116 |
| $ | 53 |
| $ | 36 |
| $ | 94 |
|
| Derivatives not designated as hedging instruments | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 271 |
| $ | 254 |
| $ | 489 |
| $ | 483 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 115 |
| 103 |
| 66 |
| 81 |
|
| Interest rate derivatives: | | | | |
| Other current assets/Other current liabilities | — |
| — |
| 1 |
| — |
|
| Total derivatives not designated as hedging instruments | $ | 386 |
| $ | 357 |
| $ | 556 |
| $ | 564 |
|
| Gross amounts recognized | $ | 536 |
| $ | 458 |
| $ | 690 |
| $ | 718 |
|
Gross amounts offset(*) | $ | (275 | ) | $ | (351 | ) | $ | (462 | ) | $ | (524 | ) |
| Net amounts recognized in the Balance Sheets | $ | 261 |
| $ | 107 |
| $ | 228 |
| $ | 194 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | |
| | As of September 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/Other current liabilities | $ | 6 |
| $ | 4 |
| $ | 13 |
| $ | 5 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 3 |
| 3 |
| 7 |
| 4 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 9 |
| $ | 7 |
| $ | 20 |
| $ | 9 |
|
| Gross amounts recognized | $ | 9 |
| $ | 7 |
| $ | 20 |
| $ | 9 |
|
| Gross amounts offset | $ | (5 | ) | $ | (5 | ) | $ | (8 | ) | $ | (8 | ) |
| Net amounts recognized in the Balance Sheets | $ | 4 |
| $ | 2 |
| $ | 12 |
| $ | 1 |
|
| | | | | |
| Georgia Power | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 10 |
| $ | 3 |
| $ | 30 |
| $ | 1 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 8 |
| 8 |
| 14 |
| 7 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 18 |
| $ | 11 |
| $ | 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 | $ | 19 |
| $ | 14 |
| $ | 46 |
| $ | 11 |
|
| Gross amounts offset | $ | (10 | ) | $ | (10 | ) | $ | (8 | ) | $ | (8 | ) |
| Net amounts recognized in the Balance Sheets | $ | 9 |
| $ | 4 |
| $ | 38 |
| $ | 3 |
|
| | | | | |
| Gulf Power | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | — |
| $ | 13 |
| $ | 4 |
| $ | 12 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 9 |
| 1 |
| 17 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | — |
| $ | 22 |
| $ | 5 |
| $ | 29 |
|
| Gross amounts recognized | $ | — |
| $ | 22 |
| $ | 5 |
| $ | 29 |
|
| Gross amounts offset | $ | — |
| $ | — |
| $ | (4 | ) | $ | (4 | ) |
| Net amounts recognized in the Balance Sheets | $ | — |
| $ | 22 |
| $ | 1 |
| $ | 25 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | |
| | As of September 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 |
| $ | 4 |
| $ | 2 |
| $ | 6 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 2 |
| 3 |
| 2 |
| 5 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 3 |
| $ | 7 |
| $ | 4 |
| $ | 11 |
|
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Interest rate derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 2 |
| $ | — |
| $ | 2 |
| $ | — |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| — |
| 1 |
| — |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 2 |
| $ | — |
| $ | 3 |
| $ | — |
|
| Gross amounts recognized | $ | 5 |
| $ | 7 |
| $ | 7 |
| $ | 11 |
|
| Gross amounts offset | $ | (3 | ) | $ | (3 | ) | $ | (3 | ) | $ | (3 | ) |
| Net amounts recognized in the Balance Sheets | $ | 2 |
| $ | 4 |
| $ | 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 | $ | 8 |
| $ | 4 |
| $ | 18 |
| $ | 4 |
|
| Foreign currency derivatives: | | | | |
| Other current assets/Other current liabilities | — |
| 23 |
| — |
| 25 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 103 |
| — |
| — |
| 33 |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 111 |
| $ | 27 |
| $ | 18 |
| $ | 62 |
|
| Derivatives not designated as hedging instruments | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 1 |
| $ | — |
| $ | 3 |
| $ | 1 |
|
| Interest rate derivatives: | | | | |
| Other current assets/Other current liabilities | — |
| — |
| 1 |
| — |
|
| Total derivatives not designated as hedging instruments | $ | 1 |
| $ | — |
| $ | 4 |
| $ | 1 |
|
| Gross amounts recognized | $ | 112 |
| $ | 27 |
| $ | 22 |
| $ | 63 |
|
| Gross amounts offset | $ | (1 | ) | $ | (1 | ) | $ | (5 | ) | $ | (5 | ) |
| Net amounts recognized in the Balance Sheets | $ | 111 |
| $ | 26 |
| $ | 17 |
| $ | 58 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | |
| | As of September 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 |
| $ | 1 |
| $ | 24 |
| $ | 3 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| — |
| 1 |
| — |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 4 |
| $ | 1 |
| $ | 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 | $ | 270 |
| $ | 254 |
| $ | 486 |
| $ | 482 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 115 |
| 103 |
| 66 |
| 81 |
|
| Total derivatives not designated as hedging instruments | $ | 385 |
| $ | 357 |
| $ | 552 |
| $ | 563 |
|
| Gross amounts of recognized | $ | 389 |
| $ | 360 |
| $ | 581 |
| $ | 569 |
|
Gross amounts offset(*) | $ | (251 | ) | $ | (327 | ) | $ | (435 | ) | $ | (497 | ) |
| Net amounts recognized in the Balance Sheets | $ | 138 |
| $ | 33 |
| $ | 146 |
| $ | 72 |
|
| |
(*) | Gross amounts offset include cash collateral held on deposit in broker margin accounts of $76 million and $62 million as of September 30, 2017 and December 31, 2016, respectively. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
At September 30, 2017 and December 31, 2016, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:
|
| | | | | | | | | | | | | | | | | | |
| Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at September 30, 2017 |
Derivative Category and Balance Sheet Location | Southern Company(b) | Alabama Power | Georgia Power | Gulf Power | Mississippi Power | Southern Company Gas(c) |
| | (in millions) | |
| Energy-related derivatives: | | | | | | |
| Other regulatory assets, current | $ | (18 | ) | $ | (1 | ) | $ | — |
| $ | (13 | ) | $ | (3 | ) | $ | (1 | ) |
| Other regulatory assets, deferred | (12 | ) | (1 | ) | (1 | ) | (9 | ) | (1 | ) | — |
|
Other regulatory liabilities, current(a) | 14 |
| 3 |
| 7 |
| — |
| — |
| 4 |
|
Other regulatory liabilities, deferred(b) | 2 |
| 1 |
| 1 |
| — |
| — |
| — |
|
| Total energy-related derivative gains (losses) | $ | (14 | ) | $ | 2 |
| $ | 7 |
| $ | (22 | ) | $ | (4 | ) | $ | 3 |
|
| |
(a) | Georgia Power includes other regulatory liabilities, current in other current liabilities. |
| |
(b) | Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities. |
| |
(c) | Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $1 million at September 30, 2017. |
|
| | | | | | | | | | | | | | | | | | |
| Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2016 |
Derivative Category and Balance Sheet Location | Southern Company(c) | Alabama Power | Georgia Power | Gulf Power | Mississippi Power | Southern Company Gas(c) |
| | (in millions) | |
| Energy-related derivatives: | | | | | | |
| Other regulatory assets, current | $ | (16 | ) | $ | (1 | ) | $ | — |
| $ | (9 | ) | $ | (5 | ) | $ | (1 | ) |
| Other regulatory assets, deferred | (19 | ) | — |
| — |
| (16 | ) | (3 | ) | — |
|
Other regulatory liabilities, current(a) | 56 |
| 8 |
| 29 |
| 1 |
| 1 |
| 17 |
|
Other regulatory liabilities, deferred(b) | 12 |
| 4 |
| 7 |
| — |
| — |
| 1 |
|
| Total energy-related derivative gains (losses) | $ | 33 |
| $ | 11 |
| $ | 36 |
| $ | (24 | ) | $ | (7 | ) | $ | 17 |
|
| |
(a) | Georgia Power includes other regulatory liabilities, current in other current liabilities. |
| |
(b) | Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities. |
| |
(c) | Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $8 million at December 31, 2016. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
For the three months ended September 30, 2017 and 2016, the pre-tax effects of energy-related derivatives, interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instruments were as follows:
|
| | | | | | | | | | | | | | | | |
Derivatives in Cash Flow Hedging Relationships | Gain (Loss) Recognized in OCI on Derivative (Effective Portion) | | Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) |
| | Statements of Income Location | Amount |
| | 2017 | | 2016 | | | 2017 | | 2016 |
| | (in millions) | | | (in millions) |
| Southern Company | | | | | | | | |
| Energy-related derivatives | $ | (6 | ) | | $ | — |
| | Depreciation and amortization | $ | (6 | ) | | $ | 1 |
|
| Interest rate derivatives | (1 | ) | | (6 | ) | | Interest expense, net of amounts capitalized | (5 | ) | | (6 | ) |
| Foreign currency derivatives | 46 |
| | 37 |
| | Interest expense, net of amounts capitalized | (5 | ) | | (6 | ) |
| | | | | | Other income (expense), net(*) | 43 |
| | 7 |
|
| Total | $ | 39 |
| | $ | 31 |
| | | $ | 27 |
| | $ | (4 | ) |
| Alabama Power | | | | | | | | |
| Interest rate derivatives | $ | — |
| | $ | — |
| | Interest expense, net of amounts capitalized | $ | (2 | ) | | $ | (2 | ) |
| Georgia Power | | | | | | | | |
| Interest rate derivatives | $ | — |
| | $ | — |
| | Interest expense, net of amounts capitalized | $ | (1 | ) | | $ | (1 | ) |
| Mississippi Power | | | | | | | | |
| Interest rate derivatives | $ | (1 | ) | | $ | (1 | ) | | Interest expense, net of amounts capitalized | $ | — |
| | $ | — |
|
| Southern Power | | | | | | | | |
| Energy-related derivatives | $ | (6 | ) | | $ | — |
| | Depreciation and amortization | $ | (6 | ) | | $ | 1 |
|
| Foreign currency derivatives | 46 |
| | 37 |
| | Interest expense, net of amounts capitalized | (5 | ) | | (6 | ) |
| | | | | | Other income (expense), net(*) | 43 |
| | 7 |
|
| Total | $ | 40 |
| | $ | 37 |
| | | $ | 32 |
| | $ | 2 |
|
| Southern Company Gas | | | | | | | | |
| Interest rate derivatives | $ | — |
| | $ | (5 | ) | | Interest expense, net of amounts capitalized | $ | — |
| | $ | — |
|
| |
(*) | The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
For the nine months ended September 30, 2017 and 2016, the pre-tax effects of energy-related derivatives, interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instruments were as follows:
|
| | | | | | | | | | | | | | | | |
Derivatives in Cash Flow
Hedging Relationships | Gain (Loss)
Recognized in OCI
on Derivative
(Effective Portion) | | Gain (Loss) Reclassified from Accumulated OCI into
Income (Effective Portion) |
| | Statements of Income Location | Amount |
| | 2017 | | 2016 | | | 2017 | | 2016 |
| | (in millions) | | | (in millions) |
| Southern Company | | | | | | | | |
| Energy-related derivatives | $ | (26 | ) | | $ | (1 | ) | | Depreciation and amortization | $ | (12 | ) | | $ | 1 |
|
| Interest rate derivatives | (2 | ) | | (189 | ) | | Interest expense, net of amounts capitalized | (15 | ) | | (13 | ) |
| Foreign currency derivatives | 114 |
| | (1 | ) | | Interest expense, net of amounts capitalized | (17 | ) | | (7 | ) |
| | | | | | Other income (expense), net(*) | 139 |
| | (13 | ) |
| Total | $ | 86 |
| | $ | (191 | ) | | | $ | 95 |
| | $ | (32 | ) |
| Alabama Power | | | | | | | | |
| Interest rate derivatives | $ | — |
| | $ | (3 | ) | | Interest expense, net of amounts capitalized | $ | (5 | ) | | $ | (5 | ) |
| Georgia Power | | | | | | | | |
| Interest rate derivatives | $ | — |
| | $ | — |
| | Interest expense, net of amounts capitalized | $ | (3 | ) | | $ | (3 | ) |
| Gulf Power | | | | | | | | |
| Energy-related derivatives | $ | (1 | ) | | $ | — |
| | Depreciation and amortization | $ | — |
| | $ | — |
|
| Interest rate derivatives | (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 | ) |
| Southern Power | | | | | | | | |
| Energy-related derivatives | $ | (21 | ) | | $ | (1 | ) | | Depreciation and amortization | $ | (12 | ) | | $ | 1 |
|
| Interest rate derivatives | — |
| | — |
| | Interest expense, net of amounts capitalized | — |
| | (1 | ) |
| Foreign currency derivatives | 114 |
| | (1 | ) | | Interest expense, net of amounts capitalized | (17 | ) | | (7 | ) |
| |
|
| |
|
| | Other income (expense), net(*) | 139 |
| | (13 | ) |
| Total | $ | 93 |
| | $ | (2 | ) | | | $ | 110 |
| | $ | (20 | ) |
| |
(*) | The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes. |
For 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 nine months ended September 30, 2017, the successor period of July 1, 2016 through September 30, 2016, and the predecessor period of January 1, 2016 through 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) |
| Derivatives in Cash Flow Hedging Relationships | Nine Months Ended September 30, 2017 | | Statements of Income Location | Nine Months Ended September 30, 2017 |
| | (in millions) | | | (in millions) |
| Energy-related derivatives | $ | (4 | ) | | Cost of natural gas | $ | — |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | |
| | Gain (Loss) Recognized in OCI on Derivative (Effective Portion) | | | Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) |
| | Successor | | | Predecessor | | | Successor | | | Predecessor |
| Derivatives in Cash Flow Hedging Relationships | July 1, 2016 through September 30, 2016 | | | January 1, 2016 through June 30, 2016 | | Statements of Income Location | July 1, 2016
through
September 30, 2016 | | | January 1, 2016 through June 30, 2016 |
| | (in millions) | | | (in millions) | | | (in millions) | | | (in millions) |
| Energy-related derivatives | $ | — |
| | | $ | — |
| | Cost of natural gas | $ | — |
| | | $ | (1 | ) |
| Interest rate derivatives | (5 | ) | | | (64 | ) | | Interest expense, net of amounts capitalized | — |
| | | — |
|
| Total | $ | (5 | ) | | | $ | (64 | ) | | | $ | — |
| | | $ | (1 | ) |
For2020, the three and nine months ended September 30, 2017 and 2016, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments were immaterial for the other registrants.
For the three and nine months ended September 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 September 30, | | Nine Months Ended September 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(*) | $ | (17 | ) | $ | — |
| | $ | 48 |
| $ | — |
|
| | Cost of natural gas | 2 |
| 6 |
| | (2 | ) | 6 |
|
| Total derivatives in non-designated hedging relationships | $ | (15 | ) | $ | 6 |
| | $ | 46 |
| $ | 6 |
|
| |
(*) | Excludes gains (losses) recorded in cost of natural gas associated with weather derivatives of $15 million for the nine months ended September 30, 2017 and immaterial amounts for all other periods presented. |
|
| | | | | | | | | | | | | | | | | | | | | |
| | | Gain (Loss) |
| | | Successor |
| Successor | | Successor | | Successor | | | Predecessor |
| Derivatives in Non-Designated Hedging Relationships | Statements of Income Location | Three Months Ended September 30, 2017 | | Three Months Ended September 30, 2016 | | Nine Months Ended September 30, 2017 | | July 1, 2016 through September 30, 2016 | | | January 1, 2016 through June 30, 2016 |
| | | (in millions) | | (in millions) | | (in millions) | | (in millions) | | | |
| Southern Company Gas | | | | | | | | | | |
| Energy Related derivatives: | Natural gas revenues(*) | $ | (17 | ) | | $ | — |
| | $ | 48 |
| | $ | — |
| | | $ | (1 | ) |
| | Cost of natural gas | 2 |
| | 6 |
| | (2 | ) | | 6 |
| | | (62 | ) |
| Total derivatives in non-designated hedging relationships | $ | (15 | ) | | $ | 6 |
| | $ | 46 |
| | $ | 6 |
| | | $ | (63 | ) |
| |
(*) | Excludes gains recorded in cost of natural gas associated with weather derivatives of $15 million for the successor nine months ended September 30, 2017 and immaterial amounts for all other periods presented. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
For the three and nine months ended September 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 nine months ended September 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 | 2017 | | 2016 | 2017 | | 2016 |
| | | (in millions) | (in millions) |
| Southern Company | | | | | | | |
| Interest rate derivatives: | Interest expense, net of amounts capitalized | $ | (5 | ) | | $ | (9 | ) | $ | (6 | ) | | $ | 15 |
|
| Georgia Power | | | | | | | |
| Interest rate derivatives: | Interest expense, net of amounts capitalized | $ | — |
| | $ | (5 | ) | $ | (1 | ) | | $ | 10 |
|
For the three and nine months ended September 30, 2017 and 2016, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were offset by changes to the carrying value of long-term debt.
There was no material ineffectiveness recorded in earnings for any registrant for any period presented.
Contingent Features
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas doRegistrants did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
There are certain derivativescontracts that could require collateral, but not accelerated payment, in the event of variousa credit rating changeschange of certain Southern Company subsidiaries. At September 30, 2017, the registrants had no collateral posted with derivative counterpartiessubsidiaries to satisfy these arrangements.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, for Georgia Power, construction of new generation at Plant Vogtle Units 3 and 4.
At September 30, 2017, the fair value of derivative liabilities with contingent features was immaterial for all registrants. The maximum potential collateral requirements arising from the credit-risk-related contingent features,under these contracts at a rating below BBB- and/or Baa3,June 30, 2020 were immaterial for all registrants. as follows:
|
| | | | | | | | | | | | | | | | | | |
| Credit Ratings | Southern Company(*) | Alabama Power | Georgia Power | Mississippi Power | Southern Power(*) | Southern Company Gas |
| | (in millions) |
| At BBB and/or Baa2 | $ | 36 |
| $ | 1 |
| $ | — |
| $ | — |
| $ | 35 |
| $ | — |
|
| At BBB- and/or Baa3 | 428 |
| 2 |
| 61 |
| 1 |
| 366 |
| — |
|
| At BB+ and/or Ba1 or below | 1,926 |
| 319 |
| 899 |
| 265 |
| 1,188 |
| 7 |
|
| |
| (*) | Southern Power has PPAs that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power's credit. The PPAs require credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses resulting from a credit downgrade. Southern Power had $105 million of cash collateral posted related to PPA requirements at June 30, 2020. |
The maximum potential collateral requirements arising fromrequirement amounts in the credit-risk-related contingent featuresprevious table for the traditional electric operating companies and Southern Power include certain agreements that could require collateral in the event that oneeither Alabama Power or more Southern Company 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. If collateral is required, fair value amounts recognized forAdditionally, a credit rating downgrade could impact 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 valueability of the positions in these accountsRegistrants to access capital markets and would be likely to impact the associated margin requirements, Alabama Power and Southern Power may be required to post collateral. At September 30, 2017, cash collateral posted in these accounts was immaterial.cost at which they do so.
Market Price Risk
Other than the Southern Company Gas maintains accounts with brokers oritems discussed below, there were no material changes to the clearing housesRegistrants' disclosures about market price risk during the second quarter 2020. For an in-depth discussion 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 September 30, 2017, cash collateral held on deposit in broker margin accounts was $76 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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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' exposuremarket price risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" in Item 7 of the Form 10-K. Also see "Overview" herein for information on volatility in the financial markets that has occurred at certain periods during 2020 resulting from the COVID-19 pandemic and Notes (I) and (J) to counterparty credit risk. Southern Company Gas may require counterpartiesthe Condensed Financial Statements herein for information relating to pledge additional collateral when deemed necessary.
In addition, Southern Company Gas conducts credit evaluations and obtains appropriate internal approvals for the counterparty's line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody's and BBB- from S&P. Generally, Southern Company Gas requires credit enhancements by way of a guaranty, cash deposit, or letter of credit for transaction counterparties that do not have investment grade ratings.derivative instruments.
Southern Company Gas also utilizes master netting agreements whenever possibleis exposed to mitigatemarket risks, including commodity price risk, interest rate risk, and weather risk. Due to various cost recovery mechanisms, the natural gas distribution utilities that sell natural gas directly to end-use customers continue to have limited 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 nettingmarket volatility of natural gas prices. Certain of the positivenatural gas distribution utilities may 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. In addition, certain non-regulated operations routinely utilize various types of derivative instruments to economically hedge certain commodity price and negative exposures with that counterpartyweather risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and a reasonable measureover-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 may not be designated, for hedge accounting treatment.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
For the periods presented below, the changes in net fair value 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.derivative contracts were as follows:
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas do not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | |
| | Second Quarter 2020 | Second Quarter 2019 | | Year-to-Date 2020 | Year-to-Date 2019 |
| | (in millions) |
| Contracts outstanding at beginning of period, assets (liabilities), net | $ | 17 |
| $ | (128 | ) | | $ | 72 |
| $ | (167 | ) |
| Contracts realized or otherwise settled | (8 | ) | 5 |
| | (99 | ) | — |
|
Current period changes(*) | 17 |
| 33 |
| | 53 |
| 77 |
|
| Contracts outstanding at the end of period, assets (liabilities), net | $ | 26 |
| $ | (90 | ) |
| $ | 26 |
| $ | (90 | ) |
| Netting of cash collateral | 114 |
| 178 |
| | 114 |
| 178 |
|
| Cash collateral and net fair value of contracts outstanding at end of period | $ | 140 |
| $ | 88 |
|
| $ | 140 |
| $ | 88 |
|
| |
(I)(*) | ACQUISITIONS AND DISPOSITIONSCurrent period changes also include the fair value of new contracts entered into during the period, if any. |
The maturities of Southern Company Gas' derivative contracts at June 30, 2020 were as follows:
|
| | | | | | | | | | | | | | | |
| | | | Fair Value Measurements |
| | | | June 30, 2020 |
| | Total
Fair Value | | Maturity |
| | | Year 1 | | Years 2 & 3 | | Years 4 and thereafter |
| | (in millions) |
Level 1(a) | $ | (80 | ) | | $ | (46 | ) | | $ | (41 | ) | | $ | 7 |
|
Level 2(b) | 26 |
| | 13 |
| | 9 |
| | 4 |
|
Level 3(c) | 80 |
| | 12 |
| | 27 |
| | 41 |
|
Fair value of contracts outstanding at end of period(d) | $ | 26 |
| | $ | (21 | ) | | $ | (5 | ) | | $ | 52 |
|
| |
| (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) | Valued using a combination of observable and unobservable inputs. |
| |
| (d) | Excludes cash collateral of $114 million. |
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
During the six months ended June 30, 2020, there were no material changes to Southern Company
Merger withCompany'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 Southern Company Gas,
Southern Company Gas is see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" herein. For an energy services holding company whose primary business is the distributionin-depth discussion of natural gas through the natural gas distribution utilities. On July 1, 2016, Southern Company completed the Merger for a total purchase price of approximately $8.0 billion and Southern Company Gas became a wholly-owned, direct subsidiary of Southern Company.
The Merger was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value aseach Registrant's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" in Item 7 of the acquisition date. The following table presents the final purchase price allocation:
|
| | | |
| Southern Company Gas Purchase Price | |
| | (in millions) |
| Current assets | $ | 1,557 |
|
| Property, plant, and equipment | 10,108 |
|
| Goodwill | 5,967 |
|
| Intangible assets | 400 |
|
| Regulatory assets | 1,118 |
|
| Other assets | 229 |
|
| Current liabilities | (2,201 | ) |
| Other liabilities | (4,742 | ) |
| Long-term debt | (4,261 | ) |
| Noncontrolling interest | (174 | ) |
| Total purchase price | $ | 8,001 |
|
The excess of the purchase price over the estimated fair values of the assets acquiredForm 10-K and liabilities assumed of $6.0 billion is recognized as goodwill, which is primarily attributable to positioning the Southern Company system to provide natural gas infrastructure to meet customers' growing energy needs and to compete for growth across the energy value chain. Southern Company anticipates that much of the value assigned to goodwill will not be deductible for tax purposes.
The valuation of identifiable intangible assets included customer relationships, trade names, and storage and transportation contracts with estimated lives of one to 28 years. The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3).
The results of operations for Southern Company Gas have been included in Southern Company's consolidated financial statements from the date of acquisition and consist of operating revenues of $565 million and $2.8 billion and net income of $15 million and $303 million for the three and nine months ended September 30, 2017, respectively, and operating revenues and net income of $543 million and $4 million, respectively, for the three months ended September 30, 2016.
The following summarized unaudited pro forma consolidated statement of earnings information assumes that the acquisition of Southern Company Gas was completed on JanuaryNote 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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | |
| | For the Nine Months Ended September 30, |
| | 2016 |
Operating revenues (in millions) | $ | 16,609 |
|
Net income attributable to Southern Company (in millions) | $ | 2,394 |
|
| Basic Earnings Per Share (EPS) | $ | 2.52 |
|
| Diluted EPS | $ | 2.51 |
|
These unaudited pro forma results are for comparative purposes only and may not be indicative of the results that would have occurred had this acquisition been completed on January 1, 2015 or the results that would be attained in the future.
Acquisition of PowerSecure
On May 9, 2016, Southern Company acquired all of the outstanding stock of PowerSecure, a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure, for $18.75 per common share in cash, resulting in an aggregate purchase price of $429 million. As a result, PowerSecure became a wholly-owned subsidiary of Southern Company.
The acquisition of PowerSecure was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value as of the acquisition date. The following table presents the final purchase price allocation:
|
| | | |
| PowerSecure Purchase Price | |
| | (in millions) |
| Current assets | $ | 172 |
|
| Property, plant, and equipment | 46 |
|
| Intangible assets | 106 |
|
| Goodwill | 284 |
|
| Other assets | 4 |
|
| Current liabilities | (121 | ) |
| Long-term debt, including current portion | (48 | ) |
| Deferred credits and other liabilities | (14 | ) |
| Total purchase price | $ | 429 |
|
The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $284 million was recognized as goodwill, which is primarily attributable to expected business expansion opportunities for PowerSecure. Southern Company anticipates that the majority of the value assigned to goodwill will not be deductible for tax purposes.
The valuation of identifiable intangible assets included customer relationships, trade names, patents, backlog, and software with estimated lives of one to 26 years. The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3).
The results of operations for PowerSecure have been included in Southern Company's consolidated financial statements from the date of acquisition and are immaterial to the consolidated financial results of Southern Company. Pro forma results of operations have not been presented for the acquisition because the effects of the acquisition were immaterial to Southern Company's consolidated financial results for all periods presented.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Southern Power
See Note 2 to the financial statements of Southern Powerunder "Financial Instruments" and Note 12Notes 13 and 14 to the financial statements of Southern Company under "Southern Power" in Item 8 of the Form 10-K, for additional information.
Acquisitions During the Nine Months Ended September 30, 2017
During the nine months ended September 30, 2017, in accordance with Southern Power's overall growth strategy, one of Southern Power's wholly-owned subsidiaries acquired the project discussed below. Acquisition-related costs were expensed as incurredwell as Notes (I) and were not material.
|
| | | | | | | | | |
| 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 |
The aggregate amounts of revenue and net income recognized by Southern Power related(J) to the Bethel facility included in Southern Power's 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 as though the acquisition occurred as of the beginning of 2017 and for the comparable 2016 period is not meaningful and has been omitted.
In connection with Southern Power's 2016 acquisitions, allocations of the purchase price to individual assets were finalized during the nine months ended September 30, 2017 with no changes to amounts originally reported for Boulder 1, Grant Plains, Grant Wind, Henrietta, Mankato, Passadumkeag, Salt Fork, Tyler Bluff, and Wake Wind.
Subsequent to September 30, 2017, Southern Power purchased all of the redeemable noncontrolling interests, representing 10% of the membership interests, in Southern Turner Renewable Energy, LLC and repaid $14 million of notes payable to Turner Renewable Energy, LLC.
Construction Projects Completed and in Progress
During the nine months ended September 30, 2017, in accordance with its overall growth strategy, Southern Power completed construction of and placed in service, or continued construction of, the projects set forth in the following table. Through September 30, 2017, total costs of construction incurred for these projects were $494 million, of which $122 million remained in CWIP. Total aggregate construction costs, excluding the acquisition costs, are expected to be between $360 million and $415 million for the Mankato and Cactus Flats facilities. The ultimate outcome of these matters cannot be determined at this time.
|
| | | | | |
Project Facility | Resource | Approximate Nameplate Capacity (MW)
| Location | Actual/Expected COD | PPA Contract Period |
Projects Completed During the Nine Months Ended September 30, 2017 |
East Pecos | Solar | 120 | Pecos County, TX | March 2017 | 15 years |
Lamesa | Solar | 102 | Dawson County, TX | April 2017 | 15 years |
| | | | | |
Projects Under Construction as of September 30, 2017 |
Cactus Flats(*)
| Wind | 148 | Concho County, TX | Third quarter 2018 | 12-15 years |
Mankato | Natural Gas | 345 | Mankato, MN | Second quarter 2019 | 20 years |
| |
(*) | On July 31, 2017, Southern Power acquired a 100% ownership interest in the Cactus Flats facility, which is in the early stages of construction, from RES America Developments, Inc. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Development Projects
In December 2016, as part of Southern Power's renewable development strategy, one of Southern Power's wholly-owned subsidiaries 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.Condensed Financial Statements herein.
Southern Company Gas
On October 15, 2017, Southern Company Gas subsidiary, Pivotal Utility Holdings, entered into agreements for the sale of the assets of two of its natural gas distribution utilities, Elizabethtown GasItem 4. Controls and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion. The completion of each sale is subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act; (ii) the receipt of required regulatory approvals, including the FERC, the Federal Communications Commission, the New Jersey BPU, and, with respect to the sale of Elkton Gas, the Maryland PSC; and (iii) other customary closing conditions. The sales are expected to be completed by the end of the third quarter 2018.
The ultimate outcome of these matters cannot be determined at this time.
| |
(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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Equity Method Investments
The carrying amounts of Southern Company Gas' equity method investments as of September 30, 2017 and December 31, 2016 and related income from those investments for the successor three and nine month periods ended September 30, 2017, the successor three-month period ended September 30, 2016, and for the predecessor period January 1, 2016 through June 30, 2016 were as follows:
|
| | | | | | |
| Balance Sheet Information | September 30, 2017 | December 31, 2016 |
| | (in millions) |
| SNG | $ | 1,385 |
| $ | 1,394 |
|
| Atlantic Coast Pipeline | 61 |
| 33 |
|
| PennEast Pipeline | 49 |
| 22 |
|
| Triton | 43 |
| 44 |
|
| Pivotal JAX LNG, LLC | 40 |
| 16 |
|
| Horizon Pipeline | 30 |
| 30 |
|
| Other | 1 |
| 2 |
|
| Total | $ | 1,609 |
| $ | 1,541 |
|
|
| | | | | | | | | | | | |
| | Successor | Successor | Successor | Predecessor |
| Income Statement Information | Three Months Ended September 30, 2017 | Three Months Ended September 30, 2016 | Nine Months Ended September 30, 2017 | January 1, 2016 through June 30, 2016 |
| | (in millions) | (in millions) | (in millions) | (in millions) |
| SNG | $ | 28 |
| $ | 27 |
| $ | 86 |
| $ | — |
|
| PennEast Pipeline | 1 |
| — |
| 5 |
| — |
|
| Atlantic Coast Pipeline | 1 |
| 1 |
| 4 |
| — |
|
| Triton | 1 |
| 1 |
| 3 |
| 1 |
|
| Horizon Pipeline | 1 |
| — |
| 2 |
| 1 |
|
| Total | $ | 32 |
| $ | 29 |
| $ | 100 |
| $ | 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 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 nine months ended September 30, 2017 and for the period September 1, 2016 through September 30, 2016 is as follows:
|
| | | | | | | | | |
| Income Statement Information | Three Months Ended September 30, 2017 | Nine Months Ended September 30, 2017 | September 1, 2016 through September 30, 2016 |
| | (in millions) |
| Revenues | $ | 146 |
| $ | 445 |
| $ | 82 |
|
| Operating income | $ | 71 |
| $ | 218 |
| $ | 60 |
|
| Net income | $ | 57 |
| $ | 172 |
| $ | 55 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
(K) SEGMENT AND RELATED INFORMATION
Southern Company
The primary businesses of the Southern Company system are electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas by Southern Company Gas. The four traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through the 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 $105 million and $295 million for the three and nine months ended September 30, 2017, respectively, and $110 million and $313 million for the three and nine months ended September 30, 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 providing energy technologies and services to electric utilities and large industrial, commercial, institutional, and municipal customers; as well as investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Financial data for business segments and products and services for the three and nine months ended September 30, 2017 and 2016 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, 2017: | | | | | | | | |
| Operating revenues | $ | 5,017 |
| $ | 618 |
| $ | (112 | ) | $ | 5,523 |
| $ | 565 |
| $ | 153 |
| $ | (40 | ) | $ | 6,201 |
|
Segment net income (loss)(a)(b) | 1,008 |
| 124 |
| — |
| 1,132 |
| 15 |
| (80 | ) | 2 |
| 1,069 |
|
Nine Months Ended
September 30, 2017: | | | | |
|
| | | |
| Operating revenues | $ | 12,960 |
| $ | 1,597 |
| $ | (318 | ) | $ | 14,239 |
| $ | 2,841 |
| $ | 442 |
| $ | (119 | ) | $ | 17,403 |
|
Segment net income (loss)(a)(b)(c) | — |
| 276 |
| — |
| 276 |
| 303 |
| (232 | ) | — |
| 347 |
|
| Total assets at September 30, 2017 | $ | 73,056 |
| $ | 14,648 |
| $ | (322 | ) | $ | 87,382 |
| $ | 22,190 |
| $ | 2,275 |
| $ | (1,532 | ) | $ | 110,315 |
|
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) | 1,022 |
| 176 |
| — |
| 1,198 |
| 4 |
| (62 | ) | (1 | ) | 1,139 |
|
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)(b) | 2,086 |
| 315 |
| — |
| 2,401 |
| 4 |
| (146 | ) | (8 | ) | 2,251 |
|
| 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.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, 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) | Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated probable losses on the Kemper IGCC of $34 million ($21 million after tax) and $88 million ($54 million after tax) for the three months ended September 30, 2017 and 2016, respectively, and $3.2 billion ($2.2 billion after tax) and $222 million ($137 million after tax) for the nine months ended September 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 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 nine months ended September 30, 2017. See Note (B) under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" for additional information.
Changes in internal controls over financial reporting. |
ProductsThere have been no changes in Southern Company's, Alabama Power's, Georgia 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 Services
|
| | | | | | | | | | | | | | | | |
| | | Electric Utilities' Revenues |
| Period | | Retail | | Wholesale | | Other | | Total |
| | | (in millions) |
| Three Months Ended September 30, 2017 | | $ | 4,615 |
| | $ | 718 |
| | $ | 190 |
| | $ | 5,523 |
|
| Three Months Ended September 30, 2016 | | 4,808 |
| | 613 |
| | 198 |
| | 5,619 |
|
| | | | | | | | | |
| Nine Months Ended September 30, 2017 | | $ | 11,786 |
| | $ | 1,867 |
| | $ | 586 |
| | $ | 14,239 |
|
| Nine Months Ended September 30, 2016 | | 11,932 |
| | 1,455 |
| | 592 |
| | 13,979 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | |
| | Southern Company Gas' Revenues |
| Period | Gas
Distribution
Operations | Gas
Marketing
Services | Other | Total |
| | (in millions) |
| Three Months Ended September 30, 2017 | $ | 430 |
| $ | 143 |
| $ | (8 | ) | $ | 565 |
|
| Nine Months Ended September 30, 2017 | $ | 2,119 |
| $ | 597 |
| $ | 125 |
| $ | 2,841 |
|
| Three and Nine Months Ended September 30, 2016 | $ | 420 |
| $ | 126 |
| $ | (3 | ) | $ | 543 |
|
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.
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 months ended September 30, 2017 and 2016, the successor nine months ended September 30, 2017, the successor period of July 1, 2016 through September 30, 2016, and the predecessor period of January 1, 2016 through 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 September 30, 2017: | | | | | | |
| Operating revenues | $ | 472 |
| $ | 143 |
| $ | (24 | ) | $ | 16 |
| $ | 607 |
| $ | 2 |
| $ | (44 | ) | $ | 565 |
|
| Segment net income | 52 |
| 1 |
| (23 | ) | 14 |
| 44 |
| (29 | ) | — |
| 15 |
|
| Successor – Nine Months Ended September 30, 2017: | | | | | | |
| Operating revenues | $ | 2,255 |
| $ | 597 |
| $ | 95 |
| $ | 53 |
| $ | 3,000 |
| $ | 7 |
| $ | (166 | ) | $ | 2,841 |
|
| Segment net income | 223 |
| 36 |
| 28 |
| 38 |
| 325 |
| (22 | ) | — |
| 303 |
|
Successor – Total assets at
September 30, 2017 | $ | 18,711 |
| $ | 2,089 |
| $ | 893 |
| $ | 2,359 |
| $ | 24,052 |
| $ | 11,400 |
| $ | (13,262 | ) | $ | 22,190 |
|
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) |
| Successor – Three Months Ended September 30, 2016: | | | | | | |
| Operating revenues | $ | 455 |
| $ | 126 |
| $ | (8 | ) | $ | 13 |
| $ | 586 |
| $ | 2 |
| $ | (45 | ) | $ | 543 |
|
| Segment net income (loss) | 27 |
| (4 | ) | (11 | ) | 14 |
| 26 |
| (22 | ) | — |
| 4 |
|
| Predecessor – January 1, 2016 through 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 September 30, 2017 | $ | 1,411 |
| | $ | 103 |
| | $ | 1,514 |
| | $ | 1,538 |
| | $ | (24 | ) |
| Successor – Nine Months Ended September 30, 2017 | 4,781 |
| | 362 |
| | 5,143 |
| | 5,048 |
| | 95 |
|
| Successor – Three Months Ended September 30, 2016 | 1,688 |
| | 77 |
| | 1,765 |
| | 1,773 |
| | (8 | ) |
| Predecessor – January 1, 2016 through 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 registrantsRegistrants 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.Registrants. Except as described below, there have been no material changes to these risk factors from those previously disclosed in the Form 10-K.
The 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 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. The Interim Assessment Agreement, as amended, expired on July 27, 2017.
Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor, including Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, 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 September 30, 2017, of the Vogtle Owners for the removal of subcontractor liens and payment of other EPC Contractor pre-petition accounts payable to total approximately $386 million, of which $340 million had been paid or accrued as of September 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $176 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 CreditRegistrants 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 June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement). Pursuantrisks related 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, which will reduce CWIP, beginning in October 2017 and continuing through January 2021. In the event Toshiba receives certain payments,COVID-19 pandemic, including, sale proceeds, from or relatedbut not limited 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 October 2, 2017, Georgia Power received the first installment of the Guarantee Obligations of $300 million from Toshiba, of which Georgia Power's proportionate share was $137 million. Georgia Power is considering potential options with respect to its right to future payments under the Guarantee Settlement Agreement and its claims against the EPC Contractor in the EPC Contractor's bankruptcy proceeding, including a potential sale of those payment rights and bankruptcy claims. Any such transaction cannot be assured and would be subject to DOE consents and related approvals under the Loan Guarantee Agreement and related agreements.
On August 10, 2017, Toshiba released its financial results for the quarter ended June 30, 2017, which reflected a negative shareholders' equity balance of approximately $4.5 billion as of June 30, 2017. Toshiba previously 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.
Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement (Bechtel Agreement) with Bechtel Power Corporation (Bechtel), whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4. Facility design and engineering remains the responsibility of the EPC Contractor under the Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its
ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. Pursuant to the Loan Guarantee Agreement, Georgia Power is required to obtain the DOE's approval of the Bechtel Agreement prior to obtaining any further advances under the Loan Guarantee Agreement.
In connection with the recommendation to continue with construction of Plant Vogtle Units 3 and 4 (described below), the Vogtle Owners agreed on a term sheet to amend the existing joint ownership agreements to provide for additional Vogtle Owner approval requirements. Under the term sheet, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including (i) the bankruptcy of Toshiba or a material breach by Toshiba of the Guarantee Settlement Agreement; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC determines that any of Georgia Power's costs relatingdisruption to the construction of Plant Vogtle Units 3 and 4 for Southern Company and Georgia Power.
COVID-19 has been declared a pandemic by the World Health Organization and the Centers for Disease Control and Prevention and has spread globally, including throughout the United States. In response, most jurisdictions, including in the United States, have instituted restrictions on travel, public gatherings, and non-essential business operations. While some jurisdictions, including some in the Southern Company system's service territory, have begun to relax these restrictions, many of these restrictions remain and there is no guarantee restrictions will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increasereimposed in the construction budget containedfuture. These restrictions have significantly disrupted economic activity in the seventeenth Vogtle Construction Monitoring (VCM) report by more than $1 billion or extensionservice territories of the project schedule containedtraditional electric operating companies and the natural gas distribution utilities and caused volatility in capital markets at certain periods during 2020. For example, retail electric revenues attributable to changes in sales decreased 3.0% in the seventeenth VCM report by more than one year.second quarter 2020 as compared to the corresponding period in 2019, as discussed further in RESULTS OF OPERATIONS – "Southern Company – Retail Electric Revenues" in Item 2 herein. In addition, under the term sheet,traditional electric operating companies and the required approvalnatural gas distribution utilities temporarily suspended disconnections for non-payment by customers and waived late fees for certain periods. The U.S. House of holdersRepresentatives has passed the Heroes Act, which would prohibit creditors, including utilities, from collecting consumer debts that are or become past-due, imposing late fees, or disconnecting customers for nonpayment. If the Heroes Act becomes law, its restrictions would apply until 120 days after the end of ownership intereststhe presidential declared emergency related to the COVID-19 pandemic. The effects of the continued COVID-19 pandemic and related responses could include extended disruptions to supply chains and capital markets, further reduced labor availability and productivity, and a prolonged reduction in economic activity. These effects could have a variety of adverse impacts on the Registrants, including continued reduced demand for energy, particularly from commercial and industrial customers, reduced cash flows and liquidity, impairment of goodwill or long-lived assets, reductions in investments recorded at fair value, and further impairment of the ability of the Registrants to develop, construct, and operate facilities, including electric generation, transmission, and distribution assets, to perform necessary corporate and customer service functions, and to access funds from financial institutions and capital markets. In addition, the COVID-19 pandemic could cause delays or cancellations to regulatory proceedings.
Further, the effects of the COVID-19 pandemic could further disrupt or delay construction, testing, supervisory, and support activities at Plant Vogtle Units 3 and 4. In mid-March 2020, Southern Nuclear began implementing policies and procedures designed to mitigate the risk of transmission of COVID-19 at the construction site, including worker distancing measures, isolating individuals who have tested positive for COVID-19, are showing symptoms consistent with COVID-19, are being tested for COVID-19, or have been in close contact with such persons, requiring self-quarantine, and adopting additional precautionary measures. In April 2020, Georgia Power announced a reduction in workforce at Plant Vogtle Units 3 and 4, is at least (i) 90% for a changewhich totaled approximately 20% of the primary construction contractor and (ii) 67% for material amendmentsthen-existing workforce. This reduction in workforce was a mitigation action intended to address the Services Agreement or agreements withimpact of the primary construction contractor or Southern Nuclear.
The term sheet also confirms thatCOVID-19 pandemic on the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.
In the seventeenth VCM report, Georgia Power recommended that construction of Plant Vogtle Units 3 and 4 be continued,workforce and construction site, including challenges with Southernlabor productivity that were exacerbated by the impact of the COVID-19 pandemic. The April 2020 workforce reduction was intended to provide operational efficiencies by increasing productivity of the remaining workforce and reducing workforce fatigue and absenteeism. Further, it was also intended to allow for increased social distancing by the workforce and facilitate compliance with the recommendations from the Centers for Disease Control and Prevention. The April 2020 workforce reduction did reduce absenteeism, providing an improvement in operational efficiency and allowing for increased social distancing. From the initial peak in April 2020, the number of active
cases at the site declined significantly during May and early June, but began increasing again in mid-June and continues to impact productivity levels and pace of activity completion. As a result of these factors, overall production improvements have not been achieved at the levels anticipated, contributing to the allocation of, and increase in, construction contingency described in Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear serving as project manager. Georgia Power believes that the most reasonable schedule for completing Plant Vogtle Units 3 and 4 is by November 2021 for Unit 3 and by November 2022 for Unit 4.Construction" herein. Georgia Power's recommendationproportionate share of the estimated incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is currently estimated to go forward with completionbe between $70 million and $115 million, which is included in the total project capital cost forecast and assumes (i) absenteeism rates continue to normalize and (ii) the intended productivity efficiencies and production targets assumed in Southern Nuclear's July 2020 aggressive site work plan are realized in the coming months. However, the ultimate impact of Vogtle Units 3 and 4 is basedthe COVID-19 pandemic on the following assumptions about the regulatory treatment of this recommendation, if the recommendation to go forward is adopted by the Georgia PSC: (i) that pursuant to Georgia law, the Georgia PSC in the seventeenth VCM proceeding approves the new costconstruction schedule and schedule forecast and finds that it is a reasonable basis for going forward, and that if the Georgia PSC disapproves all or part of the proposed cost and schedule revisions, Georgia Power may cancel Plant Vogtle Units 3 and 4 and recover its actual investment in Plant Vogtle Units 3 and 4; (ii) that the Vogtle Cost Settlement Agreement remains in full force and effect, including Georgia Power retaining the burden of proving all capital costs above $5.680 billion were prudent; (iii) that while the Georgia PSC will make no prudence finding in the seventeenth VCM proceeding, nor will the certified amount be amended consistent with the Vogtle Cost Settlement Agreement, the Georgia PSC recognizes that the certified amount is not a cap, and all costs that are approved and presumed or shown to be prudently incurred will be recoverable by Georgia Power; (iv) that Georgia Power is not a guarantor of the Toshiba Guarantee, and the failure of Toshiba to pay the Toshiba Guarantee, the failure of the U.S. Congress to extend the PTCsbudget for Plant Vogtle Units 3 and 4 or the failure of the DOE to extend the Loan Guarantee Agreement with Georgia Power to reflect the increased capital amounts, will not reduce the amount of investment Georgia Power is otherwise allowed to collect; and (v) that as conditions change and assumptions are either proven or disproven, Georgia Power and the Georgia PSC may reconsider the decision to go forward. The Georgia PSC is expected to make a decision on these matters by February 6, 2018.
Georgia Power's approximate proportionate share of the remaining estimated cost to complete Plant Vogtle Units 3 and 4 is as follows:
|
| | | |
| | (in billions) |
| Estimated cost to complete | $ | 4.2 |
|
| CWIP as of September 30, 2017 | 4.6 |
|
| Guarantee Obligations | (1.7 | ) |
| Estimated capital costs | $ | 7.1 |
|
| Vogtle Cost Settlement Agreement Revised Forecast | (5.7 | ) |
| Estimated net additional capital costs | $ | 1.4 |
|
Georgia Power's estimated financing costs during the construction period total approximately $3.4 billion, of which approximately $1.5 billion had been incurred through September 30, 2017.
Georgia Power's cancellation cost estimate results indicate that its proportionate share of the estimated costs to cancel both units is approximately $350 million. As a result, as of September 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:
|
| | | |
| | Cancellation Cost Estimate |
| | (in billions) |
| CWIP as of September 30, 2017 | $ | 4.6 |
|
| Financing costs collected, net of tax | 1.5 |
|
Cancellation costs(*) | 0.4 |
|
| Guarantee Obligations | (1.7 | ) |
| Estimated net cancellation cost | $ | 4.8 |
|
| |
(*) | 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.
The ultimate outcome of these matters cannot be 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 |
| | | | | |
| | | AlabamaMississippi Power |
| | | | | |
| | * | (b)(d)1 | - | |
| | | | |
|
| | | | |
| | (4) Instruments Describing Rights of Security Holders, Including Indentures |
| | | | |
| | Georgia Power |
| | | | |
| | (c)1 | - | |
| | | | | |
| | * | (c)(d)2 | - | Subordinated Note Indenture, datedBylaws of Mississippi Power as of September 1, 2017, between Georgia Poweramended effective July 22, 2020, and Wells Fargo Bank, National Association, as Trustee, and First Supplemental Indenture thereto dated as of September 21, 2017. (Designatedpresently in Form 8-K dated September 18, 2017, File No. 1-6468, as Exhibit 4.3 and in Form 8-K dated September 18, 2017, File No. 1-6468, as Exhibit 4.4.) |
| | | | |
| | (c)3 | - | |
| | | | | |
| | | (10) Material Contracts |
| | | | | |
| | | MississippiAlabama Power |
| | | | | |
| # | * | (e)1(b) | - | |
| | | | |
| | Southern Company Gas |
| | | | |
| | (g)1 | - | Asset Purchase Agreement, dated as of October 15, 2017, by and between Pivotal Utility Holdings, Inc., as Seller, and South Jersey Industries, Inc., as Buyer. (Designated in Form 8-K dated October 15, 2017, File No. 1-14174, as Exhibit 10.1.)Gregory J. Barker effective June 8, 2020. |
| | | | | |
| | | (24) Power of Attorney and Resolutions |
| | | | | |
| | | Southern Company |
| | | | | |
| | | (a) | - | |
| | | | | |
| | | Alabama Power |
| | | | | |
| | | (b) | - | |
| | | | | |
| | | Georgia Power |
| | | | | |
| | | (c)1 | - | |
| | | | |
| * | (c)2 | - | |
| | | | |
| | Gulf Power |
| | | | |
| | (d)1 | - | |
| | | | |
| * | (d)2 | - | |
| | | | | |
| | | Mississippi Power |
| | | | | |
| | | (e)(d) | - | |
| | | | | |
|
| | | | |
| | | Southern Power |
| | | | | |
| | | (f)(e)1 | - | |
| | | | | |
| * | (e)2 | - | |
| | | | |
|
| | | | |
| | | Southern Company Gas |
| | | | | |
| | | (g)(f) | - | |
| | | | | |
| | | (31) Section 302 Certifications |
| | | | | |
| | | Southern Company |
| | | | | |
| | * | (a)1 | - | |
| | | | | |
| | * | (a)2 | - | |
| | | | | |
| | | Alabama Power |
| | | | | |
| | * | (b)1 | - | |
| | | | | |
| | * | (b)2 | - | |
| | | | | |
| | | Georgia Power |
| | | | | |
| | * | (c)1 | - | |
| | | | | |
| | * | (c)2 | - | |
| | | | |
| | Gulf Power |
| | | | |
| * | (d)1 | - | |
| | | | |
| * | (d)2 | - | |
| | | | | |
| | | Mississippi Power |
| | | | | |
| | * | (e)(d)1 | - | |
| | | | | |
| | * | (e)(d)2 | - | |
| | | | | |
| | | Southern Power |
| | | | | |
| | * | (f)(e)1 | - | |
| | | | | |
| | * | (f)(e)2 | - | |
| | | | | |
|
| | | | |
| | | Southern Company Gas |
| | | | | |
| | * | (g)(f)1 | - | |
| | | | | |
| | * | (g)(f)2 | - | |
| | | | | |
| | | (32) Section 906 Certifications |
| | | | | |
| | | Southern Company |
| | | | | |
| | * | (a) | - | |
| | | | | |
| | | Alabama Power |
| | | | | |
| | * | (b) | - | |
| | | | | |
|
| | | | |
| | | Georgia Power |
| | | | | |
| | * | (c) | - | |
| | | | |
| | Gulf Power |
| | | | |
| * | (d) | - | |
| | | | | |
| | | Mississippi Power |
| | | | | |
| | * | (e)(d) | - | |
| | | | | |
| | | Southern Power |
| | | | | |
| | * | (f)(e) | - | |
| | | | | |
| | | Southern Company Gas |
| | | | | |
| | * | (g)(f) | - | |
| | | | | |
| | | (101) Interactive Data Files |
| | | | | |
| | * | INS | - | XBRL Instance Document – The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL 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 |
| | | | |
| | (104) Cover Page Interactive Data File |
| * | | | Formatted as inline XBRL with applicable taxonomy extension information contained in Exhibits 101. |
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. BeattieAndrew W. Evans |
| | | Executive Vice President and Chief Financial Officer |
| | | (Principal Financial Officer) |
| | | | |
| By | | /s/ Melissa K. Caen | |
| | | (Melissa K. Caen, Attorney-in-fact) | |
Date: October 31, 2017July 29, 2020
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: October 31, 2017July 29, 2020
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 | | Xia LiuDavid P. Poroch |
| | | Executive Vice President, Chief Financial Officer, Treasurer, and TreasurerComptroller |
| | | (Principal Financial Officer) |
| | | | |
| By | | /s/ Melissa K. Caen | |
| | | (Melissa K. Caen, Attorney-in-fact) | |
Date: October 31, 2017July 29, 2020
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 | | Robin B. Boren |
| | Vice President, Chief Financial Officer, and Treasurer |
| | (Principal Financial Officer) |
| | | |
By | | /s/ Melissa K. Caen | |
| | (Melissa K. Caen, Attorney-in-fact) | |
Date: October 31, 2017
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 |
| | | Senior Vice President, Chief Financial Officer, and Treasurer |
| | | (Principal Financial Officer) |
| | | | |
| By | | /s/ Melissa K. Caen | |
| | | (Melissa K. Caen, Attorney-in-fact) | |
Date: October 31, 2017July 29, 2020
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. MillerChristopher Cummiskey |
| | | Chairman, President, and Chief Executive Officer |
| | | (Principal Executive Officer) |
| | | | |
| By | | William C. GranthamElliott L. Spencer |
| | | Senior Vice President, Chief Financial Officer, and Treasurer |
| | | (Principal Financial Officer) |
| | | | |
| By | | /s/ Melissa K. Caen | |
| | | (Melissa K. Caen, Attorney-in-fact) | |
Date: October 31, 2017July 29, 2020
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. EvansKimberly S. Greene |
| | | Chairman, President, and Chief Executive Officer |
| | | (Principal Executive Officer) |
| | | | |
| By | | Elizabeth W. ReeseDaniel S. Tucker |
| | | Executive Vice President, Chief Financial Officer, and Treasurer |
| | | (Principal Financial Officer) |
| | | | |
| By | | /s/ Melissa K. Caen | |
| | | (Melissa K. Caen, Attorney-in-fact) | |
Date: October 31, 2017July 29, 2020