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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, 20172019
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 |
| | | | |
(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 | | |
| | | | | |
| 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 |
| 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, 20172019 |
|
| The Southern Company | | Par Value $5 Per Share | 1,045,231,646 | 1,003,627,691 |
|
| Alabama Power Company | | Par Value $40 Per Share | | 30,537,500 |
|
| Georgia Power Company | | Without Par Value | | 9,261,500 |
|
Gulf Power Company | | Without Par Value | | 7,392,717 |
|
| Mississippi Power Company | | Without Par Value | | 1,121,000 |
|
| Southern Power Company | | Par Value $0.01 Per Share | | 1,000 |
|
| Southern Company Gas | | Par Value $0.01 Per Share | | 100 |
|
This combined Form 10-Q is separately filed by The Southern Company, Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, Southern Power Company, and Southern Company Gas. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.
INDEX TO QUARTERLY REPORT ON FORM 10-Q
SeptemberJune 30, 20172019
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| | PART I—FINANCIAL INFORMATION | |
| Item 1. | Financial Statements (Unaudited) | |
| Item 2. | Management's Discussion and Analysis of Financial Condition and Results of Operations | |
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INDEX TO QUARTERLY REPORT ON FORM 10-Q
SeptemberJune 30, 20172019
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| | | Page
Number |
| | PART I—FINANCIAL INFORMATION (CONTINUED) | |
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| Item 3. | | |
| Item 4. | | |
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| | PART II—OTHER INFORMATION | |
| 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. | | |
| | | |
|
| |
| Term | Meaning |
| |
2012 MPSC CPCN Order | A detailed order issued by the Mississippi PSC in April 2012 confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC |
| 2013 ARP | Alternative Rate Plan approved by the Georgia PSC in 2013 for Georgia Power for the years 2014 through 2016 and subsequently extended through 2019 |
| AFUDC | Allowance for funds used during construction |
| Alabama Power | Alabama Power Company |
| Amended and Restated Loan Guarantee Agreement | Loan guarantee agreement entered into by Georgia Power with the DOE in 2014, as amended and restated on March 22, 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 |
| ASC | Accounting Standards Codification |
| 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 has a 5% ownership interest |
Baseload ActBechtel | State of Mississippi legislation designed to enhanceBechtel Power Corporation, the Mississippi PSC's authority to facilitate developmentprimary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4 |
| Bechtel Agreement | The October 23, 2017 construction of baseload generation incompletion 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
|
| Chattanooga Gas | Chattanooga Gas Company, a wholly-owned subsidiary of Southern Company Gas |
CO2 | Carbon dioxide |
| 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 Energy | Electric cooperative in Mississippi formerly known as South Mississippi Electric Power Association (SMEPA) |
CPCNCPP | Certificate of public convenience and necessityClean Power Plan, the final action published by the EPA in 2015 that established guidelines for states to develop plans to meet EPA-mandated CO2 emission rates or emission reduction goals for existing electric generating units |
| Customer Refunds | Refunds issued to Georgia Power customers in 2018 as ordered by the Georgia PSC related to the Guarantee Settlement Agreement |
| 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 |
| DSGP | Diamond State Generation Partners |
| 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 |
|
| |
| 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, 2016,2018, as applicable |
| GAAP | U.S. generally accepted accounting principles |
| Georgia Power | Georgia Power Company |
| GHG | Greenhouse gas |
| 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 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 (Plant Ratcliffe) |
| IIC | Intercompany interchange contractInterchange Contract |
| Illinois Commission | Illinois Commerce Commission the state regulatory agency for Nicor Gas |
IRCITAAC | Internal Revenue Code of 1986, as amended |
IRS | Internal Revenue ServiceInspections, Tests, Analyses, and Acceptance Criteria, standards established by the NRC |
| 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 ruleMEAG | Mercury and Air Toxics Standards rule |
Merger | 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, Chattanooga Gas, Company, and Elkton Gas)Gas as of June 30, 2018) (Nicor Gas, Atlanta Gas Light, Virginia Natural Gas, and Chattanooga Gas as of July 29, 2018) |
| NCCR | Georgia Power's Nuclear Construction Cost Recovery |
New Jersey BPUNextEra Energy | New Jersey Board of Public Utilities, the state regulatory agency for Elizabethtown GasNextEra 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. |
| OATT | Open access transmission tariff |
| 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 |
| Term | Meaning |
| Pivotal Home Solutions | Nicor Energy Services Company, until June 4, 2018 a wholly-owned subsidiary of Southern Company Gas, Company, Inc.doing business as Pivotal Home Solutions |
| Pivotal Utility Holdings | Pivotal Utility Holdings, Inc., until July 29, 2018 a wholly-owned subsidiary of Southern Company Gas, doing business as Elizabethtown Gas (until July 1, 2018), Elkton Gas (until July 1, 2018), 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 |
DEFINITIONS
(continued)
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| |
Term | Meaning |
| |
| 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 |
| Rate CNP Compliance | Alabama Power's Rate Certificated New Plant Compliance |
| Rate CNP PPA | Alabama Power's Rate Certificated New Plant Power Purchase Agreement |
| Rate ECR | Alabama Power's Rate Energy Cost Recovery |
| Rate NDR | Alabama Power's Rate Natural Disaster Reserve |
| Rate RSE | Alabama Power's Rate Stabilization and Equalization plan |
| registrants | Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power Company, and Southern Company Gas |
| revenue from contracts with customers | Revenue from contracts accounted for under the guidance of ASC 606, Revenue from Contracts with Customers |
| ROE | Return on equity |
| S&P | S&P Global Ratings, a division of S&P Global Inc. |
scrubber | Flue gas desulfurization system |
| SCS | Southern Company Services, Inc. (the Southern Company system service company) |
| SEC | U.S. Securities and Exchange Commission |
| SNG | Southern Natural Gas Company, L.L.C. |
| 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 Gas Dispositions | Southern Company Gas' disposition of Pivotal Home Solutions, Pivotal Utility Holdings' disposition of Elizabethtown Gas and Elkton Gas, and NUI Corporation's disposition of Pivotal Utility Holdings, which primarily consisted of Florida City Gas |
| Southern Company system | Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas, (as of July 1, 2016), Southern Electric Generating Company, Southern Nuclear, SCS, Southern Communications Services, Inc., PowerSecure, (as of May 9, 2016), and other subsidiaries |
| Southern Nuclear | Southern Nuclear Operating Company, Inc. |
| Southern Power | Southern Power Company and its subsidiaries |
SouthStarSP Solar | SouthStar Energy Services,SP Solar Holdings I, LP |
| SP Wind | SP Wind Holdings II, LLC |
STRIDETax Reform Legislation | Atlanta Gas Light's Strategic Infrastructure DevelopmentThe 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 through December 31, 2018; Alabama Power, Georgia Power, and Mississippi Power as of January 1, 2019 |
| Triton | Triton Container Investments, LLC |
| VCM | Vogtle Construction Monitoring |
|
| |
| Term | Meaning |
| 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 |
| 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, and Dalton |
| Vogtle Services Agreement | The June 9, 2017 services agreement between the Municipal Electric Authority of Georgia,Vogtle Owners and the CityEPC Contractor, as amended and restated on July 20, 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 |
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION8
This Quarterly Report on Form 10-Q contains forward-looking statements. Forward-looking statements include, among other things, statements concerning regulated rates, the strategic goals for the wholesale business, customer and sales growth, economic conditions, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sourcesTable 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:Contents
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, 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 of construction projects, matters related to the abandonment of the Kemper IGCC, completion of announced dispositions, 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 and environmental laws and regulations 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 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, including Plant Vogtle Units 3 and 4, which includes components based on new technology that only recently 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, subcontractors, or vendors; adverse weather conditions; shortages, delays, increased costs, or inconsistent quality of equipment, materials, and labor; contractor or supplier delay; 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 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, system integration, or regional transmission upgrades; and/or operational performance;
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;
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 ROE, equity ratios, and fuel and other cost recovery mechanisms;
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
(continued)
actions related to cost recovery for the Kemper IGCC, including ongoing settlement discussions, Mississippi PSC review of the prudence of Kemper IGCC costs and approval of further permanent rate recovery plans, and related legal or regulatory proceedings;
the ability to successfully operate the electric utilities' generating, transmission, and distribution facilities and Southern Company Gas' natural gas distribution and storage facilities and the successful performance of necessary corporate functions;
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;
in the event Georgia Power becomes obligated to provide funding to MEAG with respect to the portion of MEAG's ownership interest in Plant Vogtle Units 3 and 4 involving JEA, any inability of Georgia Power to receive repayment of such funding;
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,Plant Mankato, 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;
the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general, as well as potential impacts on the benefits of the DOE loan guarantees;ratings;
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 registrants from time to time with the SEC.
The registrants expressly disclaim any obligation to update any forward-looking statements.
THE SOUTHERN COMPANY
AND SUBSIDIARY COMPANIES
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
| | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | For the Three Months
Ended June 30, | | For the Six Months
Ended June 30, |
| | 2017 | | 2016 | | 2017 | | 2016 | 2019 | | 2018 | | 2019 | | 2018 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | | | | | | | | |
| Retail electric revenues | $ | 4,615 |
| | $ | 4,808 |
| | $ | 11,786 |
| | $ | 11,932 |
| $ | 3,540 |
| | $ | 3,740 |
| | $ | 6,623 |
| | $ | 7,308 |
|
| Wholesale electric revenues | 718 |
| | 613 |
| | 1,867 |
| | 1,455 |
| 542 |
| | 616 |
| | 1,041 |
| | 1,239 |
|
| Other electric revenues | 168 |
| | 181 |
| | 510 |
| | 529 |
| 161 |
| | 170 |
| | 331 |
| | 330 |
|
| Natural gas revenues | 532 |
| | 518 |
| | 2,746 |
| | 518 |
| |
Natural gas revenues (includes alternative revenue programs of
$1, $(4), $-, and $(27), respectively) | | 689 |
| | 706 |
| | 2,163 |
| | 2,314 |
|
| Other revenues | 168 |
| | 144 |
| | 494 |
| | 281 |
| 166 |
| | 395 |
| | 352 |
| | 808 |
|
| Total operating revenues | 6,201 |
| | 6,264 |
| | 17,403 |
| | 14,715 |
| 5,098 |
| | 5,627 |
| | 10,510 |
| | 11,999 |
|
| Operating Expenses: | | | | | | | | | | | | | | |
| Fuel | 1,285 |
| | 1,400 |
| | 3,372 |
| | 3,334 |
| 914 |
| | 1,103 |
| | 1,764 |
| | 2,204 |
|
| Purchased power | 256 |
| | 227 |
| | 646 |
| | 581 |
| 201 |
| | 236 |
| | 371 |
| | 503 |
|
| Cost of natural gas | 134 |
| | 133 |
| | 1,085 |
| | 133 |
| 191 |
| | 228 |
| | 877 |
| | 949 |
|
| Cost of other sales | 90 |
| | 84 |
| | 293 |
| | 161 |
| 84 |
| | 279 |
| | 203 |
| | 568 |
|
| Other operations and maintenance | 1,287 |
| | 1,411 |
| | 3,918 |
| | 3,616 |
| 1,316 |
| | 1,523 |
| | 2,628 |
| | 2,972 |
|
| Depreciation and amortization | 767 |
| | 695 |
| | 2,236 |
| | 1,805 |
| 755 |
| | 783 |
| | 1,506 |
| | 1,552 |
|
| Taxes other than income taxes | 303 |
| | 309 |
| | 941 |
| | 821 |
| 299 |
| | 316 |
| | 628 |
| | 671 |
|
| Estimated loss on Kemper IGCC | 34 |
| | 88 |
| | 3,155 |
| | 222 |
| |
| Estimated loss on plants under construction | | 4 |
| | 1,060 |
| | 6 |
| | 1,105 |
|
| (Gain) loss on dispositions, net | | (8 | ) | | 36 |
| | (2,506 | ) | | 36 |
|
| Total operating expenses | 4,156 |
| | 4,347 |
| | 15,646 |
| | 10,673 |
| 3,756 |
| | 5,564 |
| | 5,477 |
| | 10,560 |
|
| Operating Income | 2,045 |
| | 1,917 |
| | 1,757 |
| | 4,042 |
| 1,342 |
| | 63 |
| | 5,033 |
| | 1,439 |
|
| Other Income and (Expense): | | | | | | | | | | | | | | |
| Allowance for equity funds used during construction | 18 |
| | 52 |
| | 133 |
| | 150 |
| 31 |
| | 32 |
| | 63 |
| | 63 |
|
| Earnings from equity method investments | 32 |
| | 29 |
| | 100 |
| | 28 |
| 33 |
| | 31 |
| | 81 |
| | 72 |
|
| Interest expense, net of amounts capitalized | (407 | ) | | (374 | ) | | (1,248 | ) | | (913 | ) | (429 | ) | | (470 | ) | | (859 | ) | | (928 | ) |
| Other income (expense), net | 11 |
| | (8 | ) | | 2 |
| | (66 | ) | 99 |
| | 78 |
| | 176 |
| | 138 |
|
| Total other income and (expense) | (346 | ) | | (301 | ) | | (1,013 | ) | | (801 | ) | (266 | ) | | (329 | ) | | (539 | ) | | (655 | ) |
| Earnings Before Income Taxes | 1,699 |
| | 1,616 |
| | 744 |
| | 3,241 |
| |
| Income taxes | 590 |
| | 439 |
| | 317 |
| | 917 |
| |
| Consolidated Net Income | 1,109 |
| | 1,177 |
| | 427 |
| | 2,324 |
| |
| Less: | | | | | | | | |
| Dividends on preferred and preference stock of subsidiaries | 10 |
| | 11 |
| | 32 |
| | 34 |
| |
| Earnings (Loss) Before Income Taxes | | 1,076 |
| | (266 | ) | | 4,494 |
| | 784 |
|
| Income taxes (benefit) | | 145 |
| | (139 | ) | | 1,505 |
| | (25 | ) |
| Consolidated Net Income (Loss) | | 931 |
| | (127 | ) | | 2,989 |
| | 809 |
|
| Dividends on preferred stock of subsidiaries | | 3 |
| | 4 |
| | 7 |
| | 8 |
|
| Net income attributable to noncontrolling interests | 30 |
| | 27 |
| | 48 |
| | 39 |
| 29 |
| | 23 |
| | — |
| | 17 |
|
Consolidated Net Income Attributable to Southern Company | $ | 1,069 |
| | $ | 1,139 |
| | $ | 347 |
| | $ | 2,251 |
| |
Consolidated Net Income (Loss) Attributable to
Southern Company | | $ | 899 |
| | $ | (154 | ) | | $ | 2,982 |
| | $ | 784 |
|
| Common Stock Data: | | | | | | | | | | | | | | |
| Earnings per share — | | | | | | | | |
| Earnings (loss) per share - | | | | | | | | |
| Basic | $ | 1.07 |
| | $ | 1.18 |
| | $ | 0.35 |
| | $ | 2.40 |
| $ | 0.86 |
| | $ | (0.15 | ) | | $ | 2.86 |
| | $ | 0.77 |
|
| Diluted | $ | 1.06 |
| | $ | 1.17 |
| | $ | 0.35 |
| | $ | 2.38 |
| $ | 0.85 |
| | $ | (0.15 | ) | | $ | 2.84 |
| | $ | 0.77 |
|
| Average number of shares of common stock outstanding (in millions) | | | | | | | | | | | | | | |
| Basic | 1,003 |
| | 968 |
| | 998 |
| | 940 |
| 1,044 |
| | 1,014 |
| | 1,041 |
| | 1,012 |
|
| Diluted | 1,010 |
| | 975 |
| | 1,005 |
| | 945 |
| 1,052 |
| | 1,014 |
| | 1,049 |
| | 1,017 |
|
| 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, |
| | 2019 | | 2018 | | 2019 | | 2018 |
| | (in millions) | | (in millions) |
| Consolidated Net Income (Loss) | $ | 931 |
| | $ | (127 | ) | | $ | 2,989 |
| | $ | 809 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
Changes in fair value, net of tax of
$(11), $(18), $(21), and $(3), respectively | (32 | ) | | (54 | ) | | (60 | ) | | (8 | ) |
Reclassification adjustment for amounts included in net income,
net of tax of $(1), $21, $8, and $15, respectively | (3 | ) | | 64 |
| | 24 |
| | 45 |
|
| Pension and other postretirement benefit plans: | | | | | | | |
Reclassification adjustment for amounts included in net income,
net of tax of $-, $1, $-, and $1, respectively | — |
| | 2 |
| | 1 |
| | 4 |
|
| Total other comprehensive income (loss) | (35 | ) | | 12 |
| | (35 | ) | | 41 |
|
| Comprehensive Income (Loss) | 896 |
| | (115 | ) | | 2,954 |
| | 850 |
|
| Dividends on preferred stock of subsidiaries | 3 |
| | 4 |
| | 7 |
| | 8 |
|
| Comprehensive income attributable to noncontrolling interests | 29 |
| | 23 |
| | — |
| | 17 |
|
Consolidated Comprehensive Income (Loss) Attributable to
Southern Company | $ | 864 |
| | $ | (142 | ) | | $ | 2,947 |
| | $ | 825 |
|
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 | 2019 | | 2018 |
| | (in millions) | (in millions) |
| Operating Activities: | | | | | | |
| Consolidated net income | $ | 427 |
| | $ | 2,324 |
| $ | 2,989 |
| | $ | 809 |
|
| Adjustments to reconcile consolidated net income to net cash provided from operating activities — | | | | | | |
| Depreciation and amortization, total | 2,564 |
| | 2,109 |
| 1,623 |
| | 1,750 |
|
| Deferred income taxes | 15 |
| | (22 | ) | 274 |
| | (338 | ) |
| Allowance for equity funds used during construction | (133 | ) | | (150 | ) | (63 | ) | | (63 | ) |
| Mark-to-market adjustments | | 31 |
| | 3 |
|
| Pension, postretirement, and other employee benefits | (64 | ) | | (158 | ) | (65 | ) | | (74 | ) |
| Settlement of asset retirement obligations | (137 | ) | | (117 | ) | (143 | ) | | (97 | ) |
| Hedge settlements | — |
| | (236 | ) | |
| Estimated loss on Kemper IGCC | 3,148 |
| | 222 |
| |
| Stock based compensation expense | | 75 |
| | 83 |
|
| Estimated loss on plants under construction | | 11 |
| | 1,088 |
|
| (Gain) loss on dispositions, net | | (2,512 | ) | | 35 |
|
| Impairment charges | | 32 |
| | 161 |
|
| Other, net | (8 | ) | | (1 | ) | (22 | ) | | (34 | ) |
| Changes in certain current assets and liabilities — | | | | | | |
| -Receivables | 426 |
| | (458 | ) | 653 |
| | 94 |
|
| -Fossil fuel for generation | 59 |
| | 204 |
| |
| -Natural gas for sale, net of temporary LIFO liquidation | — |
| | (222 | ) | |
| -Prepayments | | (53 | ) | | (73 | ) |
| -Natural gas for sale | | 255 |
| | 295 |
|
| -Other current assets | (164 | ) | | (112 | ) | (18 | ) | | (40 | ) |
| -Accounts payable | (467 | ) | | (9 | ) | (1,045 | ) | | (406 | ) |
| -Accrued taxes | 157 |
| | 1,062 |
| 938 |
| | 213 |
|
| -Accrued compensation | (230 | ) | | (122 | ) | (312 | ) | | (284 | ) |
| -Retail fuel cost over recovery | (211 | ) | | (106 | ) | |
| -Other current liabilities | (129 | ) | | 88 |
| (135 | ) | | 136 |
|
| Net cash provided from operating activities | 5,253 |
| | 4,296 |
| 2,513 |
| | 3,258 |
|
| Investing Activities: | | | | | | |
| Business acquisitions, net of cash acquired | (1,032 | ) | | (9,513 | ) | |
| Property additions | (5,242 | ) | | (5,252 | ) | (3,484 | ) | | (3,828 | ) |
| Investment in restricted cash | (16 | ) | | (750 | ) | |
| Distribution of restricted cash | 33 |
| | 746 |
| |
| Nuclear decommissioning trust fund purchases | (585 | ) | | (838 | ) | (405 | ) | | (571 | ) |
| Nuclear decommissioning trust fund sales | 580 |
| | 832 |
| 400 |
| | 566 |
|
| Proceeds from dispositions and asset sales | | 5,000 |
| | 500 |
|
| Cost of removal, net of salvage | (208 | ) | | (155 | ) | (197 | ) | | (128 | ) |
| Change in construction payables, net | 120 |
| | (259 | ) | (107 | ) | | 49 |
|
| Investment in unconsolidated subsidiaries | (134 | ) | | (1,421 | ) | (134 | ) | | (63 | ) |
| Payments pursuant to LTSAs | (189 | ) | | (125 | ) | (64 | ) | | (103 | ) |
| Other investing activities | (14 | ) | | 95 |
| (7 | ) | | (46 | ) |
| Net cash used for investing activities | (6,687 | ) | | (16,640 | ) | |
| Net cash provided from (used for) investing activities | | 1,002 |
| | (3,624 | ) |
| Financing Activities: | | | | | | |
| Increase (decrease) in notes payable, net | (515 | ) | | 655 |
| |
| Increase in notes payable, net | | 83 |
| | 1,442 |
|
| Proceeds — | | | | | | |
| Long-term debt | 4,068 |
| | 14,091 |
| 1,390 |
| | 1,100 |
|
| Common stock | 613 |
| | 3,265 |
| 452 |
| | 222 |
|
| Preferred stock | 250 |
| | — |
| |
| Short-term borrowings | 1,263 |
| | — |
| 250 |
| | 1,650 |
|
| Redemptions and repurchases — | | | | | | |
| Long-term debt | (1,981 | ) | | (2,405 | ) | (2,560 | ) | | (3,379 | ) |
| Preferred and preference stock | (150 | ) | | — |
| |
| Short-term borrowings | (409 | ) | | (475 | ) | (1,850 | ) | | (550 | ) |
| Distributions to noncontrolling interests | (89 | ) | | (22 | ) | (82 | ) | | (42 | ) |
| Capital contributions from noncontrolling interests | 79 |
| | 367 |
| 5 |
| | 1,210 |
|
| Purchase of membership interests from noncontrolling interests | — |
| | (129 | ) | |
| Payment of common stock dividends | (1,716 | ) | | (1,553 | ) | (1,269 | ) | | (1,194 | ) |
| Other financing activities | (113 | ) | | (185 | ) | (67 | ) | | (223 | ) |
| 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 provided from (used for) financing activities | | (3,648 | ) | | 236 |
|
| Net Change in Cash, Cash Equivalents, and Restricted Cash | | (133 | ) | | (130 | ) |
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | | 1,519 |
| | 2,147 |
|
| Cash, Cash Equivalents, and Restricted Cash at End of Period | | $ | 1,386 |
| | $ | 2,017 |
|
| 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 |
| |
| Cash paid during the period for — | | | | |
| Interest (net of $36 and $35 capitalized for 2019 and 2018, respectively) | | $ | 844 |
| | $ | 927 |
|
| Income taxes, net | (187 | ) | | (151 | ) | 210 |
| | 4 |
|
| Noncash transactions — Accrued property additions at end of period | 805 |
| | 578 |
| 988 |
| | 1,067 |
|
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, 2019 | | At December 31, 2018 |
| | | (in millions) | | (in millions) |
| Current Assets: | | | | | | | | |
| Cash and cash equivalents | | $ | 1,841 |
| | $ | 1,975 |
| | $ | 1,383 |
| | $ | 1,396 |
|
| Receivables — | | | | | | | | |
| Customer accounts receivable | | 1,744 |
| | 1,583 |
| | 1,654 |
| | 1,726 |
|
| Energy marketing receivables | | 427 |
| | 623 |
| | 361 |
| | 801 |
|
| Unbilled revenues | | 595 |
| | 706 |
| | 583 |
| | 654 |
|
| Under recovered fuel clause revenues | | 62 |
| | — |
| | 69 |
| | 115 |
|
| Income taxes receivable, current | | 138 |
| | 544 |
| |
| Other accounts and notes receivable | | 578 |
| | 377 |
| | 756 |
| | 813 |
|
| Accumulated provision for uncollectible accounts | | (43 | ) | | (43 | ) | | (50 | ) | | (50 | ) |
| Materials and supplies | | 1,499 |
| | 1,462 |
| | 1,440 |
| | 1,465 |
|
| Fossil fuel for generation | | 571 |
| | 689 |
| | 435 |
| | 405 |
|
| Natural gas for sale | | 631 |
| | 631 |
| | 268 |
| | 524 |
|
| Prepaid expenses | | 365 |
| | 364 |
| | 543 |
| | 432 |
|
| Other regulatory assets, current | | 585 |
| | 581 |
| |
| Assets from risk management activities, net of collateral | | | 107 |
| | 222 |
|
| Other regulatory assets | | | 607 |
| | 525 |
|
| Assets held for sale | | | 58 |
| | 393 |
|
| Other current assets | | 209 |
| | 230 |
| | 138 |
| | 162 |
|
| Total current assets | | 9,202 |
| | 9,722 |
| | 8,352 |
| | 9,583 |
|
| Property, Plant, and Equipment: | | | | | | | | |
| In service | | 102,014 |
| | 98,416 |
| | 103,428 |
| | 103,706 |
|
| Less: Accumulated depreciation | | 31,164 |
| | 29,852 |
| | 30,693 |
| | 31,038 |
|
| Plant in service, net of depreciation | | 70,850 |
| | 68,564 |
| | 72,735 |
| | 72,668 |
|
| Nuclear fuel, at amortized cost | | 865 |
| | 905 |
| | 871 |
| | 875 |
|
| Construction work in progress | | 8,026 |
| | 8,977 |
| | 7,568 |
| | 7,254 |
|
| Total property, plant, and equipment | | 79,741 |
| | 78,446 |
| | 81,174 |
| | 80,797 |
|
| Other Property and Investments: | | | | | | | | |
| Goodwill | | 6,267 |
| | 6,251 |
| | 5,282 |
| | 5,315 |
|
| Equity investments in unconsolidated subsidiaries | | 1,637 |
| | 1,549 |
| | 1,557 |
| | 1,580 |
|
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 $253 and $235
at June 30, 2019 and December 31, 2018, respectively | | | 550 |
| | 613 |
|
| Nuclear decommissioning trusts, at fair value | | 1,783 |
| | 1,606 |
| | 1,942 |
| | 1,721 |
|
| Leveraged leases | | 788 |
| | 774 |
| | 813 |
| | 798 |
|
| Miscellaneous property and investments | | 236 |
| | 270 |
| | 505 |
| | 269 |
|
| Total other property and investments | | 11,613 |
| | 11,420 |
| | 10,649 |
| | 10,296 |
|
| Deferred Charges and Other Assets: | | | | | | | | |
| Operating lease right-of-use assets, net of amortization | | | 1,862 |
| | — |
|
| Deferred charges related to income taxes | | 1,318 |
| | 1,629 |
| | 794 |
| | 794 |
|
| Unamortized loss on reacquired debt | | 210 |
| | 223 |
| | 313 |
| | 323 |
|
| Regulatory assets – asset retirement obligations | | | 4,062 |
| | 2,933 |
|
| Other regulatory assets, deferred | | 6,718 |
| | 6,851 |
| | 5,835 |
| | 5,375 |
|
| Assets held for sale, deferred | | | 685 |
| | 5,350 |
|
| Other deferred charges and assets | | 1,513 |
| | 1,406 |
| | 1,141 |
| | 1,463 |
|
| Total deferred charges and other assets | | 9,759 |
| | 10,109 |
| | 14,692 |
| | 16,238 |
|
| Total Assets | | $ | 110,315 |
| | $ | 109,697 |
| | $ | 114,867 |
| | $ | 116,914 |
|
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, 2019 | | At December 31, 2018 |
| | | (in millions) | | (in millions) |
| Current Liabilities: | | | | | | | | |
| Securities due within one year | | $ | 3,505 |
| | $ | 2,587 |
| | $ | 3,148 |
| | $ | 3,198 |
|
| Notes payable | | 2,579 |
| | 2,241 |
| | 1,398 |
| | 2,915 |
|
| Energy marketing trade payables | | 451 |
| | 597 |
| | 393 |
| | 856 |
|
| Accounts payable | | 2,353 |
| | 2,228 |
| | 1,978 |
| | 2,580 |
|
| Customer deposits | | 550 |
| | 558 |
| | 489 |
| | 522 |
|
| Accrued taxes — | | | | | | | | |
| Accrued income taxes | | 176 |
| | 193 |
| | 171 |
| | 21 |
|
| Unrecognized tax benefits | | 17 |
| | 385 |
| |
| Other accrued taxes | | 690 |
| | 667 |
| | 501 |
| | 635 |
|
| Accrued interest | | 443 |
| | 518 |
| | 455 |
| | 472 |
|
| Accrued compensation | | 703 |
| | 915 |
| | 676 |
| | 1,030 |
|
| Asset retirement obligations, current | | 245 |
| | 378 |
| |
| Acquisitions payable | | — |
| | 489 |
| |
| Other regulatory liabilities, current | | 139 |
| | 236 |
| |
| Asset retirement obligations | | | 429 |
| | 404 |
|
| Other regulatory liabilities | | | 304 |
| | 376 |
|
| Liabilities held for sale | | | 36 |
| | 425 |
|
| Operating lease obligations | | | 228 |
| | — |
|
| Other current liabilities | | 752 |
| | 925 |
| | 793 |
| | 852 |
|
| Total current liabilities | | 12,603 |
| | 12,917 |
| | 10,999 |
| | 14,286 |
|
| Long-term Debt | | 44,042 |
| | 42,629 |
| | 39,682 |
| | 40,736 |
|
| Deferred Credits and Other Liabilities: | | | | | | | | |
| Accumulated deferred income taxes | | 14,321 |
| | 14,092 |
| | 7,728 |
| | 6,558 |
|
| Deferred credits related to income taxes | | | 6,386 |
| | 6,460 |
|
| Accumulated deferred ITCs | | 2,290 |
| | 2,228 |
| | 2,283 |
| | 2,372 |
|
| Employee benefit obligations | | 2,139 |
| | 2,299 |
| | 2,058 |
| | 2,147 |
|
| Operating lease obligations, deferred | | | 1,702 |
| | — |
|
| Asset retirement obligations, deferred | | 4,356 |
| | 4,136 |
| | 9,478 |
| | 8,990 |
|
| Accrued environmental remediation | | | 247 |
| | 268 |
|
| Other cost of removal obligations | | 2,708 |
| | 2,748 |
| | 2,283 |
| | 2,297 |
|
| Other regulatory liabilities, deferred | | 449 |
| | 476 |
| | 176 |
| | 169 |
|
| Liabilities held for sale, deferred | | | 39 |
| | 2,836 |
|
| Other deferred credits and liabilities | | 1,048 |
| | 1,278 |
| | 384 |
| | 465 |
|
| Total deferred credits and other liabilities | | 27,311 |
| | 27,257 |
| | 32,764 |
| | 32,562 |
|
| Total Liabilities | | 83,956 |
| | 82,803 |
| | 83,445 |
| | 87,584 |
|
| 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) | | | 31,131 |
| | 29,039 |
|
| Total Liabilities and Stockholders' Equity | | $ | 110,315 |
| | $ | 109,697 |
| | $ | 114,867 |
| | $ | 116,914 |
|
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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, 2017 | 1,009 |
| | (1 | ) | | $ | 5,038 |
| | $ | 10,469 |
| | $ | (36 | ) | | $ | 8,885 |
| | $ | (189 | ) | | $ | 1,361 |
| | $ | 25,528 |
|
Consolidated net income attributable to
Southern Company | — |
| | — |
| | — |
| | — |
| | — |
| | 938 |
| | — |
| | — |
| | 938 |
|
| Other comprehensive income | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 30 |
| | — |
| | 30 |
|
| Stock issued | 4 |
| | — |
| | 16 |
| | 97 |
| | — |
| | — |
| | — |
| | — |
| | 113 |
|
| Stock-based compensation | — |
| | — |
| | — |
| | 36 |
| | — |
| | — |
| | — |
| | — |
| | 36 |
|
| Cash dividends of $0.58 per share | — |
| | — |
| | — |
| | — |
| | — |
| | (586 | ) | | — |
| | — |
| | (586 | ) |
| Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 9 |
| | 9 |
|
| Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (13 | ) | | (13 | ) |
Net income (loss) attributable
to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (6 | ) | | (6 | ) |
| Other | — |
| | — |
| | — |
| | 1 |
| | (2 | ) | | 20 |
| | (41 | ) | | (2 | ) | | (24 | ) |
| Balance at March 31, 2018 | 1,013 |
| | (1 | ) | | 5,054 |
| | 10,603 |
| | (38 | ) | | 9,257 |
| | (200 | ) | | 1,349 |
| | 26,025 |
|
Consolidated net loss attributable to
Southern Company | — |
| | — |
| | — |
| | — |
| | — |
| | (154 | ) | | — |
| | — |
| | (154 | ) |
| Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 12 |
| | — |
| | 12 |
|
| Stock issued | 2 |
| | — |
| | 12 |
| | 97 |
| | — |
| | — |
| | — |
| | — |
| | 109 |
|
| Stock-based compensation | — |
| | — |
| | — |
| | 12 |
| | — |
| | — |
| | — |
| | — |
| | 12 |
|
| Cash dividends of $0.60 per share | — |
| | — |
| | — |
| | — |
| | — |
| | (607 | ) | | — |
| | — |
| | (607 | ) |
| Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 22 |
| | 22 |
|
| Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (29 | ) | | (29 | ) |
Net income attributable
to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 23 |
| | 23 |
|
| Sale of noncontrolling interests | — |
| | — |
| | — |
| | (407 | ) | | — |
| | — |
| | — |
| | 1,690 |
| | 1,283 |
|
| Other | — |
| | — |
| | — |
| | (2 | ) | | (1 | ) | | (2 | ) | | — |
| | 1 |
| | (4 | ) |
| Balance at June 30, 2018 | 1,015 |
| | (1 | ) | | $ | 5,066 |
| | $ | 10,303 |
| | $ | (39 | ) | | $ | 8,494 |
| | $ | (188 | ) | | $ | 3,056 |
| | $ | 26,692 |
|
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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 attributable to
Southern Company | — |
| | — |
| | — |
| | — |
| | — |
| | 2,084 |
| | — |
| | — |
| | 2,084 |
|
| 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 | ) |
Net income (loss) attributable to
noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (29 | ) | | (29 | ) |
| 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 attributable to
Southern Company | — |
| | — |
| | — |
| | — |
| | — |
| | 899 |
| | — |
| | — |
| | 899 |
|
| Other comprehensive income | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (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 | ) |
Net income attributable
to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 29 |
| | 29 |
|
| 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 |
|
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRDSECOND QUARTER 20172019 vs. THIRDSECOND QUARTER 20162018
AND
YEAR-TO-DATE 20172019 vs. YEAR-TO-DATE 20162018
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 fourthree 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 wholesale market. Southern Company Gas distributes natural gas through its natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services,pipeline investments, wholesale gas services, and gas midstream operations.marketing services. The Southern Company'sCompany system's other business activities include providing energy technologies and services to electric utilities and large industrial, commercial, institutional, and municipal customers. Customer solutions, includesuch as distributed generation systems, utilityenergy infrastructure solutions, and energy efficiency products and services.services, to customers. 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.
On January 1, 2019, Southern Company completed the sale of Gulf Power to NextEra Energy for an aggregate cash purchase price of approximately $5.8 billion (less $1.3 billion of indebtedness assumed), subject to customary working capital adjustments. The preliminary gain associated with the sale of Gulf Power totaled $2.5 billion pre-tax ($1.3 billion after tax). See Note (K) to the Condensed Financial Statements under "Southern Company" herein for additional information.
Georgia Power and Atlanta Gas Light each filed base rate cases with the Georgia PSC in June 2019. Georgia Power's filing includes a three-year Alternate Rate Plan with requested rate increases totaling $563 million, $145 million, and $234 million effective January 1, 2020, January 1, 2021, and January 1, 2022, respectively. Atlanta Gas Light's filing requests a $96 million increase in annual base rate revenues effective January 1, 2020. Nicor Gas filed a rate case with the Illinois Commission in November 2018, which was revised in April 2019, requesting an annual revenue increase of $180 million. These three rate cases are expected to conclude in 2019. In addition, Mississippi Power is scheduled to file a base rate case with the Mississippi PSC in the fourth quarter 2019. The ultimate outcome of these matters cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters" herein and Note 2 to the financial statements in Item 8 of the Form 10-K for information regarding agreements entered into by a wholly-owned subsidiary of Southern Company Gas to sell two of its natural gas distribution utilities.additional information.
Southern Company continues to focus on several key performance indicators. These indicators include, but are not limited to, customer satisfaction, plant availability, electric and natural gas system reliability, execution of major construction projects, and earnings per share.
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 1,100 MWs each). Georgia Power holds a 45.7% ownership interest in Plant Vogtle Units 3 and 4. In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. In December 2017, the Georgia PSC approved Georgia Power's recommendation to continue construction. The current expected in-service dates remain November 2021 for Unit 3 and November 2022 for Unit 4.
In the second quarter 2018, Georgia Power revised its base capital cost forecast and estimated 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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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), with respect to Georgia Power's ownership interest.
As a result of the 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, 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. 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 certain of MEAG's wholly-owned subsidiaries, including MEAG Power SPVJ, LLC (MEAG SPVJ), to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners and (ii) a term sheet (MEAG Term Sheet) with MEAG and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. On January 14, 2019, Georgia Power, MEAG, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. On February 18, 2019, Georgia Power, the other Vogtle Owners, and certain of MEAG's wholly-owned subsidiaries entered into certain amendments to their joint ownership agreements to implement the provisions of the Vogtle Owner Term Sheet.
In April 2019, Southern Nuclear completed a cost and schedule validation process to verify and update quantities of commodities remaining to install, labor hours to install remaining quantities and related productivity, testing and system turnover requirements, and forecasted staffing needs and related costs. This process confirmed the total estimated project capital cost forecast for Plant Vogtle Units 3 and 4. The expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4, as previously approved by the Georgia PSC, remain unchanged.
In March 2019, Georgia Power entered into the Amended and Restated 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, up to approximately $5.130 billion. At June 30, 2019, Georgia Power had a total of $3.46 billion of borrowings outstanding under the related multi-advance credit facilities.
The ultimate outcome of these matters cannot be determined at this time.
See FUTURE EARNINGS POTENTIAL – "Construction Program – Nuclear Construction" and Note (F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information.
RESULTS OF OPERATIONS
Net Income (Loss)
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1,053 | | N/M | | $2,198 | | N/M |
N/M - Not meaningful
Consolidated net income attributable to Southern Company was $899 million ($0.86 per share) for the second quarter 2019 compared to a net loss of $154 million ($(0.15) per share) for the corresponding period in 2018. The change was primarily due to a $1.1 billion ($0.8 billion after tax) charge in the second quarter 2018 for an estimated probable loss related to Georgia Power's construction of Plant Vogtle Units 3 and 4 and a decrease in operations and maintenance expenses.
Consolidated net income attributable to Southern Company was $3.0 billion ($2.86 per share) for year-to-date 2019 compared to $784 million ($0.77 per share) for the corresponding period in 2018. The increase was primarily due to the $2.5 billion ($1.3 billion after tax) gain on the sale of Gulf Power in 2019 and a $1.1 billion ($0.8 billion after tax) charge in the second quarter 2018 for an estimated probable loss related to Georgia Power's construction of
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Plant Vogtle Units 3 and 4. See Note (K) to the Condensed Financial Statements under "Southern Company" herein and Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information.
Retail Electric Revenues
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(200) | | (5.3) | | $(685) | | (9.4) |
In the second quarter 2019, retail electric revenues were $3.5 billion compared to $3.7 billion for the corresponding period in 2018. For year-to-date 2019, retail electric revenues were $6.6 billion compared to $7.3 billion for the corresponding period in 2018.
Details of the changes in retail electric revenues were as follows:
|
| | | | | | | | | | | | | | |
| | | Second Quarter 2019 | | Year-to-Date 2019 |
| | | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail electric – prior year | | $ | 3,740 |
| | | | $ | 7,308 |
| | |
| Estimated change resulting from – | | | | | | | | |
| Rates and pricing | | 125 |
| | 3.3 | % | | 182 |
| | 2.5 | % |
| Sales decline | | (30 | ) | | (0.8 | ) | | (41 | ) | | (0.6 | ) |
| Weather | | 34 |
| | 0.9 |
| | (56 | ) | | (0.8 | ) |
| Fuel and other cost recovery | | (28 | ) | | (0.7 | ) | | (179 | ) | | (2.4 | ) |
| Gulf Power disposition | | (301 | ) | | (8.0 | ) | | (591 | ) | | (8.1 | ) |
| Retail electric – current year | | $ | 3,540 |
| | (5.3 | )% | | $ | 6,623 |
| | (9.4 | )% |
Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018 primarily due to increased revenues at Alabama Power due to the impacts of customer bill credits related to the Tax Reform Legislation in 2018 and increases to CNP Compliance revenue, increases in the NCCR tariff effective January 1, 2019 at Georgia Power, and increases in PEP and ECO Plan rates that became effective for the first billing cycle of September 2018 at Mississippi Power. The year-to-date 2019 increase also reflects the rate pricing effect of decreased customer usage, partially offset by lower contributions from commercial and industrial customers with variable demand-driven pricing at Georgia Power.
See Note 2 to the financial statements under "Alabama Power," "Georgia Power," and "Mississippi Power" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.
Revenues attributable to changes in sales decreased in the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018. Weather-adjusted residential KWH sales decreased 1.0% and 0.3% in the second quarter and year-to-date 2019, respectively, when compared to the corresponding periods in 2018 primarily due to decreased customer usage primarily resulting from an increase in energy efficient residential appliances, partially offset by customer growth. Weather-adjusted commercial KWH sales decreased 1.3% and 1.6% in the second quarter and year-to-date 2019, respectively, when compared to the corresponding periods in 2018 primarily due to decreased customer usage resulting from an increase in energy saving initiatives. Industrial KWH sales decreased 2.0% in both the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018 as a result of a decrease in demand resulting from changes in production levels primarily in the primary metals, chemicals, stone, clay, and glass, textile, and paper sectors.
Fuel and other cost recovery revenues decreased $28 million and $179 million in the second quarter and year-to-date 2019, respectively, compared to the corresponding periods in 2018 primarily due to decreases in generation and the average cost of fuel. The year-to-date decrease was also driven by milder weather in the first quarter 2019.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(74) | | (12.0) | | $(198) | | (16.0) |
Wholesale electric revenues consist of 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 2019, wholesale electric revenues were $542 million compared to $616 million for the corresponding period in 2018. For year-to-date 2019, wholesale electric revenues were $1.0 billion compared to $1.2 billion for the corresponding period in 2018. The second quarter 2019 decrease was related to a $54 million decrease in energy revenues and a $20 million decrease in capacity revenues. The year-to-date 2019 decrease was related to a $160 million decrease in energy revenues and a $38 million decrease in capacity revenues. Excluding decreases of $7 million and $13 million of energy revenues for the second quarter and year-to-date 2019, respectively, related to the sale of Gulf Power, the decreases in energy revenues primarily related to Southern Power and included a decrease in non-PPA revenues due to a decrease in the volume of KWHs sold through short-term sales and a decrease in revenues from natural gas PPAs due to a decrease in the average cost of fuel and purchased power. These decreases were also due to lower fuel prices and lower customer demand at the traditional electric operating companies. The decreases in capacity revenues primarily related to the sales of Gulf Power and Southern Power's Plant Oleander and Plant Stanton Unit A in December 2018. See Note 15 to the financial statements under "Southern Power – Sales of Natural Gas Plants" in Item 8 of the Form 10-K for additional information.
Natural Gas Revenues
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(17) | | (2.4) | | $(151) | | (6.5) |
In the second quarter 2019, natural gas revenues were $689 million compared to $706 million for the corresponding period in 2018. For year-to-date 2019, natural gas revenues were $2.2 billion compared to $2.3 billion for the corresponding period in 2018.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of the changes in natural gas revenues were as follows:
|
| | | | | | | | | | | | | |
| | Second Quarter 2019 | | Year-to-Date 2019 |
| | (in millions) | | (% change) | | (in millions) | | (% change) |
| Natural gas revenues – prior year | $ | 706 |
| | | | $ | 2,314 |
| | |
| Estimated change resulting from – | | | | | | | |
| Infrastructure replacement programs and base rate changes | 10 |
| | 1.4 | % | | 42 |
| | 1.8 | % |
| Gas costs and other cost recovery | (13 | ) | | (1.8 | ) | | 49 |
| | 2.1 |
|
| Weather | (7 | ) | | (1.1 | ) | | — |
| | — |
|
| Wholesale gas services | 64 |
| | 9.1 |
| | (16 | ) | | (0.7 | ) |
| Southern Company Gas Dispositions | (70 | ) | | (9.9 | ) | | (237 | ) | | (10.2 | ) |
| Other | (1 | ) | | (0.1 | ) | | 11 |
| | 0.5 |
|
| Natural gas revenues – current year | $ | 689 |
| | (2.4 | )% | | $ | 2,163 |
| | (6.5 | )% |
Revenues attributable to infrastructure replacement programs and base rate changes at the natural gas distribution utilities increased in the second quarter and year-to-date 2019 compared to the corresponding periods in 2018 primarily due to increases of $4 million and $25 million, respectively, at Nicor Gas and $5 million and $14 million, respectively, at Atlanta Gas Light. These amounts include the natural gas distribution utilities' continued investments recovered through infrastructure replacement programs and base rate increases as well as increases due to the impacts of the Tax Reform Legislation.
Revenues attributable to gas costs and other cost recovery decreased in the second quarter 2019 and increased year-to-date 2019 compared to the corresponding periods in 2018. The decrease in the second quarter 2019 is primarily due to lower natural gas prices and decreased volumes of natural gas sold. The increase for year-to-date 2019 is primarily due to increased natural gas prices in the first quarter 2019, partially offset by decreased volumes of natural gas sold year-to-date 2019. 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.
Revenues decreased in the second quarter 2019 due to warmer weather, as determined by Heating Degree Days, in Illinois and Georgia compared to the corresponding period in 2018.
Revenues attributable to Southern Company Gas' wholesale gas services business increased in the second quarter 2019 and decreased year-to-date 2019 compared to the corresponding periods in 2018. The increase in the second quarter 2019 is primarily due to derivative gains, partially offset by decreased commercial activity. For year-to-date 2019, the decrease is primarily due to decreased commercial activity, partially offset by derivative gains.
See Note (B) to the Condensed Financial Statements herein under "Southern Company Gas" for additional information.
Other Revenues
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(229) | | (58.0) | | $(456) | | (56.4) |
In the second quarter 2019, other revenues were $166 million compared to $395 million for the corresponding period in 2018. For year-to-date 2019, other revenues were $352 million compared to $808 million for the corresponding period in 2018. These decreases were primarily related to PowerSecure's 2018 storm restoration services in Puerto Rico.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | |
| | Second Quarter 2019
vs.
Second Quarter 2018 | | Year-to-Date 2019
vs.
Year-to-Date 2018 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | (189 | ) | | (17.1) | | $ | (440 | ) | | (20.0) |
| Purchased power | (35 | ) | | (14.8) | | (132 | ) | | (26.2) |
| Total fuel and purchased power expenses | $ | (224 | ) | | | | $ | (572 | ) | | |
In the second quarter 2019, total fuel and purchased power expenses were $1.1 billion compared to $1.3 billion for the corresponding period in 2018. Excluding approximately $126 million associated with the sale of Gulf Power, the decrease was primarily the result of an $81 million decrease in the average cost of fuel and purchased power and a $17 million net decrease in the aggregate volume of KWHs generated and purchased.
For year-to-date 2019, total fuel and purchased power expenses were $2.1 billion compared to $2.7 billion for the corresponding period in 2018. Excluding approximately $225 million associated with the sale of Gulf Power, the decrease was primarily the result of a $198 million decrease in the average cost of fuel and purchased power and a $149 million decrease in the aggregate 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.
Details of the Southern Company system's generation and purchased power were as follows:
|
| | | | | | | |
| | Second Quarter 2019 | | Second Quarter 2018(a) | | Year-to-Date 2019 | | Year-to-Date 2018(a) |
Total generation (in billions of KWHs) | 46 | | 47 | | 90 | | 93 |
Total purchased power (in billions of KWHs) | 4 | | 4 | | 8 | | 7 |
Sources of generation (percent) — | | | | | | | |
| Gas | 52 | | 45 | | 50 | | 45 |
| Coal | 22 | | 29 | | 22 | | 29 |
| Nuclear | 16 | | 15 | | 16 | | 16 |
| Hydro | 3 | | 3 | | 5 | | 3 |
| Other | 7 | | 8 | | 7 | | 7 |
Cost of fuel, generated (in cents per net KWH)— | | | | | | | |
| Gas | 2.39 | | 2.71 | | 2.47 | | 2.78 |
| Coal | 3.04 | | 2.71 | | 2.98 | | 2.80 |
| Nuclear | 0.80 | | 0.82 | | 0.80 | | 0.80 |
Average cost of fuel, generated (in cents per net KWH) | 2.26 | | 2.39 | | 2.29 | | 2.43 |
Average cost of purchased power (in cents per net KWH)(b) | 4.89 | | 5.18 | | 5.04 | | 6.11 |
| |
| (a) | Excludes Gulf Power, which was sold on January 1, 2019. |
| |
| (b) | Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider. |
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel
In the second quarter 2019, fuel expense was $0.9 billion compared to $1.1 billion for the corresponding period in 2018. Excluding approximately $74 million related to Gulf Power in 2018, the decrease was primarily due to a 26.2% decrease in the volume of KWHs generated by coal and an 11.8% decrease in the average cost of natural gas per KWH generated, partially offset by a 12.2% increase in the average cost of coal per KWH generated and a 12.1% increase in the volume of KWHs generated by natural gas.
For year-to-date 2019, fuel expense was $1.8 billion compared to $2.2 billion for the corresponding period in 2018. Excluding approximately $127 million related to Gulf Power in 2018, the decrease was primarily due to a 27.6% decrease in the volume of KWHs generated by coal and an 11.2% decrease in the average cost of natural gas per KWH generated, partially offset by a 6.6% increase in the volume of KWHs generated by natural gas and a 6.4% increase in the average cost of coal per KWH generated.
Purchased Power
In the second quarter 2019, purchased power expense was $201 million compared to $236 million for the corresponding period in 2018. This decrease was primarily associated with Gulf Power.
For year-to-date 2019, purchased power expense was $371 million compared to $503 million for the corresponding period in 2018. Excluding approximately $98 million associated with Gulf Power, the decrease was primarily due to a 17.5% decrease in the average cost per KWH purchased and a 2.1% decrease in the volume of KWHs purchased.
See Note (K) to the Condensed Financial Statements under "Southern Company" herein for information regarding the sale of Gulf Power.
Energy purchases will vary depending on demand for energy within the Southern Company system's electric service territory, the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, and the availability of the Southern Company system's generation.
Cost of Natural Gas
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(37) | | (16.2) | | $(72) | | (7.6) |
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 80% and 85% of total cost of natural gas for the second quarter and year-to-date 2019, respectively.
In the second quarter 2019, cost of natural gas was $191 million compared to $228 million for the corresponding period in 2018. Excluding a $25 million decrease related to the Southern Company Gas Dispositions, cost of natural gas decreased $12 million.
For year-to-date 2019, cost of natural gas was $877 million compared to $949 million for the corresponding period in 2018. Excluding a $104 million decrease related to the Southern Company Gas Dispositions, cost of natural gas increased $32 million. This increase reflects an increase in natural gas prices, partially offset by a decrease in the volume of natural gas sold year-to-date 2019 compared to the corresponding period in 2018.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Cost of Other Sales
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(195) | | (69.9) | | $(365) | | (64.3) |
In the second quarter 2019, cost of other sales was $84 million compared to $279 million for the corresponding period in 2018. For year-to-date 2019, cost of other sales was $203 million compared to $568 million for the corresponding period in 2018. These decreases were primarily related to PowerSecure's 2018 storm restoration services in Puerto Rico.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(207) | | (13.6) | | $(344) | | (11.6) |
In the second quarter 2019, other operations and maintenance expenses were $1.3 billion compared to $1.5 billion for the corresponding period in 2018. For year-to-date 2019, other operations and maintenance expenses were $2.6 billion compared to $3.0 billion for the corresponding period in 2018. The second quarter and year-to-date 2019 decreases reflect approximately $90 million and $166 million, respectively, related to Gulf Power in 2018 and $34 million and $105 million, respectively, related to the Southern Company Gas Dispositions. These decreases also reflect an asset impairment charge of $119 million recorded in the second quarter 2018 at Southern Power related to the sale of Southern Power's Florida plants. These decreases were partially offset by a $32 million goodwill impairment charge in the second quarter 2019 in contemplation of the sale of PowerSecure's utility infrastructure services business unit. See Note (K) to the Condensed Financial Statements under "Southern Company" herein and Note 15 to the financial statements under "Southern Power" and "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Depreciation and Amortization
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(28) | | (3.6) | | $(46) | | (3.0) |
In the second quarter 2019, depreciation and amortization was $755 million compared to $783 million for the corresponding period in 2018. For year-to-date 2019, depreciation and amortization was $1.5 billion compared to $1.6 billion for the corresponding period in 2018. The second quarter and year-to-date 2019 decreases were primarily due to decreases of $48 million and $95 million, respectively, related to the sale of Gulf Power and decreases of $10 million and $26 million, respectively, related to the Southern Company Gas Dispositions, partially offset by increases of $29 million and $62 million, respectively, related to additional plant in service.
Taxes Other Than Income Taxes
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(17) | | (5.4) | | $(43) | | (6.4) |
In the second quarter 2019, taxes other than income taxes were $299 million compared to $316 million for the corresponding period in 2018. For year-to-date 2019, taxes other than income taxes were $628 million compared to $671 million for the corresponding period in 2018. These decreases primarily relate to the sale of Gulf Power.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Estimated Loss on Plants Under Construction
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(1,056) | | (99.6) | | $(1,099) | | (99.5) |
In the second quarter 2019, estimated loss on plants under construction was $4 million compared to $1.06 billion for the corresponding period in 2018. For year-to-date 2019, estimated loss on plants under construction was $6 million compared to $1.11 billion for the corresponding period in 2018. These decreases were primarily due to the $1.1 billion charge recorded in the second quarter 2018 as a result of Georgia Power's revised estimate to complete construction and start-up of Plant Vogtle Units 3 and 4. The second quarter and year-to-date 2019 charges were related to abandonment and closure activities for the mine and gasifier-related assets of the Kemper IGCC at Mississippi Power.
See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Georgia Power – Nuclear Construction" for additional information.
(Gain) Loss on Dispositions, Net
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $44 | | N/M | | $2,542 | | N/M |
N/M - Not meaningful
In the second quarter 2019, gain on dispositions, net was $8 million compared to a loss on dispositions, net of $36 million in the corresponding period in 2018. This change was primarily due to a $36 million loss on the sale of Pivotal Home Solutions at Southern Company Gas recorded in 2018 and a $23 million gain as a result of the sale of Southern Power's Plant Nacogdoches in the second quarter 2019, partially offset by a $15 million adjustment to the preliminary gain on the sale of Gulf Power.
For year-to-date 2019, gain on dispositions, net was $2.5 billion compared to a loss on dispositions, net of $36 million in the corresponding period in 2018. This change was primarily due to a preliminary gain of $2.5 billion ($1.3 billion after tax) on the sale of Gulf Power.
See Note (K) to the Condensed Financial Statements under "Southern Company" herein for additional information.
Interest Expense, Net of Amounts Capitalized
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(41) | | (8.7) | | $(69) | | (7.4) |
In the second quarter 2019, interest expense, net of amounts capitalized was $429 million compared to $470 million in the corresponding period in 2018. For year-to-date 2019, interest expense, net of amounts capitalized was $859 million compared to $928 million in the corresponding period in 2018. Excluding decreases of $13 million and $26 million in the second quarter and year-to-date 2019, respectively, related to the sale of Gulf Power, the decreases were primarily due to a decrease in average outstanding long-term debt, primarily at the parent company.
See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein, Note 8 to the financial statements in Item 8 of the Form 10-K, and Note (F) to the Condensed Financial Statements herein for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Income (Expense), Net
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $21 | | 26.9 | | $38 | | 27.5 |
In the second quarter 2019, other income (expense), net was $99 million compared to $78 million for the corresponding period in 2018. For year-to-date 2019, other income (expense), net was $176 million compared to $138 million for the corresponding period in 2018. These increases were primarily due to a $36 million gain arising from the settlement of litigation related to the Roserock solar facility at Southern Power in June 2019, partially offset by $24 million due to the settlement of Mississippi Power's Deepwater Horizon claim in May 2018. Also contributing to these increases were $7 million and $13 million for the second quarter and year-to-date 2019, respectively, of non-service cost-related pension income and $10 million for year-to-date 2019 of increased interest income from temporary cash investments at the parent company. See Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein and Note 3 to the financial statements under "Other Matters – Mississippi Power," in Item 8 of the Form 10-K for additional information.
Income Taxes (Benefit)
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $284 | | N/M | | $1,530 | | N/M |
N/M - Not meaningful
In the second quarter 2019, income taxes were $145 million compared to an income tax benefit of $139 million for the corresponding period in 2018. The change was primarily due to the reduction in pre-tax earnings in the second quarter 2018 resulting from the charge associated with Plant Vogtle Units 3 and 4 construction.
For year-to-date 2019, income taxes were $1.5 billion compared to an income tax benefit of $25 million for the corresponding period in 2018. The change was primarily due to the tax impacts related to the sale of Gulf Power and the reduction in pre-tax earnings in the second quarter 2018 resulting from the charge associated with Plant Vogtle Units 3 and 4 construction.
See Notes (G) and (K) to the Condensed Financial Statements herein for additional information.
Net Income Attributable to Noncontrolling Interests
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $6 | | 26.1 | | $(17) | | N/M |
N/M - Not meaningful
Substantially all noncontrolling interests relate to renewable projects at Southern Power. See Notes 1 and 7 to the financial statements in Item 8 of the Form 10-K under "General" and "Southern Power," respectively, for additional information.
In the second quarter 2019, net income attributable to noncontrolling interests was $29 million compared to $23 million for the corresponding period in 2018. The increase was primarily due to an allocation of approximately $26 million of income to the noncontrolling interest partner related to the Roserock solar facility litigation settlement, partially offset by $25 million of losses attributable to noncontrolling interests related to the tax equity partnerships entered into in 2018.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2019, net income attributable to noncontrolling interests was immaterial compared to $17 million for the corresponding period in 2018. The decrease was primarily due to $48 million of losses attributable to noncontrolling interests related to the tax equity partnerships entered into in 2018, partially offset by an allocation of approximately $29 million of income to the noncontrolling interest partner related to the Roserock solar facility litigation settlement.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern Company's future earnings potential. Future earnings will be impacted by the recently completed and additional pending disposition activities described 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. 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 constructive regulatory environments that allow for the timely recovery of prudently-incurred costs during a time of increasing costs, continued customer growth, and, for the traditional electric operating companies, the weak pace of growth in electricity use per customer, especially in residential and commercial markets. Plant Vogtle Units 3 and 4 construction and rate recovery and the profitability of Southern Power's competitive wholesale business are also major factors.
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 more multi-family home construction, all of which could contribute to a net reduction in customer usage. 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, the development or acquisition of renewable facilities and other 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 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.
On June 13, 2019, Southern Power completed the sale of its equity interests in Nacogdoches Power, LLC, the owner of an approximately 115-MW biomass facility located in Nacogdoches County, Texas, to Austin Energy, for an aggregate cash purchase price of approximately $461 million, including working capital adjustments.
On May 4, 2019, Southern Power achieved commercial operation of the 385-MW natural gas expansion unit at Plant Mankato and started providing energy under a PPA with Northern States Power on June 1, 2019. The sale of Plant Mankato to Northern States Power remains subject to state commission approvals and is expected to close in fall 2019. If these state commission approvals are not obtained by October 1, 2019, either party has the option to
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
terminate the sale, which, if elected, would result in the payment of a $15 million termination fee by Northern States Power to Southern Power. The ultimate outcome of this matter cannot be determined at this time.
For additional information relating to these issues, see RISK FACTORS and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Company in Item 7 of the Form 10-K.
Environmental Matters
The Southern Company system's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. The Southern Company system maintains comprehensive environmental compliance and GHG strategies to assess upcoming requirements and compliance costs associated with these environmental laws and regulations and to achieve stated goals. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, or changing fuel sources for certain existing units, as well as related upgrades to the Southern Company system's transmission and distribution (electric and natural gas) systems, and may impact future electric generating unit retirement and replacement decisions, results of operations, cash flows, and/or financial condition. A major portion of these costs is expected to be recovered through retail and wholesale rates. The ultimate impact of environmental laws and regulations and GHG goals will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed technology, fuel prices, and the outcome of pending and/or future legal challenges.
New or revised environmental laws and regulations could affect many areas of the traditional electric operating companies', Southern Power's, and the natural gas distribution utilities' operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be 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. Further, increased 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/or financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity and natural gas. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company in Item 7 and Note 3 to the financial statements under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Laws and Regulations
Coal Combustion Residuals
In June 2019, Alabama Power recorded an increase of approximately $308 million to its AROs primarily related to the CCR Rule and the related state rule based on management's completion of closure designs during the second quarter 2019 for all but two of its ash pond facilities, including one jointly owned with Mississippi Power. The additional estimated costs to close these ash ponds under the planned closure-in-place methodology primarily relate to cost inputs from contractor bids, internal drainage and dewatering system designs, and increases in the estimated ash volumes. The cost estimate for the remaining ash pond facilities will be updated within the next 12 months and the change could be material.
As further analysis is performed and additional details are developed with respect to ash pond closures, the traditional electric operating companies expect to periodically update their ARO cost estimates. 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, Southern Company's results of operations, cash flows, and financial condition could be materially impacted. The ultimate outcome of these matters cannot be determined at this time. See Note 6 to the financial statements in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Global Climate Issues
On July 8, 2019, the EPA published the final Affordable Clean Energy rule (ACE Rule) to repeal and replace the CPP. Implementation of the CPP has been stayed by the U.S. Supreme Court since 2016. The ACE Rule requires states to develop unit-specific CO2 emission rate standards for existing coal-fired units based on heat-rate efficiency improvements. Combustion turbines, including natural gas combined cycles, are not included as affected sources in the ACE Rule. The Southern Company system has ownership interests in 19 coal-fired units to which the ACE Rule is applicable. The ultimate impact of the ACE Rule, including the repeal and replacement of the CPP, to the Southern Company system will depend on state implementation plan requirements and the outcome of any associated legal challenges and cannot be determined at this time.
Regulatory Matters
See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.
Fuel Cost Recovery
The traditional electric operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow. The traditional electric operating companies continuously monitor their under or over recovered fuel cost balances and make appropriate filings with their state PSCs to adjust fuel cost recovery rates as necessary.
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.
Environmental Accounting Order
On April 15, 2019, Alabama Power retired Plant Gorgas Units 8, 9, and 10 and reclassified approximately $654 million of the unrecovered asset balances to regulatory assets, which are being recovered over the units' remaining useful lives, the latest being through 2037, as established prior to the decision to retire. Additionally, approximately $700 million of net capitalized asset retirement costs were reclassified to a regulatory asset in accordance with accounting guidance provided by the Alabama PSC. The asset retirement costs are being recovered through 2055. See Note 2 to the financial statements under "Alabama Power – Environmental Accounting Order" and Note 6 in Item 8 of the Form 10-K for additional information.
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 (ECCR) tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to 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.
Rate Plans
On June 28, 2019, Georgia Power filed a base rate case (Georgia Power 2019 Base Rate Case) with the Georgia PSC. The filing includes a three-year Alternate Rate Plan with requested rate increases totaling $563 million, $145 million, and $234 million effective January 1, 2020, January 1, 2021, and January 1, 2022, respectively. These
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
increases are based on a proposed retail ROE of 10.90% and a proposed equity ratio of 56% and reflect levelized revenue requirements during the three-year period, with the exception of incremental compliance costs related to CCR AROs, Demand-Side Management programs, and adjustments to the Municipal Franchise Fee tariff.
Georgia Power has requested recovery of the proposed increases through its existing base rate tariffs as follows:
|
| | | | | | | | | |
| Tariff | 2020 | 2021 | 2022 |
| | (in millions) |
| Traditional base: | | | |
| Levelized | $ | 209 |
| $ | — |
| $ | — |
|
| CCR AROs | 158 |
| 140 |
| 227 |
|
| ECCR | 165 |
| — |
| — |
|
| Demand-Side Management | 14 |
| 2 |
| 1 |
|
| Municipal Franchise Fee | 17 |
| 3 |
| 5 |
|
Total(*) | $ | 563 |
| $ | 145 |
| $ | 234 |
|
| |
| (*) | Totals may not add due to rounding. |
Georgia Power's filing primarily reflects requests to (i) address the impacts of the Tax Reform Legislation, (ii) recover the costs of recent and future capital investments in infrastructure designed to maintain high levels of reliability and superior customer service with updated depreciation rates, (iii) recover substantial storm damage expenses incurred and deferred since 2013 along with a reasonable level of storm damage expenses expected to be incurred during the three years ending December 31, 2022, and (iv) recover the costs necessary to comply with federal and state regulations for CCR AROs. In addition, the filing includes the following provisions:
Continuation of an allowed retail ROE range of 10.00% to 12.00%.
Continuation of the process whereby two-thirds of any earnings above the top of the allowed ROE range are shared with Georgia Power's customers and the remaining one-third are retained by Georgia Power.
Continuation of the option to file an Interim Cost Recovery tariff in the event earnings are projected to fall below the bottom of the ROE range during the three-year term of the plan.
Georgia Power expects the Georgia PSC to issue a final order in this matter on December 17, 2019. The ultimate outcome of this matter cannot be determined at this time.
Integrated Resource Plan
In 2016, the Georgia PSC approved Georgia Power's triennial Integrated Resource Plan, including recovery of costs up to $99 million through June 30, 2019 to preserve nuclear generation as an option at a future generation site in Stewart County, Georgia. In 2017, the Georgia PSC approved Georgia Power's decision to suspend work at the site due to changing economics, including lower load forecasts and fuel costs. In accordance with the Georgia PSC's order, costs incurred of approximately $50 million have been recorded as a regulatory asset.
On July 16, 2019, the Georgia PSC voted to approve Georgia Power's triennial Integrated Resource Plan (2019 IRP) as modified by a stipulated agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors and further modified by the Georgia PSC.
In the 2019 IRP, the Georgia PSC approved the decertification and retirement of Plant Hammond Units 1 through 4 (840 MWs) and Plant McIntosh Unit 1 (142.5 MWs) effective July 29, 2019. The Georgia PSC also approved the reclassification of the remaining net book values of the Plant Hammond and Plant McIntosh units (approximately $500 million and $40 million, respectively, at June 30, 2019), as well as any unusable materials and supplies inventory balances, upon retirement to a regulatory asset. Recovery of each unit's net book value will continue through December 31, 2019 as provided in the 2013 ARP.
For the regulatory asset balances remaining at December 31, 2019, Georgia Power requested recovery in the Georgia Power 2019 Base Rate Case as follows: (i) the net book values of Plant Mitchell Unit 3 (approximately $8
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
million at June 30, 2019) and Plant McIntosh Unit 1, any unusable materials and supplies inventory, and the future generation site in Stewart County, Georgia over a three-year period ending December 31, 2022 and (ii) the net book values of Plant Hammond Units 1 through 4 over a period equal to the applicable unit's remaining useful life through 2035. The ultimate outcome of these matters cannot be determined at this time.
Also in the 2019 IRP, the Georgia PSC rejected a request to certify approximately 25 MWs of capacity at Plant Scherer Unit 3 for the retail jurisdiction beginning January 1, 2020 following the expiration of a wholesale PPA. Georgia Power may offer such capacity in the wholesale market or to the retail jurisdiction in a future Integrated Resource Plan. The ultimate outcome of this matter cannot be determined at this time but is not expected to have a material impact on Southern Company's financial statements.
Additionally, the Georgia PSC approved Georgia Power's proposed environmental compliance strategy associated with ash pond and certain landfill closures and post-closure care in compliance with the CCR Rule and the related state rule. In the Georgia Power 2019 Base Rate Case, Georgia Power requested recovery of the under recovered balance of these compliance costs at December 31, 2019 (approximately $135 million at June 30, 2019) over a three-year period ending December 31, 2022 and recovery of estimated compliance costs of $277 million for 2020, $395 million for 2021, and $655 million for 2022 over three-year periods ending December 31, 2022, 2023, and 2024, respectively. The ultimate outcome of this matter cannot be determined at this time. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information regarding Georgia Power's AROs.
The Georgia PSC also approved Georgia Power to (i) issue requests for proposals (RFP) for capacity beginning in 2022 or 2023 and in 2026, 2027, or 2028; (ii) procure up to an additional 2,210 MWs of renewable resources through competitive RFPs; and (iii) invest in a portfolio of up to 80 MWs of battery energy storage technologies.
See "Rate Plans" herein for additional information regarding the Georgia Power 2019 Base Rate Case.
Mississippi Power
Kemper County Energy Facility
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. 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 Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.
During the second quarter and year-to-date 2019, Mississippi Power recorded pre-tax charges to income of $4 million ($3 million after tax) and $6 million ($5 million after tax), respectively, primarily resulting from the abandonment and related closure activities and ongoing period costs, net of sales proceeds, for the mine and gasifier-related assets at the Kemper County energy facility. Additional closure costs for the mine and gasifier-related assets, currently estimated at up to $10 million pre-tax (excluding dismantlement costs, net of salvage), may be incurred through the first half of 2020. In addition, period costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the mine and gasifier-related assets, are estimated at $7 million for the remainder of 2019 and $2 million to $6 million annually in 2020 through 2023.
In addition, Mississippi Power constructed the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery and is currently evaluating its options regarding the final disposition of the CO2 pipeline, including removal of the pipeline. This evaluation is expected to be complete later in 2019. If Mississippi Power ultimately decides to remove the CO2 pipeline, the cost of removal could have a material impact on Southern Company's financial statements.
In December 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the $387 million of grants received. Mississippi Power and the DOE are currently in discussions regarding the requested closeout and property disposition, which may require payment to the DOE for a portion of certain property that is to be retained by Mississippi Power. In connection with the DOE closeout discussions, on April 29, 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
of an investigation related to the Kemper County energy facility. The ultimate outcome of these matters cannot be determined at this time; however, they could have a material impact on Southern Company's financial statements.
Southern Company Gas
The natural gas distribution utilities are subject to regulation and oversight by their respective state regulatory agencies for the rates charged 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 regulatory agencies in the states in which 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 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 and energy efficiency plans.
In November 2018, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $230 million increase in annual base rate revenues. The requested increase is based on a projected test year for the 12-month period ending September 30, 2020, a ROE of 10.6%, and an increase in the equity ratio from 52% to 54% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation.
On April 16, 2019, Nicor Gas entered into a stipulation agreement to resolve all related issues with the Staff of the Illinois Commission, including a ROE of 9.86% and an equity ratio of 54%. Also on April 16, 2019, Nicor Gas filed its rebuttal testimony with the Illinois Commission incorporating the stipulation agreement and addressing the remaining items outstanding with the other two intervenors. As a result of the stipulation agreement and rebuttal testimony, the revised requested annual revenue increase is $180 million.
The Illinois Commission is expected to rule on the requested increase by early October 2019, after which rate adjustments will be effective.
On June 3, 2019, Atlanta Gas Light filed a general base rate case with the Georgia PSC requesting a $96 million increase in annual base rate revenues. The requested increase is based on a forward-looking test year for the 12-month period ending July 31, 2020, a ROE of 10.75% with an earnings band based on a ROE between 10.55% and 10.95%, and a continued equity ratio of 55%. The filing also requests the continuation of the Georgia rate adjustment mechanism, as previously authorized. Atlanta Gas Light expects the Georgia PSC to issue a final order on this matter on December 19, 2019 with the new rates becoming effective January 1, 2020.
The ultimate outcome of these matters cannot be determined at this time.
Construction Program
See RESULTS OF OPERATIONS – "Estimated Loss on Kemper IGCC," FUTURE EARNINGS POTENTIAL – "Construction Program,"
Net Income (Loss)
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1,053 | | N/M | | $2,198 | | N/M |
N/M - Not meaningful
Consolidated net income attributable to Southern Company was $899 million ($0.86 per share) for the second quarter 2019 compared to a net loss of $154 million ($(0.15) per share) for the corresponding period in 2018. The change was primarily due to a $1.1 billion ($0.8 billion after tax) charge in the second quarter 2018 for an estimated probable loss related to Georgia Power's construction of Plant Vogtle Units 3 and Note (B)4 and a decrease in operations and maintenance expenses.
Consolidated net income attributable to Southern Company was $3.0 billion ($2.86 per share) for year-to-date 2019 compared to $784 million ($0.77 per share) for the corresponding period in 2018. The increase was primarily due to the Condensed Financial Statements under "Regulatory Matters – $2.5 billion ($1.3 billion after tax) gain on the sale of Gulf Power in 2019 and a $1.1 billion ($0.8 billion after tax) charge in the second quarter 2018 for an estimated probable loss related to 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 AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 subjectPlant Vogtle Units 3 and 4. See Note (K) to the construction cost cap,Condensed Financial Statements under "Southern Company" herein 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 32 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of Southern Companythe Form 10-K for additional information.
Retail Electric Revenues
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(200) | | (5.3) | | $(685) | | (9.4) |
In the second quarter 2019, retail electric revenues were $3.5 billion compared to $3.7 billion for the corresponding period in 2018. For year-to-date 2019, retail electric revenues were $6.6 billion compared to $7.3 billion for the corresponding period in 2018.
Details of the changes in retail electric revenues were as follows:
|
| | | | | | | | | | | | | | |
| | | Second Quarter 2019 | | Year-to-Date 2019 |
| | | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail electric – prior year | | $ | 3,740 |
| | | | $ | 7,308 |
| | |
| Estimated change resulting from – | | | | | | | | |
| Rates and pricing | | 125 |
| | 3.3 | % | | 182 |
| | 2.5 | % |
| Sales decline | | (30 | ) | | (0.8 | ) | | (41 | ) | | (0.6 | ) |
| Weather | | 34 |
| | 0.9 |
| | (56 | ) | | (0.8 | ) |
| Fuel and other cost recovery | | (28 | ) | | (0.7 | ) | | (179 | ) | | (2.4 | ) |
| Gulf Power disposition | | (301 | ) | | (8.0 | ) | | (591 | ) | | (8.1 | ) |
| Retail electric – current year | | $ | 3,540 |
| | (5.3 | )% | | $ | 6,623 |
| | (9.4 | )% |
Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018 primarily due to increased revenues at Alabama Power due to the impacts of customer bill credits related to the Tax Reform Legislation in 2018 and increases to CNP Compliance revenue, increases in the NCCR tariff effective January 1, 2019 at Georgia Power, and increases in PEP and ECO Plan rates that became effective for the first billing cycle of September 2018 at Mississippi Power. The year-to-date 2019 increase also reflects the rate pricing effect of decreased customer usage, partially offset by lower contributions from commercial and industrial customers with variable demand-driven pricing at Georgia Power.
See Note 2 to the financial statements under "Integrated Coal Gasification Combined Cycle""Alabama Power," "Georgia Power," and "Mississippi Power" 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.herein for additional information.
Revenues attributable to changes in sales decreased in the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018. Weather-adjusted residential KWH sales decreased 1.0% and 0.3% in the second quarter and year-to-date 2019, respectively, when compared to the corresponding periods in 2018 primarily due to decreased customer usage primarily resulting from an increase in energy efficient residential appliances, partially offset by customer growth. Weather-adjusted commercial KWH sales decreased 1.3% and 1.6% in the second quarter and year-to-date 2019, respectively, when compared to the corresponding periods in 2018 primarily due to decreased customer usage resulting from an increase in energy saving initiatives. Industrial KWH sales decreased 2.0% in both the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018 as a result of a decrease in demand resulting from changes in production levels primarily in the primary metals, chemicals, stone, clay, and glass, textile, and paper sectors.
Fuel and other cost recovery revenues decreased $28 million and $179 million in the second quarter and year-to-date 2019, respectively, compared to the corresponding periods in 2018 primarily due to decreases in generation and the average cost of fuel. The year-to-date decrease was also driven by milder weather in the first quarter 2019.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Nuclear ConstructionElectric 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.
On March 29, 2017,Wholesale Electric Revenues
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(74) | | (12.0) | | $(198) | | (16.0) |
Wholesale electric revenues consist of 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 EPC Contractorgreatest 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 Plant Vogtle Units 3energy within the Southern Company system's electric service territory, and 4 filed for bankruptcy protection under Chapter 11the availability of the U.S. Bankruptcy Code. To provide forSouthern 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 continuationsignificant 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 work, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered intoa dedicated renewable facility through 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 intoenergy charge or through a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement). Pursuantfixed price related to the Guarantee Settlement Agreement, Toshiba acknowledgedenergy. As a result, the amountability to recover fixed and variable operations and maintenance expenses is dependent upon the level of its obligationenergy 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 Toshiba Guarantee is $3.68 billion (Guarantee Obligations), of which Georgia Power's proportionate share is approximately $1.7 billion, and thatSouthern Company system's variable cost to produce 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.energy.
In the seventeenth Vogtle Construction Monitoring (VCM) report filed on August 31, 2017, Georgiasecond quarter 2019, wholesale electric revenues were $542 million compared to $616 million for the corresponding period in 2018. For year-to-date 2019, wholesale electric revenues were $1.0 billion compared to $1.2 billion for the corresponding period in 2018. The second quarter 2019 decrease was related to a $54 million decrease in energy revenues and a $20 million decrease in capacity revenues. The year-to-date 2019 decrease was related to a $160 million decrease in energy revenues and a $38 million decrease in capacity revenues. Excluding decreases of $7 million and $13 million of energy revenues for the second quarter and year-to-date 2019, respectively, related to the sale of Gulf Power, recommended that constructionthe decreases in energy revenues primarily related to Southern Power and included a decrease in non-PPA revenues due to a decrease in the volume of Plant Vogtle Units 3KWHs sold through short-term sales and 4 be continued, with Southern Nuclear serving as project manager. Georgia Power believes thata decrease in revenues from natural gas PPAs due to a decrease in 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 additionalaverage cost of approximately $1.41 billion, net offuel and purchased power. These decreases were also due to lower fuel prices and lower customer demand at the Guarantee Settlement Agreement.traditional electric operating companies. 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 billiondecreases 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 subjectcapacity revenues primarily related to the negotiationsales of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals,Gulf Power and satisfaction of other conditions.Southern Power's Plant Oleander and Plant Stanton Unit A in December 2018. See Note 615 to the financial statements under "Southern Power – Sales of Southern Company under "DOE Loan Guarantee Borrowings"Natural Gas Plants" 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 conditionsinformation.
Natural Gas Revenues
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(17) | | (2.4) | | $(151) | | (6.5) |
In the second quarter 2019, natural gas revenues were $689 million compared to borrowing.$706 million for the corresponding period in 2018. For year-to-date 2019, natural gas revenues were $2.2 billion compared to $2.3 billion for the corresponding period in 2018.
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
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of the changes in natural gas revenues were as follows:
|
| | | | | | | | | | | | | |
| | Second Quarter 2019 | | Year-to-Date 2019 |
| | (in millions) | | (% change) | | (in millions) | | (% change) |
| Natural gas revenues – prior year | $ | 706 |
| | | | $ | 2,314 |
| | |
| Estimated change resulting from – | | | | | | | |
| Infrastructure replacement programs and base rate changes | 10 |
| | 1.4 | % | | 42 |
| | 1.8 | % |
| Gas costs and other cost recovery | (13 | ) | | (1.8 | ) | | 49 |
| | 2.1 |
|
| Weather | (7 | ) | | (1.1 | ) | | — |
| | — |
|
| Wholesale gas services | 64 |
| | 9.1 |
| | (16 | ) | | (0.7 | ) |
| Southern Company Gas Dispositions | (70 | ) | | (9.9 | ) | | (237 | ) | | (10.2 | ) |
| Other | (1 | ) | | (0.1 | ) | | 11 |
| | 0.5 |
|
| Natural gas revenues – current year | $ | 689 |
| | (2.4 | )% | | $ | 2,163 |
| | (6.5 | )% |
Revenues attributable to infrastructure replacement programs and base rate changes at the natural gas distribution utilities increased in the second quarter and year-to-date 2019 compared to the corresponding periods in 2018 primarily due to increases of $4 million and $25 million, respectively, at Nicor Gas and $5 million and $14 million, respectively, at Atlanta Gas Light. These amounts include the natural gas distribution utilities' continued investments recovered through infrastructure replacement programs and base rate increases as well as increases due to the impacts of the Tax Reform Legislation.
Revenues attributable to gas costs and other cost recovery decreased in the second quarter 2019 and increased year-to-date 2019 compared to the corresponding periods in 2018. The decrease in the second quarter 2019 is primarily due to lower natural gas prices and decreased volumes of natural gas sold. The increase for year-to-date 2019 is primarily due to increased natural gas prices in the first quarter 2019, partially offset by decreased volumes of natural gas sold year-to-date 2019. 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.
Revenues decreased in the second quarter 2019 due to warmer weather, as determined by Heating Degree Days, in Illinois and Georgia compared to the corresponding period in 2018.
Revenues attributable to Southern Company Gas' wholesale gas services business increased in the second quarter 2019 and decreased year-to-date 2019 compared to the corresponding periods in 2018. The increase in the second quarter 2019 is primarily due to derivative gains, partially offset by decreased commercial activity. For year-to-date 2019, the decrease is primarily due to decreased commercial activity, partially offset by derivative gains.
See Note (B) to the Condensed Financial Statements herein under "Southern Company Gas" for additional information.
Other Revenues
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(229) | | (58.0) | | $(456) | | (56.4) |
In the second quarter 2019, other revenues were $166 million compared to $395 million for the corresponding period in 2018. For year-to-date 2019, other revenues were $352 million compared to $808 million for the corresponding period in 2018. These decreases were primarily related to PowerSecure's 2018 storm restoration services in Puerto Rico.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | |
| | Second Quarter 2019
vs.
Second Quarter 2018 | | Year-to-Date 2019
vs.
Year-to-Date 2018 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | (189 | ) | | (17.1) | | $ | (440 | ) | | (20.0) |
| Purchased power | (35 | ) | | (14.8) | | (132 | ) | | (26.2) |
| Total fuel and purchased power expenses | $ | (224 | ) | | | | $ | (572 | ) | | |
In the second quarter 2019, total fuel and purchased power expenses were $1.1 billion compared to $1.3 billion for the corresponding period in 2018. Excluding approximately $126 million associated with the sale of Gulf Power, the decrease was primarily the result of an $81 million decrease in the average cost of fuel and purchased power and a $17 million net decrease in the aggregate volume of KWHs generated and purchased.
For year-to-date 2019, total fuel and purchased power expenses were $2.1 billion compared to $2.7 billion for the corresponding period in 2018. Excluding approximately $225 million associated with the sale of Gulf Power, the decrease was primarily the result of a $198 million decrease in the average cost of fuel and purchased power and a $149 million decrease in the aggregate 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.
Details of the Southern Company system's generation and purchased power were as follows:
|
| | | | | | | |
| | Second Quarter 2019 | | Second Quarter 2018(a) | | Year-to-Date 2019 | | Year-to-Date 2018(a) |
Total generation (in billions of KWHs) | 46 | | 47 | | 90 | | 93 |
Total purchased power (in billions of KWHs) | 4 | | 4 | | 8 | | 7 |
Sources of generation (percent) — | | | | | | | |
| Gas | 52 | | 45 | | 50 | | 45 |
| Coal | 22 | | 29 | | 22 | | 29 |
| Nuclear | 16 | | 15 | | 16 | | 16 |
| Hydro | 3 | | 3 | | 5 | | 3 |
| Other | 7 | | 8 | | 7 | | 7 |
Cost of fuel, generated (in cents per net KWH)— | | | | | | | |
| Gas | 2.39 | | 2.71 | | 2.47 | | 2.78 |
| Coal | 3.04 | | 2.71 | | 2.98 | | 2.80 |
| Nuclear | 0.80 | | 0.82 | | 0.80 | | 0.80 |
Average cost of fuel, generated (in cents per net KWH) | 2.26 | | 2.39 | | 2.29 | | 2.43 |
Average cost of purchased power (in cents per net KWH)(b) | 4.89 | | 5.18 | | 5.04 | | 6.11 |
| |
| (a) | Excludes Gulf Power, which was sold on January 1, 2019. |
| |
| (b) | Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider. |
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel
In the second quarter 2019, fuel expense was $0.9 billion compared to $1.1 billion for the corresponding period in 2018. Excluding approximately $74 million related to Gulf Power in 2018, the decrease was primarily due to a 26.2% decrease in the volume of KWHs generated by coal and an 11.8% decrease in the average cost of natural gas per KWH generated, partially offset by a 12.2% increase in the average cost of coal per KWH generated and a 12.1% increase in the volume of KWHs generated by natural gas.
For year-to-date 2019, fuel expense was $1.8 billion compared to $2.2 billion for the corresponding period in 2018. Excluding approximately $127 million related to Gulf Power in 2018, the decrease was primarily due to a 27.6% decrease in the volume of KWHs generated by coal and an 11.2% decrease in the average cost of natural gas per KWH generated, partially offset by a 6.6% increase in the volume of KWHs generated by natural gas and a 6.4% increase in the average cost of coal per KWH generated.
Purchased Power
In the second quarter 2019, purchased power expense was $201 million compared to $236 million for the corresponding period in 2018. This decrease was primarily associated with Gulf Power.
For year-to-date 2019, purchased power expense was $371 million compared to $503 million for the corresponding period in 2018. Excluding approximately $98 million associated with Gulf Power, the decrease was primarily due to a 17.5% decrease in the average cost per KWH purchased and a 2.1% decrease in the volume of KWHs purchased.
See Note (K) to the Condensed Financial Statements under "Southern Company" herein for information regarding the sale of Gulf Power.
Energy purchases will vary depending on demand for energy within the Southern Company system's electric service territory, the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, and the availability of the Southern Company system's generation.
Cost of Natural Gas
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(37) | | (16.2) | | $(72) | | (7.6) |
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 80% and 85% of total cost of natural gas for the second quarter and year-to-date 2019, respectively.
In the second quarter 2019, cost of natural gas was $191 million compared to $228 million for the corresponding period in 2018. Excluding a $25 million decrease related to the Southern Company Gas Dispositions, cost of natural gas decreased $12 million.
For year-to-date 2019, cost of natural gas was $877 million compared to $949 million for the corresponding period in 2018. Excluding a $104 million decrease related to the Southern Company Gas Dispositions, cost of natural gas increased $32 million. This increase reflects an increase in natural gas prices, partially offset by a decrease in the volume of natural gas sold year-to-date 2019 compared to the corresponding period in 2018.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Cost of Other Sales
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(195) | | (69.9) | | $(365) | | (64.3) |
In the second quarter 2019, cost of other sales was $84 million compared to $279 million for the corresponding period in 2018. For year-to-date 2019, cost of other sales was $203 million compared to $568 million for the corresponding period in 2018. These decreases were primarily related to PowerSecure's 2018 storm restoration services in Puerto Rico.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(207) | | (13.6) | | $(344) | | (11.6) |
In the second quarter 2019, other operations and maintenance expenses were $1.3 billion compared to $1.5 billion for the corresponding period in 2018. For year-to-date 2019, other operations and maintenance expenses were $2.6 billion compared to $3.0 billion for the corresponding period in 2018. The second quarter and year-to-date 2019 decreases reflect approximately $90 million and $166 million, respectively, related to Gulf Power in 2018 and $34 million and $105 million, respectively, related to the Southern Company Gas Dispositions. These decreases also reflect an asset impairment charge of $119 million recorded in the second quarter 2018 at Southern Power related to the sale of Southern Power's Florida plants. These decreases were partially offset by a $32 million goodwill impairment charge in the second quarter 2019 in contemplation of the sale of PowerSecure's utility infrastructure services business unit. See Note (K) to the Condensed Financial Statements under "Southern Company" herein and Note 15 to the financial statements under "Southern Power" and "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Depreciation and Amortization
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(28) | | (3.6) | | $(46) | | (3.0) |
In the second quarter 2019, depreciation and amortization was $755 million compared to $783 million for the corresponding period in 2018. For year-to-date 2019, depreciation and amortization was $1.5 billion compared to $1.6 billion for the corresponding period in 2018. The second quarter and year-to-date 2019 decreases were primarily due to decreases of $48 million and $95 million, respectively, related to the sale of Gulf Power and decreases of $10 million and $26 million, respectively, related to the Southern Company Gas Dispositions, partially offset by increases of $29 million and $62 million, respectively, related to additional plant in service.
Taxes Other Than Income Taxes
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(17) | | (5.4) | | $(43) | | (6.4) |
In the second quarter 2019, taxes other than income taxes were $299 million compared to $316 million for the corresponding period in 2018. For year-to-date 2019, taxes other than income taxes were $628 million compared to $671 million for the corresponding period in 2018. These decreases primarily relate to the sale of Gulf Power.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Estimated Loss on Plants Under Construction
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(1,056) | | (99.6) | | $(1,099) | | (99.5) |
In the second quarter 2019, estimated loss on plants under construction was $4 million compared to $1.06 billion for the corresponding period in 2018. For year-to-date 2019, estimated loss on plants under construction was $6 million compared to $1.11 billion for the corresponding period in 2018. These decreases were primarily due to the $1.1 billion charge recorded in the second quarter 2018 as a result of Georgia Power's revised estimate to complete construction and start-up of Plant Vogtle Units 3 and 4. The second quarter and year-to-date 2019 charges were related to abandonment and closure activities for the mine and gasifier-related assets of the Kemper IGCC at Mississippi Power.
See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Georgia Power – Nuclear Construction" for additional information.
(Gain) Loss on Dispositions, Net
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $44 | | N/M | | $2,542 | | N/M |
N/M - Not meaningful
In the second quarter 2019, gain on dispositions, net was $8 million compared to a loss on dispositions, net of $36 million in the corresponding period in 2018. This change was primarily due to a $36 million loss on the sale of Pivotal Home Solutions at Southern Company Gas recorded in 2018 and a $23 million gain as a result of the sale of Southern Power's Plant Nacogdoches in the second quarter 2019, partially offset by a $15 million adjustment to the preliminary gain on the sale of Gulf Power.
For year-to-date 2019, gain on dispositions, net was $2.5 billion compared to a loss on dispositions, net of $36 million in the corresponding period in 2018. This change was primarily due to a preliminary gain of $2.5 billion ($1.3 billion after tax) on the sale of Gulf Power.
See Note (K) to the Condensed Financial Statements under "Southern Company" herein for additional information.
Interest Expense, Net of Amounts Capitalized
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(41) | | (8.7) | | $(69) | | (7.4) |
In the second quarter 2019, interest expense, net of amounts capitalized was $429 million compared to $470 million in the corresponding period in 2018. For year-to-date 2019, interest expense, net of amounts capitalized was $859 million compared to $928 million in the corresponding period in 2018. Excluding decreases of $13 million and $26 million in the second quarter and year-to-date 2019, respectively, related to the sale of Gulf Power, the decreases were primarily due to a decrease in average outstanding long-term debt, primarily at the parent company.
See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein, Note 8 to the financial statements in Item 8 of the Form 10-K, and Note (F) to the Condensed Financial Statements herein for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Income (Expense), Net
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $21 | | 26.9 | | $38 | | 27.5 |
In the second quarter 2019, other income (expense), net was $99 million compared to $78 million for the corresponding period in 2018. For year-to-date 2019, other income (expense), net was $176 million compared to $138 million for the corresponding period in 2018. These increases were primarily due to a $36 million gain arising from the settlement of litigation related to the Roserock solar facility at Southern Power in June 2019, partially offset by $24 million due to the settlement of Mississippi Power's Deepwater Horizon claim in May 2018. Also contributing to these increases were $7 million and $13 million for the second quarter and year-to-date 2019, respectively, of non-service cost-related pension income and $10 million for year-to-date 2019 of increased interest income from temporary cash investments at the parent company. See Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein and Note 3 to the financial statements under "Other Matters – Mississippi Power," in Item 8 of the Form 10-K for additional information.
Income Taxes (Benefit)
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $284 | | N/M | | $1,530 | | N/M |
N/M - Not meaningful
In the second quarter 2019, income taxes were $145 million compared to an income tax benefit of $139 million for the corresponding period in 2018. The change was primarily due to the reduction in pre-tax earnings in the second quarter 2018 resulting from the charge associated with Plant Vogtle Units 3 and 4 construction.
For year-to-date 2019, income taxes were $1.5 billion compared to an income tax benefit of $25 million for the corresponding period in 2018. The change was primarily due to the tax impacts related to the sale of Gulf Power and the reduction in pre-tax earnings in the second quarter 2018 resulting from the charge associated with Plant Vogtle Units 3 and 4 construction.
See Notes (G) and (K) to the Condensed Financial Statements herein for additional information.
Net Income Attributable to Noncontrolling Interests
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $6 | | 26.1 | | $(17) | | N/M |
N/M - Not meaningful
Substantially all noncontrolling interests relate to renewable projects at Southern Power. See Notes 1 and 7 to the financial statements in Item 8 of the Form 10-K under "General" and "Southern Power," respectively, for additional information.
In the second quarter 2019, net income attributable to noncontrolling interests was $29 million compared to $23 million for the corresponding period in 2018. The increase was primarily due to an allocation of approximately $26 million of income to the noncontrolling interest partner related to the Roserock solar facility litigation settlement, partially offset by $25 million of losses attributable to noncontrolling interests related to the tax equity partnerships entered into in 2018.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2019, net income attributable to noncontrolling interests was immaterial compared to $17 million for the corresponding period in 2018. The decrease was primarily due to $48 million of losses attributable to noncontrolling interests related to the tax equity partnerships entered into in 2018, partially offset by an allocation of approximately $29 million of income to the noncontrolling interest partner related to the Roserock solar facility litigation settlement.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern Company's future earnings potential. Future earnings will be impacted by the recently completed and additional pending disposition activities described 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. 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 constructive regulatory environments that allow for the timely recovery of prudently-incurred costs during a time of increasing costs, continued customer growth, and, for the traditional electric operating companies, the weak pace of growth in electricity use per customer, especially in residential and commercial markets. Plant Vogtle Units 3 and 4 construction and rate recovery and the profitability of Southern Power's competitive wholesale business are also major factors.
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 more multi-family home construction, all of which could contribute to a net reduction in customer usage. 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, the development or acquisition of renewable facilities and other 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 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.
On June 13, 2019, Southern Power completed the sale of its equity interests in Nacogdoches Power, LLC, the owner of an approximately 115-MW biomass facility located in Nacogdoches County, Texas, to Austin Energy, for an aggregate cash purchase price of approximately $461 million, including working capital adjustments.
On May 4, 2019, Southern Power achieved commercial operation of the 385-MW natural gas expansion unit at Plant Mankato and started providing energy under a PPA with Northern States Power on June 1, 2019. The sale of Plant Mankato to Northern States Power remains subject to state commission approvals and is expected to close in fall 2019. If these state commission approvals are not obtained by October 1, 2019, either party has the option to
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
terminate the sale, which, if elected, would result in the payment of a $15 million termination fee by Northern States Power to Southern Power. The ultimate outcome of this matter cannot be determined at this time.
For additional information relating to these issues, see RISK FACTORS and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Company in Item 7 of the Form 10-K.
Environmental Matters
The Southern Company system's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. The Southern Company system maintains comprehensive environmental compliance and GHG strategies to assess upcoming requirements and compliance costs associated with these environmental laws and regulations and to achieve stated goals. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, or changing fuel sources for certain existing units, as well as related upgrades to the Southern Company system's transmission and distribution (electric and natural gas) systems, and may impact future electric generating unit retirement and replacement decisions, results of operations, cash flows, and/or financial condition. A major portion of these costs is expected to be recovered through retail and wholesale rates. The ultimate impact of environmental laws and regulations and GHG goals will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed technology, fuel prices, and the outcome of pending and/or future legal challenges.
New or revised environmental laws and regulations could affect many areas of the traditional electric operating companies', Southern Power's, and the natural gas distribution utilities' operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be 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. Further, increased 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/or financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity and natural gas. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company in Item 7 and Note 3 to the financial statements under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Laws and Regulations
Coal Combustion Residuals
In June 2019, Alabama Power recorded an increase of approximately $308 million to its AROs primarily related to the CCR Rule and the related state rule based on management's completion of closure designs during the second quarter 2019 for all but two of its ash pond facilities, including one jointly owned with Mississippi Power. The additional estimated costs to close these ash ponds under the planned closure-in-place methodology primarily relate to cost inputs from contractor bids, internal drainage and dewatering system designs, and increases in the estimated ash volumes. The cost estimate for the remaining ash pond facilities will be updated within the next 12 months and the change could be material.
As further analysis is performed and additional details are developed with respect to ash pond closures, the traditional electric operating companies expect to periodically update their ARO cost estimates. 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, Southern Company's results of operations, cash flows, and financial condition could be materially impacted. The ultimate outcome of these matters cannot be determined at this time. See Note 6 to the financial statements in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Global Climate Issues
On July 8, 2019, the EPA published the final Affordable Clean Energy rule (ACE Rule) to repeal and replace the CPP. Implementation of the CPP has been stayed by the U.S. Supreme Court since 2016. The ACE Rule requires states to develop unit-specific CO2 emission rate standards for existing coal-fired units based on heat-rate efficiency improvements. Combustion turbines, including natural gas combined cycles, are not included as affected sources in the ACE Rule. The Southern Company system has ownership interests in 19 coal-fired units to which the ACE Rule is applicable. The ultimate impact of the ACE Rule, including the repeal and replacement of the CPP, to the Southern Company system will depend on state implementation plan requirements and the outcome of any associated legal challenges and cannot be determined at this time.
Regulatory Matters
See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.
Fuel Cost Recovery
The traditional electric operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow. The traditional electric operating companies continuously monitor their under or over recovered fuel cost balances and make appropriate filings with their state PSCs to adjust fuel cost recovery rates as necessary.
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.
Environmental Accounting Order
On April 15, 2019, Alabama Power retired Plant Gorgas Units 8, 9, and 10 and reclassified approximately $654 million of the unrecovered asset balances to regulatory assets, which are being recovered over the units' remaining useful lives, the latest being through 2037, as established prior to the decision to retire. Additionally, approximately $700 million of net capitalized asset retirement costs were reclassified to a regulatory asset in accordance with accounting guidance provided by the Alabama PSC. The asset retirement costs are being recovered through 2055. See Note 2 to the financial statements under "Alabama Power – Environmental Accounting Order" and Note 6 in Item 8 of the Form 10-K for additional information.
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 (ECCR) tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to 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.
Rate Plans
On June 28, 2019, Georgia Power filed a base rate case (Georgia Power 2019 Base Rate Case) with the Georgia PSC. The filing includes a three-year Alternate Rate Plan with requested rate increases totaling $563 million, $145 million, and $234 million effective January 1, 2020, January 1, 2021, and January 1, 2022, respectively. These
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
increases are based on a proposed retail ROE of 10.90% and a proposed equity ratio of 56% and reflect levelized revenue requirements during the three-year period, with the exception of incremental compliance costs related to CCR AROs, Demand-Side Management programs, and adjustments to the Municipal Franchise Fee tariff.
Georgia Power has requested recovery of the proposed increases through its existing base rate tariffs as follows:
|
| | | | | | | | | |
| Tariff | 2020 | 2021 | 2022 |
| | (in millions) |
| Traditional base: | | | |
| Levelized | $ | 209 |
| $ | — |
| $ | — |
|
| CCR AROs | 158 |
| 140 |
| 227 |
|
| ECCR | 165 |
| — |
| — |
|
| Demand-Side Management | 14 |
| 2 |
| 1 |
|
| Municipal Franchise Fee | 17 |
| 3 |
| 5 |
|
Total(*) | $ | 563 |
| $ | 145 |
| $ | 234 |
|
| |
| (*) | Totals may not add due to rounding. |
Georgia Power's filing primarily reflects requests to (i) address the impacts of the Tax Reform Legislation, (ii) recover the costs of recent and future capital investments in infrastructure designed to maintain high levels of reliability and superior customer service with updated depreciation rates, (iii) recover substantial storm damage expenses incurred and deferred since 2013 along with a reasonable level of storm damage expenses expected to be incurred during the three years ending December 31, 2022, and (iv) recover the costs necessary to comply with federal and state regulations for CCR AROs. In addition, the filing includes the following provisions:
Continuation of an allowed retail ROE range of 10.00% to 12.00%.
Continuation of the process whereby two-thirds of any earnings above the top of the allowed ROE range are shared with Georgia Power's customers and the remaining one-third are retained by Georgia Power.
Continuation of the option to file an Interim Cost Recovery tariff in the event earnings are projected to fall below the bottom of the ROE range during the three-year term of the plan.
Georgia Power expects the Georgia PSC to issue a final order in this matter on December 17, 2019. The ultimate outcome of this matter cannot be determined at this time.
Integrated Resource Plan
In 2016, the Georgia PSC approved Georgia Power's triennial Integrated Resource Plan, including recovery of costs up to $99 million through June 30, 2019 to preserve nuclear generation as an option at a future generation site in Stewart County, Georgia. In 2017, the Georgia PSC approved Georgia Power's decision to suspend work at the site due to changing economics, including lower load forecasts and fuel costs. In accordance with the Georgia PSC's order, costs incurred of approximately $50 million have been recorded as a regulatory asset.
On July 16, 2019, the Georgia PSC voted to approve Georgia Power's triennial Integrated Resource Plan (2019 IRP) as modified by a stipulated agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors and further modified by the Georgia PSC.
In the 2019 IRP, the Georgia PSC approved the decertification and retirement of Plant Hammond Units 1 through 4 (840 MWs) and Plant McIntosh Unit 1 (142.5 MWs) effective July 29, 2019. The Georgia PSC also approved the reclassification of the remaining net book values of the Plant Hammond and Plant McIntosh units (approximately $500 million and $40 million, respectively, at June 30, 2019), as well as any unusable materials and supplies inventory balances, upon retirement to a regulatory asset. Recovery of each unit's net book value will continue through December 31, 2019 as provided in the 2013 ARP.
For the regulatory asset balances remaining at December 31, 2019, Georgia Power requested recovery in the Georgia Power 2019 Base Rate Case as follows: (i) the net book values of Plant Mitchell Unit 3 (approximately $8
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
million at June 30, 2019) and Plant McIntosh Unit 1, any unusable materials and supplies inventory, and the future generation site in Stewart County, Georgia over a three-year period ending December 31, 2022 and (ii) the net book values of Plant Hammond Units 1 through 4 over a period equal to the applicable unit's remaining useful life through 2035. The ultimate outcome of these matters cannot be determined at this time.
Also in the 2019 IRP, the Georgia PSC rejected a request to certify approximately 25 MWs of capacity at Plant Scherer Unit 3 for the retail jurisdiction beginning January 1, 2020 following the expiration of a wholesale PPA. Georgia Power may offer such capacity in the wholesale market or to the retail jurisdiction in a future Integrated Resource Plan. The ultimate outcome of this matter cannot be determined at this time but is not expected to have a material impact on Southern Company's financial statements.
Additionally, the Georgia PSC approved Georgia Power's proposed environmental compliance strategy associated with ash pond and certain landfill closures and post-closure care in compliance with the CCR Rule and the related state rule. In the Georgia Power 2019 Base Rate Case, Georgia Power requested recovery of the under recovered balance of these compliance costs at December 31, 2019 (approximately $135 million at June 30, 2019) over a three-year period ending December 31, 2022 and recovery of estimated compliance costs of $277 million for 2020, $395 million for 2021, and $655 million for 2022 over three-year periods ending December 31, 2022, 2023, and 2024, respectively. The ultimate outcome of this matter cannot be determined at this time. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information regarding Georgia Power's AROs.
The Georgia PSC also approved Georgia Power to (i) issue requests for proposals (RFP) for capacity beginning in 2022 or 2023 and in 2026, 2027, or 2028; (ii) procure up to an additional 2,210 MWs of renewable resources through competitive RFPs; and (iii) invest in a portfolio of up to 80 MWs of battery energy storage technologies.
See "Rate Plans" herein for additional information regarding the Georgia Power 2019 Base Rate Case.
Mississippi Power
Kemper County Energy Facility
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. 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 Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.
During the second quarter and year-to-date 2019, Mississippi Power recorded pre-tax charges to income of $4 million ($3 million after tax) and $6 million ($5 million after tax), respectively, primarily resulting from the abandonment and related closure activities and ongoing period costs, net of sales proceeds, for the mine and gasifier-related assets at the Kemper County energy facility. Additional closure costs for the mine and gasifier-related assets, currently estimated at up to $10 million pre-tax (excluding dismantlement costs, net of salvage), may be incurred through the first half of 2020. In addition, period costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the mine and gasifier-related assets, are estimated at $7 million for the remainder of 2019 and $2 million to $6 million annually in 2020 through 2023.
In addition, Mississippi Power constructed the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery and is currently evaluating its options regarding the final disposition of the CO2 pipeline, including removal of the pipeline. This evaluation is expected to be complete later in 2019. If Mississippi Power ultimately decides to remove the CO2 pipeline, the cost of removal could have a material impact on Southern Company's financial statements.
In December 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the $387 million of grants received. Mississippi Power and the DOE are currently in discussions regarding the requested closeout and property disposition, which may require payment to the DOE for a portion of certain property that is to be retained by Mississippi Power. In connection with the DOE closeout discussions, on April 29, 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
of an investigation related to the Kemper County energy facility. The ultimate outcome of these matters cannot be determined at this time; however, they could have a material impact on Southern Company's financial statements.
Southern Company Gas
The natural gas distribution utilities are subject to regulation and oversight by their respective state regulatory agencies for the rates charged 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 regulatory agencies in the states in which 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 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 and energy efficiency plans.
In November 2018, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $230 million increase in annual base rate revenues. The requested increase is based on a projected test year for the 12-month period ending September 30, 2020, a ROE of 10.6%, and an increase in the equity ratio from 52% to 54% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation.
On April 16, 2019, Nicor Gas entered into a stipulation agreement to resolve all related issues with the Staff of the Illinois Commission, including a ROE of 9.86% and an equity ratio of 54%. Also on April 16, 2019, Nicor Gas filed its rebuttal testimony with the Illinois Commission incorporating the stipulation agreement and addressing the remaining items outstanding with the other two intervenors. As a result of the stipulation agreement and rebuttal testimony, the revised requested annual revenue increase is $180 million.
The Illinois Commission is expected to rule on the requested increase by early October 2019, after which rate adjustments will be effective.
On June 3, 2019, Atlanta Gas Light filed a general base rate case with the Georgia PSC requesting a $96 million increase in annual base rate revenues. The requested increase is based on a forward-looking test year for the 12-month period ending July 31, 2020, a ROE of 10.75% with an earnings band based on a ROE between 10.55% and 10.95%, and a continued equity ratio of 55%. The filing also requests the continuation of the Georgia rate adjustment mechanism, as previously authorized. Atlanta Gas Light expects the Georgia PSC to issue a final order on this matter on December 19, 2019 with the new rates becoming effective January 1, 2020.
The ultimate outcome of these matters cannot be determined at this time.
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) |
| $(70) | | (6.1) | | $(1,904) | | (84.6) |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1,053 | | N/M | | $2,198 | | N/M |
N/M - Not meaningful
Consolidated net income attributable to Southern Company was $1.07 billion$899 million ($1.070.86 per share) for the thirdsecond quarter 20172019 compared to $1.14 billiona net loss of $154 million ($1.18(0.15) per share) for the corresponding period in 2016.2018. The decreasechange was primarily due to a decrease$1.1 billion ($0.8 billion after tax) charge in retail electric revenues duethe second quarter 2018 for an estimated probable loss related to milder weatherGeorgia Power's construction of Plant Vogtle Units 3 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 rates4 and a decrease in operations and maintenance expenses.
Consolidated net income attributable to Southern Company was $347 million$3.0 billion ($0.352.86 per share) for year-to-date 20172019 compared to $2.3 billion$784 million ($2.400.77 per share) for the corresponding period in 2016.2018. The decreaseincrease was primarily due to chargesthe $2.5 billion ($1.3 billion after tax) gain on the sale of $3.2Gulf Power in 2019 and a $1.1 billion and $222 million($0.8 billion after tax) charge in the second quarter 2018 for year-to-date 2017 and 2016, respectively,an estimated probable loss related to the Kemper IGCC at Mississippi Power. Also contributing to the change was an increaseGeorgia Power's construction 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 costs4. See Note (K) to the Condensed Financial Statements under "Southern Company" herein and Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information.
Retail Electric Revenues
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(200) | | (5.3) | | $(685) | | (9.4) |
In the second quarter 2019, retail electric revenues were $3.5 billion compared to $3.7 billion for the corresponding period in 2018. For year-to-date 2019, retail electric revenues were $6.6 billion compared to $7.3 billion for the corresponding period in 2018.
Details of the changes in retail electric revenues were as follows:
|
| | | | | | | | | | | | | | |
| | | Second Quarter 2019 | | Year-to-Date 2019 |
| | | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail electric – prior year | | $ | 3,740 |
| | | | $ | 7,308 |
| | |
| Estimated change resulting from – | | | | | | | | |
| Rates and pricing | | 125 |
| | 3.3 | % | | 182 |
| | 2.5 | % |
| Sales decline | | (30 | ) | | (0.8 | ) | | (41 | ) | | (0.6 | ) |
| Weather | | 34 |
| | 0.9 |
| | (56 | ) | | (0.8 | ) |
| Fuel and other cost recovery | | (28 | ) | | (0.7 | ) | | (179 | ) | | (2.4 | ) |
| Gulf Power disposition | | (301 | ) | | (8.0 | ) | | (591 | ) | | (8.1 | ) |
| Retail electric – current year | | $ | 3,540 |
| | (5.3 | )% | | $ | 6,623 |
| | (9.4 | )% |
Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018 primarily due to increased revenues at Alabama Power due to the impacts of customer bill credits related to the Tax Reform Legislation in 2018 and increases to CNP Compliance revenue, increases in the NCCR tariff effective January 1, 2019 at Georgia Power, and anincreases in PEP and ECO Plan rates that became effective for the first billing cycle of September 2018 at Mississippi Power. The year-to-date 2019 increase in retail base revenues effective July 2017also reflects the rate pricing effect of decreased customer usage, partially offset by lower contributions from commercial and in environmental cost recovery effective November 2016industrial customers with variable demand-driven pricing at GulfGeorgia Power.
See Note 32 to the financial statements of Southern Company under "Regulatory Matters – Alabama"Alabama Power," " – Georgia"Georgia Power,– Rate Plans," and " – Gulf Power – Retail Base Rate Cases""Mississippi Power" 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 thirdsecond quarter and year-to-date 2017 when2019 when compared to the corresponding periods in 2016.2018. Weather-adjusted residential KWH sales decreased 2.0%1.0% and 0.6%0.3% in the thirdsecond quarter and year-to-date 2017,2019, respectively, when compared to the corresponding periods in 2018 primarily due to decreased customer usage primarily resulting from an increase in penetration of energy efficient residential appliances, partially offset by customer growth. Weather-adjusted commercial KWH sales decreased 1.4%1.3% and 1.1%1.6% in the thirdsecond quarter and year-to-date 2017,2019, respectively, when compared to the corresponding periods in 2018 primarily due to decreased customer usage resulting from customer initiativesan increase in energy savings and an ongoing migration to the electronic commerce business model, partially offset by customer growth.saving initiatives. Industrial KWH sales decreased 0.5% and 1.1%2.0% in both the thirdsecond quarter and year-to-date 2017, respectively,2019 when compared to the corresponding periods in 2018 as a result of a decrease in demand resulting from changes in production levels primarily in the paper sector, partially offset by increased sales in the primary metals, chemicals, stone, clay, and glass, 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.paper sectors.
Fuel and other cost recovery revenues decreased $117$28 million and $59$179 million in the thirdsecond quarter and year-to-date 2017,2019, respectively, when compared to the corresponding periods in 20162018 primarily due to lower energy sales resulting fromdecreases in generation and the average cost of fuel. The year-to-date decrease was also driven by milder weather and lower coal prices. in the first quarter 2019.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(74) | | (12.0) | | $(198) | | (16.0) |
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'sthe 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 2019, wholesale electric revenues were $542 million compared to $616 million for the corresponding period in 2018. For year-to-date 2019, wholesale electric revenues were $1.0 billion compared to $1.2 billion for the corresponding period in 2018. The second quarter 2019 decrease was related to a $54 million decrease in energy revenues and a $20 million decrease in capacity revenues. The year-to-date 2019 decrease was related to a $160 million decrease in energy revenues and a $38 million decrease in capacity revenues. Excluding decreases of $7 million and $13 million of energy revenues for the second quarter and year-to-date 2019, respectively, related to the sale of Gulf Power, the decreases in energy revenues primarily related to Southern Power and included a decrease in non-PPA revenues due to a decrease in the volume of KWHs sold through short-term sales and a decrease in revenues from natural gas PPAs due to a decrease in the average cost of fuel and purchased power. These decreases were also due to lower fuel prices and lower customer demand at the traditional electric operating companies. The decreases in capacity revenues primarily related to the sales of Gulf Power and Southern Power's Plant Oleander and Plant Stanton Unit A in December 2018. See Note 15 to the financial statements under "Southern Power – Sales of Natural Gas Plants" in Item 8 of the Form 10-K for additional information.
Natural Gas Revenues
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(17) | | (2.4) | | $(151) | | (6.5) |
In the second quarter 2019, natural gas revenues were $689 million compared to $706 million for the corresponding period in 2018. For year-to-date 2019, natural gas revenues were $2.2 billion compared to $2.3 billion for the corresponding period in 2018.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of the changes in natural gas revenues were as follows:
|
| | | | | | | | | | | | | |
| | Second Quarter 2019 | | Year-to-Date 2019 |
| | (in millions) | | (% change) | | (in millions) | | (% change) |
| Natural gas revenues – prior year | $ | 706 |
| | | | $ | 2,314 |
| | |
| Estimated change resulting from – | | | | | | | |
| Infrastructure replacement programs and base rate changes | 10 |
| | 1.4 | % | | 42 |
| | 1.8 | % |
| Gas costs and other cost recovery | (13 | ) | | (1.8 | ) | | 49 |
| | 2.1 |
|
| Weather | (7 | ) | | (1.1 | ) | | — |
| | — |
|
| Wholesale gas services | 64 |
| | 9.1 |
| | (16 | ) | | (0.7 | ) |
| Southern Company Gas Dispositions | (70 | ) | | (9.9 | ) | | (237 | ) | | (10.2 | ) |
| Other | (1 | ) | | (0.1 | ) | | 11 |
| | 0.5 |
|
| Natural gas revenues – current year | $ | 689 |
| | (2.4 | )% | | $ | 2,163 |
| | (6.5 | )% |
Revenues attributable to infrastructure replacement programs and base rate changes at the natural gas distribution utilities increased in the second quarter and year-to-date 2019 compared to the corresponding periods in 2018 primarily due to increases of $4 million and $25 million, respectively, at Nicor Gas and $5 million and $14 million, respectively, at Atlanta Gas Light. These amounts include the natural gas distribution utilities' continued investments recovered through infrastructure replacement programs and base rate increases as well as increases due to the impacts of the Tax Reform Legislation.
Revenues attributable to gas costs and other cost recovery decreased in the second quarter 2019 and increased year-to-date 2019 compared to the corresponding periods in 2018. The decrease in the second quarter 2019 is primarily due to lower natural gas prices and decreased volumes of natural gas sold. The increase for year-to-date 2019 is primarily due to increased natural gas prices in the first quarter 2019, partially offset by decreased volumes of natural gas sold year-to-date 2019. 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.
Revenues decreased in the second quarter 2019 due to warmer weather, as determined by Heating Degree Days, in Illinois and Georgia compared to the corresponding period in 2018.
Revenues attributable to Southern Company Gas' wholesale gas services business increased in the second quarter 2019 and decreased year-to-date 2019 compared to the corresponding periods in 2018. The increase in the second quarter 2019 is primarily due to derivative gains, partially offset by decreased commercial activity. For year-to-date 2019, the decrease is primarily due to decreased commercial activity, partially offset by derivative gains.
See Note (B) to the Condensed Financial Statements herein under "Southern Company Gas" for additional information.
Other Revenues
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(229) | | (58.0) | | $(456) | | (56.4) |
In the thirdsecond quarter 2017, wholesale electric2019, other revenues were $718$166 million compared to $613$395 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.2018. For year-to-date 2017, wholesale electric2019, other 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$352 million compared to $181$808 million for the corresponding period in 2016. The decrease was2018. These decreases were primarily related to lower open access transmission tariff revenues, primarily as a result of the expiration of long-term transmissionPowerSecure's 2018 storm restoration services contracts at Georgia Power and rate adjustments at Alabama Power, and a decrease in solar application fee revenues at Georgia Power.Puerto Rico.
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 | Second Quarter 2019
vs.
Second Quarter 2018 | | Year-to-Date 2019
vs.
Year-to-Date 2018 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | (115 | ) | | (8.2) | | $ | 38 |
| | 1.1 | $ | (189 | ) | | (17.1) | | $ | (440 | ) | | (20.0) |
| Purchased power | 29 |
| | 12.8 | | 65 |
| | 11.2 | (35 | ) | | (14.8) | | (132 | ) | | (26.2) |
| Total fuel and purchased power expenses | $ | (86 | ) | | $ | 103 |
| | $ | (224 | ) | | | $ | (572 | ) | |
In the thirdsecond quarter 2017,2019, total fuel and purchased power expenses were $1.5$1.1 billion compared to $1.6$1.3 billion for the corresponding period in 2016. The2018. Excluding approximately $126 million associated with the sale of Gulf Power, the decrease was primarily the result of a $104an $81 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.and a $17 million net decrease in the aggregate volume of KWHs generated and purchased.
For year-to-date 2017,2019, total fuel and purchased power expenses were $4.0$2.1 billion compared to $3.9$2.7 billion for the corresponding period in 2016. The increase2018. Excluding approximately $225 million associated with the sale of Gulf Power, the decrease was primarily the result of a $277$198 million increasedecrease in the average cost of fuel and purchased power primarily due to higher natural gas prices, partially offset byand a $174$149 million decrease in the aggregate 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 | Second Quarter 2019 | | Second Quarter 2018(a) | | Year-to-Date 2019 | | Year-to-Date 2018(a) |
Total generation (in billions of KWHs) | 54 | | 56 | | 147 | | 145 | 46 | | 47 | | 90 | | 93 |
Total purchased power (in billions of KWHs) | 6 | | 6 | | 14 | | 15 | 4 | | 4 | | 8 | | 7 |
Sources of generation (percent) — | | | | | | |
| Gas | | 52 | | 45 | | 50 | | 45 |
| Coal | 31 | | 38 | | 30 | | 33 | 22 | | 29 | | 22 | | 29 |
| Nuclear | 15 | | 15 | | 16 | | 16 | 16 | | 15 | | 16 | | 16 |
| Gas | 47 | | 44 | | 46 | | 46 | |
| Hydro | 2 | | 1 | | 2 | | 3 | 3 | | 3 | | 5 | | 3 |
| Other | 5 | | 2 | | 6 | | 2 | 7 | | 8 | | 7 | | 7 |
Cost of fuel, generated (in cents per net KWH) — | | | | | | |
| Gas | | 2.39 | | 2.71 | | 2.47 | | 2.78 |
| Coal | 2.82 | | 2.97 | | 2.82 | | 3.10 | 3.04 | | 2.71 | | 2.98 | | 2.80 |
| Nuclear | 0.80 | | 0.81 | | 0.80 | | 0.82 | 0.80 | | 0.82 | | 0.80 | | 0.80 |
| 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 | 2.26 | | 2.39 | | 2.29 | | 2.43 |
Average cost of purchased power (in cents per net KWH)(*) | 4.96 | | 4.98 | | 5.32 | | 4.75 | |
Average cost of purchased power (in cents per net KWH)(b) | | 4.89 | | 5.18 | | 5.04 | | 6.11 |
| |
(*)(a) | Excludes Gulf Power, which was sold on January 1, 2019. |
| |
| (b) | Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider. |
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel
In the thirdsecond quarter 2017,2019, fuel expense was $1.3$0.9 billion compared to $1.4$1.1 billion for the corresponding period in 2016. The2018. Excluding approximately $74 million related to Gulf Power in 2018, the decrease was primarily due to a 21.4%26.2% decrease in the volume of KWHs generated by coal and a 5.1%an 11.8% 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% decrease12.2% increase in the average cost of coal per KWH generated and a 7.4%12.1% increase in the volume of KWHs generated by natural gas.
For year-to-date 2019, fuel expense was $1.8 billion compared to $2.2 billion for the corresponding period in 2018. Excluding approximately $127 million related to Gulf Power in 2018, the decrease was primarily due to a 27.6% decrease in the volume of KWHs generated by coal and an 11.2% decrease in the average cost of natural gas per KWH generated, partially offset by a 3.7% decrease6.6% increase in the volume of KWHs generated by natural gas.gas and a 6.4% increase in the average cost of coal per KWH generated.
Purchased Power
In the thirdsecond quarter 2017,2019, purchased power expense was $256$201 million compared to $227$236 million for the corresponding period in 2016. The increase2018. This decrease was primarily associated with Gulf Power.
For year-to-date 2019, purchased power expense was $371 million compared to $503 million for the corresponding period in 2018. Excluding approximately $98 million associated with Gulf Power, the decrease was primarily due to a 10.1% increase in the volume of KWHs purchased, partially offset by a 0.4%17.5% 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 toand 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%2.1% decrease in the volume of KWHs purchased.
See Note (K) to the Condensed Financial Statements under "Southern Company" herein for information regarding the sale of Gulf Power.
Energy purchases will vary depending on demand for energy within the Southern Company system's electric service territory, the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, and the availability of the Southern Company system's generation.
Cost of Natural Gas
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(37) | | (16.2) | | $(72) | | (7.6) |
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 80% and 85% of total cost of natural gas for the second quarter and year-to-date 2019, respectively.
In the second quarter 2019, cost of natural gas was $191 million compared to $228 million for the corresponding period in 2018. Excluding a $25 million decrease related to the Southern Company Gas Dispositions, cost of natural gas decreased $12 million.
For year-to-date 2019, cost of natural gas was $877 million compared to $949 million for the corresponding period in 2018. Excluding a $104 million decrease related to the Southern Company Gas Dispositions, cost of natural gas increased $32 million. This increase reflects an increase in natural gas prices, partially offset by a decrease in the volume of natural gas sold year-to-date 2019 compared to the corresponding period in 2018.
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 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(195) | | (69.9) | | $(365) | | (64.3) |
In the thirdsecond quarter 2017,2019, cost of other sales was $90$84 million compared to $84$279 million for the corresponding period in 2016.2018. For year-to-date 2017,2019, cost of other sales was $293$203 million compared to $161$568 million for the corresponding period in 2016. The year-to-date increase2018. These decreases were primarily reflects costs related to sales of products andPowerSecure's 2018 storm restoration 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.in Puerto Rico.
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 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(207) | | (13.6) | | $(344) | | (11.6) |
In the thirdsecond quarter 2017,2019, other operations and maintenance expenses were $1.3 billion compared to $1.4$1.5 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.
2018. For year-to-date 2017,2019, other operations and maintenance expenses were $3.9$2.6 billion compared to $3.6$3.0 billion for the corresponding period in 2016.2018. The increasesecond quarter and year-to-date 2019 decreases reflect approximately $90 million and $166 million, respectively, related to Gulf Power in 2018 and $34 million and $105 million, respectively, related to the Southern Company Gas Dispositions. These decreases also reflect an asset impairment charge of $119 million recorded in the second quarter 2018 at Southern Power related to the sale of Southern Power's Florida plants. These decreases were partially offset by a $32 million goodwill impairment charge in the second quarter 2019 in contemplation of the sale of PowerSecure's utility infrastructure services business unit. See Note (K) to the Condensed Financial Statements under "Southern Company" herein and Note 15 to the financial statements under "Southern Power" and "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Depreciation and Amortization
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(28) | | (3.6) | | $(46) | | (3.0) |
In the second quarter 2019, depreciation and amortization was $755 million compared to $783 million for the corresponding period in 2018. For year-to-date 2019, depreciation and amortization was $1.5 billion compared to $1.6 billion for the corresponding period in 2018. The second quarter and year-to-date 2019 decreases were primarily due to increasesdecreases of $420$48 million and $32$95 million, in operationsrespectively, related to the sale of Gulf Power and maintenance expenses as a resultdecreases of $10 million and $26 million, respectively, related to the inclusion of Southern Company Gas Dispositions, partially offset by increases of $29 million and PowerSecure results$62 million, respectively, related to additional plant in service.
Taxes Other Than Income Taxes
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(17) | | (5.4) | | $(43) | | (6.4) |
In the second quarter 2019, taxes other than income taxes were $299 million compared to $316 million for the nine-monthcorresponding period in 2017, respectively, a $482018. For year-to-date 2019, taxes other than income taxes were $628 million increase associated with new solar, wind, and gas facilities at Southern Power, and $32.5compared to $671 million resulting fromfor the write-downcorresponding period in 2018. These decreases primarily relate to the sale 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 factorsPower.
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 AmortizationEstimated Loss on Plants Under 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) |
| $72 | | 10.4 | | $431 | | 23.9 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(1,056) | | (99.6) | | $(1,099) | | (99.5) |
In the thirdsecond quarter 2017, depreciation and amortization2019, estimated loss on plants under construction was $767$4 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$1.06 billion for the corresponding period in 2016. The increase reflects $2542018. For year-to-date 2019, estimated loss on plants under construction was $6 million compared to $1.11 billion for the corresponding period in 2018. These decreases were primarily due to the $1.1 billion charge recorded in the second quarter 2018 as a result of the inclusionGeorgia Power's revised estimate to complete construction and start-up of Southern Company GasPlant Vogtle Units 3 and 4. The second quarter and year-to-date 2019 charges were related to abandonment and closure activities for the nine-month period in 2017 compared tomine and gasifier-related assets of the three-month period subsequent to the Merger closing on July 1, 2016. Additionally, the increase reflects $170 million related to additional plant in serviceKemper IGCC at the traditional electric operating companies and SouthernMississippi 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 32 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 NotesNote (B) to the Condensed Financial Statements herein under "Georgia Power – Nuclear Construction" for additional information.
(Gain) Loss on Dispositions, Net
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $44 | | N/M | | $2,542 | | N/M |
N/M - Not meaningful
In the second quarter 2019, gain on dispositions, net was $8 million compared to a loss on dispositions, net of $36 million in the corresponding period in 2018. This change was primarily due to a $36 million loss on the sale of Pivotal Home Solutions at Southern Company Gas recorded in 2018 and (I)a $23 million gain as a result of the sale of Southern Power's Plant Nacogdoches in the second quarter 2019, partially offset by a $15 million adjustment to the preliminary gain on the sale of Gulf Power.
For year-to-date 2019, gain on dispositions, net was $2.5 billion compared to a loss on dispositions, net of $36 million in the corresponding period in 2018. This change was primarily due to a preliminary gain of $2.5 billion ($1.3 billion after tax) on the sale of Gulf Power.
See Note (K) 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 TaxesInterest 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) |
| $(6) | | (1.9) | | $120 | | 14.6 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(41) | | (8.7) | | $(69) | | (7.4) |
For year-to-date 2017, taxes other than income taxes were $941In the second quarter 2019, interest expense, net of amounts capitalized was $429 million compared to $821$470 million forin the corresponding period in 2016. The increase primarily reflects2018. For year-to-date 2019, interest expense, net of amounts capitalized was $859 million compared to $928 million in the inclusion of Southern Company Gas taxes for the nine-monthcorresponding period in 2017 compared2018. Excluding decreases of $13 million and $26 million in the second quarter and year-to-date 2019, respectively, related to the three-month period subsequentsale of Gulf Power, the decreases were primarily due to a decrease in average outstanding long-term debt, primarily at the parent company.
See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein, Note 8 to the Merger closing on July 1, 2016.
Seefinancial statements in Item 8 of the Form 10-K, and Note (I)(F) 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 IGCCOther 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) |
| $(54) | | (61.4) | | $2,933 | | N/M |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $21 | | 26.9 | | $38 | | 27.5 |
In the second quarter 2019, other income (expense), net was $99 million compared to $78 million for the corresponding period in 2018. For year-to-date 2019, other income (expense), net was $176 million compared to $138 million for the corresponding period in 2018. These increases were primarily due to a $36 million gain arising from the settlement of litigation related to the Roserock solar facility at Southern Power in June 2019, partially offset by $24 million due to the settlement of Mississippi Power's Deepwater Horizon claim in May 2018. Also contributing to these increases were $7 million and $13 million for the second quarter and year-to-date 2019, respectively, of non-service cost-related pension income and $10 million for year-to-date 2019 of increased interest income from temporary cash investments at the parent company. See Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein and Note 3 to the financial statements under "Other Matters – Mississippi Power," in Item 8 of the Form 10-K for additional information.
Income Taxes (Benefit)
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $284 | | N/M | | $1,530 | | N/M |
N/M - Not meaningful
Estimated probable losses onIn the Kemper IGCCsecond quarter 2019, income taxes were $145 million compared to an income tax benefit of $34$139 million and $3.2 billion were recorded at Mississippi Powerfor the corresponding period in 2018. The change was primarily due to the reduction in pre-tax earnings in the thirdsecond quarter 2018 resulting from the charge associated with Plant Vogtle Units 3 and 4 construction.
For year-to-date 2017, respectively,2019, income taxes were $1.5 billion compared to $88an income tax benefit of $25 million for the corresponding period in 2018. The change was primarily due to the tax impacts related to the sale of Gulf Power and $222 millionthe reduction in pre-tax earnings in the thirdsecond quarter and year-to-date 2016, respectively. While2018 resulting from 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 costscharge associated with the gasification portions of the plantPlant Vogtle Units 3 and lignite mine.4 construction.
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)See Notes (G) 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)(K) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Allowance for Equity Funds Used During ConstructionNet Income Attributable to Noncontrolling Interests
|
| | | | | | |
| 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 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $6 | | 26.1 | | $(17) | | N/M |
N/M - Not meaningful
Substantially all noncontrolling interests relate to renewable projects at Southern Power. See Notes 1 and 7 to the financial statements in Item 8 of the Form 10-K under "General" and "Southern Power," respectively, for additional information.
In the thirdsecond quarter 2017, earnings from equity method investments were $322019, net income attributable to noncontrolling interests was $29 million compared to $29$23 million infor the corresponding period in 2016. For year-to-date 2017, earnings from2018. The increase was primarily due to an allocation of approximately $26 million of income to the noncontrolling interest partner related to the Roserock solar facility litigation settlement, partially offset by $25 million of losses attributable to noncontrolling interests related to the tax equity method investments were $100 millionpartnerships entered into in 2018.
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,2019, net of amounts capitalizedincome attributable to noncontrolling interests was $1.2 billionimmaterial 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)$17 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.
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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 2016.2018. The decrease was primarily due to $866$48 million in tax benefitsof losses attributable to noncontrolling interests related to estimated losses on the Kemper IGCC at Mississippi Power,tax equity partnerships entered into in 2018, partially offset by a $226an allocation of approximately $29 million increase reflecting the nine-month period of income taxes at Southern Company Gas in 2017 compared to the three-month period subsequentnoncontrolling interest partner related 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.Roserock solar facility litigation settlement.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern Company's future earnings potential. Future earnings will be impacted by the recently completed and additional pending disposition activities described 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. 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 environmentenvironments that allowsallow for the timely recovery of prudently-incurred costs during a time of increasing costs, continued customer growth, and, limited projected demandfor the traditional electric operating companies, the weak pace of growth over the next several years. Matters related toin electricity use per customer, especially in residential and commercial markets. 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 highermore multi-family home construction.construction, all of which could contribute to a net reduction in customer usage. 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 acquisitionsthe development or acquisition of renewable facilities and construction of electric generating facilities, the impact of tax credits from renewableother 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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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
On June 13, 2019, Southern Power is consideringcompleted the sale of upits equity interests in Nacogdoches Power, LLC, the owner of an approximately 115-MW biomass facility located in Nacogdoches County, Texas, to Austin Energy, for an aggregate cash purchase price of approximately $461 million, including working capital adjustments.
On May 4, 2019, Southern Power achieved commercial operation of the 385-MW natural gas expansion unit at Plant Mankato and started providing energy under a one-third equity interestPPA with Northern States Power on June 1, 2019. The sale of Plant Mankato to Northern States Power remains subject to state commission approvals and is expected to close in its solar asset portfolio.fall 2019. If these state commission approvals are not obtained by October 1, 2019, either party has the option to
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
terminate the sale, which, if elected, would result in the payment of a $15 million termination fee by Northern States Power to Southern Power. 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.10-K.
Environmental Matters
ComplianceThe Southern Company system's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. The Southern Company system maintains comprehensive environmental compliance and GHG strategies to assess upcoming requirements and compliance costs related to federal and stateassociated with these environmental statuteslaws and regulations and to achieve stated goals. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, or changing fuel sources for certain existing units, as well as related upgrades to the Southern Company system's transmission and distribution (electric and natural gas) systems, and may impact future electric generating unit retirement and replacement decisions, results of operations, cash flows, and/or financial condition. A major portion of these costs is expected to be recovered through retail and wholesale rates. The ultimate impact of environmental laws and regulations and GHG goals will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed technology, fuel prices, and the outcome of pending and/or future legal challenges.
New or revised environmental laws and regulations could affect many areas of the traditional electric operating companies', Southern Power's, and the natural gas distribution utilities' operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs 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, higherincreased 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, andand/or financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity and natural gas. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Laws and Regulations
Coal Combustion Residuals
In June 2019, Alabama Power recorded an increase of approximately $308 million to its AROs primarily related to the CCR Rule and the related state rule based on management's completion of closure designs during the second quarter 2019 for all but two of its ash pond facilities, including one jointly owned with Mississippi Power. The additional estimated costs to close these ash ponds under the planned closure-in-place methodology primarily relate to cost inputs from contractor bids, internal drainage and dewatering system designs, and increases in the estimated ash volumes. The cost estimate for the remaining ash pond facilities will be updated within the next 12 months and the change could be material.
As further analysis is performed and additional details are developed with respect to ash pond closures, the traditional electric operating companies expect to periodically update their ARO cost estimates. 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, Southern Company's results of operations, cash flows, and financial condition could be materially impacted. The ultimate outcome of these matters cannot be determined at this time. See Note 6 to the financial statements in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Environmental Statutes and RegulationsGlobal Climate Issues
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,July 8, 2019, the EPA published athe final Affordable Clean Energy rule redesignating a 15-county area within metropolitan Atlanta(ACE Rule) to attainment forrepeal and replace 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 noticeCPP. Implementation of the one-year extension and reinstatedCPP has been stayed by the original October 1, 2017 designation deadline.U.S. Supreme Court since 2016. The ACE Rule requires states to develop unit-specific CO2 emission rate standards for existing coal-fired units based on heat-rate efficiency improvements. Combustion turbines, including natural gas combined cycles, are not included as affected sources in the ACE Rule. The Southern Company system has ownership interests in 19 coal-fired units to which the ACE Rule is applicable. The ultimate impact of the ACE Rule, including the repeal and replacement of the CPP, to the Southern Company system will depend on state implementation plan requirements and the outcome of this matterany associated legal challenges and cannot be determined at this time.
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Southern Company in Item 7 of the Form 10-K for additional information regarding the 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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
FERCRegulatory 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 FebruaryNote 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 and Note (B) to the Condensed Financial Statements herein 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 Mattersinformation.
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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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
Environmental Accounting Order
On April 15, 2019, Alabama Power retired Plant Gorgas Units 8, 9, and 10 and reclassified approximately $654 million of the unrecovered asset balances to regulatory assets, which are being recovered over the units' remaining useful lives, the latest being through 2037, as established prior to the decision to retire. Additionally, approximately $700 million of net capitalized asset retirement costs were reclassified to a regulatory asset in accordance with accounting guidance provided by the Alabama PSC. The asset retirement costs are being recovered through 2055. See Note 32 to the financial statements of Southern Company under "Regulatory Matters"Alabama Power – Alabama Power"Environmental Accounting Order" and Note 6 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.information.
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 (ECCR) tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to thecertified 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. 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 –
Rate Plans
On June 28, 2019, Georgia Power – Nuclear Construction" in Item 8 offiled a base rate case (Georgia Power 2019 Base Rate Case) with 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.PSC. The filing includes a three-year Alternate Rate Plan with requested rate increases totaling $563 million, $145 million, and $234 million effective January 1, 2020, January 1, 2021, and January 1, 2022, respectively. These
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
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increases are based on a proposed retail ROE of 10.90% and a proposed equity ratio of 56% and reflect levelized revenue requirements during the three-year period, with the exception of incremental compliance costs related to CCR AROs, Demand-Side Management programs, and adjustments to the Municipal Franchise Fee tariff.
Georgia Power has requested recovery of the proposed increases through its existing base rate tariffs as follows:
|
| | | | | | | | | |
| Tariff | 2020 | 2021 | 2022 |
| | (in millions) |
| Traditional base: | | | |
| Levelized | $ | 209 |
| $ | — |
| $ | — |
|
| CCR AROs | 158 |
| 140 |
| 227 |
|
| ECCR | 165 |
| — |
| — |
|
| Demand-Side Management | 14 |
| 2 |
| 1 |
|
| Municipal Franchise Fee | 17 |
| 3 |
| 5 |
|
Total(*) | $ | 563 |
| $ | 145 |
| $ | 234 |
|
| |
| (*) | Totals may not add due to rounding. |
Georgia Power's filing primarily reflects requests to (i) address the impacts of the Tax Reform Legislation, (ii) recover the costs of recent and future capital investments in infrastructure designed to maintain high levels of reliability and superior customer service with updated depreciation rates, (iii) recover substantial storm damage expenses incurred and deferred since 2013 along with a reasonable level of storm damage expenses expected to be incurred during the three years ending December 31, 2022, and (iv) recover the costs necessary to comply with federal and state regulations for CCR AROs. In addition, the filing includes the following provisions:
Continuation of an allowed retail ROE range of 10.00% to 12.00%.
Continuation of the process whereby two-thirds of any earnings above the top of the allowed ROE range are shared with Georgia Power's customers and the remaining one-third are retained by Georgia Power.
Continuation of the option to file an Interim Cost Recovery tariff in the event earnings are projected to fall below the bottom of the ROE range during the three-year term of the plan.
Georgia Power expects the Georgia PSC to issue a final order in this matter on December 17, 2019. The ultimate outcome of this matter cannot be determined at this time.
Integrated Resource Plan
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters –In 2016, the Georgia Power – Integrated Resource Plan" of Southern Company in Item 7 of the Form 10-K for additional information regardingPSC approved Georgia Power's triennial Integrated Resource Plan.
On March 7,Plan, including recovery of costs up to $99 million through June 30, 2019 to preserve nuclear generation as an option at a future generation site in Stewart County, Georgia. In 2017, the Georgia PSC approved Georgia Power's decision to suspend work at a future generationthe site in Stewart County, Georgia, due to changing economics, including lower load forecasts and lower fuel costs. The timing of recovery forIn accordance with the Georgia PSC's order, costs incurred of approximately $50 million will be determinedhave been recorded as a regulatory asset.
On July 16, 2019, the Georgia PSC voted to approve Georgia Power's triennial Integrated Resource Plan (2019 IRP) as modified by a stipulated agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors and further modified by the Georgia PSC.
In the 2019 IRP, the Georgia PSC inapproved the decertification and retirement of Plant Hammond Units 1 through 4 (840 MWs) and Plant McIntosh Unit 1 (142.5 MWs) effective July 29, 2019. The Georgia PSC also approved the reclassification of the remaining net book values of the Plant Hammond and Plant McIntosh units (approximately $500 million and $40 million, respectively, at June 30, 2019), as well as any unusable materials and supplies inventory balances, upon retirement to a future base rate case. The ultimate outcomeregulatory asset. Recovery of this matter cannot be determined at this time.
Storm Damage Recovery
Georgia Power is accruing $30 million annuallyeach unit's net book value will continue 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.ARP.
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 amortizingFor the regulatory asset associated with the investment balances remaining afterat December 31, 2019, Georgia Power requested recovery in the retirementGeorgia Power 2019 Base Rate Case as follows: (i) the net book values 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 SchererMitchell 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.(approximately $8
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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million at June 30, 2019) and Plant McIntosh Unit 1, any unusable materials and supplies inventory, and the future generation site in Stewart County, Georgia over a three-year period ending December 31, 2022 and (ii) the net book values of Plant Hammond Units 1 through 4 over a period equal to the applicable unit's remaining useful life through 2035. The ultimate outcome of these matters cannot be determined at this time.
Also in the 2019 IRP, the Georgia PSC rejected a request to certify approximately 25 MWs of capacity at Plant Scherer Unit 3 for the retail jurisdiction beginning January 1, 2020 following the expiration of a wholesale PPA. Georgia Power may offer such capacity in the wholesale market or to the retail jurisdiction in a future Integrated Resource Plan. The ultimate outcome of this matter cannot be determined at this time but is not expected to have a material impact on Southern Company's financial statements.
Additionally, the Georgia PSC approved Georgia Power's proposed environmental compliance strategy associated with ash pond and certain landfill closures and post-closure care in compliance with the CCR Rule and the related state rule. In the Georgia Power 2019 Base Rate Case, Georgia Power requested recovery of the under recovered balance of these compliance costs at December 31, 2019 (approximately $135 million at June 30, 2019) over a three-year period ending December 31, 2022 and recovery of estimated compliance costs of $277 million for 2020, $395 million for 2021, and $655 million for 2022 over three-year periods ending December 31, 2022, 2023, and 2024, respectively. The ultimate outcome of this matter cannot be determined at this time. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information regarding Georgia Power's AROs.
The Georgia PSC also approved Georgia Power to (i) issue requests for proposals (RFP) for capacity beginning in 2022 or 2023 and in 2026, 2027, or 2028; (ii) procure up to an additional 2,210 MWs of renewable resources through competitive RFPs; and (iii) invest in a portfolio of up to 80 MWs of battery energy storage technologies.
See "Rate Plans" herein for additional information regarding the Georgia Power 2019 Base Rate Case.
Mississippi Power
Kemper County Energy Facility
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. 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 Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.
During the second quarter and year-to-date 2019, Mississippi Power recorded pre-tax charges to income of $4 million ($3 million after tax) and $6 million ($5 million after tax), respectively, primarily resulting from the abandonment and related closure activities and ongoing period costs, net of sales proceeds, for the mine and gasifier-related assets at the Kemper County energy facility. Additional closure costs for the mine and gasifier-related assets, currently estimated at up to $10 million pre-tax (excluding dismantlement costs, net of salvage), may be incurred through the first half of 2020. In addition, period costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the mine and gasifier-related assets, are estimated at $7 million for the remainder of 2019 and $2 million to $6 million annually in 2020 through 2023.
In addition, Mississippi Power constructed the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery and is currently evaluating its options regarding the final disposition of the CO2 pipeline, including removal of the pipeline. This evaluation is expected to be complete later in 2019. If Mississippi Power ultimately decides to remove the CO2 pipeline, the cost of removal could have a material impact on Southern Company's financial statements.
In December 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the $387 million of grants received. Mississippi Power and the DOE are currently in discussions regarding the requested closeout and property disposition, which may require payment to the DOE for a portion of certain property that is to be retained by Mississippi Power. In connection with the DOE closeout discussions, on April 29, 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
of an investigation related to the Kemper County energy facility. The ultimate outcome of these matters cannot be determined at this time; however, they could have a material impact on Southern Company's financial statements.
Southern Company Gas
Natural Gas Cost Recovery
Southern Company Gas has establishedThe 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's 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 and energy efficiency plans.
Base Rate Cases
On March 10, 2017,In November 2018, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $208$230 million increase in annual base rate revenues. The requested increase is based on a 2018 projected test year andfor the 12-month period ending September 30, 2020, a ROE of 10.7%10.6%, and an increase in the equity ratio from 52% to 54% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation.
On April 16, 2019, Nicor Gas entered into a stipulation agreement to resolve all related issues with the Staff of the Illinois Commission, including a ROE of 9.86% and an equity ratio of 54%. Also on April 16, 2019, Nicor Gas filed its rebuttal testimony with the Illinois Commission incorporating the stipulation agreement and addressing the remaining items outstanding with the other two intervenors. As a result of the stipulation agreement and rebuttal testimony, the revised requested annual revenue increase is $180 million.
The Illinois Commission is expected to rule on the requested increase in December 2017,by early October 2019, after which rate adjustments will be effective.
On June 3, 2019, Atlanta Gas Light filed a general base rate case with the Georgia PSC requesting a $96 million increase in annual base rate revenues. The requested increase is based on a forward-looking test year for the 12-month period ending July 31, 2020, a ROE of 10.75% with an earnings band based on a ROE between 10.55% and 10.95%, and a continued equity ratio of 55%. The filing also requests the continuation of the Georgia rate adjustment mechanism, as previously authorized. Atlanta Gas Light expects the Georgia PSC to issue a final order on this matter on December 19, 2019 with the new rates becoming effective January 1, 2020.
The ultimate outcome of this matterthese matters cannot be determined at this time.
Construction ProgramRegulatory Matters
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, seeSee Note 32 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 herein for additional information.
Fuel Cost Recovery
The traditional electric operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow. The traditional electric operating companies continuously monitor their under "Regulatory Matters– Georgiaor over recovered fuel cost balances and make appropriate filings with their state PSCs to adjust fuel cost recovery rates as necessary.
Alabama Power – Nuclear Construction"
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 " – Southern Company Gas–Regulatory Infrastructure Programs"Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power.
Environmental Accounting Order
On April 15, 2019, Alabama Power retired Plant Gorgas Units 8, 9, and "Integrated Coal Gasification Combined Cycle" herein. Also see10 and reclassified approximately $654 million of the unrecovered asset balances to regulatory assets, which are being recovered over the units' remaining useful lives, the latest being through 2037, as established prior to the decision to retire. Additionally, approximately $700 million of net capitalized asset retirement costs were reclassified to a regulatory asset in accordance with accounting guidance provided by the Alabama PSC. The asset retirement costs are being recovered through 2055. See Note 122 to the financial statements of Southern Company under "Southern"Alabama Power – Construction Projects"Environmental Accounting Order" and Note 6 in Item 8 of the Form 10-K and Note (I)for additional information.
Georgia Power
Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the Condensed Financial Statements under "Southernoversight of the Georgia PSC. Georgia Power" herein. 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 (ECCR) tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to 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.
Also see FINANCIAL CONDITION AND LIQUIDITY – "Capital RequirementsRate Plans
On June 28, 2019, Georgia Power filed a base rate case (Georgia Power 2019 Base Rate Case) with the Georgia PSC. The filing includes a three-year Alternate Rate Plan with requested rate increases totaling $563 million, $145 million, and Contractual Obligations" herein for additional information regarding Southern Company's capital requirements for its subsidiaries' construction programs.$234 million effective January 1, 2020, January 1, 2021, and January 1, 2022, respectively. These
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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),increases are based on a stipulation between Mississippiproposed retail ROE of 10.90% and a proposed equity ratio of 56% and reflect levelized revenue requirements during the three-year period, with the exception of incremental compliance costs related to CCR AROs, Demand-Side Management programs, and adjustments to the Municipal Franchise Fee tariff.
Georgia Power and the MPUS, authorizing rates that provide for thehas requested recovery of approximately $126 million annually relatedthe proposed increases through its existing base rate tariffs as follows:
|
| | | | | | | | | |
| Tariff | 2020 | 2021 | 2022 |
| | (in millions) |
| Traditional base: | | | |
| Levelized | $ | 209 |
| $ | — |
| $ | — |
|
| CCR AROs | 158 |
| 140 |
| 227 |
|
| ECCR | 165 |
| — |
| — |
|
| Demand-Side Management | 14 |
| 2 |
| 1 |
|
| Municipal Franchise Fee | 17 |
| 3 |
| 5 |
|
Total(*) | $ | 563 |
| $ | 145 |
| $ | 234 |
|
| |
| (*) | Totals may not add due to rounding. |
Georgia Power's filing primarily reflects requests to (i) address 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 schedulesimpacts of the regulatory assets reviewedTax Reform Legislation, (ii) recover the costs of recent and determined prudentfuture capital investments 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 accountinfrastructure designed to maintain currenthigh levels of reliability and superior customer service with updated depreciation rates, related(iii) recover substantial storm damage expenses incurred and deferred since 2013 along with a reasonable level of storm damage expenses expected 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 challengesbe incurred during the extended start-up processthree years ending December 31, 2022, and (iv) recover the costs necessary 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 timecomply with federal and significant cost.state regulations for CCR AROs. In addition, the long-term natural gas price forecast has decreased significantlyfiling includes the following provisions:
Continuation of an allowed retail ROE range of 10.00% to 12.00%.
Continuation of the process whereby two-thirds of any earnings above the top of the allowed ROE range are shared with Georgia Power's customers and the estimated costremaining one-third are retained by Georgia Power.
Continuation of operating and maintaining the facilityoption to file an Interim Cost Recovery tariff in the event earnings are projected to fall below the bottom of the ROE range during the first five full yearsthree-year term of operations has increased significantly since certification.the plan.
Georgia Power expects the Georgia PSC to issue a final order in this matter on December 17, 2019. The ultimate outcome of this matter cannot be determined at this time.
Integrated Resource Plan
In 2016, the Georgia PSC approved Georgia Power's triennial Integrated Resource Plan, including recovery of costs up to $99 million through June 30, 2019 to preserve nuclear generation as an option at a future generation site in Stewart County, Georgia. In 2017, the Georgia PSC approved Georgia Power's decision to suspend work at the site due to changing economics, including lower load forecasts and fuel costs. In accordance with the Georgia PSC's order, costs incurred of approximately $50 million have been recorded as a regulatory asset.
On June 21, 2017,July 16, 2019, the MississippiGeorgia PSC stated its intentvoted to issueapprove Georgia Power's triennial Integrated Resource Plan (2019 IRP) as modified by a stipulated agreement among Georgia Power, 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 costsstaff of the Kemper IGCC.Georgia PSC, and certain intervenors and further modified by the Georgia PSC.
In the 2019 IRP, the Georgia PSC approved the decertification and retirement of Plant Hammond Units 1 through 4 (840 MWs) and Plant McIntosh Unit 1 (142.5 MWs) effective July 29, 2019. The MississippiGeorgia 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 withalso approved the Kemper IGCC gasifier and related assets; and (iii) modification or amendmentreclassification 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 portionremaining net book values of the Kemper IGCC, given the uncertaintyPlant Hammond and Plant McIntosh units (approximately $500 million and $40 million, respectively, at June 30, 2019), as well as any unusable materials and supplies inventory balances, upon retirement to the futurea regulatory asset. Recovery of the gasifier portion of the Kemper IGCC. Mississippi Power expects toeach unit's net book value will continue to operate the combined cycle portion of the Kemper IGCCthrough December 31, 2019 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 addressedprovided in the Kemper IGCC Settlement Docket, given2013 ARP.
For the Mississippi PSC's stated intent regarding no further rate increase forregulatory asset balances remaining at December 31, 2019, Georgia Power requested recovery in the Kemper County energy facility, cost recoveryGeorgia Power 2019 Base Rate Case as follows: (i) the net book values 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,Plant Mitchell Unit 3 (approximately $8
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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which includes estimated gasifier-related costs throughmillion at June 30, 2019) and Plant McIntosh Unit 1, any unusable materials and supplies inventory, and the future generation site in Stewart County, Georgia over a three-year period ending December 31, 20172022 and (ii) the net book values of Plant Hammond Units 1 through 4 over a period equal to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costsapplicable unit's remaining useful life 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.2035. The ultimate outcome willof these matters cannot be determined by the Mississippi PSCat this time.
Also in the Kemper IGCC Settlement Docket proceedings.2019 IRP, the Georgia PSC rejected a request to certify approximately 25 MWs of capacity at Plant Scherer Unit 3 for the retail jurisdiction beginning January 1, 2020 following the expiration of a wholesale PPA. Georgia Power may offer such capacity in the wholesale market or to the retail jurisdiction in a future Integrated Resource Plan. The ultimate outcome of this matter cannot be determined at this time but is not expected to have a material impact on Southern Company's financial statements.
For additional information onAdditionally, the Kemper IGCC, including information onGeorgia PSC approved Georgia Power's proposed environmental compliance strategy associated with ash pond and certain landfill closures and post-closure care in compliance with the project economic viability analysis, pending lawsuits,CCR Rule and an ongoing SEC investigation, seethe related state rule. In the Georgia Power 2019 Base Rate Case, Georgia Power requested recovery of the under recovered balance of these compliance costs at December 31, 2019 (approximately $135 million at June 30, 2019) over a three-year period ending December 31, 2022 and recovery of estimated compliance costs of $277 million for 2020, $395 million for 2021, and $655 million for 2022 over three-year periods ending December 31, 2022, 2023, and 2024, respectively. The ultimate outcome of this matter cannot be determined at this time. See Note 36 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for additional information regarding Georgia Power's AROs.
The Georgia PSC also approved Georgia Power to (i) issue requests for proposals (RFP) for capacity beginning in 2022 or 2023 and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle"in 2026, 2027, or 2028; (ii) procure up to an additional 2,210 MWs of renewable resources through competitive RFPs; and "Other Matters"(iii) invest in a portfolio of up to 80 MWs of battery energy storage technologies.
See "Rate Plans" herein for additional information regarding the Georgia Power 2019 Base Rate Case.
Mississippi Power
Kemper County Energy Facility
As the mining permit holder, Liberty Fuels Company, LLC has a legal obligation to perform mine reclamation, 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, 2016has a contractual obligation to include, among other things, Southern Company asfund all reclamation activities. As a defendant. The individual plaintiff alleges that Mississippi Power and Southern Company violatedresult of 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 scheduleabandonment of the Kemper IGCC, final mine reclamation began in 2018 and that these alleged breachesis expected to be substantially completed in 2020, with monitoring expected to continue through 2027. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.
During the second quarter and year-to-date 2019, Mississippi Power recorded pre-tax charges to income of $4 million ($3 million after tax) and $6 million ($5 million after tax), respectively, primarily resulting from the abandonment and related closure activities and ongoing period costs, net of sales proceeds, for the mine and gasifier-related assets at the Kemper County energy facility. Additional closure costs for the mine and gasifier-related assets, currently estimated at up to $10 million pre-tax (excluding dismantlement costs, net of salvage), may be incurred through the first half of 2020. In addition, period costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the mine and gasifier-related assets, are estimated at $7 million for the remainder of 2019 and $2 million to $6 million annually in 2020 through 2023.
In addition, Mississippi Power constructed the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery and is currently evaluating its options regarding the final disposition of the CO2 pipeline, including removal of the pipeline. This evaluation is expected to be complete later in 2019. If Mississippi Power ultimately decides to remove the CO2 pipeline, the cost of removal could have unjustly enricheda material impact on Southern Company's financial statements.
In December 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the $387 million of grants received. Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damagesthe DOE are currently in discussions regarding the requested closeout and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relatingproperty disposition, which may require payment to the Kemper IGCC; askDOE for a portion of certain property that is to be retained by Mississippi Power. In connection with the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power orDOE closeout discussions, on April 29, 2019, the Civil Division of the Department of Justice informed 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 CircuitMississippi Power
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 otherinvestigation 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 theKemper County energy facility. 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.
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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 eventtime; however, 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 itselfSouthern Company Gas
The natural gas distribution utilities are subject to regulation and as agentoversight by their respective state regulatory agencies for the rates charged to their customers and other Vogtle Owners,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 regulatory agencies in the states in which 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 EPC Contractor entered intobilling factor will not have a significant effect on 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 and energy efficiency plans.
In November 2018, Nicor Gas filed a general base rate case with the Services Agreement, which was amended and restatedIllinois Commission requesting a $230 million increase in annual base rate revenues. The requested increase is based on July 20, 2017,a projected test year for the EPC Contractor to transition construction management12-month period ending September 30, 2020, a ROE of Plant Vogtle Units 310.6%, 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 inequity ratio from 52% to 54% to address the seventeenth VCM report by more than $1 billion or extensionnegative cash flow and credit metric impacts of the project schedule contained inTax Reform Legislation.
On April 16, 2019, Nicor Gas entered into a stipulation agreement to resolve all related issues with 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 changeStaff of the primary construction contractorIllinois Commission, including a ROE of 9.86% and (ii) 67% for material amendments to the Services Agreement or agreementsan equity ratio of 54%. Also on April 16, 2019, Nicor Gas filed its rebuttal testimony with the primary construction contractor or Southern Nuclear.Illinois Commission incorporating the stipulation agreement and addressing the remaining items outstanding with the other two intervenors. As a result of the stipulation agreement and rebuttal testimony, the revised requested annual revenue increase is $180 million.
The term sheet also confirms thatIllinois Commission is expected to rule on the Vogtle Owners' sole recourse againstrequested increase by early October 2019, after which rate adjustments will be effective.
On June 3, 2019, Atlanta Gas Light filed a general base rate case with the Georgia Power or Southern Nuclear for any action or inactionPSC requesting a $96 million increase in connection with their performance as agentannual base rate revenues. The requested increase is based on a forward-looking test year for the Vogtle Owners is limited12-month period ending July 31, 2020, a ROE of 10.75% with an earnings band based on a ROE between 10.55% and 10.95%, and a continued equity ratio of 55%. The filing also requests the continuation of the Georgia rate adjustment mechanism, as previously authorized. Atlanta Gas Light expects the Georgia PSC to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.issue a final order on this matter on December 19, 2019 with the new rates becoming effective January 1, 2020.
The ultimate outcome of these matters cannot be determined at this time.
Regulatory Matters
See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.
Fuel Cost Recovery
The traditional electric operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow. The traditional electric operating companies continuously monitor their under or over recovered fuel cost balances and make appropriate filings with their state PSCs to adjust fuel cost recovery rates as necessary.
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.
Environmental Accounting Order
On April 15, 2019, Alabama Power retired Plant Gorgas Units 8, 9, and 10 and reclassified approximately $654 million of the unrecovered asset balances to regulatory assets, which are being recovered over the units' remaining useful lives, the latest being through 2037, as established prior to the decision to retire. Additionally, approximately $700 million of net capitalized asset retirement costs were reclassified to a regulatory asset in accordance with accounting guidance provided by the Alabama PSC. The asset retirement costs are being recovered through 2055. See Note 2 to the financial statements under "Alabama Power – Environmental Accounting Order" and Note 6 in Item 8 of the Form 10-K for additional information.
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 (ECCR) tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to 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.
Rate Plans
On June 28, 2019, Georgia Power filed a base rate case (Georgia Power 2019 Base Rate Case) with the Georgia PSC. The filing includes a three-year Alternate Rate Plan with requested rate increases totaling $563 million, $145 million, and $234 million effective January 1, 2020, January 1, 2021, and January 1, 2022, respectively. These
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
increases are based on a proposed retail ROE of 10.90% and a proposed equity ratio of 56% and reflect levelized revenue requirements during the three-year period, with the exception of incremental compliance costs related to CCR AROs, Demand-Side Management programs, and adjustments to the Municipal Franchise Fee tariff.
Georgia Power has requested recovery of the proposed increases through its existing base rate tariffs as follows:
|
| | | | | | | | | |
| Tariff | 2020 | 2021 | 2022 |
| | (in millions) |
| Traditional base: | | | |
| Levelized | $ | 209 |
| $ | — |
| $ | — |
|
| CCR AROs | 158 |
| 140 |
| 227 |
|
| ECCR | 165 |
| — |
| — |
|
| Demand-Side Management | 14 |
| 2 |
| 1 |
|
| Municipal Franchise Fee | 17 |
| 3 |
| 5 |
|
Total(*) | $ | 563 |
| $ | 145 |
| $ | 234 |
|
| |
| (*) | Totals may not add due to rounding. |
Georgia Power's filing primarily reflects requests to (i) address the impacts of the Tax Reform Legislation, (ii) recover the costs of recent and future capital investments in infrastructure designed to maintain high levels of reliability and superior customer service with updated depreciation rates, (iii) recover substantial storm damage expenses incurred and deferred since 2013 along with a reasonable level of storm damage expenses expected to be incurred during the three years ending December 31, 2022, and (iv) recover the costs necessary to comply with federal and state regulations for CCR AROs. In addition, the filing includes the following provisions:
Continuation of an allowed retail ROE range of 10.00% to 12.00%.
Continuation of the process whereby two-thirds of any earnings above the top of the allowed ROE range are shared with Georgia Power's customers and the remaining one-third are retained by Georgia Power.
Continuation of the option to file an Interim Cost Recovery tariff in the event earnings are projected to fall below the bottom of the ROE range during the three-year term of the plan.
Georgia Power expects the Georgia PSC to issue a final order in this matter on December 17, 2019. The ultimate outcome of this matter cannot be determined at this time.
Integrated Resource Plan
In 2016, the Georgia PSC approved Georgia Power's triennial Integrated Resource Plan, including recovery of costs up to $99 million through June 30, 2019 to preserve nuclear generation as an option at a future generation site in Stewart County, Georgia. In 2017, the Georgia PSC approved Georgia Power's decision to suspend work at the site due to changing economics, including lower load forecasts and fuel costs. In accordance with the Georgia PSC's order, costs incurred of approximately $50 million have been recorded as a regulatory asset.
On July 16, 2019, the Georgia PSC voted to approve Georgia Power's triennial Integrated Resource Plan (2019 IRP) as modified by a stipulated agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors and further modified by the Georgia PSC.
In the 2019 IRP, the Georgia PSC approved the decertification and retirement of Plant Hammond Units 1 through 4 (840 MWs) and Plant McIntosh Unit 1 (142.5 MWs) effective July 29, 2019. The Georgia PSC also approved the reclassification of the remaining net book values of the Plant Hammond and Plant McIntosh units (approximately $500 million and $40 million, respectively, at June 30, 2019), as well as any unusable materials and supplies inventory balances, upon retirement to a regulatory asset. Recovery of each unit's net book value will continue through December 31, 2019 as provided in the 2013 ARP.
For the regulatory asset balances remaining at December 31, 2019, Georgia Power requested recovery in the Georgia Power 2019 Base Rate Case as follows: (i) the net book values of Plant Mitchell Unit 3 (approximately $8
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
million at June 30, 2019) and Plant McIntosh Unit 1, any unusable materials and supplies inventory, and the future generation site in Stewart County, Georgia over a three-year period ending December 31, 2022 and (ii) the net book values of Plant Hammond Units 1 through 4 over a period equal to the applicable unit's remaining useful life through 2035. The ultimate outcome of these matters cannot be determined at this time.
Also in the 2019 IRP, the Georgia PSC rejected a request to certify approximately 25 MWs of capacity at Plant Scherer Unit 3 for the retail jurisdiction beginning January 1, 2020 following the expiration of a wholesale PPA. Georgia Power may offer such capacity in the wholesale market or to the retail jurisdiction in a future Integrated Resource Plan. The ultimate outcome of this matter cannot be determined at this time but is not expected to have a material impact on Southern Company's financial statements.
Additionally, the Georgia PSC approved Georgia Power's proposed environmental compliance strategy associated with ash pond and certain landfill closures and post-closure care in compliance with the CCR Rule and the related state rule. In the Georgia Power 2019 Base Rate Case, Georgia Power requested recovery of the under recovered balance of these compliance costs at December 31, 2019 (approximately $135 million at June 30, 2019) over a three-year period ending December 31, 2022 and recovery of estimated compliance costs of $277 million for 2020, $395 million for 2021, and $655 million for 2022 over three-year periods ending December 31, 2022, 2023, and 2024, respectively. The ultimate outcome of this matter cannot be determined at this time. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information regarding Georgia Power's AROs.
The Georgia PSC also approved Georgia Power to (i) issue requests for proposals (RFP) for capacity beginning in 2022 or 2023 and in 2026, 2027, or 2028; (ii) procure up to an additional 2,210 MWs of renewable resources through competitive RFPs; and (iii) invest in a portfolio of up to 80 MWs of battery energy storage technologies.
See "Rate Plans" herein for additional information regarding the Georgia Power 2019 Base Rate Case.
Mississippi Power
Kemper County Energy Facility
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. 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 Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.
During the second quarter and year-to-date 2019, Mississippi Power recorded pre-tax charges to income of $4 million ($3 million after tax) and $6 million ($5 million after tax), respectively, primarily resulting from the abandonment and related closure activities and ongoing period costs, net of sales proceeds, for the mine and gasifier-related assets at the Kemper County energy facility. Additional closure costs for the mine and gasifier-related assets, currently estimated at up to $10 million pre-tax (excluding dismantlement costs, net of salvage), may be incurred through the first half of 2020. In addition, period costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the mine and gasifier-related assets, are estimated at $7 million for the remainder of 2019 and $2 million to $6 million annually in 2020 through 2023.
In addition, Mississippi Power constructed the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery and is currently evaluating its options regarding the final disposition of the CO2 pipeline, including removal of the pipeline. This evaluation is expected to be complete later in 2019. If Mississippi Power ultimately decides to remove the CO2 pipeline, the cost of removal could have a material impact on Southern Company's financial statements.
In December 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the $387 million of grants received. Mississippi Power and the DOE are currently in discussions regarding the requested closeout and property disposition, which may require payment to the DOE for a portion of certain property that is to be retained by Mississippi Power. In connection with the DOE closeout discussions, on April 29, 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
of an investigation related to the Kemper County energy facility. The ultimate outcome of these matters cannot be determined at this time; however, they could have a material impact on Southern Company's financial statements.
Southern Company Gas
The natural gas distribution utilities are subject to regulation and oversight by their respective state regulatory agencies for the rates charged 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 regulatory agencies in the states in which 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 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 and energy efficiency plans.
In November 2018, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $230 million increase in annual base rate revenues. The requested increase is based on a projected test year for the 12-month period ending September 30, 2020, a ROE of 10.6%, and an increase in the equity ratio from 52% to 54% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation.
On April 16, 2019, Nicor Gas entered into a stipulation agreement to resolve all related issues with the Staff of the Illinois Commission, including a ROE of 9.86% and an equity ratio of 54%. Also on April 16, 2019, Nicor Gas filed its rebuttal testimony with the Illinois Commission incorporating the stipulation agreement and addressing the remaining items outstanding with the other two intervenors. As a result of the stipulation agreement and rebuttal testimony, the revised requested annual revenue increase is $180 million.
The Illinois Commission is expected to rule on the requested increase by early October 2019, after which rate adjustments will be effective.
On June 3, 2019, Atlanta Gas Light filed a general base rate case with the Georgia PSC requesting a $96 million increase in annual base rate revenues. The requested increase is based on a forward-looking test year for the 12-month period ending July 31, 2020, a ROE of 10.75% with an earnings band based on a ROE between 10.55% and 10.95%, and a continued equity ratio of 55%. The filing also requests the continuation of the Georgia rate adjustment mechanism, as previously authorized. Atlanta Gas Light expects the Georgia PSC to issue a final order on this matter on December 19, 2019 with the new rates becoming effective January 1, 2020.
The ultimate outcome of these matters cannot be determined at this time.
Construction Program
Overview
The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue its strategy of developing and constructing new electric generating facilities, adding environmental modifications to certain existing units, expanding and improving the electric transmission and distribution systems, and updating and expanding the natural gas distribution systems. For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. Southern Company Gas is engaged in various infrastructure improvement programs designed to update or expand the natural gas distribution systems of the natural gas distribution utilities to improve reliability and meet operational flexibility and growth. The natural gas distribution utilities recover their investment and a return associated with these infrastructure programs through their regulated rates. See Notes 2 and
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
15 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" and "Southern Power," respectively, in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information.
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). See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K and "Nuclear Construction" herein for additional information.
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.
Nuclear Construction
See Note 2 to the financial statements under "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, the joint ownership agreements and related funding agreement, VCM reports, and the NCCR tariff.
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. Georgia Power holds a 45.7% ownership interest in Plant Vogtle Units 3 and 4. 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 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement. In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into several transitional arrangements to allow construction to continue. In July 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 time and materials cost basis. The Vogtle Services Agreement provides that it will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.
In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, executed the Bechtel Agreement, a cost reimbursable plus fee arrangement, whereby Bechtel is 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 the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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) | $ | 8.0 |
|
| Construction contingency estimate | 0.4 |
|
Total project capital cost forecast(a)(b) | 8.4 |
|
Net investment as of June 30, 2019(b) | (5.2 | ) |
Remaining estimate to complete(a) | $ | 3.2 |
|
| |
| (a) | Excludes financing costs expected to be capitalized through AFUDC of approximately $315 million. |
| |
| (b) | Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds. |
Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $2.0 billion had been incurred through June 30, 2019.
In April 2019, Southern Nuclear completed a cost and schedule validation process to verify and update quantities of commodities remaining to install, labor hours to install remaining quantities and related productivity, testing and system turnover requirements, and forecasted staffing needs and related costs. This process confirmed the estimated total project capital cost forecast for Plant Vogtle Units 3 and 4. The expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4, as previously approved by the Georgia PSC, remain unchanged.
As construction continues and testing and system turnover activities increase, challenges with management of contractors, subcontractors, and vendors; supervision of craft labor and related craft labor productivity, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, and/or installation and the initial testing and start-up, including any required engineering changes, of plant systems, structures, or components (some of which are based on new technology that only recently began initial operation in the global nuclear industry at this scale), or regional transmission upgrades, any of which may require additional labor and/or materials; or other issues could arise and change the projected schedule and estimated cost.
The April 2019 cost and schedule validation process established target values for monthly construction production and system turnover activities as part of a strategy to maintain and, where possible, build margin to the approved in-service dates. To support that strategy, monthly production and activity target values will continue to increase significantly throughout 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers (particularly electrical and pipefitter craft labor), as well as additional supervision and other field support resources, must be retained and deployed.
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. 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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $12 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 entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 to provide for, among other conditions, additional Vogtle Owner approval requirements. Effective in August 2018, the 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 to continue construction (as amended, and together with the November 2017 amendment, the Vogtle Joint Ownership Agreements). The Vogtle Joint Ownership Agreements also confirm 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 the 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, 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) the Vogtle Owner Term Sheet with the other Vogtle Owners and MEAG's wholly-owned subsidiaries 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) the MEAG Term Sheet with MEAG and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. On January 14, 2019, Georgia Power, MEAG, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. On February 18, 2019, Georgia Power, the other Vogtle Owners, and MEAG'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.
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 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, 2017,2019, Georgia Power had recovered approximately $1.5$2.0 billion of financing costs. Financing costs related to capital costs above $4.418 billion will be recovered through AFUDC; 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 2018, the Georgia PSC approved Georgia Power's request to increase the NCCR tariff by approximately $90$88 million annually, effective January 1, 2018, pending2019.
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
On December 20,
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 $100 million in 2018 and are estimated to have negative earnings impacts of approximately $70 million in 2019 and an aggregate of approximately $630 million from 2020 to 2022.
TheIn 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 two appeals. On January 9, 2019, GIPL, PSE, and Georgia Watch filed an appeal of this decision with the Georgia Court of Appeals. Georgia Power believes the appeal has approved sixteen VCM reports coveringno merit; however, an adverse outcome in the periods through December 31, 2016, including construction capital costs incurred, which through that date totaled $3.9 billion.appeal combined with subsequent adverse action by the Georgia PSC could have a material impact on Southern Company's results of operations, financial condition, and liquidity.
In August 2018, Georgia Power filed its seventeenthnineteenth VCM report coveringwith the period from January 1 through June 30, 2017, requestingGeorgia PSC, which requested approval of $542$578 million of construction capital costs incurred during that period, withfrom January 1, 2018 through June 30, 2018. On February 19, 2019, the Georgia PSC on August 31, 2017.
Inapproved the seventeenthnineteenth VCM, report, Georgia Power recommended that constructionbut deferred approval 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.$51.6 million of expenditures related to Georgia Power's recommendation to go forward with completionportion of Vogtle Units 3 and 4 is based onan administrative claim filed in the following assumptions aboutWestinghouse bankruptcy proceedings. Through the regulatory treatment of this recommendation, if the recommendation to go forward is adopted by the Georgia PSC: (i) that pursuant to Georgia law,nineteenth VCM, 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 allhas approved total construction 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.through June
The ultimate outcome of these matters cannot be determined at this time.
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Revised Cost and Schedule
Georgia Power's approximate proportionate share30, 2018 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$5.4 billion (before $1.7 billion of whichpayments received under the Guarantee Settlement Agreement and approximately $1.5 billion had been incurred through September$188 million in related Customer Refunds).
On April 30, 2017.
Georgia Power's cancellation cost estimate results indicate that its proportionate share2019, as requested by the staff 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, inGeorgia Power reported the eventresults 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 limitedthe cost and schedule validation process 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.PSC. On August 30, 2019, Georgia Power will continue workingfile its twentieth VCM report concurrently with its twenty-first VCM report with the Georgia PSC, which will reflect the capital cost forecast discussed previously and request approval of $1.2 billion of construction capital costs incurred from June 30, 2018 through June 30, 2019. In addition, on June 20, 2019, Georgia Power, acting for itself and as agent for the other Vogtle Owners, to determine future actionsentered into a settlement agreement 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.
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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 specifiedadministrative claim filed in the Westinghouse Design Control Document andbankruptcy proceedings. Accordingly, in the combined construction and operating licenses, including inspections by Southern Nuclear andtwentieth/twenty-first VCM report, Georgia Power will also request approval of the NRC that occur throughout construction. As a result$51.6 million 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 approvalsassociated expenditures previously deferred 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.Georgia PSC.
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.
DOE Financing
At June 30, 2019, Georgia Power had borrowed $3.46 billion related to Plant Vogtle Units 3 and 4 costs as provided through the Amended and Restated Loan Guarantee Agreement and related multi-advance credit facilities among Georgia Power, the DOE, and the FFB, which provide for borrowings of up to approximately $5.130 billion, subject to the satisfaction of certain conditions. See additional risksNote 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" 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 78 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)(F) to the Condensed Financial Statements under "Integrated Coal Gasification Combined CycleDOE Loan Guarantee Borrowings" herein and Note (G) to the Condensed Financial Statements herein for additional information. information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
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
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 mattermatters cannot be determined at this time.
Other Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Southern Company in Item 7 for additional information.
Southern Company and its subsidiaries are involved in various other matters being litigated and regulatory matters that could affect future earnings.earnings, including matters being litigated, as well as other regulatory matters and matters that could result in asset impairments. 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 regulationlaws and regulations governing air, water, land, and protection of air emissions and water discharges.other natural resources. 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 qualitylaws and water standards,regulations, 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, or potential asset impairments cannot be predicteddetermined at this time; however, for current proceedings not specifically reported in NoteNotes (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 Southern Company's financial statements. See NoteNotes (B) and (C) 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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Litigation
In January 20, 2017, a purportedputative 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 IGCCCounty 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. On June 12,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. On July 27,Also in 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.opposition. In March 2018, the court issued an order granting, in part, the defendants' motion to dismiss. The court dismissed certain claims against certain officers of Southern Company and Mississippi Power and dismissed the allegations related to a number of the statements that plaintiffs challenged as being false or misleading. In April 2018, the defendants filed a motion for reconsideration of the court's order, seeking dismissal of the remaining claims in the lawsuit. In August 2018, the court denied the motion for reconsideration and denied a motion to certify the issue for interlocutory appeal.
OnIn 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 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 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 April 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 putative securities class action.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Gwinnett County, Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper IGCC. EachCounty energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper IGCCCounty energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. EachThe 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. EachThe 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 andIn May 2018, the court deferred the consolidated caseentered an order staying this lawsuit until 30 days after certain further actionthe resolution of any dispositive motions or any settlement, whichever is earlier, in the purportedputative securities class action.
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 approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest. In the first quarter 2019, Mississippi Power and Southern Company filed motions to dismiss, which were denied by the arbitration panel on May 10, 2019.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In 2011, plaintiffs filed a putative class action complaint discussed above.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 tort law claims. In 2016, the Georgia Court of Appeals reversed the trial court's previous dismissal of the case and remanded the case to the trial court. Georgia Power filed a petition for writ of certiorari with the Georgia Supreme Court, which was granted in 2017. In June 2018, the Georgia Supreme Court affirmed the judgment of the Georgia Court of Appeals and remanded the case to the trial court for further proceedings. Following a motion by Georgia Power, on February 13, 2019, the Superior Court of Fulton County ordered the parties to submit petitions to the Georgia PSC for a declaratory ruling to address certain terms the court previously held were ambiguous as used in the Georgia PSC's orders. The order entered by the Superior Court of Fulton County 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. Georgia Power also filed a notice of appeal with the Georgia Court of Appeals regarding the Superior Court of Fulton County's February 2019 order. The amount of any possible losses cannot be calculated at this time because, among other factors, it is unknown whether conditional class certification will be upheld and the ultimate composition of any class and whether any losses would be subject to recovery from any municipalities.
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, theThe ultimate outcome of whichthese matters cannot be determined at this time.
The SEC is conducting a formal investigationMississippi Power
In conjunction with Southern Company's sale of Southern Company andGulf Power, Mississippi Power concerningand Gulf Power have committed to seek a restructuring of their 50% undivided ownership interests in Plant Daniel such that each of them would, after the estimated costs and expected in-service daterestructuring, own 100% of a generating unit. On January 15, 2019, Gulf Power provided notice to Mississippi Power that Gulf Power will retire its share of the Kemper IGCC. Southern Company believesgenerating capacity of Plant Daniel on January 15, 2024. Mississippi Power has the investigationoption to purchase Gulf Power's ownership interest for $1 on January 15, 2024, provided that Mississippi Power exercises the option no later than 120 days prior to that date. Mississippi Power is focused primarily on periods subsequent to 2010assessing the potential operational and on accounting matters, disclosure controls and procedures, and internal controls over financial reporting associated with the Kemper IGCC. See ACCOUNTING POLICIES – "Applicationeconomic effects of Critical Accounting Policies and Estimates" herein for additional information on the Kemper IGCC.Gulf Power's notice. The ultimate outcome of this matterthese matters remains subject to completion of Mississippi Power's evaluations and applicable regulatory approvals, including by the FERC and the Mississippi PSC, and cannot be determined at this time; however, ittime. See Note (K) to the Condensed Financial Statements under "Southern Company" herein for information regarding the sale of Gulf Power.
Southern Company Gas
See Note 3 to the financial statements in Item 8 of the Form 10-K under "Other Matters – Southern Company Gas" for information on a natural gas storage facility consisting of two salt dome caverns in Louisiana. The future performance of this facility, as well as Southern Company Gas' two other natural gas storage facilities located in California and Texas, could be impacted by ongoing changes in the U.S. natural gas storage market. Recent sales of natural gas storage facilities have resulted in losses for the sellers and may imply an impact on future rates and/or asset values. Southern Company Gas is not expectedevaluating these recent market transactions for impacts on its plans to return one of the salt dome caverns in Louisiana back to service in 2021. Sustained diminished natural gas storage values could trigger impairment of one or all of these natural gas storage facilities, which have a combined net book value of $438 million at June 30, 2019. The ultimate outcome of these matters cannot be determined at this time, but could have a material impact on theSouthern Company's financial statements of Southern Company.statements.
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 NoteNotes 1, 5, and 6 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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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 ofNote (A) to the Form 10-KCondensed Financial Statements herein 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 disclosuresinformation 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 hedgerecently adopted 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.standards.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company in Item 7 of the Form 10-K for additional information. Southern Company's financial condition remained stable at SeptemberJune 30, 2017.2019. 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$2.5 billion for the first ninesix months of 2017, an increase2019, a decrease of $1.0$0.7 billion from the corresponding period in 2016.2018. The increasedecrease 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.payments and the impacts of the Gulf Power disposition and the Southern Company Gas Dispositions. Net cash used forprovided from investing activities totaled $6.7$1.0 billion for the first ninesix months of 20172019 primarily due to proceeds from the sale of Gulf Power, partially offset by the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities and capital expenditures for Southern Company Gas' infrastructure replacement programs, and Southern Power's renewable acquisitions.programs. Net cash provided fromused for financing activities totaled $1.3$3.6 billion for the first ninesix months of 20172019 primarily due to repayments of short-term bank debt, net issuancesredemptions and repurchases of long-term and short-term debt, partially offset byand 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. See Notes (F) and (K) to the Condensed Financial Statements herein for additional information.
Significant balance sheet changes for the first ninesix months of 2017 include 2019 include:
decreases in assets and liabilities held for sale of $5.0 billion and $3.2 billion, respectively, primarily related to the sale of Gulf Power;
an increase of $1.3$2.1 billion in total stockholders' equity primarily related to the gain on the sale of Gulf Power;
| |
| • | operating lease right-of-use assets, net of amortization and operating lease obligations, each totaling $1.9 billion, recorded upon the adoption of FASB ASC Topic 842, Leases; |
an increase of $1.7 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, largelypartially offset by Alabama Power's reclassification of $1.4 billion to regulatory assets related to the $2.9retirement of Plant Gorgas, including $0.7 billion write-downassociated with AROs;
decreases of the gasification portions of the Kemper IGCC; a decrease of $0.4$1.5 billion in income taxes receivable, currentnotes payable 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$1.1 billion in long-term debt (including amounts due within one year) primarilyrelated to fund the Southern Company system's continuous construction programsnet repayments of short-term bank debt and for general corporate purposes;long-term debt, respectively; and a decrease
an increase of $0.7$1.2 billion in total common stockholder's equityaccumulated deferred income taxes primarily related to the estimated probable losses onexpected utilization of tax credit carryforwards in the Kemper IGCC, partially offset by2019 tax year as a result of increased taxable income from the issuancesale of Gulf Power.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Alabama Power" herein and Notes (A), (B), (F), (G), (K), and (L) to the Condensed Financial Statements herein for additional shares of common stock.information.
At the end of the thirdsecond quarter 2017,2019, the market price of Southern Company's common stock was $49.14$55.28 per share (based on the closing price as reported on the New York Stock Exchange)NYSE) and the book value was $23.99$25.73 per share, representing a market-to-book ratio of 205%215%, compared to $49.19, $25.00,$43.92, $23.91, and 197%184%, respectively, at the end of 2016.2018. Southern Company's common stock dividend for the thirdsecond quarter 20172019 was $0.58$0.62 per share compared to $0.56$0.60 per share in the thirdsecond quarter 2016.2018.
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 $3.2contractual obligations. Approximately $3.1 billion will be required through SeptemberJune 30, 20182020 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 statuteslaws 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 1215 to the financial statements of Southern Company under "Southern Power" in Item 8 of the Form 10-K and Note (I)(K) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding Southern Power's plant acquisitions.acquisitions and construction projects.
The construction program also includes Plant Vogtle Units 3 and 4, which includes components based on new technology that only recently began initial operation in the global nuclear industry at this scale and which may be subject to additional revised cost estimates during construction. The ability to control costs and avoid cost and schedule overruns during the development, construction, and operation of new facilities is subject to a number of factors, including, but not limited to, changes in labor costs, availability, and productivity; challenges with management of contractors, subcontractors, or vendors; adverse weather conditions; shortages, delays, increased costs, or inconsistent quality of equipment, materials, and labor; contractor or supplier delay; 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 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, system integration, or regional transmission upgrades; and/or operational performance. See Note 32 to the financial statements of Southern Company under "Regulatory Matters – Georgia"Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory MattersGeorgia Power – Georgia Power – Nuclear Construction" herein for information regarding Plant Vogtle Units 3 and 4 and 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.expenditures.
Sources of Capital
Southern Company intends to meet its future capital needs through operating cash flows, short-termborrowings from financial institutions, and debt term loans, and external security issuances.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. The amount and timing of additional equity capital and debt issuances in 2017,2019, as well as in subsequent years, will be contingent on Southern
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 from financial institutions, and equity contributions or loans from Southern Company. In addition, Southern Power also plans to utilize tax equity partnership contributions.contributions, as well as funds resulting from its pending asset sale. 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. Also see Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding the pending sale of Plant Mankato.
In addition, in 2014, Georgia Power entered into a loan guarantee agreement with the DOE and, in March 2019, entered into the Amended and Restated 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 Amended and Restated Loan Guarantee Agreement, the DOE has agreed to guarantee borrowingsthe obligations 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)note purchase agreements among the DOE, Georgia Power, the DOE, and the FFB. As of SeptemberFFB and related promissory notes which provide for two multi-advance term loan facilities, under which Georgia Power may make term loan borrowings through the FFB in an amount up to approximately $5.130 billion, provided that certain conditions are met. At June 30, 2017,2019, Georgia Power had borrowed $2.6$3.46 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 3Facilities. See Notes (B) 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)(F) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" and "DOE Loan Guarantee Borrowings," respectively, herein for additional information regardinginformation.
Southern Company's current liabilities frequently exceed current assets because of scheduled maturities of long-term debt and the Loan Guarantee Agreement, including applicable covenants, eventsperiodic use 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.
short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs. As of SeptemberJune 30, 2017,2019, Southern Company's current liabilities exceeded current assets by $3.4$2.6 billion, primarily due to long-term debt that is due within one year of $3.5and notes payable totaling $4.5 billion (comprised of(including approximately $1.0$0.9 billion at the parent company, $0.3$1.5 billion at AlabamaGeorgia 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$0.8 billion at Southern Company Gas)., partially offset by $1.4 billion of cash and cash equivalents. 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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Committed credit arrangements with banks at SeptemberJune 30, 20172019 were as follows:
| | | | Expires | | | | Executable Term Loans | | Expires Within One Year | Expires | | | | |
| Company | 2017 | 2018 | 2019 | 2020 | 2022 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out | 2019 | 2020 | 2022 | 2024 | | Total | | Unused | | Due within One Year |
| | (in millions) | (in millions) |
Southern Company(a) | $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 2,000 |
| | $ | 2,000 |
| | $ | 2,000 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 2,000 |
| | $ | 2,000 |
| | $ | 1,999 |
| | $ | — |
|
| Alabama Power | — |
| 35 |
| — |
| 500 |
| 800 |
| | 1,335 |
| | 1,335 |
| | — |
| | — |
| | — |
| | 35 |
| 3 |
| 500 |
| — |
| 800 |
| | 1,303 |
| | 1,303 |
| | 3 |
|
| Georgia Power | — |
| — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,732 |
| | — |
| | — |
| | — |
| | — |
| — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,736 |
| | — |
|
| Gulf Power | 30 |
| 195 |
| 25 |
| 30 |
| — |
| | 280 |
| | 280 |
| | 45 |
| | — |
| | — |
| | 40 |
| |
| Mississippi Power | 100 |
| — |
| — |
| — |
| — |
| | 100 |
| | 100 |
| | — |
| | — |
| | — |
| | 100 |
| — |
| — |
| 150 |
| — |
| | 150 |
| | 150 |
| | — |
|
Southern Power Company(b) | — |
| — |
| — |
| — |
| 750 |
| | 750 |
| | 728 |
| | — |
| | — |
| | — |
| | — |
| |
Southern Power(b) | | — |
| — |
| — |
| 600 |
| | 600 |
| | 561 |
| | — |
|
Southern Company Gas(c) | — |
| — |
| — |
| — |
| 1,900 |
| | 1,900 |
| | 1,861 |
| | — |
| | — |
| | — |
| | — |
| — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,745 |
| | — |
|
| Other | — |
| 30 |
| — |
| — |
| — |
| | 30 |
| | 30 |
| | 20 |
| | — |
| | 20 |
| | 10 |
| — |
| 30 |
| — |
| — |
| | 30 |
| | 30 |
| | 30 |
|
| Southern Company Consolidated | $ | 130 |
| $ | 260 |
| $ | 25 |
| $ | 530 |
| $ | 7,200 |
| | $ | 8,145 |
| | $ | 8,066 |
| | $ | 65 |
| | $ | — |
| | $ | 20 |
| | $ | 185 |
| $ | 3 |
| $ | 530 |
| $ | 150 |
| $ | 6,900 |
| | $ | 7,583 |
| | $ | 7,524 |
| | $ | 33 |
|
| |
| (a) | Represents the Southern Company parent entity. |
| |
| (b) | Does not include Southern Power's Power Company's $120 million continuing letter of credit facility for standby letters of credit expiring in 2019,2021, of which $11130 million has been used for letters of credit and $9 million remains was unused at SeptemberJune 30, 20172019. Southern Power's subsidiaries are not parties to its bank credit arrangement. |
| |
| (c) | Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.21.25 billion of these arrangements.this arrangement. Southern Company Gas' committed credit arrangementsarrangement also include includes $700500 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. |
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
See Note 68 to the financial statements of Southern Company under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E)(F) 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,SEGCO, 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 SeptemberJune 30, 2017,2019, Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and 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 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, Nicor Gas, and Nicor Gas.SEGCO. The amount of variable rate pollution control revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of SeptemberJune 30, 20172019 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.$1.4 billion. In addition, at SeptemberJune 30, 2017,2019, the traditional electric operating companies had approximately $699$272 million of pollution control revenue bonds outstanding that wereare 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),Alabama Power, Georgia Power, Southern Power Company, Southern Company Gas, and 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. 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(*) | | Short-term Debt at June 30, 2019 | | Short-term Debt During the Period(*) |
| | | Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding | | Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) | | | | (in millions) | | (in millions) | | | | (in millions) | | | | (in millions) |
| Commercial paper | | $ | 1,725 |
| | 1.5 | % | | $ | 1,895 |
| | 1.5 | % | | $ | 2,284 |
| | $ | 1,148 |
| | 2.6 | % | | $ | 1,173 |
| | 2.8 | % | | $ | 1,562 |
|
| Short-term bank debt | | 854 |
| | 2.0 | % | | 938 |
| | 2.1 | % | | 1,017 |
| | 250 |
| | 2.9 | % | | 127 |
| | 3.0 | % | | 250 |
|
| Total | | $ | 2,579 |
| | 1.7 | % | | $ | 2,833 |
| | 1.7 | % | | | | $ | 1,398 |
| | 2.7 | % | | $ | 1,300 |
| | 2.8 | % | | |
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended SeptemberJune 30, 2017.2019. |
Southern Company believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, bank term loans, and operating cash flows.
Credit Rating Risk
At SeptemberJune 30, 2017,2019, 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.management, and construction of new generation at Plant Vogtle Units 3 and 4.
The maximum potential collateral requirements under these contracts at SeptemberJune 30, 20172019 were as follows:
| | | Credit Ratings | Maximum Potential
Collateral
Requirements | Maximum Potential
Collateral
Requirements |
| | (in millions) | (in millions) |
| At BBB and/or Baa2 | $ | 38 |
| $ | 30 |
|
| At BBB- and/or Baa3 | $ | 647 |
| $ | 433 |
|
At BB+ and/or Ba1(*) | $ | 2,352 |
| $ | 1,935 |
|
| |
| (*) | 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 downgradedAs a result of the senior unsecuredTax Reform Legislation, certain financial metrics, such as the funds from operations to 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 consolidatedpercentage, used by the credit rating outlook foragencies to assess Southern Company and its subsidiaries (including the traditional electric operating companies, Southern Power,may be negatively impacted. Southern Company Gas,and most of its regulated subsidiaries have taken actions to mitigate the resulting impacts, which, among other alternatives, include adjusting capital structure. Absent actions by Southern Company Gas Capital, and Nicor Gas) from stable to negative.
On March 30, 2017, Fitch placedits subsidiaries that fully mitigate the impacts, the credit ratings of Southern Company and certain of its subsidiaries could be negatively affected. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information related to state PSC or other regulatory agency actions, including approvals and requests for additional or continued adjustments of capital structure related to the Tax Reform Legislation for Alabama Power, Georgia Power, Atlanta Gas Light, and Mississippi Power on rating watch negative.Nicor Gas, which are expected to help mitigate the potential adverse impacts to certain of their credit metrics.
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 ninesix months of 2017,2019, Southern Company issued approximately 10.611.5 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $479$452 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 ninesix months of 2017:2019:
| | | Company | Senior Note Issuances | | Senior Note Maturities and Redemptions | | Revenue Bond Maturities, Redemptions, and Repurchases | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(a) | Senior Note Maturities, Redemptions, and Repurchases | | Revenue Bond Issuances and Reofferings of Purchased Bonds | | Revenue Bond Maturities, Redemptions, and Repurchases | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(a) |
| | (in millions) | (in millions) |
Southern Company(b) | $ | 300 |
| | $ | 400 |
| | $ | — |
| | $ | 500 |
| | $ | 400 |
| $ | 2,100 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Alabama Power | 550 |
| | 200 |
| | 36 |
| | — |
| | — |
| 200 |
| | — |
| | — |
| | — |
| | — |
|
| Georgia Power | 1,350 |
| | 450 |
| | 65 |
| | 370 |
| | 13 |
| — |
| | 513 |
| | 223 |
| | 835 |
| | 3 |
|
| Gulf Power | 300 |
| | 85 |
| | — |
| | 6 |
| | — |
| |
| Mississippi Power | — |
| | — |
| | — |
| | 40 |
| | 893 |
| — |
| | 43 |
| | — |
| | — |
| | — |
|
| Southern Power | — |
| | — |
| | — |
| | 43 |
| | 4 |
| |
Southern Company Gas(c) | 450 |
| | — |
| | — |
| | 200 |
| | 22 |
| |
| Other | — |
| | — |
| | — |
| | — |
| | 12 |
| — |
| | — |
| | 25 |
| | — |
| | 9 |
|
Elimination(d) | — |
| | — |
| | — |
| | (40 | ) | | (599 | ) | |
| Southern Company Consolidated | $ | 2,950 |
| | $ | 1,135 |
| | $ | 101 |
| | $ | 1,119 |
| | $ | 745 |
| $ | 2,300 |
| | $ | 556 |
| | $ | 248 |
| | $ | 835 |
| | $ | 12 |
|
| |
| (a) | Includes reductions in capitalfinance lease obligations resulting from cash payments under capitalfinance 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 byExcept as otherwise described herein, 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'sits 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 working capital. The subsidiaries also used the proceeds for their continuous construction programs.
In September 2017, Alabama Power issued 10January 2019, Southern Company repaid a $250 million shares ($250short-term uncommitted bank credit arrangement and a $1.5 billion short-term floating rate bank loan.
Also in January 2019, through cash tender offers, Southern Company repurchased and retired approximately $522 million of the $1.0 billion aggregate principal amount outstanding of its 1.85% Senior Notes due July 1, 2019 (1.85% Notes), approximately $180 million of the $350 million aggregate stated capital)principal amount outstanding of 5.00% Class A Preferred Stock, Cumulative, Par Value $1 Per Share (Stated Capital $25 Per Share).its Series 2014B 2.15% Senior Notes due September 1, 2019 (Series 2014B Notes), and approximately $504 million of the $750 million aggregate principal amount outstanding of its Series 2018A Floating Rate Notes due February 14, 2020 (Series 2018A Notes), for an aggregate purchase price, excluding accrued and unpaid interest, of approximately $1.2 billion. In addition, following the completion of the cash tender offers, in February 2019, Southern Company completed the redemption of all of the Series 2018A Notes, 1.85% Notes, and Series 2014B Notes remaining outstanding.
As reflected in the table above, in March 2019, Georgia Power made additional borrowings under the FFB Credit Facilities in an aggregate principal amount of $835 million at an interest rate of 3.213% through the final maturity date of February 20, 2044. The proceeds were used in October 2017 to redeem all 2 million shares ($50 million aggregate stated capital)reimburse Georgia Power for Eligible Project Costs relating to the construction 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,Plant Vogtle Units 3 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, 2017.4.
In June 2017,2019, Georgia Power entered into threetwo short-term floating rate bank loans in aggregate principal amounts of $50$125 million $150 million, and $100 million, with maturity dateseach, both 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, GeorgiaMay 2019, Southern Power repaid its $50 million floating rate bank loan due December 1, 2017 and $250 million of the $500at maturity a $100 million aggregate principal amount outstanding pursuantshort-term bank loan.
Subsequent to its uncommitted bank credit arrangement. Also in August 2017, Georgia Power amended its $100 million floating rate bank loan to extend theJune 30, 2019, Nicor Gas repaid at 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$50 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 of4.7% 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 MortgageJuly 30, 2019.
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 ninesix months ended SeptemberJune 30, 2017,2019, 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 11Instruments" and Notes 13 and 14 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)Notes (I) and Note (H)(J) 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 thirdsecond quarter 20172019 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 | 2019 | | 2018 | | 2019 | | 2018 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | | | | | | | | |
| Retail revenues | $ | 1,595 |
| | $ | 1,629 |
| | $ | 4,155 |
| | $ | 4,139 |
| $ | 1,378 |
| | $ | 1,338 |
| | $ | 2,592 |
| | $ | 2,624 |
|
| Wholesale revenues, non-affiliates | 77 |
| | 82 |
| | 210 |
| | 211 |
| 62 |
| | 65 |
| | 123 |
| | 139 |
|
| Wholesale revenues, affiliates | 18 |
| | 18 |
| | 83 |
| | 49 |
| 4 |
| | 31 |
| | 63 |
| | 82 |
|
| Other revenues | 50 |
| | 56 |
| | 158 |
| | 162 |
| 69 |
| | 69 |
| | 143 |
| | 131 |
|
| Total operating revenues | 1,740 |
| | 1,785 |
| | 4,606 |
| | 4,561 |
| 1,513 |
| | 1,503 |
| | 2,921 |
| | 2,976 |
|
| Operating Expenses: | | | | | | | | | | | | | | |
| Fuel | 343 |
| | 410 |
| | 944 |
| | 973 |
| 252 |
| | 347 |
| | 553 |
| | 672 |
|
| Purchased power, non-affiliates | 57 |
| | 63 |
| | 132 |
| | 139 |
| 47 |
| | 48 |
| | 84 |
| | 113 |
|
| Purchased power, affiliates | 55 |
| | 41 |
| | 117 |
| | 129 |
| 69 |
| | 43 |
| | 90 |
| | 80 |
|
| Other operations and maintenance | 391 |
| | 348 |
| | 1,134 |
| | 1,097 |
| 402 |
| | 402 |
| | 812 |
| | 788 |
|
| Depreciation and amortization | 185 |
| | 177 |
| | 549 |
| | 524 |
| 200 |
| | 189 |
| | 399 |
| | 379 |
|
| Taxes other than income taxes | 93 |
| | 96 |
| | 284 |
| | 286 |
| 98 |
| | 94 |
| | 200 |
| | 192 |
|
| Total operating expenses | 1,124 |
| | 1,135 |
| | 3,160 |
| | 3,148 |
| 1,068 |
| | 1,123 |
| | 2,138 |
| | 2,224 |
|
| Operating Income | 616 |
| | 650 |
| | 1,446 |
| | 1,413 |
| 445 |
| | 380 |
| | 783 |
| | 752 |
|
| Other Income and (Expense): | | | | | | | | | | | | | | |
| Allowance for equity funds used during construction | 11 |
| | 7 |
| | 27 |
| | 23 |
| 14 |
| | 14 |
| | 28 |
| | 27 |
|
| Interest expense, net of amounts capitalized | (76 | ) | | (77 | ) | | (229 | ) | | (224 | ) | (82 | ) | | (80 | ) | | (165 | ) | | (158 | ) |
| Other income (expense), net | (5 | ) | | (5 | ) | | (8 | ) | | (16 | ) | 11 |
| | 12 |
| | 25 |
| | 15 |
|
| Total other income and (expense) | (70 | ) | | (75 | ) | | (210 | ) | | (217 | ) | (57 | ) | | (54 | ) | | (112 | ) | | (116 | ) |
| Earnings Before Income Taxes | 546 |
| | 575 |
| | 1,236 |
| | 1,196 |
| 388 |
| | 326 |
| | 671 |
| | 636 |
|
| Income taxes | 216 |
| | 219 |
| | 493 |
| | 462 |
| 89 |
| | 64 |
| | 151 |
| | 145 |
|
| Net Income | 330 |
| | 356 |
| | 743 |
| | 734 |
| 299 |
| | 262 |
| | 520 |
| | 491 |
|
| 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 | | 3 |
| | 3 |
| | 7 |
| | 7 |
|
| Net Income After Dividends on Preferred Stock | | $ | 296 |
| | $ | 259 |
| | $ | 513 |
| | $ | 484 |
|
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 | 2019 | | 2018 | | 2019 | | 2018 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Net Income | $ | 330 |
| | $ | 356 |
| | $ | 743 |
| | $ | 734 |
| $ | 299 |
| | $ | 262 |
| | $ | 520 |
| | $ | 491 |
|
| 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 |
| $ | 300 |
| | $ | 263 |
| | $ | 522 |
| | $ | 493 |
|
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 | 2019 | | 2018 |
| | (in millions) | (in millions) |
| Operating Activities: | | | | | | |
| Net income | $ | 743 |
| | $ | 734 |
| $ | 520 |
| | $ | 491 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | | | | |
| Depreciation and amortization, total | 666 |
| | 634 |
| 493 |
| | 452 |
|
| Deferred income taxes | 260 |
| | 267 |
| 138 |
| | 48 |
|
| Allowance for equity funds used during construction | (27 | ) | | (23 | ) | (28 | ) | | (27 | ) |
| Pension, postretirement, and other employee benefits | (4 | ) | | (14 | ) | (13 | ) | | (28 | ) |
| Settlement of asset retirement obligations | | (43 | ) | | (19 | ) |
| Other, net | 43 |
| | (12 | ) | (1 | ) | | (21 | ) |
| Changes in certain current assets and liabilities — | | | | | | |
| -Receivables | (163 | ) | | (4 | ) | 6 |
| | (153 | ) |
| -Fossil fuel stock | 34 |
| | 18 |
| |
| -Prepayments | | (59 | ) | | (57 | ) |
| -Materials and supplies | | 5 |
| | (47 | ) |
| -Other current assets | (58 | ) | | (46 | ) | (10 | ) | | 29 |
|
| -Accounts payable | (125 | ) | | (113 | ) | (246 | ) | | (196 | ) |
| -Accrued taxes | 159 |
| | 207 |
| 8 |
| | 134 |
|
| -Accrued compensation | (48 | ) | | (22 | ) | (88 | ) | | (70 | ) |
| -Retail fuel cost over recovery | (76 | ) | | (104 | ) | |
| -Other current liabilities | 7 |
| | 19 |
| 13 |
| | 116 |
|
| Net cash provided from operating activities | 1,411 |
| | 1,541 |
| 695 |
| | 652 |
|
| Investing Activities: | | | | | | |
| Property additions | (1,211 | ) | | (947 | ) | (833 | ) | | (997 | ) |
| Nuclear decommissioning trust fund purchases | (174 | ) | | (275 | ) | (139 | ) | | (131 | ) |
| Nuclear decommissioning trust fund sales | 174 |
| | 275 |
| 139 |
| | 131 |
|
| Cost of removal, net of salvage | (82 | ) | | (70 | ) | (48 | ) | | (34 | ) |
| Change in construction payables | 105 |
| | (37 | ) | (103 | ) | | (29 | ) |
| Other investing activities | (29 | ) | | (28 | ) | (18 | ) | | (15 | ) |
| Net cash used for investing activities | (1,217 | ) | | (1,082 | ) | (1,002 | ) | | (1,075 | ) |
| Financing Activities: | | | | | | |
| Proceeds — | | | | | | |
| Senior notes | 550 |
| | 400 |
| — |
| | 500 |
|
| Capital contributions from parent company | 337 |
| | 253 |
| 1,254 |
| | 488 |
|
| Preferred stock | 250 |
| | — |
| |
| Other long-term debt | — |
| | 45 |
| |
| Redemptions — |
|
| |
| |
| Pollution control revenue bonds | (36 | ) | | — |
| |
| Senior notes | (200 | ) | | (200 | ) | |
| Redemptions — Senior notes | | (200 | ) | | — |
|
| Payment of common stock dividends | (536 | ) | | (574 | ) | (422 | ) | | (402 | ) |
| Other financing activities | (26 | ) | | (21 | ) | (15 | ) | | (21 | ) |
| 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 | | 617 |
| | 565 |
|
| Net Change in Cash, Cash Equivalents, and Restricted Cash | | 310 |
| | 142 |
|
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | | 313 |
| | 544 |
|
| Cash, Cash Equivalents, and Restricted Cash at End of Period | | $ | 623 |
| | $ | 686 |
|
| 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 $10 and $10 capitalized for 2019 and 2018, respectively) | | $ | 154 |
| | $ | 143 |
|
| Income taxes, net | 146 |
| | (70 | ) | 63 |
| | 17 |
|
| Noncash transactions — Accrued property additions at end of period | 189 |
| | 84 |
| 168 |
| | 216 |
|
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, 2019 | | At December 31, 2018 |
| | | (in millions) | | (in millions) |
| Current Assets: | | | | | | | | |
| Cash and cash equivalents | | $ | 953 |
| | $ | 420 |
| | $ | 623 |
| | $ | 313 |
|
| Receivables — | | | | | | | | |
| Customer accounts receivable | | 428 |
| | 348 |
| | 432 |
| | 403 |
|
| Unbilled revenues | | 149 |
| | 146 |
| | 173 |
| | 150 |
|
| Affiliated | | | 38 |
| | 94 |
|
| Other accounts and notes receivable | | 47 |
| | 27 |
| | 55 |
| | 51 |
|
| Affiliated | | 45 |
| | 40 |
| |
| Accumulated provision for uncollectible accounts | | (8 | ) | | (10 | ) | | (10 | ) | | (10 | ) |
| Fossil fuel stock | | 171 |
| | 205 |
| | 143 |
| | 141 |
|
| Materials and supplies | | 455 |
| | 435 |
| | 530 |
| | 546 |
|
| Prepaid expenses | | 58 |
| | 34 |
| | 170 |
| | 66 |
|
| Other regulatory assets, current | | 122 |
| | 149 |
| |
| Other regulatory assets | | | 204 |
| | 137 |
|
| Other current assets | | 5 |
| | 11 |
| | 26 |
| | 18 |
|
| Total current assets | | 2,425 |
| | 1,805 |
| | 2,384 |
| | 1,909 |
|
| Property, Plant, and Equipment: | | | | | | | | |
| In service | | 26,619 |
| | 26,031 |
| | 29,070 |
| | 30,402 |
|
| Less: Accumulated provision for depreciation | | 9,463 |
| | 9,112 |
| | 9,397 |
| | 9,988 |
|
| Plant in service, net of depreciation | | 17,156 |
| | 16,919 |
| | 19,673 |
| | 20,414 |
|
| Nuclear fuel, at amortized cost | | 314 |
| | 336 |
| | 322 |
| | 324 |
|
| Construction work in progress | | 928 |
| | 491 |
| | 1,097 |
| | 1,113 |
|
| Total property, plant, and equipment | | 18,398 |
| | 17,746 |
| | 21,092 |
| | 21,851 |
|
| Other Property and Investments: | | | | | | | | |
| Equity investments in unconsolidated subsidiaries | | 65 |
| | 66 |
| | 64 |
| | 65 |
|
| Nuclear decommissioning trusts, at fair value | | 869 |
| | 792 |
| | 964 |
| | 847 |
|
| Miscellaneous property and investments | | 121 |
| | 112 |
| | 129 |
| | 127 |
|
| Total other property and investments | | 1,055 |
| | 970 |
| | 1,157 |
| | 1,039 |
|
| Deferred Charges and Other Assets: | | | | | | | | |
| Operating lease right-of-use assets, net of amortization | | | 152 |
| | — |
|
| Deferred charges related to income taxes | | 525 |
| | 525 |
| | 240 |
| | 240 |
|
| Deferred under recovered regulatory clause revenues | | 17 |
| | 150 |
| | 25 |
| | 116 |
|
| Regulatory assets – asset retirement obligations | | | 1,016 |
| | 147 |
|
| Other regulatory assets, deferred | | 1,191 |
| | 1,157 |
| | 1,824 |
| | 1,240 |
|
| Other deferred charges and assets | | 178 |
| | 163 |
| | 177 |
| | 188 |
|
| Total deferred charges and other assets | | 1,911 |
| | 1,995 |
| | 3,434 |
| | 1,931 |
|
| Total Assets | | $ | 23,789 |
| | $ | 22,516 |
| | $ | 28,067 |
| | $ | 26,730 |
|
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, 2019 | | At December 31, 2018 |
| | | (in millions) | | (in millions) |
| Current Liabilities: | | | | | | | | |
| Securities due within one year | | $ | 325 |
| | $ | 561 |
| | $ | 1 |
| | $ | 201 |
|
| Accounts payable — | | | | | | | | |
| Affiliated | | 275 |
| | 297 |
| | 321 |
| | 364 |
|
| Other | | 376 |
| | 433 |
| | 334 |
| | 614 |
|
| Customer deposits | | 92 |
| | 88 |
| | 98 |
| | 96 |
|
| Accrued taxes — | | | | | |
| Accrued income taxes | | 115 |
| | 45 |
| |
| Other accrued taxes | | 128 |
| | 42 |
| |
| Accrued taxes | | | 102 |
| | 44 |
|
| Accrued interest | | 75 |
| | 78 |
| | 88 |
| | 89 |
|
| Accrued compensation | | 151 |
| | 193 |
| | 140 |
| | 227 |
|
| Other regulatory liabilities, current | | 4 |
| | 85 |
| |
| Asset retirement obligations | | | 156 |
| | 163 |
|
| Other current liabilities | | 50 |
| | 76 |
| | 155 |
| | 161 |
|
| Total current liabilities | | 1,591 |
| | 1,898 |
| | 1,395 |
| | 1,959 |
|
| Long-term Debt | | 7,083 |
| | 6,535 |
| | 7,926 |
| | 7,923 |
|
| Deferred Credits and Other Liabilities: | | | | | | | | |
| Accumulated deferred income taxes | | 4,919 |
| | 4,654 |
| | 3,117 |
| | 2,962 |
|
| Deferred credits related to income taxes | | 60 |
| | 65 |
| | 2,006 |
| | 2,027 |
|
| Accumulated deferred ITCs | | 118 |
| | 110 |
| | 103 |
| | 106 |
|
| Employee benefit obligations | | 289 |
| | 300 |
| | 309 |
| | 314 |
|
| Asset retirement obligations | | 1,564 |
| | 1,503 |
| |
| Operating lease obligations | | | 137 |
| | — |
|
| Asset retirement obligations, deferred | | | 3,389 |
| | 3,047 |
|
| Other cost of removal obligations | | 630 |
| | 684 |
| | 464 |
| | 497 |
|
| Other regulatory liabilities, deferred | | 93 |
| | 100 |
| |
| Other regulatory liabilities | | | 69 |
| | 69 |
|
| Other deferred credits and liabilities | | 51 |
| | 63 |
| | 32 |
| | 58 |
|
| Total deferred credits and other liabilities | | 7,724 |
| | 7,479 |
| | 9,626 |
| | 9,080 |
|
| Total Liabilities | | 16,398 |
| | 15,912 |
| | 18,947 |
| | 18,962 |
|
| 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) | | | 8,829 |
| | 7,477 |
|
| Total Liabilities and Stockholder's Equity | | $ | 23,789 |
| | $ | 22,516 |
| | $ | 28,067 |
| | $ | 26,730 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA 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, 2017 | 31 |
| | $ | 1,222 |
| | $ | 2,986 |
| | $ | 2,647 |
| | $ | (26 | ) | | $ | 6,829 |
|
Net income after dividends on
preferred stock | — |
| | — |
| | — |
| | 225 |
| | — |
| | 225 |
|
| Capital contributions from parent company | — |
| | — |
| | 488 |
| | — |
| | — |
| | 488 |
|
| Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
| Cash dividends on common stock | — |
| | — |
| | — |
| | (202 | ) | | — |
| | (202 | ) |
| Other | — |
| | — |
| | — |
| | — |
| | (6 | ) | | (6 | ) |
| Balance at March 31, 2018 | 31 |
| | 1,222 |
| | 3,474 |
| | 2,670 |
| | (31 | ) | | 7,335 |
|
Net income after dividends on
preferred stock | — |
| | — |
| | — |
| | 259 |
| | — |
| | 259 |
|
| Capital contributions from parent company | — |
| | — |
| | 5 |
| | — |
| | — |
| | 5 |
|
| Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
| Cash dividends on common stock | — |
| | — |
| | — |
| | (200 | ) | | — |
| | (200 | ) |
| Other | — |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
| Balance at June 30, 2018 | 31 |
| | $ | 1,222 |
| | $ | 3,480 |
| | $ | 2,729 |
| | $ | (30 | ) | | $ | 7,401 |
|
| | | | | | | | | | | | |
| 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 (loss) | — |
| | — |
| | — |
| | — |
| | 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 (loss) | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
| Cash dividends on common stock | — |
| | — |
| | — |
| | (211 | ) | | — |
| | (211 | ) |
| Balance at June 30, 2019 | 31 |
| | $ | 1,222 |
| | $ | 4,767 |
| | $ | 2,866 |
| | $ | (26 | ) | | $ | 8,829 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRDSECOND QUARTER 20172019 vs. THIRDSECOND QUARTER 20162018
AND
YEAR-TO-DATE 20172019 vs. YEAR-TO-DATE 20162018
OVERVIEW
Alabama Power operates as a vertically integrated utility providing electric service to retail and wholesale customers within its traditional service territory located in the State of Alabama in addition to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of Alabama Power's business of providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales and customers, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, including CCR rules, reliability, fuel, capital expenditures, including improving the electric transmission and distribution systems, 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 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) |
| (% change) |
| (change in millions) |
| (% change) |
| $37 | | 14.3 | | $29 | | 6.0 |
Alabama Power's net income after dividends on preferred and preference stock for the thirdsecond quarter 20172019 was $325$296 million compared to $352$259 million for the corresponding period in 2016.2018. The decreaseincrease was primarily related to an increase in retail revenues associated with the impacts of customer bill credits issued in 2018 related to the Tax Reform Legislation, as well as additional capital investments recovered through Rate CNP Compliance, partially offset by a decrease in retail revenues associated with customer usage.
Alabama Power's net income after dividends on preferred stock for year-to-date 2019 was $513 million compared to $484 million for the corresponding period in 2018. This increase was primarily related to an increase in retail revenues associated with the impacts of customer bill credits issued in 2018 related to the Tax Reform Legislation, as well as additional capital investments recovered through Rate CNP Compliance. This increase was partially offset by decreases in retail revenues associated with milder weather and lower customer usage in the third quarter 2017 comparedas well as increases 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.expenses and depreciation.
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 comparedSee Note 2 to the corresponding periodfinancial statements under "Alabama Power – Rate RSE" in 2016, and an increase in non-fuel operations and maintenance expenses.Item 8 of the Form 10-K for additional information.
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
Retail Revenues
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $40 | | 3.0 | | $(32) | | (1.2) |
In the second quarter 2019, retail revenues were $1.38 billion compared to $1.34 billion for the corresponding period in 2018. For year-to-date 2019, retail revenues were $2.59 billion compared to $2.62 billion for the corresponding period in 2018.
Details of the changes in retail revenues were as follows:
| | | | Third Quarter 2017 |
| Year-to-Date 2017 | Second Quarter 2019 |
| Year-to-Date 2019 |
| | (in millions) |
| (% change) |
| (in millions) |
| (% change) | (in millions) |
| (% change) |
| (in millions) |
| (% change) |
| Retail – prior year | $ | 1,629 |
| | | | $ | 4,139 |
| | | $ | 1,338 |
| | | | $ | 2,624 |
| | |
| Estimated change resulting from – | | | | | | | | | | | | | | |
| Rates and pricing | 85 |
| | 5.2 |
| | 240 |
| | 5.8 |
| 62 |
| | 4.7 | % | | 96 |
| | 3.7 | % |
| Sales decline | (18 | ) | | (1.1 | ) | | (31 | ) | | (0.7 | ) | (15 | ) | | (1.1 | ) | | (31 | ) | | (1.2 | ) |
| Weather | (50 | ) | | (3.1 | ) | | (116 | ) | | (2.8 | ) | 6 |
| | 0.4 |
| | (19 | ) | | (0.7 | ) |
| Fuel and other cost recovery | (51 | ) | | (3.1 | ) | | (77 | ) | | (1.9 | ) | (13 | ) | | (1.0 | ) | | (78 | ) | | (3.0 | ) |
| Retail – current year | $ | 1,595 |
| | (2.1 | )% | | $ | 4,155 |
| �� | 0.4 | % | $ | 1,378 |
| | 3.0 | % | | $ | 2,592 |
| | (1.2 | )% |
Revenues associated with changes in rates and pricing increased in the thirdsecond quarter and year-to-date 20172019 when compared to the corresponding periods in 20162018 primarily due to an increasethe impacts of customer bill credits related to the Tax Reform Legislation in rates under2018, as well as additional capital investments recovered through Rate RSE effective January 1, 2017.CNP Compliance. See Note 32 to the financial statements of Alabamaunder "Alabama Power under "Retail Regulatory Matters"– Rate RSE" and " – Rate CNP Compliance" in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales decreased in the thirdsecond quarter and year-to-date 20172019 when compared to the corresponding periods in 2016.2018. Weather-adjusted residential KWH sales decreased 2.4%1.5% and 1.1% for2.0% in the thirdsecond quarter and year-to-date 2017,2019, respectively, primarily due to lower customer usage resulting from an increase in penetration of energy efficient residential appliances, partially offset by customer growth. Weather-adjustedand weather-adjusted commercial KWH sales decreased 1.2% and 2.3% and 1.4% forin the thirdsecond quarter and year-to-date 2017,2019, respectively, when compared to the corresponding periods in 2018. These decreases primarily due to lower customer usage resultingresulted from customer initiatives in energy savings for commercial customers and an ongoing migration to the electronic commerce business model, partially offset by customer growth.more energy-efficient residential appliances. Industrial KWH sales increased 1.8%decreased 3.2% and 0.6% for3.1% in the thirdsecond quarter and year-to-date 2017,2019, respectively, when compared to the corresponding periods in 2018 as a result of an increasea decrease in demand resulting from changes in production levels primarily in the primary metals and chemicals sectors for the second quarter 2019 and primary metals, chemicals, and miningpaper sectors partially offsetfor year-to-date 2019.
Residential and commercial sales revenues decreased year-to-date 2019 by a decrease in demand from the pipeline sector.
Revenues resulting from changes in weather decreased in the third quarter1.2% and year-to-date 20170.7%, respectively, due to milder weather experienced in Alabama Power's service territorythe first quarter 2019 when compared to the corresponding periodsperiod 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.2018.
Fuel and other cost recovery revenues decreased in the thirdsecond quarter and year-to-date 20172019 when compared to the corresponding periods in 20162018 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 32 to the financial statements of Alabama Power under "Retail Regulatory Matters""Alabama Power" in Item 8 of the Form 10-K for additional information.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale Revenues – Affiliates 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) |
| $— | | — | | $34 | | 69.4 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(3) | | (4.6) | | $(16) | | (11.5) |
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.
For year-to-date 2019, wholesale revenues from sales to non-affiliates were $123 million compared to $139 million for the corresponding period in 2018. The decrease was primarily due to a 7.1% decrease in KWH sales as a result of lower demand and a 4.8% decrease in the price of energy due to lower natural gas prices in 2019 compared to the corresponding period in 2018.
Wholesale Revenues – Affiliates
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(27) | | (87.1) | | $(19) | | (23.2) |
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through Alabama Power's energy cost recovery clause.
In the second quarter 2019, wholesale revenues from sales to affiliates were $4 million compared to $31 million for the corresponding period in 2018. The decrease was primarily due to an 87.4% decrease in KWH sales as a result of decreased coal generation associated with the retirement of Plant Gorgas Units 8, 9, and 10 and a 6.7% decrease in the price of energy as a result of lower natural gas prices in the second quarter 2019 compared to the corresponding period in 2018.
For year-to-date 2019, wholesale revenues from sales to affiliates were $63 million compared to $82 million for the corresponding period in 2018. The decrease was primarily due to a 13.1% decrease in KWH sales as a result of decreased coal generation associated with the retirement of Plant Gorgas Units 8, 9, and 10 and an 11.0% decrease in the price of energy due to increased hydro generation in 2019 as compared to the corresponding period in 2018.
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 | Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| | (change in millions) |
| (% change) | | (change in millions) | | (% change) | (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| Fuel | $ | (67 | ) | | (16.3) | | $ | (29 | ) | | (3.0 | ) | $ | (95 | ) | | (27.4) | | $ | (119 | ) | | (17.7 | ) |
| Purchased power – non-affiliates | (6 | ) | | (9.5) | | (7 | ) | | (5.0 | ) | (1 | ) | | (2.1) | | (29 | ) | | (25.7 | ) |
| Purchased power – affiliates | 14 |
| | 34.1 | | (12 | ) | | (9.3 | ) | 26 |
| | 60.5 | | 10 |
| | 12.5 |
|
| Total fuel and purchased power expenses | $ | (59 | ) | | $ | (48 | ) | | | $ | (70 | ) | | $ | (138 | ) | | |
In the thirdsecond quarter 2017,2019, fuel and purchased power expenses were $455$368 million compared to $514$438 million for the corresponding period in 2016. The decrease was2018. For year-to-date 2019, fuel and purchased power expenses were $727 million compared to $865 million for the corresponding period in 2018. These decreases were primarily due to a $43 million net decrease related to the volume of KWHs generated (excluding hydro) 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.purchased.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Alabama Power's energy cost recovery clause. See Note 32 to the financial statements of Alabamaunder "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 | Second Quarter 2019 | | Second Quarter 2018 | | Year-to-Date 2019 |
| Year-to-Date 2018 |
Total generation (in billions of KWHs) | 16 | | 18 | | 46 | | 46 | 12 | | 15 | | 29 | | 31 |
Total purchased power (in billions of KWHs) | 2 | | 2 | | 5 | | 6 | 3 | | 2 | | 4 | | 3 |
Sources of generation (percent) — | | |
| Coal | 52 | | 59 | | 49 | | 51 | 43 | | 53 | | 43 | | 52 |
| Nuclear | 24 | | 22 | | 25 | | 24 | 26 | | 20 | | 24 | | 21 |
| Gas | 19 | | 18 | | 20 | | 19 | 23 | | 20 | | 21 | | 19 |
| Hydro | 5 | | 1 | | 6 | | 6 | 8 | | 7 | | 12 | | 8 |
Cost of fuel, generated (in cents per net KWH) — | | |
| Coal | 2.61 | | 2.73 | | 2.61 | | 2.80 | 2.86 | | 2.79 | | 2.82 | | 2.74 |
| Nuclear | 0.75 | | 0.77 | | 0.75 | | 0.78 | 0.78 | | 0.80 | | 0.78 | | 0.77 |
| Gas | 2.72 | | 2.85 | | 2.74 | | 2.62 | 2.48 | | 2.51 | | 2.53 | | 2.69 |
Average cost of fuel, generated (in cents per net KWH)(a)(b) | 2.17 | | 2.32 | | 2.15 | | 2.25 | 2.18 | | 2.31 | | 2.19 | | 2.27 |
Average cost of purchased power (in cents per net KWH)(b)(c) | 5.65 | | 5.70 | | 5.57 | | 4.81 | 4.01 | | 4.72 | | 4.45 | | 5.72 |
| |
(a) | In the second quarter and year-to-date 2018, cost of fuel and average cost of fuel, generated exclude a $30 million adjustment in accordance with an Alabama PSC accounting order. See Note 2 to the financial statements under "Alabama Power – Tax Reform Accounting Order" in Item 8 of the Form 10-K for additional information. |
| |
| (b) | KWHs generated by hydro are excluded from the average cost of fuel, generated. |
| |
(b)
(c) | 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 thirdsecond quarter 2017,2019, fuel expense was $343$252 million compared to $410$347 million for the corresponding period in 2016.2018. The decrease was primarily due to a 31.3% decrease in the volume of KWHs generated by coal and an 18.4%11.9% increase in the volume of KWHs generated by nuclear.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2019, fuel expense was $553 million compared to $672 million for the corresponding period in 2018. The decrease was primarily due to a 45.3% increase in the volume of KWHs generated by hydro, a 21.9% decrease in the volume of KWHs generated by coal, a 4.6%5.1% increase in the volume of KWHs generated by nuclear, and a 6.0% 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. agreements.
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 $944increased $30 million comparedin both the second quarter and year-to-date 2018 in accordance with an Alabama PSC accounting order authorizing the use of excess deferred income taxes 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 excludesunder recovered 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)costs (Tax Reform Accounting Order). The increase was partially offset by a 14.5% decrease in the average cost per KWH of capacity and energy at SEGCO. See Note 42 to the financial statements of Alabamaunder "Alabama Power – Tax Reform Accounting Order" in Item 8 of the Form 10-K for additional information.
Purchased Power – Non-Affiliates
For year-to-date 2017,2019, purchased power expense from affiliatesnon-affiliates was $117$84 million compared to $129$113 million for the corresponding period in 2016.2018. The decrease was primarily related to a 26.6%14.3% decrease in the average cost of purchased power per KWH due to lower natural gas prices and an 11.9% decrease in the amount of energy purchased due to milder weather in the first quarter 2019 compared to the corresponding period in 2018.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the second quarter 2019, purchased power expense from affiliates was $69 million compared to $43 million for the corresponding period in 2018. For year-to-date 2019, purchased power expense from affiliates was $90 million compared to $80 million for the corresponding period in 2018. These increases were primarily related to the availability of lower-cost generation compared to Alabama Power's owned generation and a decrease in demandcoal generation as a result of milder weather in 2017, partially offset by a 22.9% increase in the average costretirement 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
Plant Gorgas Units 8, 9, and 10.
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 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $— | | — | | $24 | | 3.0 |
In the third quarter 2017,For year-to-date 2019, other operations and maintenance expenses were $391$812 million compared to $348$788 million for the corresponding period in 2016. The2018. This increase was primarily due to increases of $26$15 million in scheduled generation outage costs, $11Rate CNP Compliance-related expenses and $13 million in vegetation managementsteam generation 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 increasesthe timing 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.outages.
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 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $11 | | 5.8 | | $20 | | 5.3 |
In the thirdsecond quarter 2017,2019, depreciation and amortization was $185$200 million compared to $177$189 million for the corresponding period in 2016.2018. For year-to-date 2017,2019, depreciation and amortization was $549$399 million compared to $524$379 million for the corresponding period in 2016.2018. 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, projectsdistribution, and asset retirement obligation recovery, partially offset by a decreasetransmission.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Income (Expense), Net
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(1) | | (8.3) | | $10 | | 66.7 |
For year-to-date 2019, other income (expense), net was $25 million compared to $15 million for the corresponding period in distribution-related depreciation rates.2018. This increase was primarily due to increases in interest income from temporary cash investments and non-service cost-related pension income.
Income Taxes
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $25 | | 39.1 | | $6 | | 4.1 |
In the second quarter 2019, income taxes were $89 million compared to $64 million for the corresponding period in 2018. This increase was primarily due to higher pre-tax earnings in the second quarter 2019 compared to the corresponding period in 2018 and the application of the Tax Reform Accounting Order in 2018. See Note 12 to the financial statements of Alabamaunder "Alabama Power under "Depreciation and Amortization"– Tax Reform Accounting Order" 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 demandthe weak pace of growth over the next several years. Future earnings will be driven primarily byin new customers and electricity use per customer, growth.especially in residential and commercial markets. 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.transactions, both of which could contribute to a net reduction in customer usage. 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
ComplianceAlabama Power's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. Alabama Power maintains comprehensive environmental compliance and GHG strategies to assess upcoming requirements and compliance costs related to federal and stateassociated with these environmental statuteslaws and regulations and to achieve stated goals. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, or changing fuel sources for certain existing units, as well as related upgrades to Alabama Power's transmission and distribution systems, and may impact future electric generating unit retirement and replacement decisions, results of operations, cash flows, and/or financial condition. These costs are being collected through existing ratemaking and billing provisions. The ultimate impact of environmental laws and regulations and GHG
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
goals will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed technology, fuel prices, and the outcome of pending and/or future legal challenges.
New or revised environmental laws and regulations could affect many areas of Alabama Power's operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs 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, higherincreased costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, andand/or financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Alabama Power in Item 7 of the Form 10-K and Note 2 to the financial statements under "Alabama Power – Rate CNP Compliance" and Note 3 to the financial statements of Alabama Power under "Environmental Matters"Remediation" in Item 8 of the Form 10-K for additional information.
Environmental StatutesLaws and Regulations
Water QualityCoal Combustion Residuals
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" ofIn June 2019, Alabama Power recorded an increase of approximately $308 million to its AROs primarily related to the CCR Rule and the related state rule based on management's completion of closure designs during the second quarter 2019 for all but two of its ash pond facilities. The additional estimated costs to close these ash ponds under the planned closure-in-place methodology primarily relate to cost inputs from contractor bids, internal drainage and dewatering system designs, and increases in the estimated ash volumes. The cost estimate for the remaining ash pond facilities will be updated within the next 12 months and the change could be material.
As further analysis is performed and additional details are developed with respect to all ash pond closures, Alabama Power expects to periodically update these cost estimates as necessary. Additionally, the closure designs and plans are subject to approval by environmental regulatory agencies. Absent continued recovery of ARO costs through regulated rates, Alabama Power's results of operations, cash flows, and financial condition could be materially impacted. The ultimate outcome of this matter cannot be determined at this time. See Note 6 to the financial statements in Item 78 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
Global Climate Issues
On July 8, 2019, the EPA published the final Affordable Clean Energy rule (ACE Rule) to repeal and replace the CPP. Implementation of the CPP has been stayed by the U.S. Supreme Court since 2016. The ACE Rule requires states to develop unit-specific CO2 emission rate standards for existing coal-fired units based on heat-rate efficiency improvements. Combustion turbines, including natural gas combined cycles, are not included as affected sources in the ACE Rule. Alabama Power has ownership interests in seven coal-fired units to which the ACE Rule is applicable. The ultimate impact of the ACE Rule, including the repeal and replacement of the CPP, to Alabama Power will depend on state implementation plan requirements and the outcome of any associated legal challenges and cannot be determined at this time.
FERC Matters
See Note 2 to the financial statements under "FERC Matters – Open Access Transmission Tariff" in Item 8 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.information.
On June 27, 2017,28, 2019, the EPAFERC approved a settlement agreement between Alabama Municipal Electric Authority and Cooperative Energy and SCS and the U.S. Army Corpstraditional electric operating companies (including Alabama Power) agreeing to an OATT rate reduction based on a 10.6% ROE, with a retroactive effective date of Engineers proposedMay 10, 2018, and a five-year moratorium on these parties seeking changes to rescind the final rule that revised the regulatory definition of watersOATT formula rate. The terms of the U.S. for all CWA programs. The final rule has been stayed since October 2015 byOATT settlement agreement will not have a material impact on 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"financial statements of Alabama Power in Item 7 of the Form 10-K for additional information.Power.
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 3Note 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information regarding Alabama Power's rate mechanisms, accounting orders, and the recovery balance of each regulatory clause for Alabama Power.
Environmental Accounting Order
On April 15, 2019, Alabama Power retired Plant Gorgas Units 8, 9, and 10 and reclassified approximately $654 million of the unrecovered asset balances to regulatory assets, which are being recovered over the units' remaining useful lives, the latest being through 2037, as established prior to the decision to retire. Additionally, approximately $700 million of net capitalized asset retirement costs were reclassified to a regulatory asset in accordance with accounting guidance provided by the Alabama PSC. The asset retirement costs are being recovered through 2055. See Note 2 to the financial statements under "Nuclear Outage"Alabama Power – Environmental Accounting Order" and "Retail Regulatory Matters," respectively,Note 6 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.information.
Other Matters
Alabama Power is involved in various other matters that could affect future earnings, including matters being litigated and regulatory matters that could affect future earnings.matters. 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 regulationlaws and regulations governing air, water, land, and protection of air emissions and water discharges.other natural resources. 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 qualitylaws and water standards,regulations, 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 predicteddetermined at this time; however, for current proceedings not specifically reported in NoteNotes (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 Alabama Power's financial statements. See NoteNotes (B) and (C) 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.
In response to changing customer expectations, payment patterns, and ongoing efforts to increase overall operating efficiencies, Alabama Power initiated a plan to close 40 of its 86 payment offices by the end of 2019. Charges associated with these activities are not expected to have a material impact on Alabama Power's financial statements.
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 NoteNotes 1, 5, and 6 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.estimates.
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 expectedRecently Issued Accounting Standards
See Note (A) to have a material impact on either the timing or amount of revenues recognized inCondensed Financial Statements herein for information regarding 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 hedgerecently adopted 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.standards.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Alabama Power in Item 7 of the Form 10-K for additional information. Alabama Power's financial condition remained stable at SeptemberJune 30, 2017.2019. 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$695 million for the first ninesix months of 2017, a decrease2019, an increase of $130$43 million as compared to the first ninesix months of 2016.2018. The decreaseincrease in net cash provided from operating activities was primarily due to increased fuel cost recovery, partially offset by the receiptprior year impacts of income tax refunds in 2016 as a result of bonus depreciation.customer billing reductions related to the Tax Reform Legislation. Net cash used for investing activities totaled $1.2$1.0 billion for the first ninesix months of 20172019 primarily due to gross property additions related to additional capital expenditures for distribution, environmental, and transmission and steam generation.assets. Net cash provided from financing activities totaled $339$617 million for the first ninesix months of 20172019 primarily due to an issuance of long-term debt and preferred stock and additional capital contributions from Southern Company, partially offset by a payment of common stock dividend paymentsdividends and a redemption of long-term debt.debt maturity. Fluctuations in cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first ninesix months of 20172019 include increases of $652$869 million in regulatory assets associated with AROs and $584 million in other regulatory assets, deferred and a decrease of $759 million in property, plant, and equipment primarily due to additions to distribution, transmission, and steam generation, $548 million in long-term debtequipment. These changes were primarily due to the issuanceimpacts of retiring and reclassifying Plant Gorgas Units 8, 9, and 10. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Alabama Power – Environmental Accounting Order" for additional senior notes, $533information. Other significant increases include $1.4 billion in total common stockholder's equity, primarily due to a $1.2 billion capital contribution from Southern Company, $342 million in asset retirement obligations, deferred due to an increase in the ARO estimate primarily related to ash pond facilities, and $310 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 dueequivalents. See Note (A) to the September 2017 issuance, as well as a decrease of $236 million in securities due within one year.Condensed Financial Statements under "Asset Retirement Obligations" 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 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,contractual obligations. There are no 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 Septemberthrough June 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.2020.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – General" and " – Global Climate Issues"Matters" 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 statuteslaws 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
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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, borrowings from financial institutions, 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. In January 2019, Alabama Power received a capital contribution totaling $1.225 billion from Southern Company. 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 SeptemberJune 30, 2017,2019, Alabama Power had approximately $953$623 million of cash and cash equivalents. Committed credit arrangements with banks at SeptemberJune 30, 20172019 were as follows:
| | | Expires | Expires | | | | | | Expires Within One Year | Expires | | | | |
| 2018 | | 2020 | | 2022 | | Total | | Unused | | Term Out | | No Term Out | |
| 2019 | | 2019 | | 2020 | | 2024 | | Total | | Unused |
(in millions) | | $ | 35 |
| | $ | 500 |
| | $ | 800 |
| | $ | 1,335 |
| | $ | 1,335 |
| | $ | — |
| | $ | 35 |
| 3 |
| | $ | 500 |
| | $ | 800 |
| | $ | 1,303 |
| | $ | 1,303 |
|
See Note 68 to the financial statements of Alabama Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E)(F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
InAs reflected in the table above, in May 2017 and September 2017,2019, Alabama Power amended its $800 million and $500 million multi-year credit arrangements,arrangement, which, among other things, extended the maturity datesdate from 20202022 to 2022 and 2018 to 2020, respectively, as reflected in the table above.2024.
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 SeptemberJune 30, 2017,2019, 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 SeptemberJune 30, 2017.2019. At SeptemberJune 30, 2017,2019, Alabama Power had no$87 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.
Alabama Power also has substantial cash flow from operating activities and access to the 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. Short-term borrowings are included in notes payable in the balance sheets.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of commercial papershort-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 | | $ | 30 |
| | 1.3 | % | | $ | 220 |
|
|
| | | | | | | | | | |
| | Short-term Debt During the Period(*) |
| | Average
Amount Outstanding | | Weighted
Average
Interest
Rate | | Maximum
Amount
Outstanding |
| | (in millions) | | | | (in millions) |
| Commercial paper | $ | 26 |
| | 2.6 | % | | $ | 190 |
|
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended SeptemberJune 30, 2017.2019. No short-term debt was outstanding at SeptemberJune 30, 2017.2019. |
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 SeptemberJune 30, 2017,2019, 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 At June 30, 2019, 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 (an affiliate of 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 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 consolidatedAs a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating outlook foragencies to assess Southern Company and its subsidiaries, (includingincluding Alabama Power) from stablePower, may be negatively impacted. The modifications to negative.Rate RSE and other commitments approved by the Alabama PSC are expected to help mitigate these potential adverse impacts to certain credit metrics and will help Alabama Power meet its goal of achieving an equity ratio of approximately 55% by the end of 2025. See Note 2 to the financial statements under "Alabama Power – Rate RSE" in Item 8 of the Form 10-K for additional information.
Financing Activities
In February 2017,2019, 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%Z 5.125% 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 OctoberFebruary 15, 2017.2019.
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)
Income Taxes
|
| | | | | | | | | | | | | | | |
| | 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 | $ | 2,402 |
| | $ | 2,540 |
| | $ | 5,995 |
| | $ | 6,164 |
|
| Wholesale revenues, non-affiliates | 45 |
| | 49 |
| | 124 |
| | 131 |
|
| Wholesale revenues, affiliates | 6 |
| | 9 |
| | 23 |
| | 24 |
|
| Other revenues | 93 |
| | 100 |
| | 284 |
| | 302 |
|
| Total operating revenues | 2,546 |
| | 2,698 |
| | 6,426 |
| | 6,621 |
|
| Operating Expenses: | | | | | | | |
| Fuel | 482 |
| | 575 |
| | 1,297 |
| | 1,390 |
|
| Purchased power, non-affiliates | 119 |
| | 102 |
| | 310 |
| | 277 |
|
| Purchased power, affiliates | 161 |
| | 142 |
| | 470 |
| | 392 |
|
| Other operations and maintenance | 413 |
| | 496 |
| | 1,194 |
| | 1,393 |
|
| Depreciation and amortization | 225 |
| | 215 |
| | 669 |
| | 639 |
|
| Taxes other than income taxes | 112 |
| | 114 |
| | 311 |
| | 311 |
|
| Total operating expenses | 1,512 |
| | 1,644 |
| | 4,251 |
| | 4,402 |
|
| Operating Income | 1,034 |
| | 1,054 |
| | 2,175 |
| | 2,219 |
|
| Other Income and (Expense): | | | | | | | |
| Interest expense, net of amounts capitalized | (105 | ) | | (98 | ) | | (310 | ) | | (290 | ) |
| Other income (expense), net | 5 |
| | 11 |
| | 41 |
| | 35 |
|
| Total other income and (expense) | (100 | ) | | (87 | ) | | (269 | ) | | (255 | ) |
| Earnings Before Income Taxes | 934 |
| | 967 |
| | 1,906 |
| | 1,964 |
|
| Income taxes | 350 |
| | 363 |
| | 705 |
| | 734 |
|
| Net Income | 584 |
| | 604 |
| | 1,201 |
| | 1,230 |
|
| 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 |
|
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $25 | | 39.1 | | $6 | | 4.1 |
In the second quarter 2019, income taxes were $89 million compared to $64 million for the corresponding period in 2018. This increase was primarily due to higher pre-tax earnings in the second quarter 2019 compared to the corresponding period in 2018 and the application of the Tax Reform Accounting Order in 2018. See Note 2 to the financial statements under "Alabama Power – Tax Reform Accounting Order" in Item 8 of the Form 10-K for additional information.
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 | $ | 584 |
| | $ | 604 |
| | $ | 1,201 |
| | $ | 1,230 |
|
| 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 |
|
| Total other comprehensive income (loss) | 1 |
| | 1 |
| | 2 |
| | 2 |
|
| Comprehensive Income | $ | 585 |
| | $ | 605 |
| | $ | 1,203 |
| | $ | 1,232 |
|
The accompanying notesresults 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 the weak pace of growth in new customers and electricity use per customer, especially in residential and commercial markets. 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, both of which could contribute to a net reduction in customer usage. 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. 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
Alabama Power's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. Alabama Power maintains comprehensive environmental compliance and GHG strategies to assess upcoming requirements and compliance costs associated with these environmental laws and regulations and to achieve stated goals. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, or changing fuel sources for certain existing units, as they relatewell as related upgrades to Georgia PowerAlabama Power's transmission and distribution systems, and may impact future electric generating unit retirement and replacement decisions, results of operations, cash flows, and/or financial condition. These costs are an integral partbeing collected through existing ratemaking and billing provisions. The ultimate impact of these condensed financial statements.environmental laws and regulations and GHG
GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED) |
| | | | | | | |
| | For the Nine Months Ended September 30, |
| | 2017 | | 2016 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 1,201 |
| | $ | 1,230 |
|
| Adjustments to reconcile net income to net cash provided from operating activities -- | | | |
| Depreciation and amortization, total | 821 |
| | 794 |
|
| Deferred income taxes | 328 |
| | 346 |
|
| Allowance for equity funds used during construction | (29 | ) | | (36 | ) |
| Deferred expenses | (30 | ) | | (40 | ) |
| Pension, postretirement, and other employee benefits | (42 | ) | | (14 | ) |
| Settlement of asset retirement obligations | (95 | ) | | (93 | ) |
| Other, net | (21 | ) | | 7 |
|
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (254 | ) | | (162 | ) |
| -Fossil fuel stock | (2 | ) | | 128 |
|
| -Other current assets | (29 | ) | | 62 |
|
| -Accounts payable | (161 | ) | | 39 |
|
| -Accrued taxes | (52 | ) | | (22 | ) |
| -Accrued compensation | (60 | ) | | (26 | ) |
| -Retail fuel cost over recovery | (84 | ) | | 9 |
|
| -Other current liabilities | (11 | ) | | 44 |
|
| Net cash provided from operating activities | 1,480 |
| | 2,266 |
|
| Investing Activities: | | | |
| Property additions | (1,907 | ) | | (1,566 | ) |
| Nuclear decommissioning trust fund purchases | (411 | ) | | (563 | ) |
| Nuclear decommissioning trust fund sales | 406 |
| | 558 |
|
| Cost of removal, net of salvage | (54 | ) | | (45 | ) |
| Change in construction payables, net of joint owner portion | 180 |
| | (139 | ) |
| Payments pursuant to LTSAs | (59 | ) | | (27 | ) |
| Sale of property | 63 |
| | 10 |
|
| Other investing activities | (52 | ) | | 14 |
|
| Net cash used for investing activities | (1,834 | ) | | (1,758 | ) |
| Financing Activities: | | | |
| Decrease in notes payable, net | (391 | ) | | (63 | ) |
| Proceeds — | | | |
| Capital contributions from parent company | 412 |
| | 294 |
|
| Senior notes | 1,350 |
| | 650 |
|
| FFB loan | — |
| | 300 |
|
| 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 | ) |
| Other financing activities | (48 | ) | | (26 | ) |
| 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 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid during the period for — | | | |
| Interest (net of $17 and $15 capitalized for 2017 and 2016, respectively) | $ | 284 |
| | $ | 277 |
|
| Income taxes, net | 369 |
| | 188 |
|
| Noncash transactions — Accrued property additions at end of period | 470 |
| | 226 |
|
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 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 266 |
| | $ | 3 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 670 |
| | 523 |
|
| Unbilled revenues | | 276 |
| | 224 |
|
| Under recovered fuel clause revenues | | 62 |
| | — |
|
| Joint owner accounts receivable | | 222 |
| | 57 |
|
| Other accounts and notes receivable | | 82 |
| | 81 |
|
| Affiliated | | 21 |
| | 18 |
|
| Accumulated provision for uncollectible accounts | | (3 | ) | | (3 | ) |
| Fossil fuel stock | | 300 |
| | 298 |
|
| Materials and supplies | | 480 |
| | 479 |
|
| Prepaid expenses | | 82 |
| | 105 |
|
| Other regulatory assets, current | | 200 |
| | 193 |
|
| Other current assets | | 27 |
| | 38 |
|
| Total current assets | | 2,685 |
| | 2,016 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 34,589 |
| | 33,841 |
|
| Less: Accumulated provision for depreciation | | 11,655 |
| | 11,317 |
|
| Plant in service, net of depreciation | | 22,934 |
| | 22,524 |
|
| Nuclear fuel, at amortized cost | | 551 |
| | 569 |
|
| Construction work in progress | | 5,751 |
| | 4,939 |
|
| Total property, plant, and equipment | | 29,236 |
| | 28,032 |
|
| Other Property and Investments: | | | | |
| Equity investments in unconsolidated subsidiaries | | 53 |
| | 60 |
|
| Nuclear decommissioning trusts, at fair value | | 914 |
| | 814 |
|
| Miscellaneous property and investments | | 51 |
| | 46 |
|
| Total other property and investments | | 1,018 |
| | 920 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 669 |
| | 676 |
|
| Other regulatory assets, deferred | | 2,890 |
| | 2,774 |
|
| Other deferred charges and assets | | 608 |
| | 417 |
|
| Total deferred charges and other assets | | 4,167 |
| | 3,867 |
|
| Total Assets | | $ | 37,106 |
| | $ | 34,835 |
|
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholder's Equity | | At September 30, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 261 |
| | $ | 460 |
|
| Notes payable | | 400 |
| | 391 |
|
| Accounts payable — | | | | |
| Affiliated | | 396 |
| | 438 |
|
| Other | | 1,012 |
| | 589 |
|
| Customer deposits | | 270 |
| | 265 |
|
| Accrued taxes | | 353 |
| | 407 |
|
| Accrued interest | | 121 |
| | 106 |
|
| Accrued compensation | | 164 |
| | 224 |
|
| Asset retirement obligations, current | | 214 |
| | 299 |
|
| Other current liabilities | | 192 |
| | 297 |
|
| Total current liabilities | | 3,383 |
| | 3,476 |
|
| Long-term Debt | | 11,610 |
| | 10,225 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 6,328 |
| | 6,000 |
|
| Accumulated deferred ITCs | | 248 |
| | 256 |
|
| Employee benefit obligations | | 665 |
| | 703 |
|
| Asset retirement obligations, deferred | | 2,367 |
| | 2,233 |
|
| Other deferred credits and liabilities | | 232 |
| | 320 |
|
| Total deferred credits and other liabilities | | 9,840 |
| | 9,512 |
|
| Total Liabilities | | 24,833 |
| | 23,213 |
|
| Preferred Stock | | 45 |
| | 45 |
|
| Preference Stock | | 221 |
| | 221 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, without par value — | | | | |
| Authorized — 20,000,000 shares | | | | |
| Outstanding — 9,261,500 shares | | 398 |
| | 398 |
|
| Paid-in capital | | 7,308 |
| | 6,885 |
|
| Retained earnings | | 4,311 |
| | 4,086 |
|
| Accumulated other comprehensive loss | | (10 | ) | | (13 | ) |
| Total common stockholder's equity | | 12,007 |
| | 11,356 |
|
| Total Liabilities and Stockholder's Equity | | $ | 37,106 |
| | $ | 34,835 |
|
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIAALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRD QUARTER 2017 vs. THIRD QUARTER 2016goals will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed technology, fuel prices, and the outcome of pending and/or future legal challenges.
New or revised environmental laws and regulations could affect many areas of Alabama Power's operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be recovered in rates on a timely basis. Environmental compliance costs are recovered through Rate CNP Compliance. Further, increased costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and/or financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Alabama Power in Item 7 of the Form 10-K and Note 2 to the financial statements under "Alabama Power – Rate CNP Compliance" and Note 3 to the financial statements under "Environmental Remediation" in Item 8 of the Form 10-K for additional information.
YEAR-TO-DATE 2017 vs. YEAR-TO-DATE 2016Environmental Laws and Regulations
Coal Combustion Residuals
OVERVIEW
GeorgiaIn June 2019, Alabama Power operates as a vertically integrated utility providing electric servicerecorded an increase of approximately $308 million to retail customers within its traditional service territory locatedAROs primarily related to the CCR Rule and the related state rule based on management's completion of closure designs during the second quarter 2019 for all but two of its ash pond facilities. The additional estimated costs to close these ash ponds under the planned closure-in-place methodology primarily relate to cost inputs from contractor bids, internal drainage and dewatering system designs, and increases in the estimated ash volumes. The cost estimate for the remaining ash pond facilities will be updated within the Statenext 12 months and the change could be material.
As further analysis is performed and additional details are developed with respect to all ash pond closures, Alabama Power expects to periodically update these cost estimates as necessary. Additionally, the closure designs and plans are subject to approval by environmental regulatory agencies. Absent continued recovery of GeorgiaARO costs through regulated rates, Alabama Power's results of operations, cash flows, and financial condition could be materially impacted. The ultimate outcome of this matter cannot be determined at this time. See Note 6 to wholesale customersthe financial statements in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
Global Climate Issues
On July 8, 2019, the EPA published the final Affordable Clean Energy rule (ACE Rule) to repeal and replace the CPP. Implementation of the CPP has been stayed by the U.S. Supreme Court since 2016. The ACE Rule requires states to develop unit-specific CO2 emission rate standards for existing coal-fired units based on heat-rate efficiency improvements. Combustion turbines, including natural gas combined cycles, are not included as affected sources in the Southeast.
Many factors affectACE Rule. Alabama Power has ownership interests in seven coal-fired units to which the opportunities,ACE Rule is applicable. The ultimate impact of the ACE Rule, including the repeal and replacement of the CPP, to Alabama Power will depend on state implementation plan requirements and the outcome of any associated legal challenges and risks of Georgia Power's business of providing electric service. These factors includecannot be determined at this time.
FERC Matters
See Note 2 to the ability to maintain a constructive regulatory environment, to maintain and grow energy sales, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, reliability, fuel, capital expenditures, and restoration following major storms. Georgia Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Georgia Power for the foreseeable future.
Georgia Power continues to focus on several key performance indicators including, but not limited to, customer satisfaction, plant availability, system reliability, the execution of major construction projects, and net income after dividends on preferred and preference stock.
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 protectionfinancial statements under Chapter 11"FERC Matters – Open Access Transmission Tariff" in Item 8 of the U.S. Bankruptcy Code. To provideForm 10-K for a continuation of work, 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. additional information.
On June 9, 2017, Georgia Power and28, 2019, the other Vogtle Owners and Toshiba entered intoFERC approved a settlement agreement regardingbetween Alabama Municipal Electric Authority and Cooperative Energy and SCS and the Toshiba Guarantee (Guarantee Settlement Agreement). Pursuanttraditional electric operating companies (including Alabama Power) agreeing to an OATT rate reduction based on a 10.6% ROE, with a retroactive effective date of May 10, 2018, and a five-year moratorium on these parties seeking changes 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 installmentOATT formula rate. The terms of the Guarantee ObligationsOATT settlement agreement will not have a material impact on the financial statements of $300 million from Toshiba, of which Georgia Power's proportionate share was $137 million.Alabama Power.
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
GEORGIAALABAMA 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.Retail Regulatory Matters
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 andAlabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the negotiationoversight of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals,Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and satisfaction of other conditions.Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See Note 62 to the financial statements of Georgia Power under "DOE Loan Guarantee Borrowings""Alabama Power" in Item 8 of the Form 10-K and Note (E)(B) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information including applicable covenants, eventsregarding Alabama Power's rate mechanisms, accounting orders, and the recovery balance of default, mandatory prepayment events,each regulatory clause for Alabama Power.
Environmental Accounting Order
On April 15, 2019, Alabama Power retired Plant Gorgas Units 8, 9, and conditions10 and reclassified approximately $654 million of the unrecovered asset balances to borrowing.
An inability or other failure by Toshiba to perform its obligations underregulatory assets, which are being recovered over the Guarantee Settlement Agreement could have a further material impact onunits' remaining useful lives, the net costlatest being through 2037, as established prior to the Vogtle Ownersdecision to complete constructionretire. Additionally, approximately $700 million of Plant Vogtle Units 3net capitalized asset retirement costs were reclassified to a regulatory asset in accordance with accounting guidance provided by the Alabama PSC. The asset retirement costs are being recovered through 2055. See Note 2 to the financial statements under "Alabama Power – Environmental Accounting Order" and 4Note 6 in Item 8 of the Form 10-K for additional information.
Other Matters
Alabama Power is involved in various other matters that could affect future earnings, including matters being litigated and therefore, on Georgiaregulatory matters. In addition, Alabama Power is subject to certain claims and legal actions arising in the ordinary course of business. Alabama Power's financial statements. business activities are subject to extensive governmental regulation related to public health and the environment, such as laws and regulations governing air, water, land, and protection of other natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations, 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 thesesuch pending or potential litigation or regulatory matters cannot be determined at this time.time; however, for current proceedings not specifically reported 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 Alabama Power's financial statements. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction"Notes (B) and (C) to the Condensed Financial Statements herein for additional informationa discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
In response to changing customer expectations, payment patterns, and ongoing efforts to increase overall operating efficiencies, Alabama Power initiated a plan to close 40 of its 86 payment offices by the end of 2019. Charges associated with these activities are not expected to have a material impact on Plant Vogtle Units 3 and 4, including GeorgiaAlabama Power's cost-to-complete and cancellation cost assessments for Plant Vogtle Units 3 and 4.financial statements.
RESULTS OF OPERATIONSACCOUNTING POLICIES
Net IncomeApplication of Critical Accounting Policies and Estimates
|
| | | | | | |
| 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 preferredAlabama Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Notes 1, 5, 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 compared6 to the corresponding periodsfinancial statements in 2016, partially offset by lower non-fuelItem 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 maintenance expenses.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.
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.
GEORGIAALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of the changes in retail revenues were as follows:Recently Issued Accounting Standards
|
| | | | | | | | | | | | | |
| | 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 comparedSee Note (A) 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. Condensed Financial Statements herein for information regarding Alabama Power's recently adopted accounting standards.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIALFINANCIAL CONDITION AND LIQUIDITY – "Retail Regulatory Matters – Nuclear Construction""Overview" 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 GeorgiaAlabama Power in Item 7 of the Form 10-K for additional information. Alabama Power's financial condition remained stable at June 30, 2019. 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 $695 million for the first six months of 2019, an increase of $43 million as compared to the first six months of 2018. The increase in net cash provided from operating activities was primarily due to increased fuel cost recovery, partially offset by the prior year impacts of customer billing reductions related to the Tax Reform Legislation. Net cash used for investing activities totaled $1.0 billion for the first six months of 2019 primarily related to additional capital expenditures for distribution, environmental, and transmission assets. Net cash provided from financing activities totaled $617 million for the first six months of 2019 primarily due to capital contributions from Southern Company, partially offset by a payment of common stock dividends and a long-term debt maturity. Fluctuations in cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first six months of 2019 include increases of $869 million in regulatory assets associated with AROs and $584 million in other regulatory assets, deferred and a decrease of $759 million in property, plant, and equipment. These changes were primarily due to the impacts of retiring and reclassifying Plant Gorgas Units 8, 9, and 10. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Alabama Power – Environmental Accounting Order" for additional information. Other significant increases include $1.4 billion in total common stockholder's equity, primarily due to a $1.2 billion capital contribution from Southern Company, $342 million in asset retirement obligations, deferred due to an increase in the ARO estimate primarily related to ash pond facilities, and $310 million in cash and cash equivalents. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" 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 Alabama Power in Item 7 of the Form 10-K for a description of Alabama Power's capital requirements and contractual obligations. There are no scheduled maturities of long-term debt through June 30, 2020.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Alabama Power in Item 7 of the Form 10-K for additional information on Alabama Power's environmental compliance strategy.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to 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
GEORGIAALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Revenuescost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
|
| | | | | | |
| 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) |
InAlabama Power plans to obtain the third quarter 2017, other revenues were $93 million comparedfunds to $100 million for the corresponding period in 2016. The decrease was primarily duemeet its future capital needs from sources similar 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 millionthose used in the corresponding period in 2016. The decrease waspast, which were primarily due tofrom operating cash flows, external security issuances, borrowings from financial institutions, 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. In January 2019, Alabama Power received 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 $2.08capital contribution totaling $1.225 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.from Southern Company. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIALFINANCIAL CONDITION AND LIQUIDITY – "Retail Regulatory Matters – Fuel Cost Recovery""Sources of GeorgiaCapital" of Alabama Power in Item 7 of the Form 10-K for additional information.
Alabama Power's current liabilities sometimes exceed current assets because of long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs.
At June 30, 2019, Alabama Power had approximately $623 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2019 were as follows:
|
| | | | | | | | | | | | | | | | | | |
| Expires | | | | |
| 2019 | | 2020 | | 2024 | | Total | | Unused |
| (in millions) |
| $ | 3 |
| | $ | 500 |
| | $ | 800 |
| | $ | 1,303 |
| | $ | 1,303 |
|
See 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.
As reflected in the table above, in May 2019, Alabama Power amended its $800 million multi-year credit arrangement, which, among other things, extended the maturity date from 2022 to 2024.
Most of these bank credit arrangements, as well as Alabama Power's term loan arrangements, contain covenants that limit debt levels and contain cross-acceleration provisions to other indebtedness (including guarantee obligations) of Alabama Power. Such cross-acceleration provisions to other indebtedness would trigger an event of default if Alabama Power defaulted on indebtedness, the payment of which was then accelerated. At June 30, 2019, 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 June 30, 2019. At June 30, 2019, Alabama Power had $87 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.
Alabama Power also has substantial cash flow from operating activities and access to the 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. Short-term borrowings are included in notes payable in the balance sheets.
GEORGIAALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of Georgia Power's generation and purchased powershort-term borrowings 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 |
|
| | | | | | | | | | |
| | Short-term Debt During the Period(*) |
| | Average
Amount Outstanding | | Weighted
Average
Interest
Rate | | Maximum
Amount
Outstanding |
| | (in millions) | | | | (in millions) |
| Commercial paper | $ | 26 |
| | 2.6 | % | | $ | 190 |
|
| |
| (*) | Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated byand maximum amounts are based upon daily balances during the provider.three-month period ended June 30, 2019. No short-term debt was outstanding at June 30, 2019. |
FuelAlabama Power believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and operating cash flows.
In the third quarter 2017, fuel expense was $482 million compared to $575 millionCredit Rating Risk
At June 30, 2019, Alabama Power did not have any credit arrangements that would require material changes in the corresponding period in 2016. The decrease was primarily due topayment schedules or terminations as 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% increasecredit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the volumeevent of KWHs purchaseda credit rating change to supportBBB 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. At June 30, 2019, the maximum potential collateral requirements at a rating below BBB- and/or Baa3 totaled approximately $359 million.
Included in these amounts are certain agreements that could require collateral in the event that either Alabama Power or Georgia Power (an affiliate of Alabama Power) has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company system transmission reliabilityguaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Alabama Power to access capital markets and duewould be likely to unplanned outagesimpact the cost at Georgia Power-owned generating units andwhich it does so.
As a 5.9% increase inresult of the average cost per KWH purchased primarily resultingTax Reform Legislation, certain financial metrics, such as the funds from higher natural gas prices.
Energy purchases from affiliates will vary depending on demand andoperations to debt percentage, used by the availability and cost of generating resources at each company within thecredit rating agencies to assess Southern Company system. These purchases are made in accordance with the IIC orand its subsidiaries, including Alabama Power, may be negatively impacted. The modifications to Rate RSE and other contractual agreements, all ascommitments approved by the FERC.
Other OperationsAlabama PSC are expected to help mitigate these potential adverse impacts to certain credit metrics 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) |
Inwill help Alabama Power meet its goal of achieving an equity ratio of approximately 55% by 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 decreasesend 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 related2025. See Note 2 to the timingfinancial statements under "Alabama Power – Rate RSE" in Item 8 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" hereinForm 10-K for additional information.
Other Income (Expense), NetFinancing Activities
In February 2019, Alabama Power repaid at maturity $200 million aggregate principal amount of Series Z 5.125% Senior Notes due February 15, 2019.
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.
|
| | | | | | |
| 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 TaxesIntegrated Resource Plan
In 2016, the Georgia PSC approved Georgia Power's triennial Integrated Resource Plan, including recovery of costs up to $99 million through June 30, 2019 to preserve nuclear generation as an option at a future generation site in Stewart County, Georgia. In 2017, the Georgia PSC approved Georgia Power's decision to suspend work at the site due to changing economics, including lower load forecasts and fuel costs. In accordance with the Georgia PSC's order, costs incurred of approximately $50 million have been recorded as a regulatory asset.
On July 16, 2019, the Georgia PSC voted to approve Georgia Power's triennial Integrated Resource Plan (2019 IRP) as modified by a stipulated agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors and further modified by the Georgia PSC.
In the 2019 IRP, the Georgia PSC approved the decertification and retirement of Plant Hammond Units 1 through 4 (840 MWs) and Plant McIntosh Unit 1 (142.5 MWs) effective July 29, 2019. The Georgia PSC also approved the reclassification of the remaining net book values of the Plant Hammond and Plant McIntosh units (approximately $500 million and $40 million, respectively, at June 30, 2019), as well as any unusable materials and supplies inventory balances, upon retirement to a regulatory asset. Recovery of each unit's net book value will continue through December 31, 2019 as provided in the 2013 ARP.
For the regulatory asset balances remaining at December 31, 2019, Georgia Power requested recovery in the Georgia Power 2019 Base Rate Case as follows: (i) the net book values of Plant Mitchell Unit 3 (approximately $8
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
million at June 30, 2019) and Plant McIntosh Unit 1, any unusable materials and supplies inventory, and the future generation site in Stewart County, Georgia over a three-year period ending December 31, 2022 and (ii) the net book values of Plant Hammond Units 1 through 4 over a period equal to the applicable unit's remaining useful life through 2035. The ultimate outcome of these matters cannot be determined at this time.
Also in the 2019 IRP, the Georgia PSC rejected a request to certify approximately 25 MWs of capacity at Plant Scherer Unit 3 for the retail jurisdiction beginning January 1, 2020 following the expiration of a wholesale PPA. Georgia Power may offer such capacity in the wholesale market or to the retail jurisdiction in a future Integrated Resource Plan. The ultimate outcome of this matter cannot be determined at this time but is not expected to have a material impact on Southern Company's financial statements.
Additionally, the Georgia PSC approved Georgia Power's proposed environmental compliance strategy associated with ash pond and certain landfill closures and post-closure care in compliance with the CCR Rule and the related state rule. In the Georgia Power 2019 Base Rate Case, Georgia Power requested recovery of the under recovered balance of these compliance costs at December 31, 2019 (approximately $135 million at June 30, 2019) over a three-year period ending December 31, 2022 and recovery of estimated compliance costs of $277 million for 2020, $395 million for 2021, and $655 million for 2022 over three-year periods ending December 31, 2022, 2023, and 2024, respectively. The ultimate outcome of this matter cannot be determined at this time. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information regarding Georgia Power's AROs.
The Georgia PSC also approved Georgia Power to (i) issue requests for proposals (RFP) for capacity beginning in 2022 or 2023 and in 2026, 2027, or 2028; (ii) procure up to an additional 2,210 MWs of renewable resources through competitive RFPs; and (iii) invest in a portfolio of up to 80 MWs of battery energy storage technologies.
See "Rate Plans" herein for additional information regarding the Georgia Power 2019 Base Rate Case.
Mississippi Power
Kemper County Energy Facility
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. 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 Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.
During the second quarter and year-to-date 2019, Mississippi Power recorded pre-tax charges to income of $4 million ($3 million after tax) and $6 million ($5 million after tax), respectively, primarily resulting from the abandonment and related closure activities and ongoing period costs, net of sales proceeds, for the mine and gasifier-related assets at the Kemper County energy facility. Additional closure costs for the mine and gasifier-related assets, currently estimated at up to $10 million pre-tax (excluding dismantlement costs, net of salvage), may be incurred through the first half of 2020. In addition, period costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the mine and gasifier-related assets, are estimated at $7 million for the remainder of 2019 and $2 million to $6 million annually in 2020 through 2023.
In addition, Mississippi Power constructed the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery and is currently evaluating its options regarding the final disposition of the CO2 pipeline, including removal of the pipeline. This evaluation is expected to be complete later in 2019. If Mississippi Power ultimately decides to remove the CO2 pipeline, the cost of removal could have a material impact on Southern Company's financial statements.
In December 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the $387 million of grants received. Mississippi Power and the DOE are currently in discussions regarding the requested closeout and property disposition, which may require payment to the DOE for a portion of certain property that is to be retained by Mississippi Power. In connection with the DOE closeout discussions, on April 29, 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
of an investigation related to the Kemper County energy facility. The ultimate outcome of these matters cannot be determined at this time; however, they could have a material impact on Southern Company's financial statements.
Southern Company Gas
The natural gas distribution utilities are subject to regulation and oversight by their respective state regulatory agencies for the rates charged 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 regulatory agencies in the states in which 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 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 and energy efficiency plans.
In November 2018, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $230 million increase in annual base rate revenues. The requested increase is based on a projected test year for the 12-month period ending September 30, 2020, a ROE of 10.6%, and an increase in the equity ratio from 52% to 54% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation.
On April 16, 2019, Nicor Gas entered into a stipulation agreement to resolve all related issues with the Staff of the Illinois Commission, including a ROE of 9.86% and an equity ratio of 54%. Also on April 16, 2019, Nicor Gas filed its rebuttal testimony with the Illinois Commission incorporating the stipulation agreement and addressing the remaining items outstanding with the other two intervenors. As a result of the stipulation agreement and rebuttal testimony, the revised requested annual revenue increase is $180 million.
The Illinois Commission is expected to rule on the requested increase by early October 2019, after which rate adjustments will be effective.
On June 3, 2019, Atlanta Gas Light filed a general base rate case with the Georgia PSC requesting a $96 million increase in annual base rate revenues. The requested increase is based on a forward-looking test year for the 12-month period ending July 31, 2020, a ROE of 10.75% with an earnings band based on a ROE between 10.55% and 10.95%, and a continued equity ratio of 55%. The filing also requests the continuation of the Georgia rate adjustment mechanism, as previously authorized. Atlanta Gas Light expects the Georgia PSC to issue a final order on this matter on December 19, 2019 with the new rates becoming effective January 1, 2020.
The ultimate outcome of these matters cannot be determined at this time.
Construction Program
Overview
The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue its strategy of developing and constructing new electric generating facilities, adding environmental modifications to certain existing units, expanding and improving the electric transmission and distribution systems, and updating and expanding the natural gas distribution systems. For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. Southern Company Gas is engaged in various infrastructure improvement programs designed to update or expand the natural gas distribution systems of the natural gas distribution utilities to improve reliability and meet operational flexibility and growth. The natural gas distribution utilities recover their investment and a return associated with these infrastructure programs through their regulated rates. See Notes 2 and
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
15 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" and "Southern Power," respectively, in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information.
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). See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K and "Nuclear Construction" herein for additional information.
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.
Nuclear Construction
See Note 2 to the financial statements under "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, the joint ownership agreements and related funding agreement, VCM reports, and the NCCR tariff.
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. Georgia Power holds a 45.7% ownership interest in Plant Vogtle Units 3 and 4. 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 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement. In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into several transitional arrangements to allow construction to continue. In July 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 time and materials cost basis. The Vogtle Services Agreement provides that it will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.
In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, executed the Bechtel Agreement, a cost reimbursable plus fee arrangement, whereby Bechtel is 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 the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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:
|
| | | | | | |
| 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 billions) |
Base project capital cost forecast(a)(b) | $ | 8.0 |
|
| Construction contingency estimate | 0.4 |
|
Total project capital cost forecast(a)(b) | 8.4 |
|
Net investment as of June 30, 2019(b) | (5.2 | ) |
Remaining estimate to complete(a) | $ | 3.2 |
|
| |
| (a) | Excludes financing costs expected to be capitalized through AFUDC of approximately $315 million. |
| |
| (b) | Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds. |
Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $2.0 billion had been incurred through June 30, 2019.
In April 2019, Southern Nuclear completed a cost and schedule validation process to verify and update quantities of commodities remaining to install, labor hours to install remaining quantities and related productivity, testing and system turnover requirements, and forecasted staffing needs and related costs. This process confirmed the third quarterestimated total project capital cost forecast for Plant Vogtle Units 3 and 4. The expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4, as previously approved by the Georgia PSC, remain unchanged.
As construction continues and testing and system turnover activities increase, challenges with management of contractors, subcontractors, and vendors; supervision of craft labor and related craft labor productivity, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, and/or installation and the initial testing and start-up, including any required engineering changes, of plant systems, structures, or components (some of which are based on new technology that only recently began initial operation in the global nuclear industry at this scale), or regional transmission upgrades, any of which may require additional labor and/or materials; or other issues could arise and change the projected schedule and estimated cost.
The April 2019 cost and schedule validation process established target values for monthly construction production and system turnover activities as part of a strategy to maintain and, where possible, build margin to the approved in-service dates. To support that strategy, monthly production and activity target values will continue to increase significantly throughout 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers (particularly electrical and pipefitter craft labor), as well as additional supervision and other field support resources, must be retained and deployed.
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. 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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $12 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, income taxesthe Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 to provide for, among other conditions, additional Vogtle Owner approval requirements. Effective in August 2018, the 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 to continue construction (as amended, and together with the November 2017 amendment, the Vogtle Joint Ownership Agreements). The Vogtle Joint Ownership Agreements also confirm 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 the 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, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were $350required 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) the Vogtle Owner Term Sheet with the other Vogtle Owners and MEAG's wholly-owned subsidiaries 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) the MEAG Term Sheet with MEAG and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. On January 14, 2019, Georgia Power, MEAG, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. On February 18, 2019, Georgia Power, the other Vogtle Owners, and MEAG'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.
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 Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. At June 30, 2019, Georgia Power had recovered approximately $2.0 billion of financing costs. Financing costs related to capital costs above $4.418 billion will be recovered through AFUDC; however, Georgia Power will not record AFUDC related to any 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 2018, the Georgia PSC approved Georgia Power's request to increase the NCCR tariff by $88 million comparedannually, effective January 1, 2019.
Georgia Power is required to $363file semi-annual VCM reports with the Georgia PSC 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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
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 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 should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (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 impact of payments received under the Guarantee 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 revised cost forecast 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 ROE used to calculate the NCCR tariff (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, (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 in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 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 base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective Unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $100 million in the corresponding period in 2016. For year-to-date 2017, income taxes were $705 million compared2018 and are estimated to $734have negative earnings impacts of approximately $70 million in 2019 and an aggregate of approximately $630 million from 2020 to 2022.
In its January 11, 2018 order, the corresponding periodGeorgia 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 two appeals. On January 9, 2019, GIPL, PSE, and Georgia Watch filed an appeal of this decision with the Georgia Court of Appeals. Georgia Power believes the appeal has no merit; however, an adverse outcome in 2016. The decreases were primarily due to lower pre-tax earnings and increased state ITCs.
FUTURE EARNINGS POTENTIAL
Thethe appeal combined with subsequent adverse action by the Georgia PSC could have a material impact on Southern Company's results of operations, discussed above are not necessarily indicativefinancial condition, and liquidity.
In August 2018, Georgia Power filed its nineteenth VCM report with the Georgia PSC, which requested approval of $578 million of construction capital costs incurred from January 1, 2018 through June 30, 2018. On February 19, 2019, the Georgia PSC approved the nineteenth VCM, but deferred approval of $51.6 million of expenditures related to Georgia Power's future earnings potential. The levelportion of an administrative claim filed in the Westinghouse bankruptcy proceedings. Through the nineteenth VCM, the Georgia Power's future earnings dependsPSC has approved total construction capital costs incurred through June
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
30, 2018 of $5.4 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds).
On April 30, 2019, as requested by the staff of the Georgia PSC, Georgia Power reported the results of the cost and schedule validation process to the Georgia PSC. On August 30, 2019, Georgia Power will file its twentieth VCM report concurrently with its twenty-first VCM report with the Georgia PSC, which will reflect the capital cost forecast discussed previously and request approval of $1.2 billion of construction capital costs incurred from June 30, 2018 through June 30, 2019. In addition, on numerous factors that affect the opportunities, challenges,June 20, 2019, Georgia Power, acting for itself 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 allowas agent for the timely recoveryother Vogtle Owners, entered into a settlement agreement related to the administrative claim filed in the Westinghouse bankruptcy proceedings. Accordingly, in the twentieth/twenty-first VCM report, Georgia Power will also request approval of prudently-incurred costs duringthe $51.6 million of associated expenditures previously deferred by the Georgia PSC.
The ultimate outcome of these matters cannot be determined at this time.
See RISK FACTORS of Southern Company in the Form 10-K for a timediscussion of increasing costscertain risks associated with the licensing, construction, and limited projected demand growth overoperation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the next several years. Mattersworld.
DOE Financing
At June 30, 2019, Georgia Power had borrowed $3.46 billion related to Plant Vogtle Units 3 and 4 constructioncosts as provided through the Amended and rate recoveryRestated Loan Guarantee Agreement and related multi-advance credit facilities among Georgia Power, the DOE, and the FFB, which provide for borrowings of up to approximately $5.130 billion, subject to the satisfaction of certain conditions. See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (F) 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 ultimate outcome of these matters cannot be determined at this time.
Other Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Southern Company in Item 7 for additional information.
Southern Company and its subsidiaries are also major factors. Futureinvolved in various other matters that could affect future earnings, willincluding matters being litigated, as well as other regulatory matters and matters that could result in asset impairments. 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 laws and regulations governing air, water, land, and protection of other natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations, 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, regulatory matters, or potential asset impairments cannot be driven primarilydetermined at this time; however, for current proceedings not specifically reported 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 Southern Company's financial statements. See Notes (B) and (C) 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.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Litigation
In January 2017, a putative 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 by customer growth. Earnings will also depend upon maintainingMonroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and growing sales, considering,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 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 adoptionplaintiffs 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 March 2018, the court issued an order granting, in part, the defendants' motion to dismiss. The court dismissed certain claims against certain officers of Southern Company and Mississippi Power and dismissed the allegations related to a number of the statements that plaintiffs challenged as being false or misleading. In April 2018, the defendants filed a motion for reconsideration of the court's order, seeking dismissal of the remaining claims in the lawsuit. In August 2018, the court denied the motion for reconsideration and denied a motion to certify the issue for interlocutory appeal.
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 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 April 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 putative 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 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 May 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 putative securities class action.
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 approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest. In the first quarter 2019, Mississippi Power and Southern Company filed motions to dismiss, which were denied by the arbitration panel on May 10, 2019.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 tort law claims. In 2016, the Georgia Court of Appeals reversed the trial court's previous dismissal of the case and remanded the case to the trial court. Georgia Power filed a petition for writ of certiorari with the Georgia Supreme Court, which was granted in 2017. In June 2018, the Georgia Supreme Court affirmed the judgment of the Georgia Court of Appeals and remanded the case to the trial court for further proceedings. Following a motion by Georgia Power, on February 13, 2019, the Superior Court of Fulton County ordered the parties to submit petitions to the Georgia PSC for a declaratory ruling to address certain terms the court previously held were ambiguous as used in the Georgia PSC's orders. The order entered by the Superior Court of Fulton County 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. Georgia Power also filed a notice of appeal with the Georgia Court of Appeals regarding the Superior Court of Fulton County's February 2019 order. The amount of any possible losses cannot be calculated at this time because, among other factors, it is unknown whether conditional class certification will be upheld and the ultimate composition of any class and whether any losses would be subject to recovery from any municipalities.
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. The ultimate outcome of these matters cannot be determined at this time.
Mississippi Power
In conjunction with Southern Company's sale of Gulf Power, Mississippi Power and Gulf Power have committed to seek a restructuring of their 50% undivided ownership interests in Plant Daniel such that each of them would, after the restructuring, own 100% of a generating unit. On January 15, 2019, Gulf Power provided notice to Mississippi Power that Gulf Power will retire its share of the generating capacity of Plant Daniel on January 15, 2024. Mississippi Power has the option to purchase Gulf Power's ownership interest for $1 on January 15, 2024, provided that Mississippi Power exercises the option no later than 120 days prior to that date. Mississippi Power is assessing the potential operational and economic effects of Gulf Power's notice. The ultimate outcome of these matters remains subject to completion of Mississippi Power's evaluations and applicable regulatory approvals, including by the FERC and the Mississippi PSC, and cannot be determined at this time. See Note (K) to the Condensed Financial Statements under "Southern Company" herein for information regarding the sale of Gulf Power.
Southern Company Gas
See Note 3 to the financial statements in Item 8 of the Form 10-K under "Other Matters – Southern Company Gas" for information on a natural gas storage facility consisting of two salt dome caverns in Louisiana. The future performance of this facility, as well as Southern Company Gas' two other natural gas storage facilities located in California and Texas, could be impacted by ongoing changes in the U.S. natural gas storage market. Recent sales of natural gas storage facilities have resulted in losses for the sellers and may imply an impact on future rates and/or penetration ratesasset values. Southern Company Gas is evaluating these recent market transactions for impacts on its plans to return one of increasingly energy-efficient technologies, increasing volumesthe salt dome caverns in Louisiana back to service in 2021. Sustained diminished natural gas storage values could trigger impairment of electronic commerce transactions,one or all of these natural gas storage facilities, which have a combined net book value of $438 million at June 30, 2019. The ultimate outcome of these matters cannot be determined at this time, but could have a material impact on Southern Company's financial statements.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and higher multi-family home construction. EarningsEstimates
Southern Company prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Notes 1, 5, and 6 to the financial statements 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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
Recently Issued Accounting Standards
See Note (A) to the Condensed Financial Statements herein for information regarding Southern Company's recently adopted accounting standards.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company in Item 7 of the Form 10-K for additional information. Southern Company's financial condition remained stable at June 30, 2019. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $2.5 billion for the first six months of 2019, a decrease of $0.7 billion from the corresponding period in 2018. The decrease in net cash provided from operating activities was primarily due to the timing of vendor payments and the impacts of the Gulf Power disposition and the Southern Company Gas Dispositions. Net cash provided from investing activities totaled $1.0 billion for the first six months of 2019 primarily due to proceeds from the sale of Gulf Power, partially offset by the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities and capital expenditures for Southern Company Gas' infrastructure replacement programs. Net cash used for financing activities totaled $3.6 billion for the first six months of 2019 primarily due to repayments of short-term bank debt, net redemptions and repurchases of long-term debt, and common stock dividend payments. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities. See Notes (F) and (K) to the Condensed Financial Statements herein for additional information.
Significant balance sheet changes for the first six months of 2019 include:
decreases in assets and liabilities held for sale of $5.0 billion and $3.2 billion, respectively, primarily related to the sale of Gulf Power;
an increase of $2.1 billion in total stockholders' equity primarily related to the gain on the sale of Gulf Power;
| |
| • | operating lease right-of-use assets, net of amortization and operating lease obligations, each totaling $1.9 billion, recorded upon the adoption of FASB ASC Topic 842, Leases; |
an increase of $1.7 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, partially offset by Alabama Power's reclassification of $1.4 billion to regulatory assets related to the retirement of Plant Gorgas, including $0.7 billion associated with AROs;
decreases of $1.5 billion in notes payable and $1.1 billion in long-term debt (including amounts due within one year) related to net repayments of short-term bank debt and long-term debt, respectively; and
an increase of $1.2 billion in accumulated deferred income taxes primarily related to the expected utilization of tax credit carryforwards in the 2019 tax year as a result of increased taxable income from the sale of Gulf Power.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Alabama Power" herein and Notes (A), (B), (F), (G), (K), and (L) to the Condensed Financial Statements herein for additional information.
At the end of the second quarter 2019, the market price of Southern Company's common stock was $55.28 per share (based on the closing price as reported on the NYSE) and the book value was $25.73 per share, representing a market-to-book ratio of 215%, compared to $43.92, $23.91, and 184%, respectively, at the end of 2018. Southern Company's common stock dividend for the second quarter 2019 was $0.62 per share compared to $0.60 per share in the second quarter 2018.
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 and contractual obligations. Approximately $3.1 billion will be required through June 30, 2020 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.
The construction programs are subject to a varietyperiodic review and revision, and actual construction costs may vary from these estimates because of othernumerous factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers,include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the useoutcome of alternative energyany legal challenges to environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources by customers,at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; state regulatory agency approvals; changes in the priceexpected environmental compliance program; changes in legislation; the cost and efficiency of electricity, the price elasticity of demand,construction labor, equipment, and materials; project scope and design changes; storm impacts; and the ratecost of economiccapital. 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 15 to the financial statements under "Southern Power" in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding Southern Power's plant acquisitions and construction projects.
The construction program also includes Plant Vogtle Units 3 and 4, which includes components based on new technology that only recently began initial operation in the global nuclear industry at this scale and which may be subject to additional revised cost estimates during construction. The ability to control costs and avoid cost and schedule overruns during the development, construction, and operation of new facilities is subject to a number of factors, including, but not limited to, changes in labor costs, availability, and productivity; challenges with management of contractors, subcontractors, or decline in Georgia Power's service territory. Demandvendors; adverse weather conditions; shortages, delays, increased costs, or inconsistent quality of equipment, materials, and labor; contractor or supplier delay; 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 the timely submittal by Southern Nuclear of the ITAAC documentation for electricity is primarily driveneach unit and the related reviews and approvals by the paceNRC necessary to support NRC authorization to load fuel; challenges with start-up activities, including major equipment failure, system integration, or regional transmission upgrades; and/or operational performance. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of economicthe Form 10-K and Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for information regarding Plant Vogtle Units 3 and 4 and additional factors that may impact construction expenditures.
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. The amount and timing of additional equity and debt issuances in 2019, as well as in subsequent years, will be contingent on Southern
GEORGIASOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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, borrowings from financial institutions, and equity contributions or loans from Southern Company. Southern Power also plans to utilize tax equity partnership contributions, as well as funds resulting from its pending asset sale. 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. Also see Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding the pending sale of Plant Mankato.
In addition, in 2014, Georgia Power entered into a loan guarantee agreement with the DOE and, in March 2019, entered into the Amended and Restated Loan Guarantee Agreement, 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 Amended and Restated Loan Guarantee Agreement, the DOE has agreed to guarantee the obligations of Georgia Power under note purchase agreements among the DOE, Georgia Power, and the FFB and related promissory notes which provide for two multi-advance term loan facilities, under which Georgia Power may make term loan borrowings through the FFB in an amount up to approximately $5.130 billion, provided that certain conditions are met. At June 30, 2019, Georgia Power had borrowed $3.46 billion under the FFB Credit Facilities. See Notes (B) and (F) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" and "DOE Loan Guarantee Borrowings," respectively, herein for additional information.
Southern Company's current liabilities frequently exceed current assets because of scheduled maturities of long-term debt and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs. As of June 30, 2019, Southern Company's current liabilities exceeded current assets by $2.6 billion, primarily due to long-term debt that is due within one year and notes payable totaling $4.5 billion (including approximately $0.9 billion at the parent company, $1.5 billion at Georgia Power, $0.3 billion at Mississippi Power, $0.9 billion at Southern Power, and $0.8 billion at Southern Company Gas), partially offset by $1.4 billion of cash and cash equivalents. 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.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Committed credit arrangements with banks at June 30, 2019 were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Expires | | | | |
| Company | 2019 | 2020 | 2022 | 2024 | | Total | | Unused | | Due within One Year |
| | (in millions) |
Southern Company(a) | $ | — |
| $ | — |
| $ | — |
| $ | 2,000 |
| | $ | 2,000 |
| | $ | 1,999 |
| | $ | — |
|
| Alabama Power | 3 |
| 500 |
| — |
| 800 |
| | 1,303 |
| | 1,303 |
| | 3 |
|
| Georgia Power | — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,736 |
| | — |
|
| Mississippi Power | — |
| — |
| 150 |
| — |
| | 150 |
| | 150 |
| | — |
|
Southern Power(b) | — |
| — |
| — |
| 600 |
| | 600 |
| | 561 |
| | — |
|
Southern Company Gas(c) | — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,745 |
| | — |
|
| Other | — |
| 30 |
| — |
| — |
| | 30 |
| | 30 |
| | 30 |
|
| Southern Company Consolidated | $ | 3 |
| $ | 530 |
| $ | 150 |
| $ | 6,900 |
| | $ | 7,583 |
| | $ | 7,524 |
| | $ | 33 |
|
| |
| (a) | Represents the Southern Company parent entity. |
| |
| (b) | Does not include Southern Power Company's $120 million continuing letter of credit facility for standby letters of credit expiring in 2021, of which $30 million was unused at June 30, 2019. Southern Power's subsidiaries are not parties to its bank credit arrangement. |
| |
| (c) | 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. |
See 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.
Most of these bank credit arrangements, as well as the term loan arrangements of Alabama Power, Georgia Power, and SEGCO, contain covenants that limit debt levels and contain cross-acceleration or cross-default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of the individual company. Such cross-default provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness or guarantee obligations over a specified threshold. Such cross-acceleration provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness, the payment of which was then accelerated. At June 30, 2019, Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, 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 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 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, Nicor Gas, and SEGCO. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of June 30, 2019 was approximately $1.4 billion. In addition, at June 30, 2019, the traditional electric operating companies had approximately $272 million of revenue bonds outstanding that are required to be remarketed within the next 12 months.
Southern Company, Alabama Power, Georgia Power, Southern Power Company, Southern Company Gas, 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. 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 June 30, 2019 | | 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 | | $ | 1,148 |
| | 2.6 | % | | $ | 1,173 |
| | 2.8 | % | | $ | 1,562 |
|
| Short-term bank debt | | 250 |
| | 2.9 | % | | 127 |
| | 3.0 | % | | 250 |
|
| Total | | $ | 1,398 |
| | 2.7 | % | | $ | 1,300 |
| | 2.8 | % | | |
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2019. |
Southern Company believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, bank term loans, and operating cash flows.
Credit Rating Risk
At June 30, 2019, Southern Company and its subsidiaries did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain subsidiaries to BBB and/or Baa2 or below. These contracts are for physical electricity and natural gas purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, interest rate management, and construction of new generation at Plant Vogtle Units 3 and 4.
The maximum potential collateral requirements under these contracts at June 30, 2019 were as follows:
|
| | | |
| Credit Ratings | Maximum Potential
Collateral
Requirements |
| | (in millions) |
| At BBB and/or Baa2 | $ | 30 |
|
| At BBB- and/or Baa3 | $ | 433 |
|
At BB+ and/or Ba1(*) | $ | 1,935 |
|
| |
| (*) | 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.
As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries may be negatively impacted. Southern Company and most of its regulated subsidiaries have taken actions to mitigate the resulting impacts, which, among other alternatives, include adjusting capital structure. Absent actions by Southern Company and its subsidiaries that fully mitigate the impacts, the credit ratings of Southern Company and certain of its subsidiaries could be negatively affected. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information related to state PSC or other regulatory agency actions, including approvals and requests for additional or continued adjustments of capital structure related to the Tax Reform Legislation for Alabama Power, Georgia Power, Atlanta Gas Light, and Nicor Gas, which are expected to help mitigate the potential adverse impacts to certain of their credit metrics.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Financing Activities
During the first six months of 2019, Southern Company issued approximately 11.5 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $452 million.
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first six months of 2019:
|
| | | | | | | | | | | | | | | | | | | |
| Company | Senior Note Maturities, Redemptions, and Repurchases | | Revenue Bond Issuances and Reofferings of Purchased Bonds | | Revenue Bond Maturities, Redemptions, and Repurchases | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(a) |
| | (in millions) |
Southern Company(b) | $ | 2,100 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Alabama Power | 200 |
| | — |
| | — |
| | — |
| | — |
|
| Georgia Power | — |
| | 513 |
| | 223 |
| | 835 |
| | 3 |
|
| Mississippi Power | — |
| | 43 |
| | — |
| | — |
| | — |
|
| Other | — |
| | — |
| | 25 |
| | — |
| | 9 |
|
| Southern Company Consolidated | $ | 2,300 |
| | $ | 556 |
| | $ | 248 |
| | $ | 835 |
| | $ | 12 |
|
| |
| (a) | Includes reductions in finance lease obligations resulting from cash payments under finance leases. |
| |
| (b) | Represents the Southern Company parent entity. |
Except as otherwise described herein, Southern Company and its subsidiaries used the proceeds of debt issuances for their redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including working capital. The subsidiaries also used the proceeds for their construction programs.
In January 2019, Southern Company repaid a $250 million short-term uncommitted bank credit arrangement and a $1.5 billion short-term floating rate bank loan.
Also in January 2019, through cash tender offers, Southern Company repurchased and retired approximately $522 million of the $1.0 billion aggregate principal amount outstanding of its 1.85% Senior Notes due July 1, 2019 (1.85% Notes), approximately $180 million of the $350 million aggregate principal amount outstanding of its Series 2014B 2.15% Senior Notes due September 1, 2019 (Series 2014B Notes), and approximately $504 million of the $750 million aggregate principal amount outstanding of its Series 2018A Floating Rate Notes due February 14, 2020 (Series 2018A Notes), for an aggregate purchase price, excluding accrued and unpaid interest, of approximately $1.2 billion. In addition, following the completion of the cash tender offers, in February 2019, Southern Company completed the redemption of all of the Series 2018A Notes, 1.85% Notes, and Series 2014B Notes remaining outstanding.
As reflected in the table above, in March 2019, Georgia Power made additional borrowings under the FFB Credit Facilities in an aggregate principal amount of $835 million at an interest rate of 3.213% through the final maturity date of February 20, 2044. The proceeds were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4.
In June 2019, Georgia Power entered into two short-term floating rate bank loans in aggregate principal amounts of $125 million each, both of which bear interest based on one-month LIBOR.
In May 2019, Southern Power repaid at maturity a $100 million aggregate principal amount short-term bank loan.
Subsequent to June 30, 2019, Nicor Gas repaid at maturity $50 million aggregate principal amount of 4.7% first mortgage bonds due July 30, 2019.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company and its subsidiaries plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
PART I
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
During the six months ended June 30, 2019, 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 Southern Company Gas, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company Gas 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 under "Financial Instruments" and Notes 13 and 14 to the financial statements in Item 8 of the Form 10-K. Also see Notes (I) and (J) 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, 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, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended) during the second quarter 2019 that have materially affected or are reasonably likely to materially affect Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting.
ALABAMA POWER COMPANY
ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months
Ended June 30, | | For the Six Months
Ended June 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
| | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | |
| Retail revenues | $ | 1,378 |
| | $ | 1,338 |
| | $ | 2,592 |
| | $ | 2,624 |
|
| Wholesale revenues, non-affiliates | 62 |
| | 65 |
| | 123 |
| | 139 |
|
| Wholesale revenues, affiliates | 4 |
| | 31 |
| | 63 |
| | 82 |
|
| Other revenues | 69 |
| | 69 |
| | 143 |
| | 131 |
|
| Total operating revenues | 1,513 |
| | 1,503 |
| | 2,921 |
| | 2,976 |
|
| Operating Expenses: | | | | | | | |
| Fuel | 252 |
| | 347 |
| | 553 |
| | 672 |
|
| Purchased power, non-affiliates | 47 |
| | 48 |
| | 84 |
| | 113 |
|
| Purchased power, affiliates | 69 |
| | 43 |
| | 90 |
| | 80 |
|
| Other operations and maintenance | 402 |
| | 402 |
| | 812 |
| | 788 |
|
| Depreciation and amortization | 200 |
| | 189 |
| | 399 |
| | 379 |
|
| Taxes other than income taxes | 98 |
| | 94 |
| | 200 |
| | 192 |
|
| Total operating expenses | 1,068 |
| | 1,123 |
| | 2,138 |
| | 2,224 |
|
| Operating Income | 445 |
| | 380 |
| | 783 |
| | 752 |
|
| Other Income and (Expense): | | | | | | | |
| Allowance for equity funds used during construction | 14 |
| | 14 |
| | 28 |
| | 27 |
|
| Interest expense, net of amounts capitalized | (82 | ) | | (80 | ) | | (165 | ) | | (158 | ) |
| Other income (expense), net | 11 |
| | 12 |
| | 25 |
| | 15 |
|
| Total other income and (expense) | (57 | ) | | (54 | ) | | (112 | ) | | (116 | ) |
| Earnings Before Income Taxes | 388 |
| | 326 |
| | 671 |
| | 636 |
|
| Income taxes | 89 |
| | 64 |
| | 151 |
| | 145 |
|
| Net Income | 299 |
| | 262 |
| | 520 |
| | 491 |
|
| Dividends on Preferred Stock | 3 |
| | 3 |
| | 7 |
| | 7 |
|
| Net Income After Dividends on Preferred Stock | $ | 296 |
| | $ | 259 |
| | $ | 513 |
| | $ | 484 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months
Ended June 30, | | For the Six Months
Ended June 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
| | (in millions) | | (in millions) |
| Net Income | $ | 299 |
| | $ | 262 |
| | $ | 520 |
| | $ | 491 |
|
| 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 |
|
| Total other comprehensive income (loss) | 1 |
| | 1 |
| | 2 |
| | 2 |
|
| Comprehensive Income | $ | 300 |
| | $ | 263 |
| | $ | 522 |
| | $ | 493 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
|
| | | | | | | |
| | For the Six Months
Ended June 30, |
| | 2019 | | 2018 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 520 |
| | $ | 491 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 493 |
| | 452 |
|
| Deferred income taxes | 138 |
| | 48 |
|
| Allowance for equity funds used during construction | (28 | ) | | (27 | ) |
| Pension, postretirement, and other employee benefits | (13 | ) | | (28 | ) |
| Settlement of asset retirement obligations | (43 | ) | | (19 | ) |
| Other, net | (1 | ) | | (21 | ) |
| Changes in certain current assets and liabilities — | | | |
| -Receivables | 6 |
| | (153 | ) |
| -Prepayments | (59 | ) | | (57 | ) |
| -Materials and supplies | 5 |
| | (47 | ) |
| -Other current assets | (10 | ) | | 29 |
|
| -Accounts payable | (246 | ) | | (196 | ) |
| -Accrued taxes | 8 |
| | 134 |
|
| -Accrued compensation | (88 | ) | | (70 | ) |
| -Other current liabilities | 13 |
| | 116 |
|
| Net cash provided from operating activities | 695 |
| | 652 |
|
| Investing Activities: | | | |
| Property additions | (833 | ) | | (997 | ) |
| Nuclear decommissioning trust fund purchases | (139 | ) | | (131 | ) |
| Nuclear decommissioning trust fund sales | 139 |
| | 131 |
|
| Cost of removal, net of salvage | (48 | ) | | (34 | ) |
| Change in construction payables | (103 | ) | | (29 | ) |
| Other investing activities | (18 | ) | | (15 | ) |
| Net cash used for investing activities | (1,002 | ) | | (1,075 | ) |
| Financing Activities: | | | |
| Proceeds — | | | |
| Senior notes | — |
| | 500 |
|
| Capital contributions from parent company | 1,254 |
| | 488 |
|
| Redemptions — Senior notes | (200 | ) | | — |
|
| Payment of common stock dividends | (422 | ) | | (402 | ) |
| Other financing activities | (15 | ) | | (21 | ) |
| Net cash provided from financing activities | 617 |
| | 565 |
|
| Net Change in Cash, Cash Equivalents, and Restricted Cash | 310 |
| | 142 |
|
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 313 |
| | 544 |
|
| Cash, Cash Equivalents, and Restricted Cash at End of Period | $ | 623 |
| | $ | 686 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid during the period for — | | | |
| Interest (net of $10 and $10 capitalized for 2019 and 2018, respectively) | $ | 154 |
| | $ | 143 |
|
| Income taxes, net | 63 |
| | 17 |
|
| Noncash transactions — Accrued property additions at end of period | 168 |
| | 216 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At June 30, 2019 | | At December 31, 2018 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 623 |
| | $ | 313 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 432 |
| | 403 |
|
| Unbilled revenues | | 173 |
| | 150 |
|
| Affiliated | | 38 |
| | 94 |
|
| Other accounts and notes receivable | | 55 |
| | 51 |
|
| Accumulated provision for uncollectible accounts | | (10 | ) | | (10 | ) |
| Fossil fuel stock | | 143 |
| | 141 |
|
| Materials and supplies | | 530 |
| | 546 |
|
| Prepaid expenses | | 170 |
| | 66 |
|
| Other regulatory assets | | 204 |
| | 137 |
|
| Other current assets | | 26 |
| | 18 |
|
| Total current assets | | 2,384 |
| | 1,909 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 29,070 |
| | 30,402 |
|
| Less: Accumulated provision for depreciation | | 9,397 |
| | 9,988 |
|
| Plant in service, net of depreciation | | 19,673 |
| | 20,414 |
|
| Nuclear fuel, at amortized cost | | 322 |
| | 324 |
|
| Construction work in progress | | 1,097 |
| | 1,113 |
|
| Total property, plant, and equipment | | 21,092 |
| | 21,851 |
|
| Other Property and Investments: | | | | |
| Equity investments in unconsolidated subsidiaries | | 64 |
| | 65 |
|
| Nuclear decommissioning trusts, at fair value | | 964 |
| | 847 |
|
| Miscellaneous property and investments | | 129 |
| | 127 |
|
| Total other property and investments | | 1,157 |
| | 1,039 |
|
| Deferred Charges and Other Assets: | | | | |
| Operating lease right-of-use assets, net of amortization | | 152 |
| | — |
|
| Deferred charges related to income taxes | | 240 |
| | 240 |
|
| Deferred under recovered regulatory clause revenues | | 25 |
| | 116 |
|
| Regulatory assets – asset retirement obligations | | 1,016 |
| | 147 |
|
| Other regulatory assets, deferred | | 1,824 |
| | 1,240 |
|
| Other deferred charges and assets | | 177 |
| | 188 |
|
| Total deferred charges and other assets | | 3,434 |
| | 1,931 |
|
| Total Assets | | $ | 28,067 |
| | $ | 26,730 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholder's Equity | | At June 30, 2019 | | At December 31, 2018 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 1 |
| | $ | 201 |
|
| Accounts payable — | | | | |
| Affiliated | | 321 |
| | 364 |
|
| Other | | 334 |
| | 614 |
|
| Customer deposits | | 98 |
| | 96 |
|
| Accrued taxes | | 102 |
| | 44 |
|
| Accrued interest | | 88 |
| | 89 |
|
| Accrued compensation | | 140 |
| | 227 |
|
| Asset retirement obligations | | 156 |
| | 163 |
|
| Other current liabilities | | 155 |
| | 161 |
|
| Total current liabilities | | 1,395 |
| | 1,959 |
|
| Long-term Debt | | 7,926 |
| | 7,923 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 3,117 |
| | 2,962 |
|
| Deferred credits related to income taxes | | 2,006 |
| | 2,027 |
|
| Accumulated deferred ITCs | | 103 |
| | 106 |
|
| Employee benefit obligations | | 309 |
| | 314 |
|
| Operating lease obligations | | 137 |
| | — |
|
| Asset retirement obligations, deferred | | 3,389 |
| | 3,047 |
|
| Other cost of removal obligations | | 464 |
| | 497 |
|
| Other regulatory liabilities | | 69 |
| | 69 |
|
| Other deferred credits and liabilities | | 32 |
| | 58 |
|
| Total deferred credits and other liabilities | | 9,626 |
| | 9,080 |
|
| Total Liabilities | | 18,947 |
| | 18,962 |
|
| Redeemable Preferred Stock | | 291 |
| | 291 |
|
Common Stockholder's Equity (See accompanying statements) | | 8,829 |
| | 7,477 |
|
| Total Liabilities and Stockholder's Equity | | $ | 28,067 |
| | $ | 26,730 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA 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, 2017 | 31 |
| | $ | 1,222 |
| | $ | 2,986 |
| | $ | 2,647 |
| | $ | (26 | ) | | $ | 6,829 |
|
Net income after dividends on
preferred stock | — |
| | — |
| | — |
| | 225 |
| | — |
| | 225 |
|
| Capital contributions from parent company | — |
| | — |
| | 488 |
| | — |
| | — |
| | 488 |
|
| Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
| Cash dividends on common stock | — |
| | — |
| | — |
| | (202 | ) | | — |
| | (202 | ) |
| Other | — |
| | — |
| | — |
| | — |
| | (6 | ) | | (6 | ) |
| Balance at March 31, 2018 | 31 |
| | 1,222 |
| | 3,474 |
| | 2,670 |
| | (31 | ) | | 7,335 |
|
Net income after dividends on
preferred stock | — |
| | — |
| | — |
| | 259 |
| | — |
| | 259 |
|
| Capital contributions from parent company | — |
| | — |
| | 5 |
| | — |
| | — |
| | 5 |
|
| Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
| Cash dividends on common stock | — |
| | — |
| | — |
| | (200 | ) | | — |
| | (200 | ) |
| Other | — |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
| Balance at June 30, 2018 | 31 |
| | $ | 1,222 |
| | $ | 3,480 |
| | $ | 2,729 |
| | $ | (30 | ) | | $ | 7,401 |
|
| | | | | | | | | | | | |
| 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 (loss) | — |
| | — |
| | — |
| | — |
| | 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 (loss) | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
| Cash dividends on common stock | — |
| | — |
| | — |
| | (211 | ) | | — |
| | (211 | ) |
| Balance at June 30, 2019 | 31 |
| | $ | 1,222 |
| | $ | 4,767 |
| | $ | 2,866 |
| | $ | (26 | ) | | $ | 8,829 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
growth that may be affected by changesSECOND QUARTER 2019 vs. SECOND QUARTER 2018
AND
YEAR-TO-DATE 2019 vs. YEAR-TO-DATE 2018
OVERVIEW
Alabama Power operates as a vertically integrated utility providing electric service to retail and wholesale customers within its traditional service territory located in regionalthe State of Alabama in addition to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and global economic conditions, which may impact future earnings.
Current proposalsrisks 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 customers, and to effectively manage and secure timely recovery of costs. These costs include those related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% ofprojected long-term demand growth, stringent environmental standards, including CCR rules, reliability, fuel, capital expenditures, including improving the electric transmission and distribution systems, and restoration following major storms. Alabama Power has various regulatory mechanisms that operate to be deducted,address cost recovery. Effectively operating pursuant to these regulatory mechanisms and eliminatingappropriately balancing required costs and capital expenditures with customer prices will continue to challenge Alabama Power for the interest deduction.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 stock.
RESULTS OF OPERATIONS
Net Income
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) |
| (% change) |
| (change in millions) |
| (% change) |
| $37 | | 14.3 | | $29 | | 6.0 |
Alabama Power's net income after dividends on preferred stock for the second quarter 2019 was $296 million compared to $259 million for the corresponding period in 2018. The ultimate impactincrease was primarily related to an increase in retail revenues associated with the impacts of any tax reform proposals, including any potential changescustomer bill credits issued in 2018 related to the availability of nuclear PTCs, is dependentTax Reform Legislation, as well as additional capital investments recovered through Rate CNP Compliance, partially offset by a decrease in retail revenues associated with customer usage.
Alabama Power's net income after dividends on preferred stock for year-to-date 2019 was $513 million compared to $484 million for 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 FACTORScorresponding period 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 costs2018. This increase was primarily related to federalan increase in retail revenues associated with the impacts of customer bill credits issued in 2018 related to the Tax Reform Legislation, as well as additional capital investments recovered through Rate CNP Compliance. This increase was partially offset by decreases in retail revenues associated with milder weather and state environmental statutes and regulations could affect earnings if such costs cannot continuelower customer usage as well as increases 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 stateexpenses 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. depreciation.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Georgia Power in Item 7 and Note 32 to the financial statements of Georgiaunder "Alabama Power under "Environmental Matters"– Rate RSE" 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. 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 Georgia 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.
GEORGIAALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
On June 27, 2017,Retail Revenues
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $40 | | 3.0 | | $(32) | | (1.2) |
In the EPA andsecond quarter 2019, retail revenues were $1.38 billion compared to $1.34 billion for the U.S. Army Corps of Engineers proposedcorresponding period in 2018. For year-to-date 2019, retail revenues were $2.59 billion compared to rescind$2.62 billion for the final rule that revised the regulatory definition of waterscorresponding period in 2018.
Details of the U.S. for all CWA programs. The final rule has been stayed since October 2015 bychanges in retail revenues were as follows:
|
| | | | | | | | | | | | | |
| | Second Quarter 2019 |
| Year-to-Date 2019 |
| | (in millions) |
| (% change) |
| (in millions) |
| (% change) |
| Retail – prior year | $ | 1,338 |
| | | | $ | 2,624 |
| | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 62 |
| | 4.7 | % | | 96 |
| | 3.7 | % |
| Sales decline | (15 | ) | | (1.1 | ) | | (31 | ) | | (1.2 | ) |
| Weather | 6 |
| | 0.4 |
| | (19 | ) | | (0.7 | ) |
| Fuel and other cost recovery | (13 | ) | | (1.0 | ) | | (78 | ) | | (3.0 | ) |
| Retail – current year | $ | 1,378 |
| | 3.0 | % | | $ | 2,592 |
| | (1.2 | )% |
Revenues associated with changes in rates and pricing increased in 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 Georgia Power in Item 7 of the Form 10-K for additional information.
On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA to review the Clean Power Plansecond quarter 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 oryear-to-date 2019 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 Georgia 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 Georgia 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 Georgia Power) and Southern Power to their market-based rate tariff. While the FERC's order references 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, the FERC issued an order in responsecompared to the traditional electric operating companies' (including Georgia Power's) and Southern Power's June 30, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including Georgia Power) and Southern Power to show cause within 60 days why market-based rate authority should not be revokedcorresponding periods in certain areas adjacent2018 primarily due 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 Georgia Power) and Southern Power expect to make a filing within the specified 60 days responding to the FERC's order.
The ultimate outcomeimpacts of these matters cannot be determined at this time.
Retail Regulatory Matters
Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, ECCR tariffs, and Municipal Franchise Fee tariffs. In addition, financing costscustomer bill credits related to the construction of Plant Vogtle Units 3 and 4 are being collectedTax Reform Legislation in 2018, as well as additional capital investments recovered through the NCCR tariff and fuel costs are collected through a separate fuel cost recovery tariff.Rate CNP Compliance. See "Nuclear Construction" herein and Note 32 to the financial statements of Georgiaunder "Alabama Power under "Retail Regulatory Matters – Nuclear Construction"Rate RSE" and " – Rate CNP Compliance" in Item 8 of the Form 10-K for additional information regardinginformation.
Revenues attributable to changes in sales decreased in the NCCR tariff. Also see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIALsecond quarter and year-to-date 2019 when compared to the corresponding periods in 2018. Weather-adjusted residential KWH sales decreased 1.5% and 2.0% in the second quarter and year-to-date 2019, respectively, and weather-adjusted commercial KWH sales decreased 1.2% and 2.3% in the second quarter and year-to-date 2019, respectively, when compared to the corresponding periods in 2018. These decreases primarily resulted from customer initiatives in energy savings for commercial customers and more energy-efficient residential appliances. Industrial KWH sales decreased 3.2% and 3.1% in the second quarter and year-to-date 2019, respectively, when compared to the corresponding periods in 2018 as a result of a decrease in demand resulting from changes in production levels primarily in the primary metals and chemicals sectors for the second quarter 2019 and primary metals, chemicals, and paper sectors for year-to-date 2019.
Residential and commercial sales revenues decreased year-to-date 2019 by 1.2% and 0.7%, respectively, due to milder weather in the first quarter 2019 when compared to the corresponding period in 2018.
Fuel and other cost recovery revenues decreased in the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018 primarily due to a decrease in generation and 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 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.
GEORGIAALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale Revenues – Non-Affiliates
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(3) | | (4.6) | | $(16) | | (11.5) |
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.
For year-to-date 2019, wholesale revenues from sales to non-affiliates were $123 million compared to $139 million for the corresponding period in 2018. The decrease was primarily due to a 7.1% decrease in KWH sales as a result of lower demand and a 4.8% decrease in the price of energy due to lower natural gas prices in 2019 compared to the corresponding period in 2018.
Wholesale Revenues – Affiliates
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(27) | | (87.1) | | $(19) | | (23.2) |
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through Alabama Power's energy cost recovery clause.
In the second quarter 2019, wholesale revenues from sales to affiliates were $4 million compared to $31 million for the corresponding period in 2018. The decrease was primarily due to an 87.4% decrease in KWH sales as a result of decreased coal generation associated with the retirement of Plant Gorgas Units 8, 9, and 10 and a 6.7% decrease in the price of energy as a result of lower natural gas prices in the second quarter 2019 compared to the corresponding period in 2018.
For year-to-date 2019, wholesale revenues from sales to affiliates were $63 million compared to $82 million for the corresponding period in 2018. The decrease was primarily due to a 13.1% decrease in KWH sales as a result of decreased coal generation associated with the retirement of Plant Gorgas Units 8, 9, and 10 and an 11.0% decrease in the price of energy due to increased hydro generation in 2019 as compared to the corresponding period in 2018.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | | |
| | Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| | (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| Fuel | $ | (95 | ) | | (27.4) | | $ | (119 | ) | | (17.7 | ) |
| Purchased power – non-affiliates | (1 | ) | | (2.1) | | (29 | ) | | (25.7 | ) |
| Purchased power – affiliates | 26 |
| | 60.5 | | 10 |
| | 12.5 |
|
| Total fuel and purchased power expenses | $ | (70 | ) | | | | $ | (138 | ) | | |
In the second quarter 2019, fuel and purchased power expenses were $368 million compared to $438 million for the corresponding period in 2018. For year-to-date 2019, fuel and purchased power expenses were $727 million compared to $865 million for the corresponding period in 2018. These decreases were primarily related to the volume of KWHs generated (excluding hydro) 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 Alabama Power's energy cost recovery clause. See Note 2 to the financial statements under "Alabama Power – "Retail Regulatory Matters – Fuel Cost Recovery" of Georgia PowerRate ECR" in Item 78 of the Form 10-K for additional information regardinginformation.
Details of Alabama Power's generation and purchased power were as follows:
|
| | | | | | | |
| | Second Quarter 2019 | | Second Quarter 2018 | | Year-to-Date 2019 |
| Year-to-Date 2018 |
Total generation (in billions of KWHs) | 12 | | 15 | | 29 | | 31 |
Total purchased power (in billions of KWHs) | 3 | | 2 | | 4 | | 3 |
Sources of generation (percent) — | | | | | | | |
| Coal | 43 | | 53 | | 43 | | 52 |
| Nuclear | 26 | | 20 | | 24 | | 21 |
| Gas | 23 | | 20 | | 21 | | 19 |
| Hydro | 8 | | 7 | | 12 | | 8 |
Cost of fuel, generated (in cents per net KWH) — (a) | | | | | | | |
| Coal | 2.86 | | 2.79 | | 2.82 | | 2.74 |
| Nuclear | 0.78 | | 0.80 | | 0.78 | | 0.77 |
| Gas | 2.48 | | 2.51 | | 2.53 | | 2.69 |
Average cost of fuel, generated (in cents per net KWH)(a)(b) | 2.18 | | 2.31 | | 2.19 | | 2.27 |
Average cost of purchased power (in cents per net KWH)(c) | 4.01 | | 4.72 | | 4.45 | | 5.72 |
| |
| (a) | In the second quarter and year-to-date 2018, cost of fuel and average cost of fuel, generated exclude a $30 million adjustment in accordance with an Alabama PSC accounting order. See Note 2 to the financial statements under "Alabama Power – Tax Reform Accounting Order" in Item 8 of the Form 10-K for additional information. |
| |
| (b) | KWHs generated by hydro are excluded from the average cost of fuel, generated. |
| |
| (c) | 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 2019, fuel cost recovery.expense was $252 million compared to $347 million for the corresponding period in 2018. The decrease was primarily due to a 31.3% decrease in the volume of KWHs generated by coal and an 11.9% increase in the volume of KWHs generated by nuclear.
Renewables
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2019, fuel expense was $553 million compared to $672 million for the corresponding period in 2018. The decrease was primarily due to a 45.3% increase in the volume of KWHs generated by hydro, a 21.9% decrease in the volume of KWHs generated by coal, a 5.1% increase in the volume of KWHs generated by nuclear, and a 6.0% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements.
In addition, fuel expense increased $30 million in both the second quarter and year-to-date 2018 in accordance with an Alabama PSC accounting order authorizing the use of excess deferred income taxes to offset under recovered fuel costs (Tax Reform Accounting Order). See Note 2 to the financial statements under "Alabama Power – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Integrated Resource Plan" of Georgia PowerTax Reform Accounting Order" in Item 78 of the Form 10-K for additional information regarding renewableinformation.
Purchased Power – Non-Affiliates
For year-to-date 2019, purchased power expense from non-affiliates was $84 million compared to $113 million for the corresponding period in 2018. The decrease was primarily related to a 14.3% decrease in the average cost of purchased power per KWH due to lower natural gas prices and an 11.9% decrease in the amount of energy projects.purchased due to milder weather in the first quarter 2019 compared to the corresponding period in 2018.
On May 16, 2017,Energy purchases from non-affiliates will vary depending on the Georgia PSCmarket prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the second quarter 2019, purchased power expense from affiliates was $69 million compared to $43 million for the corresponding period in 2018. For year-to-date 2019, purchased power expense from affiliates was $90 million compared to $80 million for the corresponding period in 2018. These increases were primarily related to the availability of lower-cost generation compared to Alabama Power's owned generation and a decrease in coal generation as a result of the retirement of Plant Gorgas Units 8, 9, and 10.
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 Georgia Power's requestby the FERC.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $— | | — | | $24 | | 3.0 |
For year-to-date 2019, other operations and maintenance expenses were $812 million compared to build, own,$788 million for the corresponding period in 2018. This increase was primarily due to increases of $15 million in Rate CNP Compliance-related expenses and operate a 139-MW solar$13 million in steam generation facility at a U.S. Air Force base that is expectedcosts primarily due to be placedthe timing of outages.
Depreciation and Amortization
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $11 | | 5.8 | | $20 | | 5.3 |
In the second quarter 2019, depreciation and amortization was $200 million compared to $189 million for the corresponding period in 2018. For year-to-date 2019, depreciation and amortization was $399 million compared to $379 million for the corresponding period in 2018. These increases were primarily due to additional plant in service byassociated with steam, distribution, and transmission.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Income (Expense), Net
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(1) | | (8.3) | | $10 | | 66.7 |
For year-to-date 2019, other income (expense), net was $25 million compared to $15 million for 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 expectedcorresponding period in 2018. This increase was primarily due to be placedincreases in service in the fourth quarter 2017.interest income from temporary cash investments and non-service cost-related pension income.
The ultimate outcome of these matters cannot be determined at this time.
Integrated Resource PlanRegulatory Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Integrated Resource Plan" of Georgia PowerNote 2 to the financial statements in Item 78 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.
Fuel Cost Recovery
The traditional electric operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow. The traditional electric operating companies continuously monitor their under or over recovered fuel cost balances and make appropriate filings with their state PSCs to adjust fuel cost recovery rates as necessary.
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.
Environmental Accounting Order
On April 15, 2019, Alabama Power retired Plant Gorgas Units 8, 9, and 10 and reclassified approximately $654 million of the unrecovered asset balances to regulatory assets, which are being recovered over the units' remaining useful lives, the latest being through 2037, as established prior to the decision to retire. Additionally, approximately $700 million of net capitalized asset retirement costs were reclassified to a regulatory asset in accordance with accounting guidance provided by the Alabama PSC. The asset retirement costs are being recovered through 2055. See Note 2 to the financial statements under "Alabama Power – Environmental Accounting Order" and Note 6 in Item 8 of the Form 10-K for additional information regarding information.
Georgia Power
Georgia Power's triennial Integrated Resource Plan.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 (ECCR) tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to 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.
Rate Plans
On March 7, 2017,June 28, 2019, Georgia Power filed a base rate case (Georgia Power 2019 Base Rate Case) with the Georgia PSC. The filing includes a three-year Alternate Rate Plan with requested rate increases totaling $563 million, $145 million, and $234 million effective January 1, 2020, January 1, 2021, and January 1, 2022, respectively. These
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
increases are based on a proposed retail ROE of 10.90% and a proposed equity ratio of 56% and reflect levelized revenue requirements during the three-year period, with the exception of incremental compliance costs related to CCR AROs, Demand-Side Management programs, and adjustments to the Municipal Franchise Fee tariff.
Georgia Power has requested recovery of the proposed increases through its existing base rate tariffs as follows:
|
| | | | | | | | | |
| Tariff | 2020 | 2021 | 2022 |
| | (in millions) |
| Traditional base: | | | |
| Levelized | $ | 209 |
| $ | — |
| $ | — |
|
| CCR AROs | 158 |
| 140 |
| 227 |
|
| ECCR | 165 |
| — |
| — |
|
| Demand-Side Management | 14 |
| 2 |
| 1 |
|
| Municipal Franchise Fee | 17 |
| 3 |
| 5 |
|
Total(*) | $ | 563 |
| $ | 145 |
| $ | 234 |
|
| |
| (*) | Totals may not add due to rounding. |
Georgia Power's filing primarily reflects requests to (i) address the impacts of the Tax Reform Legislation, (ii) recover the costs of recent and future capital investments in infrastructure designed to maintain high levels of reliability and superior customer service with updated depreciation rates, (iii) recover substantial storm damage expenses incurred and deferred since 2013 along with a reasonable level of storm damage expenses expected to be incurred during the three years ending December 31, 2022, and (iv) recover the costs necessary to comply with federal and state regulations for CCR AROs. In addition, the filing includes the following provisions:
Continuation of an allowed retail ROE range of 10.00% to 12.00%.
Continuation of the process whereby two-thirds of any earnings above the top of the allowed ROE range are shared with Georgia Power's customers and the remaining one-third are retained by Georgia Power.
Continuation of the option to file an Interim Cost Recovery tariff in the event earnings are projected to fall below the bottom of the ROE range during the three-year term of the plan.
Georgia Power expects the Georgia PSC approved Georgia Power's decision to suspend work atissue a future generation sitefinal order 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.this matter on December 17, 2019. 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 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 rate case required to be filed by July 1, 2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Georgia Power's financial statements. See Note 1 to the financial statements of Georgia Power under "Storm Damage Recovery" in Item 8 of the Form 10-K for additional information regarding Georgia Power's storm damage reserve.
Nuclear Construction
See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the construction of Plant Vogtle Units 3 and 4, 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%.
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 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.
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
GEORGIA POWER COMPANY
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, 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.
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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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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
See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.
Fuel Cost Recovery
The traditional electric operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow. The traditional electric operating companies continuously monitor their under or over recovered fuel cost balances and make appropriate filings with their state PSCs to adjust fuel cost recovery rates as necessary.
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.
Environmental Accounting Order
On April 15, 2019, Alabama Power retired Plant Gorgas Units 8, 9, and 10 and reclassified approximately $654 million of the unrecovered asset balances to regulatory assets, which are being recovered over the units' remaining useful lives, the latest being through 2037, as established prior to the decision to retire. Additionally, approximately $700 million of net capitalized asset retirement costs were reclassified to a regulatory asset in accordance with accounting guidance provided by the Alabama PSC. The asset retirement costs are being recovered through 2055. See Note 2 to the financial statements under "Alabama Power – Environmental Accounting Order" and Note 6 in Item 8 of the Form 10-K for additional information.
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 (ECCR) tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to 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.
Rate Plans
On June 28, 2019, Georgia Power filed a base rate case (Georgia Power 2019 Base Rate Case) with the Georgia PSC. The filing includes a three-year Alternate Rate Plan with requested rate increases totaling $563 million, $145 million, and $234 million effective January 1, 2020, January 1, 2021, and January 1, 2022, respectively. These
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
increases are based on a proposed retail ROE of 10.90% and a proposed equity ratio of 56% and reflect levelized revenue requirements during the three-year period, with the exception of incremental compliance costs related to CCR AROs, Demand-Side Management programs, and adjustments to the Municipal Franchise Fee tariff.
Georgia Power has requested recovery of the proposed increases through its existing base rate tariffs as follows:
|
| | | | | | | | | |
| Tariff | 2020 | 2021 | 2022 |
| | (in millions) |
| Traditional base: | | | |
| Levelized | $ | 209 |
| $ | — |
| $ | — |
|
| CCR AROs | 158 |
| 140 |
| 227 |
|
| ECCR | 165 |
| — |
| — |
|
| Demand-Side Management | 14 |
| 2 |
| 1 |
|
| Municipal Franchise Fee | 17 |
| 3 |
| 5 |
|
Total(*) | $ | 563 |
| $ | 145 |
| $ | 234 |
|
| |
| (*) | Totals may not add due to rounding. |
Georgia Power's filing primarily reflects requests to (i) address the impacts of the Tax Reform Legislation, (ii) recover the costs of recent and future capital investments in infrastructure designed to maintain high levels of reliability and superior customer service with updated depreciation rates, (iii) recover substantial storm damage expenses incurred and deferred since 2013 along with a reasonable level of storm damage expenses expected to be incurred during the three years ending December 31, 2022, and (iv) recover the costs necessary to comply with federal and state regulations for CCR AROs. In addition, the filing includes the following provisions:
Continuation of an allowed retail ROE range of 10.00% to 12.00%.
Continuation of the process whereby two-thirds of any earnings above the top of the allowed ROE range are shared with Georgia Power's customers and the remaining one-third are retained by Georgia Power.
Continuation of the option to file an Interim Cost Recovery tariff in the event earnings are projected to fall below the bottom of the ROE range during the three-year term of the plan.
Georgia Power expects the Georgia PSC to issue a final order in this matter on December 17, 2019. The ultimate outcome of this matter cannot be determined at this time.
Integrated Resource Plan
In 2016, the Georgia PSC approved Georgia Power's triennial Integrated Resource Plan, including recovery of costs up to $99 million through June 30, 2019 to preserve nuclear generation as an option at a future generation site in Stewart County, Georgia. In 2017, the Georgia PSC approved Georgia Power's decision to suspend work at the site due to changing economics, including lower load forecasts and fuel costs. In accordance with the Georgia PSC's order, costs incurred of approximately $50 million have been recorded as a regulatory asset.
On July 16, 2019, the Georgia PSC voted to approve Georgia Power's triennial Integrated Resource Plan (2019 IRP) as modified by a stipulated agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors and further modified by the Georgia PSC.
In the 2019 IRP, the Georgia PSC approved the decertification and retirement of Plant Hammond Units 1 through 4 (840 MWs) and Plant McIntosh Unit 1 (142.5 MWs) effective July 29, 2019. The Georgia PSC also approved the reclassification of the remaining net book values of the Plant Hammond and Plant McIntosh units (approximately $500 million and $40 million, respectively, at June 30, 2019), as well as any unusable materials and supplies inventory balances, upon retirement to a regulatory asset. Recovery of each unit's net book value will continue through December 31, 2019 as provided in the 2013 ARP.
For the regulatory asset balances remaining at December 31, 2019, Georgia Power requested recovery in the Georgia Power 2019 Base Rate Case as follows: (i) the net book values of Plant Mitchell Unit 3 (approximately $8
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
million at June 30, 2019) and Plant McIntosh Unit 1, any unusable materials and supplies inventory, and the future generation site in Stewart County, Georgia over a three-year period ending December 31, 2022 and (ii) the net book values of Plant Hammond Units 1 through 4 over a period equal to the applicable unit's remaining useful life through 2035. The ultimate outcome of these matters cannot be determined at this time.
Also in the 2019 IRP, the Georgia PSC rejected a request to certify approximately 25 MWs of capacity at Plant Scherer Unit 3 for the retail jurisdiction beginning January 1, 2020 following the expiration of a wholesale PPA. Georgia Power may offer such capacity in the wholesale market or to the retail jurisdiction in a future Integrated Resource Plan. The ultimate outcome of this matter cannot be determined at this time but is not expected to have a material impact on Southern Company's financial statements.
Additionally, the Georgia PSC approved Georgia Power's proposed environmental compliance strategy associated with ash pond and certain landfill closures and post-closure care in compliance with the CCR Rule and the related state rule. In the Georgia Power 2019 Base Rate Case, Georgia Power requested recovery of the under recovered balance of these compliance costs at December 31, 2019 (approximately $135 million at June 30, 2019) over a three-year period ending December 31, 2022 and recovery of estimated compliance costs of $277 million for 2020, $395 million for 2021, and $655 million for 2022 over three-year periods ending December 31, 2022, 2023, and 2024, respectively. The ultimate outcome of this matter cannot be determined at this time. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information regarding Georgia Power's AROs.
The Georgia PSC also approved Georgia Power to (i) issue requests for proposals (RFP) for capacity beginning in 2022 or 2023 and in 2026, 2027, or 2028; (ii) procure up to an additional 2,210 MWs of renewable resources through competitive RFPs; and (iii) invest in a portfolio of up to 80 MWs of battery energy storage technologies.
See "Rate Plans" herein for additional information regarding the Georgia Power 2019 Base Rate Case.
Mississippi Power
Kemper County Energy Facility
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. 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 Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.
During the second quarter and year-to-date 2019, Mississippi Power recorded pre-tax charges to income of $4 million ($3 million after tax) and $6 million ($5 million after tax), respectively, primarily resulting from the abandonment and related closure activities and ongoing period costs, net of sales proceeds, for the mine and gasifier-related assets at the Kemper County energy facility. Additional closure costs for the mine and gasifier-related assets, currently estimated at up to $10 million pre-tax (excluding dismantlement costs, net of salvage), may be incurred through the first half of 2020. In addition, period costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the mine and gasifier-related assets, are estimated at $7 million for the remainder of 2019 and $2 million to $6 million annually in 2020 through 2023.
In addition, Mississippi Power constructed the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery and is currently evaluating its options regarding the final disposition of the CO2 pipeline, including removal of the pipeline. This evaluation is expected to be complete later in 2019. If Mississippi Power ultimately decides to remove the CO2 pipeline, the cost of removal could have a material impact on Southern Company's financial statements.
In December 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the $387 million of grants received. Mississippi Power and the DOE are currently in discussions regarding the requested closeout and property disposition, which may require payment to the DOE for a portion of certain property that is to be retained by Mississippi Power. In connection with the DOE closeout discussions, on April 29, 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
of an investigation related to the Kemper County energy facility. The ultimate outcome of these matters cannot be determined at this time; however, they could have a material impact on Southern Company's financial statements.
Southern Company Gas
The natural gas distribution utilities are subject to regulation and oversight by their respective state regulatory agencies for the rates charged 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 regulatory agencies in the states in which 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 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 and energy efficiency plans.
In November 2018, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $230 million increase in annual base rate revenues. The requested increase is based on a projected test year for the 12-month period ending September 30, 2020, a ROE of 10.6%, and an increase in the equity ratio from 52% to 54% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation.
On April 16, 2019, Nicor Gas entered into a stipulation agreement to resolve all related issues with the Staff of the Illinois Commission, including a ROE of 9.86% and an equity ratio of 54%. Also on April 16, 2019, Nicor Gas filed its rebuttal testimony with the Illinois Commission incorporating the stipulation agreement and addressing the remaining items outstanding with the other two intervenors. As a result of the stipulation agreement and rebuttal testimony, the revised requested annual revenue increase is $180 million.
The Illinois Commission is expected to rule on the requested increase by early October 2019, after which rate adjustments will be effective.
On June 3, 2019, Atlanta Gas Light filed a general base rate case with the Georgia PSC requesting a $96 million increase in annual base rate revenues. The requested increase is based on a forward-looking test year for the 12-month period ending July 31, 2020, a ROE of 10.75% with an earnings band based on a ROE between 10.55% and 10.95%, and a continued equity ratio of 55%. The filing also requests the continuation of the Georgia rate adjustment mechanism, as previously authorized. Atlanta Gas Light expects the Georgia PSC to issue a final order on this matter on December 19, 2019 with the new rates becoming effective January 1, 2020.
The ultimate outcome of these matters cannot be determined at this time.
Construction Program
Overview
The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue its strategy of developing and constructing new electric generating facilities, adding environmental modifications to certain existing units, expanding and improving the electric transmission and distribution systems, and updating and expanding the natural gas distribution systems. For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. Southern Company Gas is engaged in various infrastructure improvement programs designed to update or expand the natural gas distribution systems of the natural gas distribution utilities to improve reliability and meet operational flexibility and growth. The natural gas distribution utilities recover their investment and a return associated with these infrastructure programs through their regulated rates. See Notes 2 and
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
15 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" and "Southern Power," respectively, in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information.
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). See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K and "Nuclear Construction" herein for additional information.
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.
Nuclear Construction
See Note 2 to the financial statements under "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, the joint ownership agreements and related funding agreement, VCM reports, and the NCCR tariff.
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. Georgia Power holds a 45.7% ownership interest in Plant Vogtle Units 3 and 4. 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 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement. In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into several transitional arrangements to allow construction to continue. In July 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 time and materials cost basis. The Vogtle Services Agreement provides that it will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.
In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, executed the Bechtel Agreement, a cost reimbursable plus fee arrangement, whereby Bechtel is 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 the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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) | $ | 8.0 |
|
| Construction contingency estimate | 0.4 |
|
Total project capital cost forecast(a)(b) | 8.4 |
|
Net investment as of June 30, 2019(b) | (5.2 | ) |
Remaining estimate to complete(a) | $ | 3.2 |
|
| |
| (a) | Excludes financing costs expected to be capitalized through AFUDC of approximately $315 million. |
| |
| (b) | Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds. |
Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $2.0 billion had been incurred through June 30, 2019.
In April 2019, Southern Nuclear completed a cost and schedule validation process to verify and update quantities of commodities remaining to install, labor hours to install remaining quantities and related productivity, testing and system turnover requirements, and forecasted staffing needs and related costs. This process confirmed the estimated total project capital cost forecast for Plant Vogtle Units 3 and 4. The expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4, as previously approved by the Georgia PSC, remain unchanged.
As construction continues and testing and system turnover activities increase, challenges with management of contractors, subcontractors, and vendors; supervision of craft labor and related craft labor productivity, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, and/or installation and the initial testing and start-up, including any required engineering changes, of plant systems, structures, or components (some of which are based on new technology that only recently began initial operation in the global nuclear industry at this scale), or regional transmission upgrades, any of which may require additional labor and/or materials; or other issues could arise and change the projected schedule and estimated cost.
The April 2019 cost and schedule validation process established target values for monthly construction production and system turnover activities as part of a strategy to maintain and, where possible, build margin to the approved in-service dates. To support that strategy, monthly production and activity target values will continue to increase significantly throughout 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers (particularly electrical and pipefitter craft labor), as well as additional supervision and other field support resources, must be retained and deployed.
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. 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
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million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $12 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 entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 to provide for, among other conditions, additional Vogtle Owner approval requirements. Effective in August 2018, the 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 to continue construction (as amended, and together with the November 2017 amendment, the Vogtle Joint Ownership Agreements). The Vogtle Joint Ownership Agreements also confirm 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 the 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, 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) the Vogtle Owner Term Sheet with the other Vogtle Owners and MEAG's wholly-owned subsidiaries 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) the MEAG Term Sheet with MEAG and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. On January 14, 2019, Georgia Power, MEAG, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. On February 18, 2019, Georgia Power, the other Vogtle Owners, and MEAG'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.
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 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, 2017,2019, Georgia Power had recovered approximately $1.5$2.0 billion of financing costs. Financing costs related to capital costs above $4.418 billion will be recovered through AFUDC; 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 2018, the Georgia PSC approved Georgia Power's request to increase the NCCR tariff by approximately $90$88 million annually, effective January 1, 2018, pending2019.
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
On December 20,
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
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 $100 million in 2018 and are estimated to have negative earnings impacts of approximately $70 million in 2019 and an aggregate of approximately $630 million from 2020 to 2022.
TheIn 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 two appeals. On January 9, 2019, GIPL, PSE, and Georgia Watch filed an appeal of this decision with the Georgia Court of Appeals. Georgia Power believes the appeal has approved sixteen VCM reports coveringno merit; however, an adverse outcome in the periods through December 31, 2016, including construction capital costs incurred, which through that date totaled $3.9 billion.appeal combined with subsequent adverse action by the Georgia PSC could have a material impact on Southern Company's results of operations, financial condition, and liquidity.
In August 2018, Georgia Power filed its seventeenthnineteenth VCM report coveringwith the period from January 1 through June 30, 2017, requestingGeorgia PSC, which requested approval of $542$578 million of construction capital costs incurred during that period, withfrom January 1, 2018 through June 30, 2018. On February 19, 2019, the Georgia PSC on August 31, 2017.
Inapproved the seventeenthnineteenth VCM, report, Georgia Power recommended that constructionbut deferred approval 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.$51.6 million of expenditures related to Georgia Power's recommendation to go forward with completionportion of Vogtle Units 3 and 4 is based onan administrative claim filed in the following assumptions aboutWestinghouse bankruptcy proceedings. Through the regulatory treatment of this recommendation, ifnineteenth VCM, the recommendation to go forwardGeorgia PSC has approved total construction capital costs incurred through June
GEORGIA POWERSOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
is adopted30, 2018 of $5.4 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds).
On April 30, 2019, as requested by the staff of the Georgia PSC, Georgia Power reported the results of the cost and schedule validation process to the Georgia PSC. On August 30, 2019, Georgia Power will file its twentieth VCM report concurrently with its twenty-first VCM report with the Georgia PSC, which will reflect the capital cost forecast discussed previously and request approval of $1.2 billion of construction capital costs incurred from June 30, 2018 through June 30, 2019. In addition, on June 20, 2019, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a settlement agreement related to the administrative claim filed in the Westinghouse bankruptcy proceedings. Accordingly, in the twentieth/twenty-first VCM report, Georgia Power will also request approval of the $51.6 million of associated expenditures previously deferred 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.PSC.
The ultimate outcome of these matters cannot be determined at this time.
Revised Cost and Schedule
Georgia Power's approximate proportionate shareSee RISK FACTORS 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 PSCSouthern Company in the eventForm 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 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 existmajor incident at a nuclear facility anywhere 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 carryingworld.
DOE Financing
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 SeptemberAt June 30, 2017,2019, Georgia Power had borrowed $2.6$3.46 billion related to Plant Vogtle Units 3 and 4 costs as provided through the Amended and Restated Loan Guarantee Agreement and arelated multi-advance credit facilityfacilities among Georgia Power, the DOE, and the FFB, which providesprovide for borrowings of up to $3.46approximately $5.130 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 68 to the financial statements of Georgia Power under "DOE"Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (E)(F) 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 IRSultimate outcome of these matters cannot be determined at this time.
Other Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Southern Company in Item 7 for additional information.
Southern Company and its subsidiaries are involved in various other matters that could affect future earnings, including matters being litigated, as well as other regulatory matters and matters that could result in asset impairments. 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 laws and regulations governing air, water, land, and protection of other natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations, has allocated PTCsoccurred 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, regulatory matters, or potential asset impairments cannot be determined at this time; however, for current proceedings not specifically reported 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 Southern Company's financial statements. See Notes (B) and (C) 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.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Litigation
In January 2017, a putative 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 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 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 March 2018, the court issued an order granting, in part, the defendants' motion to dismiss. The court dismissed certain claims against certain officers of Southern Company and Mississippi Power and dismissed the allegations related to a number of the statements that plaintiffs challenged as being false or misleading. In April 2018, the defendants filed a motion for reconsideration of the court's order, seeking dismissal of the remaining claims in the lawsuit. In August 2018, the court denied the motion for reconsideration and denied a motion to certify the issue for interlocutory appeal.
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 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 April 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 putative 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 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 May 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 putative securities class action.
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 approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest. In the first quarter 2019, Mississippi Power and Southern Company filed motions to dismiss, which were denied by the arbitration panel on May 10, 2019.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 tort law claims. In 2016, the Georgia Court of Appeals reversed the trial court's previous dismissal of the case and remanded the case to the trial court. Georgia Power filed a petition for writ of certiorari with the Georgia Supreme Court, which was granted in 2017. In June 2018, the Georgia Supreme Court affirmed the judgment of the Georgia Court of Appeals and remanded the case to the trial court for further proceedings. Following a motion by Georgia Power, on February 13, 2019, the Superior Court of Fulton County ordered the parties to submit petitions to the Georgia PSC for a declaratory ruling to address certain terms the court previously held were ambiguous as used in the Georgia PSC's orders. The order entered by the Superior Court of Fulton County 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. Georgia Power also filed a notice of appeal with the Georgia Court of Appeals regarding the Superior Court of Fulton County's February 2019 order. The amount of any possible losses cannot be calculated at this time because, among other factors, it is unknown whether conditional class certification will be upheld and the ultimate composition of any class and whether any losses would be subject to recovery from any municipalities.
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. The ultimate outcome of these matters cannot be determined at this time.
Mississippi Power
In conjunction with Southern Company's sale of Gulf Power, Mississippi Power and Gulf Power have committed to seek a restructuring of their 50% undivided ownership interests in Plant Daniel such that each of them would, after the restructuring, own 100% of a generating unit. On January 15, 2019, Gulf Power provided notice to Mississippi Power that Gulf Power will retire its share of the generating capacity of Plant Daniel on January 15, 2024. Mississippi Power has the option to purchase Gulf Power's ownership interest for $1 on January 15, 2024, provided that Mississippi Power exercises the option no later than 120 days prior to that date. Mississippi Power is assessing the potential operational and economic effects of Gulf Power's notice. The ultimate outcome of these matters remains subject to completion of Mississippi Power's evaluations and applicable regulatory approvals, including by the FERC and the Mississippi PSC, and cannot be determined at this time. See Note (K) to the Condensed Financial Statements under "Southern Company" herein for information regarding the sale of Gulf Power.
Southern Company Gas
See Note 3 to the financial statements in Item 8 of the Form 10-K under "Other Matters – Southern Company Gas" for information on a natural gas storage facility consisting of two salt dome caverns in Louisiana. The future performance of this facility, as well as Southern Company Gas' two other natural gas storage facilities located in California and Texas, could be impacted by ongoing changes in the U.S. natural gas storage market. Recent sales of natural gas storage facilities have resulted in losses for the sellers and may imply an impact on future rates and/or asset values. Southern Company Gas is evaluating these recent market transactions for impacts on its plans to return one of the salt dome caverns in Louisiana back to service in 2021. Sustained diminished natural gas storage values could trigger impairment of one or all of these natural gas storage facilities, which have a combined net book value of $438 million at June 30, 2019. The ultimate outcome of these matters cannot be determined at this time, but could have a material impact on Southern Company's financial statements.
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 Notes 1, 5, and 6 to the financial statements 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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
Recently Issued Accounting Standards
See Note (A) to the Condensed Financial Statements herein for information regarding Southern Company's recently adopted accounting standards.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company in Item 7 of the Form 10-K for additional information. Southern Company's financial condition remained stable at June 30, 2019. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $2.5 billion for the first six months of 2019, a decrease of $0.7 billion from the corresponding period in 2018. The decrease in net cash provided from operating activities was primarily due to the timing of vendor payments and the impacts of the Gulf Power disposition and the Southern Company Gas Dispositions. Net cash provided from investing activities totaled $1.0 billion for the first six months of 2019 primarily due to proceeds from the sale of Gulf Power, partially offset by the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities and capital expenditures for Southern Company Gas' infrastructure replacement programs. Net cash used for financing activities totaled $3.6 billion for the first six months of 2019 primarily due to repayments of short-term bank debt, net redemptions and repurchases of long-term debt, and common stock dividend payments. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities. See Notes (F) and (K) to the Condensed Financial Statements herein for additional information.
Significant balance sheet changes for the first six months of 2019 include:
decreases in assets and liabilities held for sale of $5.0 billion and $3.2 billion, respectively, primarily related to the sale of Gulf Power;
an increase of $2.1 billion in total stockholders' equity primarily related to the gain on the sale of Gulf Power;
| |
| • | operating lease right-of-use assets, net of amortization and operating lease obligations, each totaling $1.9 billion, recorded upon the adoption of FASB ASC Topic 842, Leases; |
an increase of $1.7 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, partially offset by Alabama Power's reclassification of $1.4 billion to regulatory assets related to the retirement of Plant Gorgas, including $0.7 billion associated with AROs;
decreases of $1.5 billion in notes payable and $1.1 billion in long-term debt (including amounts due within one year) related to net repayments of short-term bank debt and long-term debt, respectively; and
an increase of $1.2 billion in accumulated deferred income taxes primarily related to the expected utilization of tax credit carryforwards in the 2019 tax year as a result of increased taxable income from the sale of Gulf Power.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Alabama Power" herein and Notes (A), (B), (F), (G), (K), and (L) to the Condensed Financial Statements herein for additional information.
At the end of the second quarter 2019, the market price of Southern Company's common stock was $55.28 per share (based on the closing price as reported on the NYSE) and the book value was $25.73 per share, representing a market-to-book ratio of 215%, compared to $43.92, $23.91, and 184%, respectively, at the end of 2018. Southern Company's common stock dividend for the second quarter 2019 was $0.62 per share compared to $0.60 per share in the second quarter 2018.
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 and contractual obligations. Approximately $3.1 billion will be required through June 30, 2020 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 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; 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 15 to the financial statements under "Southern Power" in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding Southern Power's plant acquisitions and construction projects.
The construction program also includes Plant Vogtle Units 3 and 4, which includes components based on new technology that only recently began initial operation in the global nuclear industry at this scale and which may be subject to additional revised cost estimates during construction. The ability to control costs and avoid cost and schedule overruns during the development, construction, and operation of new facilities is subject to a number of factors, including, but not limited to, changes in labor costs, availability, and productivity; challenges with management of contractors, subcontractors, or vendors; adverse weather conditions; shortages, delays, increased costs, or inconsistent quality of equipment, materials, and labor; contractor or supplier delay; 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 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, system integration, or regional transmission upgrades; and/or operational performance. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for information regarding Plant Vogtle Units 3 and 4 and additional factors that may impact construction expenditures.
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. The amount and timing of additional equity and debt issuances in 2019, as well as in subsequent years, will be contingent on Southern
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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, borrowings from financial institutions, and equity contributions or loans from Southern Company. Southern Power also plans to utilize tax equity partnership contributions, as well as funds resulting from its pending asset sale. 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. Also see Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding the pending sale of Plant Mankato.
In addition, in 2014, Georgia Power entered into a loan guarantee agreement with the DOE and, in March 2019, entered into the Amended and Restated Loan Guarantee Agreement, 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 Amended and Restated Loan Guarantee Agreement, the DOE has agreed to guarantee the obligations of Georgia Power under note purchase agreements among the DOE, Georgia Power, and the FFB and related promissory notes which provide for two multi-advance term loan facilities, under which Georgia Power may make term loan borrowings through the FFB in an amount up to approximately $5.130 billion, provided that certain conditions are met. At June 30, 2019, Georgia Power had borrowed $3.46 billion under the FFB Credit Facilities. See Notes (B) and (F) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" and "DOE Loan Guarantee Borrowings," respectively, herein for additional information.
Southern Company's current liabilities frequently exceed current assets because of scheduled maturities of long-term debt and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs. As of June 30, 2019, Southern Company's current liabilities exceeded current assets by $2.6 billion, primarily due to long-term debt that is due within one year and notes payable totaling $4.5 billion (including approximately $0.9 billion at the parent company, $1.5 billion at Georgia Power, $0.3 billion at Mississippi Power, $0.9 billion at Southern Power, and $0.8 billion at Southern Company Gas), partially offset by $1.4 billion of cash and cash equivalents. 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.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Committed credit arrangements with banks at June 30, 2019 were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Expires | | | | |
| Company | 2019 | 2020 | 2022 | 2024 | | Total | | Unused | | Due within One Year |
| | (in millions) |
Southern Company(a) | $ | — |
| $ | — |
| $ | — |
| $ | 2,000 |
| | $ | 2,000 |
| | $ | 1,999 |
| | $ | — |
|
| Alabama Power | 3 |
| 500 |
| — |
| 800 |
| | 1,303 |
| | 1,303 |
| | 3 |
|
| Georgia Power | — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,736 |
| | — |
|
| Mississippi Power | — |
| — |
| 150 |
| — |
| | 150 |
| | 150 |
| | — |
|
Southern Power(b) | — |
| — |
| — |
| 600 |
| | 600 |
| | 561 |
| | — |
|
Southern Company Gas(c) | — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,745 |
| | — |
|
| Other | — |
| 30 |
| — |
| — |
| | 30 |
| | 30 |
| | 30 |
|
| Southern Company Consolidated | $ | 3 |
| $ | 530 |
| $ | 150 |
| $ | 6,900 |
| | $ | 7,583 |
| | $ | 7,524 |
| | $ | 33 |
|
| |
| (a) | Represents the Southern Company parent entity. |
| |
| (b) | Does not include Southern Power Company's $120 million continuing letter of credit facility for standby letters of credit expiring in 2021, of which $30 million was unused at June 30, 2019. Southern Power's subsidiaries are not parties to its bank credit arrangement. |
| |
| (c) | 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. |
See 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.
Most of these bank credit arrangements, as well as the term loan arrangements of Alabama Power, Georgia Power, and SEGCO, contain covenants that limit debt levels and contain cross-acceleration or cross-default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of the individual company. Such cross-default provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness or guarantee obligations over a specified threshold. Such cross-acceleration provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness, the payment of which was then accelerated. At June 30, 2019, Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, 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 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 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, Nicor Gas, and SEGCO. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of June 30, 2019 was approximately $1.4 billion. In addition, at June 30, 2019, the traditional electric operating companies had approximately $272 million of revenue bonds outstanding that are required to be remarketed within the next 12 months.
Southern Company, Alabama Power, Georgia Power, Southern Power Company, Southern Company Gas, 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. 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 June 30, 2019 | | 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 | | $ | 1,148 |
| | 2.6 | % | | $ | 1,173 |
| | 2.8 | % | | $ | 1,562 |
|
| Short-term bank debt | | 250 |
| | 2.9 | % | | 127 |
| | 3.0 | % | | 250 |
|
| Total | | $ | 1,398 |
| | 2.7 | % | | $ | 1,300 |
| | 2.8 | % | | |
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2019. |
Southern Company believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, bank term loans, and operating cash flows.
Credit Rating Risk
At June 30, 2019, Southern Company and its subsidiaries did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain subsidiaries to BBB and/or Baa2 or below. These contracts are for physical electricity and natural gas purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, interest rate management, and construction of new generation at Plant Vogtle Units 3 and 4.
The maximum potential collateral requirements under these contracts at June 30, 2019 were as follows:
|
| | | |
| Credit Ratings | Maximum Potential
Collateral
Requirements |
| | (in millions) |
| At BBB and/or Baa2 | $ | 30 |
|
| At BBB- and/or Baa3 | $ | 433 |
|
At BB+ and/or Ba1(*) | $ | 1,935 |
|
| |
| (*) | 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.
As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries may be negatively impacted. Southern Company and most of its regulated subsidiaries have taken actions to mitigate the resulting impacts, which, among other alternatives, include adjusting capital structure. Absent actions by Southern Company and its subsidiaries that fully mitigate the impacts, the credit ratings of Southern Company and certain of its subsidiaries could be negatively affected. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information related to state PSC or other regulatory agency actions, including approvals and requests for additional or continued adjustments of capital structure related to the Tax Reform Legislation for Alabama Power, Georgia Power, Atlanta Gas Light, and Nicor Gas, which are expected to help mitigate the potential adverse impacts to certain of their credit metrics.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Financing Activities
During the first six months of 2019, Southern Company issued approximately 11.5 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $452 million.
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first six months of 2019:
|
| | | | | | | | | | | | | | | | | | | |
| Company | Senior Note Maturities, Redemptions, and Repurchases | | Revenue Bond Issuances and Reofferings of Purchased Bonds | | Revenue Bond Maturities, Redemptions, and Repurchases | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(a) |
| | (in millions) |
Southern Company(b) | $ | 2,100 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Alabama Power | 200 |
| | — |
| | — |
| | — |
| | — |
|
| Georgia Power | — |
| | 513 |
| | 223 |
| | 835 |
| | 3 |
|
| Mississippi Power | — |
| | 43 |
| | — |
| | — |
| | — |
|
| Other | — |
| | — |
| | 25 |
| | — |
| | 9 |
|
| Southern Company Consolidated | $ | 2,300 |
| | $ | 556 |
| | $ | 248 |
| | $ | 835 |
| | $ | 12 |
|
| |
| (a) | Includes reductions in finance lease obligations resulting from cash payments under finance leases. |
| |
| (b) | Represents the Southern Company parent entity. |
Except as otherwise described herein, Southern Company and its subsidiaries used the proceeds of debt issuances for their redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including working capital. The subsidiaries also used the proceeds for their construction programs.
In January 2019, Southern Company repaid a $250 million short-term uncommitted bank credit arrangement and a $1.5 billion short-term floating rate bank loan.
Also in January 2019, through cash tender offers, Southern Company repurchased and retired approximately $522 million of the $1.0 billion aggregate principal amount outstanding of its 1.85% Senior Notes due July 1, 2019 (1.85% Notes), approximately $180 million of the $350 million aggregate principal amount outstanding of its Series 2014B 2.15% Senior Notes due September 1, 2019 (Series 2014B Notes), and approximately $504 million of the $750 million aggregate principal amount outstanding of its Series 2018A Floating Rate Notes due February 14, 2020 (Series 2018A Notes), for an aggregate purchase price, excluding accrued and unpaid interest, of approximately $1.2 billion. In addition, following the completion of the cash tender offers, in February 2019, Southern Company completed the redemption of all of the Series 2018A Notes, 1.85% Notes, and Series 2014B Notes remaining outstanding.
As reflected in the table above, in March 2019, Georgia Power made additional borrowings under the FFB Credit Facilities in an aggregate principal amount of $835 million at an interest rate of 3.213% through the final maturity date of February 20, 2044. The proceeds were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4.
In June 2019, Georgia Power entered into two short-term floating rate bank loans in aggregate principal amounts of $125 million each, both of which bear interest based on one-month LIBOR.
In May 2019, Southern Power repaid at maturity a $100 million aggregate principal amount short-term bank loan.
Subsequent to June 30, 2019, Nicor Gas repaid at maturity $50 million aggregate principal amount of 4.7% first mortgage bonds due July 30, 2019.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company and its subsidiaries plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
PART I
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
During the six months ended June 30, 2019, 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 Southern Company Gas, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company Gas 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 under "Financial Instruments" and Notes 13 and 14 to the financial statements in Item 8 of the Form 10-K. Also see Notes (I) and (J) 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, 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 applicable unit be placeddisclosure 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, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended) during the second quarter 2019 that have materially affected or are reasonably likely to materially affect Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting.
ALABAMA POWER COMPANY
ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months
Ended June 30, | | For the Six Months
Ended June 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
| | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | |
| Retail revenues | $ | 1,378 |
| | $ | 1,338 |
| | $ | 2,592 |
| | $ | 2,624 |
|
| Wholesale revenues, non-affiliates | 62 |
| | 65 |
| | 123 |
| | 139 |
|
| Wholesale revenues, affiliates | 4 |
| | 31 |
| | 63 |
| | 82 |
|
| Other revenues | 69 |
| | 69 |
| | 143 |
| | 131 |
|
| Total operating revenues | 1,513 |
| | 1,503 |
| | 2,921 |
| | 2,976 |
|
| Operating Expenses: | | | | | | | |
| Fuel | 252 |
| | 347 |
| | 553 |
| | 672 |
|
| Purchased power, non-affiliates | 47 |
| | 48 |
| | 84 |
| | 113 |
|
| Purchased power, affiliates | 69 |
| | 43 |
| | 90 |
| | 80 |
|
| Other operations and maintenance | 402 |
| | 402 |
| | 812 |
| | 788 |
|
| Depreciation and amortization | 200 |
| | 189 |
| | 399 |
| | 379 |
|
| Taxes other than income taxes | 98 |
| | 94 |
| | 200 |
| | 192 |
|
| Total operating expenses | 1,068 |
| | 1,123 |
| | 2,138 |
| | 2,224 |
|
| Operating Income | 445 |
| | 380 |
| | 783 |
| | 752 |
|
| Other Income and (Expense): | | | | | | | |
| Allowance for equity funds used during construction | 14 |
| | 14 |
| | 28 |
| | 27 |
|
| Interest expense, net of amounts capitalized | (82 | ) | | (80 | ) | | (165 | ) | | (158 | ) |
| Other income (expense), net | 11 |
| | 12 |
| | 25 |
| | 15 |
|
| Total other income and (expense) | (57 | ) | | (54 | ) | | (112 | ) | | (116 | ) |
| Earnings Before Income Taxes | 388 |
| | 326 |
| | 671 |
| | 636 |
|
| Income taxes | 89 |
| | 64 |
| | 151 |
| | 145 |
|
| Net Income | 299 |
| | 262 |
| | 520 |
| | 491 |
|
| Dividends on Preferred Stock | 3 |
| | 3 |
| | 7 |
| | 7 |
|
| Net Income After Dividends on Preferred Stock | $ | 296 |
| | $ | 259 |
| | $ | 513 |
| | $ | 484 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months
Ended June 30, | | For the Six Months
Ended June 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
| | (in millions) | | (in millions) |
| Net Income | $ | 299 |
| | $ | 262 |
| | $ | 520 |
| | $ | 491 |
|
| 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 |
|
| Total other comprehensive income (loss) | 1 |
| | 1 |
| | 2 |
| | 2 |
|
| Comprehensive Income | $ | 300 |
| | $ | 263 |
| | $ | 522 |
| | $ | 493 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
|
| | | | | | | |
| | For the Six Months
Ended June 30, |
| | 2019 | | 2018 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 520 |
| | $ | 491 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 493 |
| | 452 |
|
| Deferred income taxes | 138 |
| | 48 |
|
| Allowance for equity funds used during construction | (28 | ) | | (27 | ) |
| Pension, postretirement, and other employee benefits | (13 | ) | | (28 | ) |
| Settlement of asset retirement obligations | (43 | ) | | (19 | ) |
| Other, net | (1 | ) | | (21 | ) |
| Changes in certain current assets and liabilities — | | | |
| -Receivables | 6 |
| | (153 | ) |
| -Prepayments | (59 | ) | | (57 | ) |
| -Materials and supplies | 5 |
| | (47 | ) |
| -Other current assets | (10 | ) | | 29 |
|
| -Accounts payable | (246 | ) | | (196 | ) |
| -Accrued taxes | 8 |
| | 134 |
|
| -Accrued compensation | (88 | ) | | (70 | ) |
| -Other current liabilities | 13 |
| | 116 |
|
| Net cash provided from operating activities | 695 |
| | 652 |
|
| Investing Activities: | | | |
| Property additions | (833 | ) | | (997 | ) |
| Nuclear decommissioning trust fund purchases | (139 | ) | | (131 | ) |
| Nuclear decommissioning trust fund sales | 139 |
| | 131 |
|
| Cost of removal, net of salvage | (48 | ) | | (34 | ) |
| Change in construction payables | (103 | ) | | (29 | ) |
| Other investing activities | (18 | ) | | (15 | ) |
| Net cash used for investing activities | (1,002 | ) | | (1,075 | ) |
| Financing Activities: | | | |
| Proceeds — | | | |
| Senior notes | — |
| | 500 |
|
| Capital contributions from parent company | 1,254 |
| | 488 |
|
| Redemptions — Senior notes | (200 | ) | | — |
|
| Payment of common stock dividends | (422 | ) | | (402 | ) |
| Other financing activities | (15 | ) | | (21 | ) |
| Net cash provided from financing activities | 617 |
| | 565 |
|
| Net Change in Cash, Cash Equivalents, and Restricted Cash | 310 |
| | 142 |
|
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 313 |
| | 544 |
|
| Cash, Cash Equivalents, and Restricted Cash at End of Period | $ | 623 |
| | $ | 686 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid during the period for — | | | |
| Interest (net of $10 and $10 capitalized for 2019 and 2018, respectively) | $ | 154 |
| | $ | 143 |
|
| Income taxes, net | 63 |
| | 17 |
|
| Noncash transactions — Accrued property additions at end of period | 168 |
| | 216 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At June 30, 2019 | | At December 31, 2018 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 623 |
| | $ | 313 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 432 |
| | 403 |
|
| Unbilled revenues | | 173 |
| | 150 |
|
| Affiliated | | 38 |
| | 94 |
|
| Other accounts and notes receivable | | 55 |
| | 51 |
|
| Accumulated provision for uncollectible accounts | | (10 | ) | | (10 | ) |
| Fossil fuel stock | | 143 |
| | 141 |
|
| Materials and supplies | | 530 |
| | 546 |
|
| Prepaid expenses | | 170 |
| | 66 |
|
| Other regulatory assets | | 204 |
| | 137 |
|
| Other current assets | | 26 |
| | 18 |
|
| Total current assets | | 2,384 |
| | 1,909 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 29,070 |
| | 30,402 |
|
| Less: Accumulated provision for depreciation | | 9,397 |
| | 9,988 |
|
| Plant in service, net of depreciation | | 19,673 |
| | 20,414 |
|
| Nuclear fuel, at amortized cost | | 322 |
| | 324 |
|
| Construction work in progress | | 1,097 |
| | 1,113 |
|
| Total property, plant, and equipment | | 21,092 |
| | 21,851 |
|
| Other Property and Investments: | | | | |
| Equity investments in unconsolidated subsidiaries | | 64 |
| | 65 |
|
| Nuclear decommissioning trusts, at fair value | | 964 |
| | 847 |
|
| Miscellaneous property and investments | | 129 |
| | 127 |
|
| Total other property and investments | | 1,157 |
| | 1,039 |
|
| Deferred Charges and Other Assets: | | | | |
| Operating lease right-of-use assets, net of amortization | | 152 |
| | — |
|
| Deferred charges related to income taxes | | 240 |
| | 240 |
|
| Deferred under recovered regulatory clause revenues | | 25 |
| | 116 |
|
| Regulatory assets – asset retirement obligations | | 1,016 |
| | 147 |
|
| Other regulatory assets, deferred | | 1,824 |
| | 1,240 |
|
| Other deferred charges and assets | | 177 |
| | 188 |
|
| Total deferred charges and other assets | | 3,434 |
| | 1,931 |
|
| Total Assets | | $ | 28,067 |
| | $ | 26,730 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholder's Equity | | At June 30, 2019 | | At December 31, 2018 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 1 |
| | $ | 201 |
|
| Accounts payable — | | | | |
| Affiliated | | 321 |
| | 364 |
|
| Other | | 334 |
| | 614 |
|
| Customer deposits | | 98 |
| | 96 |
|
| Accrued taxes | | 102 |
| | 44 |
|
| Accrued interest | | 88 |
| | 89 |
|
| Accrued compensation | | 140 |
| | 227 |
|
| Asset retirement obligations | | 156 |
| | 163 |
|
| Other current liabilities | | 155 |
| | 161 |
|
| Total current liabilities | | 1,395 |
| | 1,959 |
|
| Long-term Debt | | 7,926 |
| | 7,923 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 3,117 |
| | 2,962 |
|
| Deferred credits related to income taxes | | 2,006 |
| | 2,027 |
|
| Accumulated deferred ITCs | | 103 |
| | 106 |
|
| Employee benefit obligations | | 309 |
| | 314 |
|
| Operating lease obligations | | 137 |
| | — |
|
| Asset retirement obligations, deferred | | 3,389 |
| | 3,047 |
|
| Other cost of removal obligations | | 464 |
| | 497 |
|
| Other regulatory liabilities | | 69 |
| | 69 |
|
| Other deferred credits and liabilities | | 32 |
| | 58 |
|
| Total deferred credits and other liabilities | | 9,626 |
| | 9,080 |
|
| Total Liabilities | | 18,947 |
| | 18,962 |
|
| Redeemable Preferred Stock | | 291 |
| | 291 |
|
Common Stockholder's Equity (See accompanying statements) | | 8,829 |
| | 7,477 |
|
| Total Liabilities and Stockholder's Equity | | $ | 28,067 |
| | $ | 26,730 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA 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, 2017 | 31 |
| | $ | 1,222 |
| | $ | 2,986 |
| | $ | 2,647 |
| | $ | (26 | ) | | $ | 6,829 |
|
Net income after dividends on
preferred stock | — |
| | — |
| | — |
| | 225 |
| | — |
| | 225 |
|
| Capital contributions from parent company | — |
| | — |
| | 488 |
| | — |
| | — |
| | 488 |
|
| Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
| Cash dividends on common stock | — |
| | — |
| | — |
| | (202 | ) | | — |
| | (202 | ) |
| Other | — |
| | — |
| | — |
| | — |
| | (6 | ) | | (6 | ) |
| Balance at March 31, 2018 | 31 |
| | 1,222 |
| | 3,474 |
| | 2,670 |
| | (31 | ) | | 7,335 |
|
Net income after dividends on
preferred stock | — |
| | — |
| | — |
| | 259 |
| | — |
| | 259 |
|
| Capital contributions from parent company | — |
| | — |
| | 5 |
| | — |
| | — |
| | 5 |
|
| Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
| Cash dividends on common stock | — |
| | — |
| | — |
| | (200 | ) | | — |
| | (200 | ) |
| Other | — |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
| Balance at June 30, 2018 | 31 |
| | $ | 1,222 |
| | $ | 3,480 |
| | $ | 2,729 |
| | $ | (30 | ) | | $ | 7,401 |
|
| | | | | | | | | | | | |
| 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 (loss) | — |
| | — |
| | — |
| | — |
| | 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 (loss) | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
| Cash dividends on common stock | — |
| | — |
| | — |
| | (211 | ) | | — |
| | (211 | ) |
| Balance at June 30, 2019 | 31 |
| | $ | 1,222 |
| | $ | 4,767 |
| | $ | 2,866 |
| | $ | (26 | ) | | $ | 8,829 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
SECOND QUARTER 2019 vs. SECOND QUARTER 2018
AND
YEAR-TO-DATE 2019 vs. YEAR-TO-DATE 2018
OVERVIEW
Alabama Power operates as a vertically integrated utility providing electric service to retail and wholesale customers within its traditional service territory located in the State of Alabama in addition to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of Alabama Power's business of providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales and customers, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, including CCR rules, reliability, fuel, capital expenditures, including improving the electric transmission and distribution systems, 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 stock.
RESULTS OF OPERATIONS
Net Income
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) |
| (% change) |
| (change in millions) |
| (% change) |
| $37 | | 14.3 | | $29 | | 6.0 |
Alabama Power's net income after dividends on preferred stock for the second quarter 2019 was $296 million compared to $259 million for the corresponding period in 2018. The increase was primarily related to an increase in retail revenues associated with the impacts of customer bill credits issued in 2018 related to the Tax Reform Legislation, as well as additional capital investments recovered through Rate CNP Compliance, partially offset by a decrease in retail revenues associated with customer usage.
Alabama Power's net income after dividends on preferred stock for year-to-date 2019 was $513 million compared to $484 million for the corresponding period in 2018. This increase was primarily related to an increase in retail revenues associated with the impacts of customer bill credits issued in 2018 related to the Tax Reform Legislation, as well as additional capital investments recovered through Rate CNP Compliance. This increase was partially offset by decreases in retail revenues associated with milder weather and lower customer usage as well as increases to operations and maintenance expenses and depreciation.
See Note 2 to the financial statements under "Alabama Power – Rate RSE" 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
Retail Revenues
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $40 | | 3.0 | | $(32) | | (1.2) |
In the second quarter 2019, retail revenues were $1.38 billion compared to $1.34 billion for the corresponding period in 2018. For year-to-date 2019, retail revenues were $2.59 billion compared to $2.62 billion for the corresponding period in 2018.
Details of the changes in retail revenues were as follows:
|
| | | | | | | | | | | | | |
| | Second Quarter 2019 |
| Year-to-Date 2019 |
| | (in millions) |
| (% change) |
| (in millions) |
| (% change) |
| Retail – prior year | $ | 1,338 |
| | | | $ | 2,624 |
| | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 62 |
| | 4.7 | % | | 96 |
| | 3.7 | % |
| Sales decline | (15 | ) | | (1.1 | ) | | (31 | ) | | (1.2 | ) |
| Weather | 6 |
| | 0.4 |
| | (19 | ) | | (0.7 | ) |
| Fuel and other cost recovery | (13 | ) | | (1.0 | ) | | (78 | ) | | (3.0 | ) |
| Retail – current year | $ | 1,378 |
| | 3.0 | % | | $ | 2,592 |
| | (1.2 | )% |
Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018 primarily due to the impacts of customer bill credits related to the Tax Reform Legislation in 2018, as well as additional capital investments recovered through Rate CNP Compliance. See Note 2 to the financial statements under "Alabama Power – Rate RSE" and " – Rate CNP Compliance" 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 2019 when compared to the corresponding periods in 2018. Weather-adjusted residential KWH sales decreased 1.5% and 2.0% in the second quarter and year-to-date 2019, respectively, and weather-adjusted commercial KWH sales decreased 1.2% and 2.3% in the second quarter and year-to-date 2019, respectively, when compared to the corresponding periods in 2018. These decreases primarily resulted from customer initiatives in energy savings for commercial customers and more energy-efficient residential appliances. Industrial KWH sales decreased 3.2% and 3.1% in the second quarter and year-to-date 2019, respectively, when compared to the corresponding periods in 2018 as a result of a decrease in demand resulting from changes in production levels primarily in the primary metals and chemicals sectors for the second quarter 2019 and primary metals, chemicals, and paper sectors for year-to-date 2019.
Residential and commercial sales revenues decreased year-to-date 2019 by 1.2% and 0.7%, respectively, due to milder weather in the first quarter 2019 when compared to the corresponding period in 2018.
Fuel and other cost recovery revenues decreased in the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018 primarily due to a decrease in generation and 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 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale Revenues – Non-Affiliates
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(3) | | (4.6) | | $(16) | | (11.5) |
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.
For year-to-date 2019, wholesale revenues from sales to non-affiliates were $123 million compared to $139 million for the corresponding period in 2018. The decrease was primarily due to a 7.1% decrease in KWH sales as a result of lower demand and a 4.8% decrease in the price of energy due to lower natural gas prices in 2019 compared to the corresponding period in 2018.
Wholesale Revenues – Affiliates
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(27) | | (87.1) | | $(19) | | (23.2) |
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through Alabama Power's energy cost recovery clause.
In the second quarter 2019, wholesale revenues from sales to affiliates were $4 million compared to $31 million for the corresponding period in 2018. The decrease was primarily due to an 87.4% decrease in KWH sales as a result of decreased coal generation associated with the retirement of Plant Gorgas Units 8, 9, and 10 and a 6.7% decrease in the price of energy as a result of lower natural gas prices in the second quarter 2019 compared to the corresponding period in 2018.
For year-to-date 2019, wholesale revenues from sales to affiliates were $63 million compared to $82 million for the corresponding period in 2018. The decrease was primarily due to a 13.1% decrease in KWH sales as a result of decreased coal generation associated with the retirement of Plant Gorgas Units 8, 9, and 10 and an 11.0% decrease in the price of energy due to increased hydro generation in 2019 as compared to the corresponding period in 2018.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | | |
| | Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| | (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| Fuel | $ | (95 | ) | | (27.4) | | $ | (119 | ) | | (17.7 | ) |
| Purchased power – non-affiliates | (1 | ) | | (2.1) | | (29 | ) | | (25.7 | ) |
| Purchased power – affiliates | 26 |
| | 60.5 | | 10 |
| | 12.5 |
|
| Total fuel and purchased power expenses | $ | (70 | ) | | | | $ | (138 | ) | | |
In the second quarter 2019, fuel and purchased power expenses were $368 million compared to $438 million for the corresponding period in 2018. For year-to-date 2019, fuel and purchased power expenses were $727 million compared to $865 million for the corresponding period in 2018. These decreases were primarily related to the volume of KWHs generated (excluding hydro) 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 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.
Details of Alabama Power's generation and purchased power were as follows:
|
| | | | | | | |
| | Second Quarter 2019 | | Second Quarter 2018 | | Year-to-Date 2019 |
| Year-to-Date 2018 |
Total generation (in billions of KWHs) | 12 | | 15 | | 29 | | 31 |
Total purchased power (in billions of KWHs) | 3 | | 2 | | 4 | | 3 |
Sources of generation (percent) — | | | | | | | |
| Coal | 43 | | 53 | | 43 | | 52 |
| Nuclear | 26 | | 20 | | 24 | | 21 |
| Gas | 23 | | 20 | | 21 | | 19 |
| Hydro | 8 | | 7 | | 12 | | 8 |
Cost of fuel, generated (in cents per net KWH) — (a) | | | | | | | |
| Coal | 2.86 | | 2.79 | | 2.82 | | 2.74 |
| Nuclear | 0.78 | | 0.80 | | 0.78 | | 0.77 |
| Gas | 2.48 | | 2.51 | | 2.53 | | 2.69 |
Average cost of fuel, generated (in cents per net KWH)(a)(b) | 2.18 | | 2.31 | | 2.19 | | 2.27 |
Average cost of purchased power (in cents per net KWH)(c) | 4.01 | | 4.72 | | 4.45 | | 5.72 |
| |
| (a) | In the second quarter and year-to-date 2018, cost of fuel and average cost of fuel, generated exclude a $30 million adjustment in accordance with an Alabama PSC accounting order. See Note 2 to the financial statements under "Alabama Power – Tax Reform Accounting Order" in Item 8 of the Form 10-K for additional information. |
| |
| (b) | KWHs generated by hydro are excluded from the average cost of fuel, generated. |
| |
| (c) | 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 2019, fuel expense was $252 million compared to $347 million for the corresponding period in 2018. The decrease was primarily due to a 31.3% decrease in the volume of KWHs generated by coal and an 11.9% increase in the volume of KWHs generated by nuclear.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2019, fuel expense was $553 million compared to $672 million for the corresponding period in 2018. The decrease was primarily due to a 45.3% increase in the volume of KWHs generated by hydro, a 21.9% decrease in the volume of KWHs generated by coal, a 5.1% increase in the volume of KWHs generated by nuclear, and a 6.0% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements.
In addition, fuel expense increased $30 million in both the second quarter and year-to-date 2018 in accordance with an Alabama PSC accounting order authorizing the use of excess deferred income taxes to offset under recovered fuel costs (Tax Reform Accounting Order). See Note 2 to the financial statements under "Alabama Power – Tax Reform Accounting Order" in Item 8 of the Form 10-K for additional information.
Purchased Power – Non-Affiliates
For year-to-date 2019, purchased power expense from non-affiliates was $84 million compared to $113 million for the corresponding period in 2018. The decrease was primarily related to a 14.3% decrease in the average cost of purchased power per KWH due to lower natural gas prices and an 11.9% decrease in the amount of energy purchased due to milder weather in the first quarter 2019 compared to the corresponding period in 2018.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the second quarter 2019, purchased power expense from affiliates was $69 million compared to $43 million for the corresponding period in 2018. For year-to-date 2019, purchased power expense from affiliates was $90 million compared to $80 million for the corresponding period in 2018. These increases were primarily related to the availability of lower-cost generation compared to Alabama Power's owned generation and a decrease in coal generation as a result of the retirement of Plant Gorgas Units 8, 9, and 10.
Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $— | | — | | $24 | | 3.0 |
For year-to-date 2019, other operations and maintenance expenses were $812 million compared to $788 million for the corresponding period in 2018. This increase was primarily due to increases of $15 million in Rate CNP Compliance-related expenses and $13 million in steam generation costs primarily due to the timing of outages.
Depreciation and Amortization
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $11 | | 5.8 | | $20 | | 5.3 |
In the second quarter 2019, depreciation and amortization was $200 million compared to $189 million for the corresponding period in 2018. For year-to-date 2019, depreciation and amortization was $399 million compared to $379 million for the corresponding period in 2018. These increases were primarily due to additional plant in service associated with steam, distribution, and transmission.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Income (Expense), Net
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(1) | | (8.3) | | $10 | | 66.7 |
For year-to-date 2019, other income (expense), net was $25 million compared to $15 million for the corresponding period in 2018. This increase was primarily due to increases in interest income from temporary cash investments and non-service cost-related pension income.
Income Taxes
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $25 | | 39.1 | | $6 | | 4.1 |
In the second quarter 2019, income taxes were $89 million compared to $64 million for the corresponding period in 2018. This increase was primarily due to higher pre-tax earnings in the second quarter 2019 compared to the corresponding period in 2018 and the application of the Tax Reform Accounting Order in 2018. See Note 2 to the financial statements under "Alabama Power – Tax Reform Accounting Order" in Item 8 of the Form 10-K for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Alabama Power's future earnings potential. The level of Alabama Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Alabama Power's primary business of 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 the weak pace of growth in new customers and electricity use per customer, especially in residential and commercial markets. 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, both of which could contribute to a net reduction in customer usage. 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. 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
Alabama Power's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. Alabama Power maintains comprehensive environmental compliance and GHG strategies to assess upcoming requirements and compliance costs associated with these environmental laws and regulations and to achieve stated goals. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, or changing fuel sources for certain existing units, as well as related upgrades to Alabama Power's transmission and distribution systems, and may impact future electric generating unit retirement and replacement decisions, results of operations, cash flows, and/or financial condition. These costs are being collected through existing ratemaking and billing provisions. The ultimate impact of environmental laws and regulations and GHG
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
goals will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed technology, fuel prices, and the outcome of pending and/or future legal challenges.
New or revised environmental laws and regulations could affect many areas of Alabama Power's operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be recovered in rates on a timely basis. Environmental compliance costs are recovered through Rate CNP Compliance. Further, increased costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and/or financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Alabama Power in Item 7 of the Form 10-K and Note 2 to the financial statements under "Alabama Power – Rate CNP Compliance" and Note 3 to the financial statements under "Environmental Remediation" in Item 8 of the Form 10-K for additional information.
Environmental Laws and Regulations
Coal Combustion Residuals
In June 2019, Alabama Power recorded an increase of approximately $308 million to its AROs primarily related to the CCR Rule and the related state rule based on management's completion of closure designs during the second quarter 2019 for all but two of its ash pond facilities. The additional estimated costs to close these ash ponds under the planned closure-in-place methodology primarily relate to cost inputs from contractor bids, internal drainage and dewatering system designs, and increases in the estimated ash volumes. The cost estimate for the remaining ash pond facilities will be updated within the next 12 months and the change could be material.
As further analysis is performed and additional details are developed with respect to all ash pond closures, Alabama Power expects to periodically update these cost estimates as necessary. Additionally, the closure designs and plans are subject to approval by environmental regulatory agencies. Absent continued recovery of ARO costs through regulated rates, Alabama Power's results of operations, cash flows, and financial condition could be materially impacted. The ultimate outcome of this matter cannot be determined at this time. See Note 6 to the financial statements in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
Global Climate Issues
On July 8, 2019, the EPA published the final Affordable Clean Energy rule (ACE Rule) to repeal and replace the CPP. Implementation of the CPP has been stayed by the U.S. Supreme Court since 2016. The ACE Rule requires states to develop unit-specific CO2 emission rate standards for existing coal-fired units based on heat-rate efficiency improvements. Combustion turbines, including natural gas combined cycles, are not included as affected sources in the ACE Rule. Alabama Power has ownership interests in seven coal-fired units to which the ACE Rule is applicable. The ultimate impact of the ACE Rule, including the repeal and replacement of the CPP, to Alabama Power will depend on state implementation plan requirements and the outcome of any associated legal challenges and cannot be determined at this time.
FERC Matters
See Note 2 to the financial statements under "FERC Matters – Open Access Transmission Tariff" in Item 8 of the Form 10-K for additional information.
On June 28, 2019, the FERC approved a settlement agreement between Alabama Municipal Electric Authority and Cooperative Energy and SCS and the traditional electric operating companies (including Alabama Power) agreeing to an OATT rate reduction based on a 10.6% ROE, with a retroactive effective date of May 10, 2018, and a five-year moratorium on these parties seeking changes to the OATT formula rate. The terms of the OATT settlement agreement will not have a material impact on the financial statements of Alabama Power.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 Note 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information regarding Alabama Power's rate mechanisms, accounting orders, and the recovery balance of each regulatory clause for Alabama Power.
Environmental Accounting Order
On April 15, 2019, Alabama Power retired Plant Gorgas Units 8, 9, and 10 and reclassified approximately $654 million of the unrecovered asset balances to regulatory assets, which are being recovered over the units' remaining useful lives, the latest being through 2037, as established prior to 2021.the decision to retire. Additionally, approximately $700 million of net capitalized asset retirement costs were reclassified to a regulatory asset in accordance with accounting guidance provided by the Alabama PSC. The asset retirement costs are being recovered through 2055. See Note 2 to the financial statements under "Alabama Power – Environmental Accounting Order" and Note 6 in Item 8 of the Form 10-K for additional information.
Other Matters
Alabama Power is involved in various other matters that could affect future earnings, including matters being litigated and regulatory matters. 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 laws and regulations governing air, water, land, and protection of other natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations, 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 determined at this time; however, for current proceedings not specifically reported 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 Alabama Power's financial statements. See Notes (B) and (C) 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.
In response to changing customer expectations, payment patterns, and ongoing efforts to increase overall operating efficiencies, Alabama Power initiated a plan to close 40 of its 86 payment offices by the end of 2019. Charges associated with these activities are not expected to have a material impact on Alabama Power's financial statements.
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 Notes 1, 5, and 6 to the financial statements 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.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Recently Issued Accounting Standards
See Note (A) to the Condensed Financial Statements herein for information regarding Alabama Power's recently adopted accounting standards.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Alabama Power in Item 7 of the Form 10-K for additional information. Alabama Power's financial condition remained stable at June 30, 2019. 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 $695 million for the first six months of 2019, an increase of $43 million as compared to the first six months of 2018. The increase in net present valuecash provided from operating activities was primarily due to increased fuel cost recovery, partially offset by the prior year impacts of customer billing reductions related to the Tax Reform Legislation. Net cash used for investing activities totaled $1.0 billion for the first six months of 2019 primarily related to additional capital expenditures for distribution, environmental, and transmission assets. Net cash provided from financing activities totaled $617 million for the first six months of 2019 primarily due to capital contributions from Southern Company, partially offset by a payment of common stock dividends and a long-term debt maturity. Fluctuations in cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first six months of 2019 include increases of $869 million in regulatory assets associated with AROs and $584 million in other regulatory assets, deferred and a decrease of $759 million in property, plant, and equipment. These changes were primarily due to the impacts of retiring and reclassifying Plant Gorgas Units 8, 9, and 10. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Alabama Power – Environmental Accounting Order" for additional information. Other significant increases include $1.4 billion in total common stockholder's equity, primarily due to a $1.2 billion capital contribution from Southern Company, $342 million in asset retirement obligations, deferred due to an increase in the ARO estimate primarily related to ash pond facilities, and $310 million in cash and cash equivalents. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" 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 Alabama Power in Item 7 of the Form 10-K for a description of Alabama Power's capital requirements and contractual obligations. There are no scheduled maturities of long-term debt through June 30, 2020.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Alabama Power in Item 7 of the Form 10-K for additional information on Alabama Power's environmental compliance strategy.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to 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
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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, external security issuances, borrowings from financial institutions, 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. In January 2019, Alabama Power received a capital contribution totaling $1.225 billion from Southern Company. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Alabama Power in Item 7 of the Form 10-K for additional information.
Alabama Power's current liabilities sometimes exceed current assets because of long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs.
At June 30, 2019, Alabama Power had approximately $623 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2019 were as follows:
|
| | | | | | | | | | | | | | | | | | |
| Expires | | | | |
| 2019 | | 2020 | | 2024 | | Total | | Unused |
| (in millions) |
| $ | 3 |
| | $ | 500 |
| | $ | 800 |
| | $ | 1,303 |
| | $ | 1,303 |
|
See 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.
As reflected in the table above, in May 2019, Alabama Power amended its $800 million multi-year credit arrangement, which, among other things, extended the maturity date from 2022 to 2024.
Most of these bank credit arrangements, as well as Alabama Power's term loan arrangements, contain covenants that limit debt levels and contain cross-acceleration provisions to other indebtedness (including guarantee obligations) of Alabama Power. Such cross-acceleration provisions to other indebtedness would trigger an event of default if Alabama Power defaulted on indebtedness, the payment of which was then accelerated. At June 30, 2019, 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 June 30, 2019. At June 30, 2019, Alabama Power had $87 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.
Alabama Power also has substantial cash flow from operating activities and access to the 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. Short-term borrowings are included in notes payable in the balance sheets.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of short-term borrowings were as follows:
|
| | | | | | | | | | |
| | Short-term Debt During the Period(*) |
| | Average
Amount Outstanding | | Weighted
Average
Interest
Rate | | Maximum
Amount
Outstanding |
| | (in millions) | | | | (in millions) |
| Commercial paper | $ | 26 |
| | 2.6 | % | | $ | 190 |
|
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2019. No short-term debt was outstanding at June 30, 2019. |
Alabama Power believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and operating cash flows.
Credit Rating Risk
At June 30, 2019, 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. At June 30, 2019, the maximum potential collateral requirements at a rating below BBB- and/or Baa3 totaled approximately $359 million.
Included in these amounts are certain agreements that could require collateral in the event that either Alabama Power or Georgia Power (an affiliate of 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 Alabama Power to access capital markets and would be likely to impact the cost at which it does so.
As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including Alabama Power, may be negatively impacted. The modifications to Rate RSE and other commitments approved by the Alabama PSC are expected to help mitigate these potential adverse impacts to certain credit metrics and will help Alabama Power meet its goal of achieving an equity ratio of approximately 55% by the end of 2025. See Note 2 to the financial statements under "Alabama Power – Rate RSE" in Item 8 of the Form 10-K for additional information.
Financing Activities
In February 2019, Alabama Power repaid at maturity $200 million aggregate principal amount of Series Z 5.125% Senior Notes due February 15, 2019.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Alabama Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
GEORGIA POWER COMPANY
GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months
Ended June 30, | | For the Six Months
Ended June 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
| | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | |
| Retail revenues | $ | 1,946 |
| | $ | 1,889 |
| | $ | 3,614 |
| | $ | 3,688 |
|
| Wholesale revenues, non-affiliates | 33 |
| | 36 |
| | 62 |
| | 80 |
|
| Wholesale revenues, affiliates | 3 |
| | 3 |
| | 5 |
| | 13 |
|
| Other revenues | 135 |
| | 120 |
| | 270 |
| | 227 |
|
| Total operating revenues | 2,117 |
| | 2,048 |
| | 3,951 |
| | 4,008 |
|
| Operating Expenses: | | | | | | | |
| Fuel | 390 |
| | 378 |
| | 689 |
| | 790 |
|
| Purchased power, non-affiliates | 124 |
| | 111 |
| | 242 |
| | 233 |
|
| Purchased power, affiliates | 134 |
| | 178 |
| | 310 |
| | 349 |
|
| Other operations and maintenance | 463 |
| | 457 |
| | 913 |
| | 863 |
|
| Depreciation and amortization | 244 |
| | 230 |
| | 483 |
| | 458 |
|
| Taxes other than income taxes | 115 |
| | 106 |
| | 220 |
| | 214 |
|
| Estimated loss on Plant Vogtle Units 3 and 4 | — |
| | 1,060 |
| | — |
| | 1,060 |
|
| Total operating expenses | 1,470 |
| | 2,520 |
| | 2,857 |
| | 3,967 |
|
| Operating Income (Loss) | 647 |
| | (472 | ) | | 1,094 |
| | 41 |
|
| Other Income and (Expense): | | | | | | | |
| Interest expense, net of amounts capitalized | (105 | ) | | (102 | ) | | (201 | ) | | (208 | ) |
| Other income (expense), net | 35 |
| | 35 |
| | 77 |
| | 73 |
|
| Total other income and (expense) | (70 | ) | | (67 | ) | | (124 | ) | | (135 | ) |
| Earnings (Loss) Before Income Taxes | 577 |
| | (539 | ) | | 970 |
| | (94 | ) |
| Income taxes (benefit) | 129 |
| | (143 | ) | | 211 |
| | (50 | ) |
| Net Income (Loss) | $ | 448 |
| | $ | (396 | ) | | $ | 759 |
| | $ | (44 | ) |
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months
Ended June 30, | | For the Six Months
Ended June 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
| | (in millions) | | (in millions) |
| Net Income (Loss) | $ | 448 |
| | $ | (396 | ) | | $ | 759 |
| | $ | (44 | ) |
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
| Changes in fair value, net of tax of $(9), $-, $(9), and $-, respectively | (28 | ) | | — |
| | (28 | ) | | — |
|
Reclassification adjustment for amounts included in net income,
net of tax of $-, $-, $-, and $1, respectively | 1 |
| | 1 |
| | 1 |
| | 2 |
|
| Total other comprehensive income (loss) | (27 | ) | | 1 |
| | (27 | ) | | 2 |
|
| Comprehensive Income (Loss) | $ | 421 |
| | $ | (395 | ) | | $ | 732 |
| | $ | (42 | ) |
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED) |
| | | | | | | |
| | For the Six Months
Ended June 30, |
| | 2019 | | 2018 |
| | (in millions) |
| Operating Activities: | | | |
| Net income (loss) | $ | 759 |
| | $ | (44 | ) |
| Adjustments to reconcile net income (loss) to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 583 |
| | 562 |
|
| Deferred income taxes | 153 |
| | (256 | ) |
| Pension, postretirement, and other employee benefits | (56 | ) | | (47 | ) |
| Settlement of asset retirement obligations | (76 | ) | | (49 | ) |
| Estimated loss on Plant Vogtle Units 3 and 4 | — |
| | 1,060 |
|
| Other, net | — |
| | 29 |
|
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (43 | ) | | (103 | ) |
| -Fossil fuel stock | (26 | ) | | 38 |
|
| -Prepaid income taxes | 63 |
| | 115 |
|
| -Other current assets | 22 |
| | 25 |
|
| -Accounts payable | (94 | ) | | (87 | ) |
| -Accrued taxes | (139 | ) | | (89 | ) |
| -Accrued compensation | (32 | ) | | (56 | ) |
| -Other current liabilities | (2 | ) | | (26 | ) |
| Net cash provided from operating activities | 1,112 |
| | 1,072 |
|
| Investing Activities: | | | |
| Property additions | (1,712 | ) | | (1,501 | ) |
| Nuclear decommissioning trust fund purchases | (266 | ) | | (440 | ) |
| Nuclear decommissioning trust fund sales | 260 |
| | 435 |
|
| Cost of removal, net of salvage | (107 | ) | | (50 | ) |
| Change in construction payables, net of joint owner portion | (5 | ) | | 86 |
|
| Payments pursuant to LTSAs | (9 | ) | | (46 | ) |
| Proceeds from dispositions and asset sales | 9 |
| | 134 |
|
| Other investing activities | (4 | ) | | (11 | ) |
| Net cash used for investing activities | (1,834 | ) | | (1,393 | ) |
| Financing Activities: | | | |
| Increase in notes payable, net | 11 |
| | 480 |
|
| Proceeds — | | | |
| FFB loan | 835 |
| | — |
|
| Pollution control revenue bonds | 513 |
| | — |
|
| Short-term borrowings | 250 |
| | — |
|
| Capital contributions from parent company | 46 |
| | 1,502 |
|
| Redemptions and repurchases — | | | |
| Senior notes | — |
| | (1,000 | ) |
| Pollution control revenue bonds | (223 | ) | | (398 | ) |
| Short-term borrowings | — |
| | (150 | ) |
| Other long-term debt | — |
| | (100 | ) |
| Payment of common stock dividends | (788 | ) | | (691 | ) |
| Premiums on redemption and repurchases of senior notes | — |
| | (152 | ) |
| Other financing activities | (24 | ) | | (11 | ) |
| Net cash provided from (used for) financing activities | 620 |
| | (520 | ) |
| Net Change in Cash, Cash Equivalents, and Restricted Cash | (102 | ) | | (841 | ) |
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 112 |
| | 852 |
|
| Cash, Cash Equivalents, and Restricted Cash at End of Period | $ | 10 |
| | $ | 11 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
| Interest (net of $16 and $12 capitalized for 2019 and 2018, respectively) | $ | 179 |
| | $ | 211 |
|
| Income taxes, net | (6 | ) | | 64 |
|
| Noncash transactions — Accrued property additions at end of period | 650 |
| | 669 |
|
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At June 30, 2019 | | At December 31, 2018 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 10 |
| | $ | 4 |
|
| Restricted cash and cash equivalents | | — |
| | 108 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 603 |
| | 591 |
|
| Unbilled revenues | | 267 |
| | 208 |
|
| Under recovered fuel clause revenues | | 69 |
| | 115 |
|
| Joint owner accounts receivable | | 178 |
| | 170 |
|
| Affiliated | | 16 |
| | 39 |
|
| Other accounts and notes receivable | | 240 |
| | 80 |
|
| Accumulated provision for uncollectible accounts | | (2 | ) | | (2 | ) |
| Fossil fuel stock | | 257 |
| | 231 |
|
| Materials and supplies | | 513 |
| | 519 |
|
| Prepaid expenses | | 68 |
| | 142 |
|
| Other regulatory assets | | 240 |
| | 199 |
|
| Other current assets | | 58 |
| | 70 |
|
| Total current assets | | 2,517 |
| | 2,474 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 38,517 |
| | 37,675 |
|
| Less: Accumulated provision for depreciation | | 12,140 |
| | 12,096 |
|
| Plant in service, net of depreciation | | 26,377 |
| | 25,579 |
|
| Nuclear fuel, at amortized cost | | 549 |
| | 550 |
|
| Construction work in progress | | 5,193 |
| | 4,833 |
|
| Total property, plant, and equipment | | 32,119 |
| | 30,962 |
|
| Other Property and Investments: | | | | |
| Equity investments in unconsolidated subsidiaries | | 51 |
| | 51 |
|
| Nuclear decommissioning trusts, at fair value | | 978 |
| | 873 |
|
| Miscellaneous property and investments | | 74 |
| | 72 |
|
| Total other property and investments | | 1,103 |
| | 996 |
|
| Deferred Charges and Other Assets: | | | | |
| Operating lease right-of-use assets, net of amortization | | 1,492 |
| | — |
|
| Deferred charges related to income taxes | | 518 |
| | 517 |
|
| Regulatory assets – asset retirement obligations | | 2,839 |
| | 2,644 |
|
| Other regulatory assets, deferred | | 2,272 |
| | 2,258 |
|
| Other deferred charges and assets | | 379 |
| | 514 |
|
| Total deferred charges and other assets | | 7,500 |
| | 5,933 |
|
| Total Assets | | $ | 43,239 |
| | $ | 40,365 |
|
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholder's Equity | | At June 30, 2019 | | At December 31, 2018 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 988 |
| | $ | 617 |
|
| Notes payable | | 555 |
| | 294 |
|
| Accounts payable — | | | | |
| Affiliated | | 477 |
| | 575 |
|
| Other | | 901 |
| | 890 |
|
| Customer deposits | | 282 |
| | 276 |
|
| Accrued taxes | | 238 |
| | 377 |
|
| Accrued interest | | 112 |
| | 105 |
|
| Accrued compensation | | 163 |
| | 221 |
|
| Asset retirement obligations | | 240 |
| | 202 |
|
| Other regulatory liabilities | | 145 |
| | 169 |
|
| Other current liabilities | | 383 |
| | 183 |
|
| Total current liabilities | | 4,484 |
| | 3,909 |
|
| Long-term Debt | | 10,150 |
| | 9,364 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 3,212 |
| | 3,062 |
|
| Deferred credits related to income taxes | | 3,078 |
| | 3,080 |
|
| Accumulated deferred ITCs | | 257 |
| | 262 |
|
| Employee benefit obligations | | 550 |
| | 599 |
|
| Operating lease obligations | | 1,377 |
| | — |
|
| Asset retirement obligations, deferred | | 5,643 |
| | 5,627 |
|
| Other deferred credits and liabilities | | 172 |
| | 139 |
|
| Total deferred credits and other liabilities | | 14,289 |
| | 12,769 |
|
| Total Liabilities | | 28,923 |
| | 26,042 |
|
Common Stockholder's Equity (See accompanying statements) | | 14,316 |
| | 14,323 |
|
| Total Liabilities and Stockholder's Equity | | $ | 43,239 |
| | $ | 40,365 |
|
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA 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, 2017 | 9 |
| | $ | 398 |
| | $ | 7,328 |
| | $ | 4,215 |
| | $ | (10 | ) | | $ | 11,931 |
|
| Net income | — |
| | — |
| | — |
| | 352 |
| | — |
| | 352 |
|
| Capital contributions from parent company | — |
| | — |
| | 1,476 |
| | — |
| | — |
| | 1,476 |
|
| Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
| Cash dividends on common stock | — |
| | — |
| | — |
| | (339 | ) | | — |
| | (339 | ) |
| Other | — |
| | — |
| | 1 |
| | — |
| | (2 | ) | | (1 | ) |
| Balance at March 31, 2018 | 9 |
| | 398 |
| | 8,805 |
| | 4,228 |
| | (11 | ) | | 13,420 |
|
| Net loss | — |
| | — |
| | — |
| | (396 | ) | | — |
| | (396 | ) |
| Capital contributions from parent company | — |
| | — |
| | 29 |
| | — |
| | — |
| | 29 |
|
| Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
| Cash dividends on common stock | — |
| | — |
| | — |
| | (352 | ) | | — |
| | (352 | ) |
| Balance at June 30, 2018 | 9 |
| | $ | 398 |
| | $ | 8,834 |
| | $ | 3,480 |
| | $ | (10 | ) | | $ | 12,702 |
|
| | | | | | | | | | | | |
| 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 (loss) | — |
| | — |
| | — |
| | — |
| | 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 |
|
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
SECOND QUARTER 2019 vs. SECOND QUARTER 2018
AND
YEAR-TO-DATE 2019 vs. YEAR-TO-DATE 2018
OVERVIEW
Georgia Power operates as a vertically integrated utility providing electric service to retail customers within its traditional service territory located within the State of Georgia and to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of Georgia Power's PTCsbusiness of providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales and customers, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, including CCR rules, reliability, fuel, capital expenditures, including new generating facilities and expanding and improving transmission and distribution facilities, and restoration following major storms. Georgia Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Georgia Power for the foreseeable future.
On June 28, 2019, Georgia Power filed a base rate case with the Georgia PSC. The filing includes a three-year Alternate Rate Plan with requested rate increases totaling $563 million, $145 million, and $234 million effective January 1, 2020, January 1, 2021, and January 1, 2022, respectively. The ultimate outcome of this matter cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" – "Rate Plans" herein for additional information.
Georgia Power continues to focus on several key performance indicators, including, but not limited to, customer satisfaction, plant availability, system reliability, the execution of major construction projects, and net income.
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 1,100 MWs each). Georgia Power holds a 45.7% ownership interest in Plant Vogtle Units 3 and 4. In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. In December 2017, the Georgia PSC approved Georgia Power's recommendation to continue construction. The current expected in-service dates remain November 2021 for Unit 3 and November 2022 for Unit 4.
In the second quarter 2018, Georgia Power revised its base capital cost forecast and estimated 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 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), with respect to Georgia Power's ownership interest.
As a result of the 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, 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. 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 certain of MEAG's wholly-owned subsidiaries, including MEAG Power SPVJ, LLC (MEAG SPVJ), to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners and (ii) a term sheet (MEAG Term Sheet) with MEAG and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. On January 14, 2019, Georgia Power, MEAG, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. On February 18, 2019, Georgia Power, the other Vogtle Owners, and certain of MEAG's wholly-owned subsidiaries
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
entered into certain amendments to their joint ownership agreements to implement the provisions of the Vogtle Owner Term Sheet.
In April 2019, Southern Nuclear completed a cost and schedule validation process to verify and update quantities of commodities remaining to install, labor hours to install remaining quantities and related productivity, testing and system turnover requirements, and forecasted staffing needs and related costs. This process confirmed the total estimated project capital cost forecast for Plant Vogtle Units 3 and 4. The expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4, as previously approved by the Georgia PSC, remain unchanged.
In March 2019, Georgia Power entered into the Amended and Restated 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, up to approximately $5.130 billion. At June 30, 2019, Georgia Power had a total of $3.46 billion of borrowings outstanding under the related multi-advance credit facilities.
The ultimate outcome of these matters cannot be determined at this time.
See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" and Note (F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information.
RESULTS OF OPERATIONS
Net Income (Loss)
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $844 | | N/M | | $803 | | N/M |
N/M - Not meaningful
Georgia Power's net income for the second quarter 2019 was $448 million compared to a net loss of $396 million for the corresponding period in 2018. The change was primarily due to a $1.1 billion ($0.8 billion after tax) charge in the second quarter 2018 for an estimated probable loss related to Georgia Power's construction of Plant Vogtle Units 3 and 4 and an increase in retail revenues associated with an increase in the NCCR tariff effective January 1, 2019 and warmer weather in the second quarter 2019 compared to the corresponding period in 2018.
For year-to-date 2019, net income was $759 million compared to a net loss of $44 million for the corresponding period in 2018. The change was primarily due to a $1.1 billion ($0.8 billion after tax) charge in the second quarter 2018 for an estimated probable loss related to Georgia Power's construction of Plant Vogtle Units 3 and 4, an increase in other revenues primarily related to unregulated new energy conservation project sales, and an increase in retail revenues associated with an increase in the NCCR tariff effective January 1, 2019. Partially offsetting the change was a decrease in retail revenues associated with milder weather in the first quarter 2019 compared to the corresponding period in 2018 and higher non-fuel operations and maintenance expenses.
Retail Revenues
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $57 | | 3.0 | | $(74) | | (2.0) |
In the second quarter 2019, retail revenues were $1.95 billion compared to $1.89 billion for the corresponding period in 2018. For year-to-date 2019, retail revenues were $3.61 billion compared to $3.69 billion for the corresponding period in 2018.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of the changes in retail revenues were as follows:
|
| | | | | | | | | | | | | |
| | Second Quarter 2019 | | Year-to-Date 2019 |
| | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | $ | 1,889 |
| | | | $ | 3,688 |
| | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 52 |
| | 2.8 | % | | 61 |
| | 1.7 | % |
| Sales decline | (15 | ) | | (0.8 | ) | | (11 | ) | | (0.3 | ) |
| Weather | 28 |
| | 1.5 |
| | (29 | ) | | (0.8 | ) |
| Fuel cost recovery | (8 | ) | | (0.4 | ) | | (95 | ) | | (2.6 | ) |
| Retail – current year | $ | 1,946 |
| | 3.1 | % | | $ | 3,614 |
| | (2.0 | )% |
Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018. The increases were primarily due to an increase in the NCCR tariff effective January 1, 2019. The year-to-date 2019 increase also reflects the rate pricing effect of decreased customer usage, partially offset by lower contributions from commercial and industrial customers with variable demand-driven pricing. See 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 second quarter and year-to-date 2019 when compared to the corresponding periods in 2018. Weather-adjusted residential KWH sales decreased 0.8% in the second quarter 2019 primarily due to a decline in average customer usage, partially offset by customer growth. Weather-adjusted residential KWH sales increased 0.7% for year-to-date 2019 primarily due to customer growth, partially offset by a decline in average customer usage resulting from increases in energy saving initiatives and multi-family housing. Weather-adjusted commercial KWH sales decreased 1.2% and 1.1% in the second quarter and year-to-date 2019, respectively, primarily due to a decline in average customer usage resulting from an increase in energy saving initiatives, partially offset by customer growth. Weather-adjusted industrial KWH sales decreased 0.9% and 0.7% in the second quarter and year-to-date 2019, respectively, primarily due to decreases in the stone, clay, and glass and textile sectors. Additionally, the decrease in the second quarter 2019 also reflects a decrease in the paper sector and the decrease for year-to-date 2019 was partially offset by an increase in the paper sector.
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 2019 when compared to the corresponding periods in 2018. For year-to-date 2019, the decrease was primarily due to decreased energy sales driven by milder weather in the first quarter 2019, resulting in lower customer demand, and lower generation 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 – "Retail Regulatory Matters – Fuel Cost Recovery" of Georgia Power in Item 7 of the Form 10-K for additional information.
Wholesale Revenues – Non-Affiliates
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(3) | | (8.3) | | $(18) | | (22.5) |
Wholesale revenues from sales to non-affiliates consist of PPAs and short-term opportunity sales. Wholesale revenues from PPAs have both capacity and energy components. Wholesale capacity revenues from PPAs are 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
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
In the second quarter 2019, wholesale revenues from sales to non-affiliates were $33 million compared to $36 million for the corresponding period in 2018. For year-to-date 2019, wholesale revenues from sales to non-affiliates were $62 million compared to $80 million for the corresponding period in 2018. The decrease for year-to-date 2019 was primarily due to a decrease in energy revenues primarily due to lower customer demand and lower energy prices.
Other Revenues
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $15 | | 12.5 | | $43 | | 18.9 |
In the second quarter 2019, other revenues were $135 million compared to $120 million for the corresponding period in 2018. The increase was primarily due to revenue increases of $6 million from unregulated sales associated with new energy conservation projects, $3 million from OATT sales, and $3 million from power delivery maintenance contracts.
For year-to-date 2019, other revenues were $270 million compared to $227 million for the corresponding period in 2018. The increase was primarily due to revenue increases of $11 million from unregulated new energy conservation project sales, $9 million from OATT sales, $8 million from outdoor lighting LED conversions and sales, $4 million from solar application fees, and $3 million from power delivery maintenance contracts.
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | | | |
| | Second Quarter 2019
vs.
Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | 12 |
| | 3.2 |
| | $ | (101 | ) | | (12.8 | ) |
| Purchased power – non-affiliates | 13 |
| | 11.7 |
| | 9 |
| | 3.9 |
|
| Purchased power – affiliates | (44 | ) | | (24.7 | ) | | (39 | ) | | (11.2 | ) |
| Total fuel and purchased power expenses | $ | (19 | ) | | | | $ | (131 | ) | | |
In the second quarter 2019, total fuel and purchased power expenses were $648 million compared to $667 million in the corresponding period in 2018. The decrease was primarily due to a net decrease of $19 million related to the volume of KWHs generated and purchased.
For year-to-date 2019, total fuel and purchased power expenses were $1.24 billion compared to $1.37 billion in the corresponding period in 2018. The decrease was primarily due to a $114 million decrease related to the average cost of fuel and purchased power primarily related to lower energy prices and more rainfall for hydro generation in the first quarter 2019 and a net $17 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 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:
|
| | | | | | | |
| | Second Quarter 2019 | | Second Quarter 2018 | | Year-to-Date 2019 | | Year-to-Date 2018 |
Total generation (in billions of KWHs) | 16 | | 15 | | 29 | | 31 |
Total purchased power (in billions of KWHs) | 6 | | 8 | | 15 | | 14 |
Sources of generation (percent) — | | | | | | | |
| Gas | 45 | | 40 | | 47 | | 42 |
| Coal | 26 | | 29 | | 23 | | 29 |
| Nuclear | 26 | | 28 | | 26 | | 26 |
| Hydro | 3 | | 3 | | 4 | | 3 |
Cost of fuel, generated (in cents per net KWH) — | | | | | | | |
| Gas | 2.48 | | 2.61 | | 2.53 | | 2.67 |
| Coal | 3.18 | | 3.26 | | 3.20 | | 3.31 |
| Nuclear | 0.81 | | 0.83 | | 0.81 | | 0.83 |
Average cost of fuel, generated (in cents per net KWH) | 2.23 | | 2.30 | | 2.22 | | 2.37 |
Average cost of purchased power (in cents per net KWH)(*) | 4.59 | | 4.37 | | 4.23 | | 4.81 |
| |
| (*) | 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 2019, fuel expense was $390 million compared to $378 million in the corresponding period in 2018. The increase was primarily due to a 9.5% increase in the volume of KWHs generated primarily due to warmer weather in the second quarter 2019 compared to the corresponding period in 2018, partially offset by a 3.0% decrease in the average cost of fuel primarily related to lower natural gas and coal prices.
For year-to-date 2019, fuel expense was $689 million compared to $790 million in the corresponding period in 2018. The decrease was primarily due to a 6.9% decrease in the volume of KWHs generated primarily due to scheduled generation outages and milder weather in the first quarter 2019 compared to the corresponding period in 2018, a 6.3% decrease in the average cost of fuel primarily related to lower natural gas and coal prices, and more rainfall for hydro generation in the first quarter 2019.
Purchased Power – Non-Affiliates
In the second quarter 2019, purchased power expense from non-affiliates was $124 million compared to $111 million in the corresponding period in 2018. For year-to-date 2019, purchased power expense from non-affiliates was $242 million compared to $233 million in the corresponding period in 2018. The increases were primarily due to 15.1% and 24.6% increases in the volume of KWHs purchased in the second quarter and year-to-date 2019, respectively, primarily due to scheduled generation outages at Georgia Power-owned generating units, partially offset by 2.3% and 18.7% decreases in the average cost per KWH purchased in the second quarter and year-to-date 2019, respectively, primarily due to lower energy prices.
The volume increases also reflect purchases from Gulf Power which were classified as affiliate prior to January 1, 2019. See Note (K) to the Condensed Financial Statements under "Southern Company" herein for information regarding the sale of Gulf Power.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Purchased Power – Affiliates
In the second quarter 2019, purchased power expense from affiliates was $134 million compared to $178 million in the corresponding period in 2018. The decrease was primarily due to a 26.4% decrease in the volume of KWHs purchased as Georgia Power units generally dispatched at a lower cost than other Southern Company system resources, partially offset by a 2.9% increase in the average cost per KWH purchased.
For year-to-date 2019, purchased power expense from affiliates was $310 million compared to $349 million in the corresponding period in 2018. The decrease was primarily due to an 11.0% decrease in the average cost per KWH purchased primarily resulting from lower energy prices.
The decreases in purchased power expense from affiliates also reflect the classification of capacity expenses of $6 million and $12 million in the second quarter and year-to-date 2019, respectively, related to PPAs with Southern Power accounted for as finance leases following the adoption of FASB ASC Topic 842, Leases (ASC 842). In 2019, these expenses are included in depreciation and amortization and interest expense, net of amounts capitalized. The changes in the volume of KWHs purchased also include the effect of classifying purchases from Gulf Power as non-affiliate beginning January 1, 2019. See Notes (L) and (K) to the Condensed Financial Statements herein for additional information regarding Georgia Power's adoption of ASC 842 and the sale of Gulf Power, respectively.
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 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $6 | | 1.3 | | $50 | | 5.8 |
In the second quarter 2019, other operations and maintenance expenses were $463 million compared to $457 million in the corresponding period in 2018. For year-to-date 2019, other operations and maintenance expenses were $913 million compared to $863 million in the corresponding period in 2018. The increases in the second quarter and year-to-date 2019 reflect adjustments of $8 million and $15 million, respectively, for FERC fees following the conclusion of a multi-year audit of headwater benefits associated with hydro facilities.
The increase in the second quarter 2019 was also due to an increase of $7 million in generation maintenance costs, partially offset by decreases of $5 million in distribution overhead line operation and maintenance costs and $5 million in employee benefit expenses.
The increase for year-to-date 2019 was also due to increases of $14 million in scheduled generation outage expenses, $10 million related to affiliate labor billing credits received in 2018, and $9 million of expenses associated with unregulated new energy conservation project sales, partially offset by a decrease of $7 million in customer accounts and sales expenses.
Depreciation and Amortization
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $14 | | 6.1 | | $25 | | 5.5 |
In the second quarter 2019, depreciation and amortization was $244 million compared to $230 million in the corresponding period in 2018. For year-to-date 2019, depreciation and amortization was $483 million compared to $458 million in the corresponding period in 2018. The increases were primarily due to additional plant in service and reflect the classification of approximately $2 million and $4 million in the second quarter and year-to-date 2019, respectively, related to PPAs with Southern Power accounted for as finance leases following the adoption of
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ASC 842. In prior periods, the expenses related to these PPAs were included in purchased power, affiliates. See Note (L) to the Condensed Financial Statements herein for additional information regarding Georgia Power's adoption of ASC 842.
Estimated Loss on Plant Vogtle Units 3 and 4 |
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(1,060) | | N/M | | $(1,060) | | N/M |
N/M - Not meaningful
In the second quarter 2018, an estimated probable loss of $1.1 billion was recorded to reflect Georgia Power's revised estimate to complete construction and start-up of Plant Vogtle Units 3 and 4, which reflects the increase in costs included in the revised base capital cost forecast for which Georgia Power did not seek rate recovery and costs included in the revised construction contingency estimate for which Georgia Power may seek rate recovery as and when such costs are appropriately included in the base capital cost forecast. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information.
Interest Expense, Net of Amounts Capitalized
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $3 | | 2.9 | | $(7) | | (3.4) |
In the second quarter 2019, interest expense, net of amounts capitalized was $105 million compared to $102 million in the corresponding period in 2018. For year-to-date 2019, interest expense, net of amounts capitalized was $201 million compared to $208 million in the corresponding period in 2018. The decrease for year-to-date 2019 was primarily due to a $15 million decrease in interest expense associated with a decrease in average outstanding borrowings, partially offset by the reclassification of $8 million related to PPAs with Southern Power accounted for as finance leases following the adoption of ASC 842. In prior periods, the expenses related to these PPAs were included in purchased power, affiliates. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings and Note (L) to the Condensed Financial Statements herein for additional information regarding Georgia Power's adoption of ASC 842.
Income Taxes (Benefit)
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 |
| Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) |
| (% change) |
| (change in millions) | | (% change) |
| $272 |
| N/M |
| $261 | | N/M |
N/M - Not meaningful
In the second quarter 2019, income taxes were $129 million compared to an income tax benefit of $143 million in the corresponding period in 2018. For year-to-date 2019, income taxes were $211 million compared to an income tax benefit of $50 million in the corresponding period in 2018. The changes were primarily due to the reduction in pre-tax earnings (loss) in the second quarter 2018 resulting from the charge associated with Plant Vogtle Units 3 and 4 construction, partially offset by an increase in state ITCs. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of 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
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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, continued customer growth, and the weak pace of growth in electricity use per customer, especially in residential and commercial markets. Plant Vogtle Units 3 and 4 construction and rate recovery are also major factors. 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 more multi-family home construction, all of which could contribute to a net reduction in customer usage. 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 growth that may be affected by changes in regional and global economic conditions, which may impact future earnings.
For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Georgia Power in Item 7 of the Form 10-K.
Environmental Matters
Georgia Power's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. Georgia Power maintains comprehensive environmental compliance and GHG strategies to assess upcoming requirements and compliance costs associated with these environmental laws and regulations and to achieve stated goals. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, or changing fuel sources for certain existing units, as well as related upgrades to Georgia Power's transmission and distribution systems, and may impact future electric generating unit retirement and replacement decisions, results of operations, cash flows, and/or financial condition. A major portion of these costs is expected to be recovered through retail rates. The ultimate impact of environmental laws and regulations and GHG goals will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed technology, fuel prices, and the outcome of pending and/or future legal challenges.
New or revised environmental laws and regulations could affect many areas of Georgia Power's operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be 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. Further, increased costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and/or financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Georgia Power in Item 7 and Note 3 to the financial statements under "Environmental Remediation" in Item 8 of the Form 10-K for additional information.
Global Climate Issues
On July 8, 2019, the EPA published the final Affordable Clean Energy rule (ACE Rule) to repeal and replace the CPP. Implementation of the CPP has been stayed by the U.S. Supreme Court since 2016. The ACE Rule requires states to develop unit-specific CO2 emission rate standards for existing coal-fired units based on heat-rate efficiency improvements. Combustion turbines, including natural gas combined cycles, are not included as affected sources in the ACE Rule. Georgia Power has ownership interests in nine coal-fired units to which the ACE Rule is applicable. The ultimate impact of the ACE Rule, including the repeal and replacement of the CPP, to Georgia Power will depend on state implementation plan requirements and the outcome of any associated legal challenges and cannot be determined at this time.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FERC Matters
See Note 2 to the financial statements under "FERC Matters – Open Access Transmission Tariff" in Item 8 of the Form 10-K for additional information.
On June 28, 2019, the FERC approved a settlement agreement between Alabama Municipal Electric Authority and Cooperative Energy and SCS and the traditional electric operating companies (including Georgia Power) agreeing to an OATT rate reduction based on a 10.6% ROE, with a retroactive effective date of May 10, 2018, and a five-year moratorium on these parties seeking changes to the OATT formula rate. The terms of the OATT settlement agreement will not have a material impact on the financial statements of Georgia Power.
Retail Regulatory Matters
Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, ECCR tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to 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. See Note 2 to the financial statements under "Georgia Power" in Item 8 of the Form 10-K for additional information regarding regulatory matters.
Rate Plans
On June 28, 2019, Georgia Power filed a base rate case (Georgia Power 2019 Base Rate Case) with the Georgia PSC. The filing includes a three-year Alternate Rate Plan with requested rate increases totaling $563 million, $145 million, and $234 million effective January 1, 2020, January 1, 2021, and January 1, 2022, respectively. These increases are based on a proposed retail ROE of 10.90% and a proposed equity ratio of 56% and reflect levelized revenue requirements during the three-year period, with the exception of incremental compliance costs related to CCR AROs, Demand-Side Management programs, and adjustments to the Municipal Franchise Fee tariff.
Georgia Power has requested recovery of the proposed increases through its existing base rate tariffs as follows:
|
| | | | | | | | | |
| Tariff | 2020 | 2021 | 2022 |
| | (in millions) |
| Traditional base: | | | |
| Levelized | $ | 209 |
| $ | — |
| $ | — |
|
| CCR AROs | 158 |
| 140 |
| 227 |
|
| ECCR | 165 |
| — |
| — |
|
| Demand-Side Management | 14 |
| 2 |
| 1 |
|
| Municipal Franchise Fee | 17 |
| 3 |
| 5 |
|
Total(*) | $ | 563 |
| $ | 145 |
| $ | 234 |
|
| |
| (*) | Totals may not add due to rounding. |
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Georgia Power's filing primarily reflects requests to (i) address the impacts of the Tax Reform Legislation, (ii) recover the costs of recent and future capital investments in infrastructure designed to maintain high levels of reliability and superior customer service with updated depreciation rates, (iii) recover substantial storm damage expenses incurred and deferred since 2013 along with a reasonable level of storm damage expenses expected to be incurred during the three years ending December 31, 2022, and (iv) recover the costs necessary to comply with federal and state regulations for CCR AROs. In addition, the filing includes the following provisions:
Continuation of an allowed retail ROE range of 10.00% to 12.00%.
Continuation of the process whereby two-thirds of any earnings above the top of the allowed ROE range are shared with Georgia Power's customers and the remaining one-third are retained by Georgia Power.
Continuation of the option to file an Interim Cost Recovery tariff in the event earnings are projected to fall below the bottom of the ROE range during the three-year term of the plan.
Georgia Power expects the Georgia PSC to issue a final order in this matter on December 17, 2019. The ultimate outcome of this matter cannot be determined at this time.
Integrated Resource Plan
In 2016, the Georgia PSC approved Georgia Power's triennial Integrated Resource Plan, including recovery of costs up to $99 million through June 30, 2019 to preserve nuclear generation as an option at a future generation site in Stewart County, Georgia. In 2017, the Georgia PSC approved Georgia Power's decision to suspend work at the site due to changing economics, including lower load forecasts and fuel costs. In accordance with the Georgia PSC's order, costs incurred of approximately $50 million have been recorded as a regulatory asset.
On July 16, 2019, the Georgia PSC voted to approve Georgia Power's triennial Integrated Resource Plan (2019 IRP) as modified by a stipulated agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors and further modified by the Georgia PSC.
In the 2019 IRP, the Georgia PSC approved the decertification and retirement of Plant Hammond Units 1 through 4 (840 MWs) and Plant McIntosh Unit 1 (142.5 MWs) effective July 29, 2019. The Georgia PSC also approved the reclassification of the remaining net book values of the Plant Hammond and Plant McIntosh units (approximately $500 million and $40 million, respectively, at June 30, 2019), as well as any unusable materials and supplies inventory balances, upon retirement to a regulatory asset. Recovery of each unit's net book value will continue through December 31, 2019 as provided in the 2013 ARP.
For the regulatory asset balances remaining at December 31, 2019, Georgia Power requested recovery in the Georgia Power 2019 Base Rate Case as follows: (i) the net book values of Plant Mitchell Unit 3 (approximately $8 million at June 30, 2019) and Plant McIntosh Unit 1, any unusable materials and supplies inventory, and the future generation site in Stewart County, Georgia over a three-year period ending December 31, 2022 and (ii) the net book values of Plant Hammond Units 1 through 4 over a period equal to the applicable unit's remaining useful life through 2035. The ultimate outcome of these matters cannot be determined at this time.
Also in the 2019 IRP, the Georgia PSC rejected a request to certify approximately 25 MWs of capacity at Plant Scherer Unit 3 for the retail jurisdiction beginning January 1, 2020 following the expiration of a wholesale PPA. Georgia Power may offer such capacity in the wholesale market or to the retail jurisdiction in a future Integrated Resource Plan. The ultimate outcome of this matter cannot be determined at this time but is not expected to have a material impact on Georgia Power's financial statements.
Additionally, the Georgia PSC approved Georgia Power's proposed environmental compliance strategy associated with ash pond and certain landfill closures and post-closure care in compliance with the CCR Rule and the related state rule. In the Georgia Power 2019 Base Rate Case, Georgia Power requested recovery of the under recovered balance of these compliance costs at December 31, 2019 (approximately $135 million at June 30, 2019) over a three-year period ending December 31, 2022 and recovery of estimated compliance costs of $277 million for 2020, $395 million for 2021, and $655 million for 2022 over three-year periods ending December 31, 2022, 2023, and
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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2024, respectively. The ultimate outcome of this matter cannot be determined at this time. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information regarding Georgia Power's AROs.
The Georgia PSC also approved Georgia Power to (i) issue requests for proposals (RFP) for capacity beginning in 2022 or 2023 and in 2026, 2027, or 2028; (ii) procure up to an additional 2,210 MWs of renewable resources through competitive RFPs; and (iii) invest in a portfolio of up to 80 MWs of battery energy storage technologies.
See "Rate Plans" herein for additional information regarding the Georgia Power 2019 Base Rate Case.
Nuclear Construction
See Note 2 to the financial statements under "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, the joint ownership agreements and related funding agreement, VCM reports, and the NCCR tariff.
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. Georgia Power holds a 45.7% ownership interest in Plant Vogtle Units 3 and 4. 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 $400 million per unit.1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement. In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into several transitional arrangements to allow construction to continue. In July 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 time and materials cost basis. The Vogtle Services Agreement provides that it will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.
In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, executed the Bechtel Agreement, a cost reimbursable plus fee arrangement, whereby Bechtel is 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 the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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) | $ | 8.0 |
|
| Construction contingency estimate | 0.4 |
|
Total project capital cost forecast(a)(b) | 8.4 |
|
Net investment as of June 30, 2019(b) | (5.2 | ) |
Remaining estimate to complete(a) | $ | 3.2 |
|
| |
| (a) | Excludes financing costs expected to be capitalized through AFUDC of approximately $315 million. |
| |
| (b) | Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds. |
Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $2.0 billion had been incurred through June 30, 2019.
In April 2019, Southern Nuclear completed a cost and schedule validation process to verify and update quantities of commodities remaining to install, labor hours to install remaining quantities and related productivity, testing and system turnover requirements, and forecasted staffing needs and related costs. This process confirmed the estimated total project capital cost forecast for Plant Vogtle Units 3 and 4. The expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4, as previously approved by the Georgia PSC, remain unchanged.
As construction continues and testing and system turnover activities increase, challenges with management of contractors, subcontractors, and vendors; supervision of craft labor and related craft labor productivity, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, and/or installation and the initial testing and start-up, including any required engineering changes, of plant systems, structures, or components (some of which are based on new technology that only recently began initial operation in the global nuclear industry at this scale), or regional transmission upgrades, any of which may require additional labor and/or materials; or other issues could arise and change the projected schedule and estimated cost.
The April 2019 cost and schedule validation process established target values for monthly construction production and system turnover activities as part of a strategy to maintain and, where possible, build margin to the approved in-service dates. To support that strategy, monthly production and activity target values will continue to increase significantly throughout 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers (particularly electrical and pipefitter craft labor), as well as additional supervision and other field support resources, must be retained and deployed.
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.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 resolutionsubmittal by Southern Nuclear of Inspections, Tests, Analyses, and Acceptance Criteriathe ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel, 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 ultimate outcome of these matters cannot be determined at this time. However, any extension of 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 impactregulatory-approved project schedule is currently estimated to result in additional base capital costs of approximately $50
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
million per month, based on Georgia Power's ownership interests, and cost.AFUDC of approximately $12 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 entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 to provide for, among other conditions, additional Vogtle Owner approval requirements. Effective in August 2018, the 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 to continue construction (as amended, and together with the November 2017 amendment, the Vogtle Joint Ownership Agreements). The Vogtle Joint Ownership Agreements also confirm 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 the 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, 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) the Vogtle Owner Term Sheet with the other Vogtle Owners and MEAG's wholly-owned subsidiaries 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) the MEAG Term Sheet with MEAG and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. On January 14, 2019, Georgia Power, MEAG, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. On February 18, 2019, Georgia Power, the other Vogtle Owners, and MEAG'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.
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 Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. At June 30, 2019, Georgia Power had recovered approximately $2.0 billion of financing costs. Financing costs related to capital costs above $4.418 billion will be recovered through AFUDC; however, Georgia Power will not record AFUDC related to any 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 2018, the Georgia PSC approved Georgia Power's request to increase the NCCR tariff by $88 million annually, effective January 1, 2019.
Georgia Power is required to file semi-annual VCM reports with the Georgia PSC 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
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
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 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 should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (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 impact of payments received under the Guarantee 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 revised cost forecast 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 ROE used to calculate the NCCR tariff (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, (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 in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 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 base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective Unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $100 million in 2018 and are estimated to have negative earnings impacts of approximately $70 million in 2019 and an aggregate of approximately $630 million from 2020 to 2022.
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 two appeals. On January 9, 2019, GIPL, PSE, and Georgia Watch filed an appeal of this decision with the Georgia Court of Appeals. Georgia Power believes the appeal has no merit; however, an adverse outcome in the appeal combined with subsequent adverse action by the Georgia PSC could have a material impact on Georgia Power's results of operations, financial condition, and liquidity.
In August 2018, Georgia Power filed its nineteenth VCM report with the Georgia PSC, which requested approval of $578 million of construction capital costs incurred from January 1, 2018 through June 30, 2018. On February 19, 2019, the Georgia PSC approved the nineteenth VCM, but deferred approval of $51.6 million of expenditures related to Georgia Power's portion of an administrative claim filed in the Westinghouse bankruptcy proceedings. Through the nineteenth VCM, the Georgia PSC has approved total construction capital costs incurred through June
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
30, 2018 of $5.4 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds).
On April 30, 2019, as requested by the staff of the Georgia PSC, Georgia Power reported the results of the cost and schedule validation process to the Georgia PSC. On August 30, 2019, Georgia Power will file its twentieth VCM report concurrently with its twenty-first VCM report with the Georgia PSC, which will reflect the capital cost forecast discussed previously and request approval of $1.2 billion of construction capital costs incurred from June 30, 2018 through June 30, 2019. In addition, on June 20, 2019, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a settlement agreement related to the administrative claim filed in the Westinghouse bankruptcy proceedings. Accordingly, in the twentieth/twenty-first VCM report, Georgia Power will also request approval of the $51.6 million of associated expenditures previously deferred by the Georgia PSC.
The ultimate outcome of these matters cannot be determined at this time.
See RISK FACTORS of Georgia Power in Item 1A of the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world.
DOE Financing
At June 30, 2019, Georgia Power had borrowed $3.46 billion related to Plant Vogtle Units 3 and 4 costs as provided through the Amended and Restated Loan Guarantee Agreement and related multi-advance credit facilities among Georgia Power, the DOE, and the FFB, which provide for borrowings of up to approximately $5.130 billion, subject to the satisfaction of certain conditions. See additional risksNote 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 1A8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein regarding the EPC Contractor's bankruptcy.for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
The ultimate outcome of these matters cannot be determined at this time.
Other Matters
Georgia Power is involved in various other matters that could affect future earnings, including matters being litigated and regulatory matters that could affect future earnings.matters. 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 regulationlaws and regulations governing air, water, land, and protection of air emissions and water discharges.other natural resources. 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 qualitylaws and water standards,regulations, 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 cannot be predicteddetermined at this time; however, for current proceedings not specifically reported in NoteNotes (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 Georgia Power's financial statements. See NoteNotes (B) and (C) 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.
Litigation
In 2011, plaintiffs filed a putative class action against Georgia Power regularly reviews its businessin 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 transformmunicipalities) exceeded the amounts allowed in orders of the Georgia PSC and modernize. Primarily in responsealleging certain state tort law claims. In 2016, the Georgia Court of Appeals reversed the trial court's previous dismissal of the case and remanded the case to changing customer expectations and payment patterns, including electronic payments and alternative payment locations, and ongoing efforts to increase overall operating efficiencies,the trial court. Georgia Power initiatedfiled a petition for writ of certiorari with the closureGeorgia Supreme
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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Court, which was granted in 2017. In June 2018, the Georgia Supreme Court affirmed the judgment of the Georgia Court of Appeals and an employee attrition plan affecting approximately 300 positions. Charges associatedremanded the case to the trial court for further proceedings. Following a motion by Georgia Power, on February 13, 2019, the Superior Court of Fulton County ordered the parties to submit petitions to the Georgia PSC for a declaratory ruling to address certain terms the court previously held were ambiguous as used in the Georgia PSC's orders. The order entered by the Superior Court of Fulton County also conditionally certified the proposed class. In March 2019, Georgia Power and the plaintiffs filed petitions with these activities did notthe Georgia PSC seeking confirmation of the proper application of the municipal franchise fee schedule pursuant to the Georgia PSC's orders. Georgia Power also filed a notice of appeal with the Georgia Court of Appeals regarding the Superior Court of Fulton County's February 2019 order. Georgia Power believes the plaintiffs' claims have a material impact on Georgia Power's resultsno merit. The amount of operations, financial position, or cash flows.any possible losses cannot be calculated at this time because, among other factors, it is unknown whether conditional class certification will be upheld and the ultimate composition of any class and whether any losses would be subject to recovery from any municipalities. The efficiencies gained are expected to place downward pressure on operating costs in 2018.ultimate outcome of this matter cannot be determined at this time.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Georgia Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in NoteNotes 1, 5, and 6 to the financial statements of Georgia Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Georgia Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Georgia Power in Item 7 of the Form 10-K for a complete discussion of Georgia Power's critical accounting policies and estimates related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, and Contingent Obligations.estimates.
Recently Issued Accounting Standards
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Georgia Power in Item 7 ofNote (A) to the Form 10-KCondensed Financial Statements herein 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 disclosuresinformation 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 Georgia Power's financial statements, if material. In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Georgia Power expects CIAC to be out of the scope of ASC 606.
The 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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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 hedgerecently adopted 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.standards.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Georgia Power in Item 7 of the Form 10-K for additional information. Georgia Power's financial condition remained stable at SeptemberJune 30, 2017.2019. 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$1.1 billion for the first ninesix months of 2017 compared to $2.27 billion for the corresponding period in 2016. The decrease was primarily due to the timing of vendor payments2019 and fossil fuel stock purchases and an increase in under-recovered fuel costs.2018. Net cash used for investing activities totaled $1.83$1.8 billion for the first ninesix months of 2017 compared to $1.76 billion for the corresponding period in 20162019 primarily related to installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities.facilities, including approximately $660 million related to the construction of Plant Vogtle Units 3 and 4. Net cash provided from financing activities totaled $617$620 million for the first ninesix 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 is2019 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, the reoffering of pollution control revenue bonds, and an increase in redemptionsshort-term borrowings, partially offset by payment of short-term borrowings.common stock dividends and the redemption and repurchase of pollution control revenue bonds. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first ninesix months of 20172019 include increasesrecording $1.5 billion in operating lease right-of-use assets, net of amortization and $1.5 billion in operating lease obligations related to the adoption of ASC 842, an increase of $1.2 billion in property, plant, and equipment to comply with environmental standards and the
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
construction of generation, transmission, and distribution facilities, and an increase of $1.2 billion in long-term debt (including securities due within one year) primarily due to issuancesborrowings from the FFB for construction of senior notesPlant Vogtle Units 3 and junior subordinated notes, $423 million in accounts payable, other primarily due to charges for restoration costs related to Hurricane Irma4 and liabilities for the removalreoffering of subcontractor liens relatedpollution control revenue bonds previously purchased and held by Georgia Power. See Note (L) to the EPC Contractor's bankruptcy,Condensed Financial Statements herein for additional information on the adoption of ASC 842. Also see Notes (B) and $423 million in paid-in capital primarily due(F) to capital contributions received from Southern Company. See FUTURE EARNINGS POTENTIALthe Condensed Financial Statements under "Georgia Power – Nuclear Construction"Retail Regulatory Matters – Storm Damage Recovery" and " – Nuclear ConstructionDOE Loan Guarantee Borrowings," respectively, herein for additional information regarding Hurricane IrmaPlant Vogtle Units 3 and 4 and the EPC Contractor's bankruptcy, respectively.related Amended and Restated Loan Guarantee Agreement.
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.contractual obligations. Approximately $261$988 million will be required through SeptemberJune 30, 20182020 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 statuteslaws 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. The construction program also includes Plant Vogtle Units 3 and 4, which includes components based on new technology that only recently began initial operation in the global nuclear industry at this scale and which may be subject to additional revised cost estimates during construction. The ability to control costs and avoid cost and schedule overruns during the development, construction, and operation of new facilities is subject to a number of factors, including, but not limited to, changes in labor costs, availability, and productivity; challenges with management of contractors, subcontractors, or vendors; adverse weather conditions; shortages, delays, increased costs, or inconsistent quality of equipment, materials, and labor; contractor or supplier delay; 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 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, system integration, or regional transmission upgrades; and/or operational performance. See Note 32 to the financial statements of Georgiaunder "Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory MattersGeorgia Power – 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.expenditures.
Sources of Capital
Georgia Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, external security issuances, term loans,borrowings from financial institutions, 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,approvals, 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 a loan guarantee agreement with the DOE and, in March 2019, entered into the Amended and Restated 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
reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4.
Under the Amended and Restated Loan Guarantee Agreement, the DOE has agreed to guarantee the obligations of Georgia Power under note purchase agreements among the DOE, Georgia Power, and the FFB and related promissory notes which provide for two multi-advance term loan facilities (FFB Credit Facilities). Under the FFB Credit Facilities, Georgia Power may make term loan borrowings ofthrough the FFB in an amount up to $3.46approximately $5.130 billion, (not toprovided that total aggregate borrowings under the FFB Credit Facilities may not exceed 70% of (i) Eligible Project Costs lessminus (ii) approximately $1.492 billion (reflecting the amounts received from Toshibaby Georgia Power under the Guarantee Settlement Agreement and amounts received fromless 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 SeptemberCustomer Refunds). At June 30, 2017,2019, Georgia Power had borrowed $2.6$3.46 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.Facilities.
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)(F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information regarding the Amended and Restated 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 MattersGeorgia Power – 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. At June 30, 2019, Georgia Power intendsPower's current liabilities exceeded current assets by $2.0 billion primarily due to utilize operating cash flows, short-termlong-term debt external security issuances, term loans, equity contributions from Southern Company,that is due within one year of $988 million 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.notes payable of $555 million.
At SeptemberJune 30, 2017,2019, Georgia Power had approximately $266$10 million of cash and cash equivalents. Georgia Power'sequivalents and a multi-year committed credit arrangement with banks at September 30, 2017 wastotaling $1.75 billion, of which $1.73$1.74 billion was unused. In May 2017,2019, Georgia Power amended its multi-yearbank credit arrangement which, among other things, extended the maturity date from 20202022 to 2022.
2024. This bank credit arrangement, as well as Georgia Power's term loan arrangements, containscontain a covenant that limits debt levels and containscontain a cross-acceleration provision to other indebtedness (including guarantee obligations) of Georgia Power. Such cross-acceleration provisionprovisions to other indebtedness would trigger an event of default if Georgia Power defaulted on indebtedness, the payment of which was then accelerated. At SeptemberJune 30, 2017,2019, Georgia Power was in compliance with this covenant. ThisThe 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 68 to the financial statements of Georgia Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E)(F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
A portion of the $1.74 billion unused bank credit with banksarrangement is allocated to provide liquidity support to Georgia Power's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of SeptemberJune 30, 20172019 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.million. In addition, at SeptemberJune 30, 2017,2019, Georgia Power had $509$185 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 isShort-term borrowings are included in notes payable in the balance sheets.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of short-term borrowings were as follows:
| | | | | Short-term Debt at September 30, 2017 | | Short-term Debt During the Period(*) | Short-term Debt at June 30, 2019 | | Short-term Debt During the Period(*) |
| | | Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding | Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) | | | | (in millions) | (in millions) | | | | (in millions) | | | | (in millions) |
| Commercial paper | | $ | — |
| | — | % | | $ | 109 |
| | 1.5 | % | | $ | 428 |
| $ | 305 |
| | 2.7 | % | | $ | 288 |
| | 2.7 | % | | $ | 485 |
|
| Short-term bank debt | | 400 |
| | 2.0 | % | | 568 |
| | 2.0 | % | | 800 |
| 250 |
| | 2.9 | % | | 69 |
| | 2.9 | % | | 250 |
|
| Total | | $ | 400 |
| | 2.0 | % | | $ | 677 |
| | 2.0 | % | | | $ | 555 |
| | 2.8 | % | | $ | 357 |
| | 2.8 | % | | |
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended SeptemberJune 30, 2017.2019. |
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 SeptemberJune 30, 2017,2019, Georgia Power did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, and transmission.construction of new generation at Plant Vogtle Units 3 and 4.
The maximum potential collateral requirements under these contracts at SeptemberJune 30, 20172019 were as follows:
| | | Credit Ratings | Maximum Potential
Collateral
Requirements | Maximum Potential
Collateral
Requirements |
| | (in millions) | (in millions) |
| At BBB- and/or Baa3 | $ | 87 |
| $ | 92 |
|
| Below BBB- and/or Baa3 | $ | 1,021 |
| $ | 1,040 |
|
Included in these amounts are certain agreements that could require collateral in the event that Georgia Power or Alabama Power (an affiliate of 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 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 PowerAs a result of the Tax Reform Legislation, certain financial metrics, such as the funds from stableoperations to negative.
On March 24, 2017, S&P revised its consolidateddebt percentage, used by the credit rating outlook foragencies to assess Southern Company and its subsidiaries, (includingincluding Georgia Power) from stablePower, may be negatively impacted. A settlement agreement between Georgia Power and the staff of the Georgia PSC regarding the retail rate impact of the Tax Reform Legislation, as approved by the Georgia PSC in April 2018, is expected to negative.help mitigate these potential adverse impacts to certain credit metrics by allowing a higher retail equity ratio through 2019, which Georgia Power has requested to extend in the Georgia Power 2019 Base Rate Case. See Note (B) to the Condensed Financial Statements and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Rate Plans" for additional information, including requests for additional capital structure adjustments.
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,January 2019, Georgia Power issued $450redeemed approximately $13 million, $20 million, and $75 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2017A 2.00% Senior Notes due1992, Eighth Series 1994, and Second Series 1995, respectively.
In March 30, 20202019, Georgia Power made additional borrowings under the FFB Credit Facilities in an aggregate principal amount of $835 million at an interest rate of 3.213% through the final maturity date of February 20, 2044. The proceeds were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and $4004.
Also in March 2019, Georgia Power reoffered to the public the following pollution control revenue bonds that previously had been purchased and held by Georgia Power:
$173 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2017B 3.25% Senior Notes due March 30, 2027. The proceeds were used to repay a portion2009;
approximately $105 million aggregate principal amount of Georgia Power's short-term indebtednessDevelopment Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2013; and for general corporate purposes, including Georgia Power's continuous construction program.
$65 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2008.
In April 2017,2019, Georgia Power purchased and held $27the following pollution control revenue bonds. In May 2019, Georgia Power reoffered these pollution control revenue bonds to the public.
$55 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fourth Series 1994;
$30 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fourth Series 1995;
$20 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Ninth Series 1994; and
$10 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 1994.
In June 2019, Georgia Power reoffered to the public $55 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1995. Subsequent to September 30, 2017,1994, which had been previously purchased and held by Georgia Power remarketed these bonds to the public.Power.
InAlso in June 2017, Georgia Power repaid at maturity $450 million aggregate principal amount of Series 2007B 5.70% Senior Notes.
In June 2017,2019, Georgia Power entered into threetwo short-term floating rate bank loans in aggregate principal amounts of $50$125 million $150 million, and $100 million, with maturity dateseach, both 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" in Item 8 of the Form 10-K for additional information.
Details of Gulf 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) | 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 cost of fuel resulting from lower coal 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 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 $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 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) |
| $(5) | | (5.8) | | $13 | | 5.4 |
In the third quarter 2017, other operations and maintenance expenses were $81 million compared to $86 million for the corresponding period in 2016. The decrease was primarily due to lower employee compensation and benefits, including pension costs, and the suspension of the property damage reserve accrual in accordance with the 2017 Rate Case Settlement Agreement.
For year-to-date 2017, other operations 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 were 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 rules and cannot be determined at this time, but could have a material impact on Gulf Power's financial statements. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Gulf Power in Item 7 of the Form 10-K.
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in retail rates or through long-term wholesale agreements on a timely 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.
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 resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause rate approved by the Florida PSC in November 2016.
Cost Recovery Clauses
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Cost Recovery Clauses" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K for additional information regarding Gulf Power's recovery of retail costs through various regulatory clauses and accounting orders. Gulf Power has four regulatory clauses which are approved by the Florida PSC. See Note (B) to the Condensed Financial Statements herein for additional information.
As discussed previously, the 2017 Rate Case Settlement Agreement resolved the remaining issues related to Gulf Power's inclusion of certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 in the environmental cost recovery clause and no adjustment to the environmental cost recovery clause rate approved by the Florida PSC in November 2016 was made.
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 application of these policies, certain estimates are made that may have a material impact on Gulf Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Gulf Power in Item 7 of the Form 10-K for a complete discussion of Gulf Power's critical accounting policies and estimates related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, and Contingent Obligations.
Recently Issued Accounting Standards
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, 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, | For the Three Months
Ended June 30, | | For the Six Months
Ended June 30, |
| | 2017 | | 2016 | | 2017 | | 2016 | 2019 | | 2018 | | 2019 | | 2018 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | | | | | | | | |
| Retail revenues | $ | 243 |
| | $ | 263 |
| | $ | 665 |
| | $ | 652 |
| $ | 215 |
| | $ | 212 |
| | $ | 418 |
| | $ | 406 |
|
| Wholesale revenues, non-affiliates | 72 |
| | 78 |
| | 196 |
| | 198 |
| 57 |
| | 59 |
| | 114 |
| | 127 |
|
| Wholesale revenues, affiliates | 21 |
| | 7 |
| | 40 |
| | 23 |
| 37 |
| | 19 |
| | 58 |
| | 54 |
|
| Other revenues | 5 |
| | 4 |
| | 14 |
| | 12 |
| 4 |
| | 7 |
| | 10 |
| | 11 |
|
| Total operating revenues | 341 |
| | 352 |
| | 915 |
| | 885 |
| 313 |
| | 297 |
| | 600 |
| | 598 |
|
| Operating Expenses: | | | | | | | | | | | | | | |
| Fuel | 120 |
| | 112 |
| | 301 |
| | 268 |
| 105 |
| | 98 |
| | 198 |
| | 197 |
|
| Purchased power, non-affiliates | 4 |
| | 3 |
| | 7 |
| | 4 |
| |
| Purchased power, affiliates | 2 |
| | 5 |
| | 13 |
| | 14 |
| |
| Purchased power | | 6 |
| | 7 |
| | 9 |
| | 16 |
|
| Other operations and maintenance | 66 |
| | 74 |
| | 206 |
| | 211 |
| 68 |
| | 67 |
| | 127 |
| | 141 |
|
| Depreciation and amortization | 39 |
| | 30 |
| | 120 |
| | 114 |
| 48 |
| | 44 |
| | 95 |
| | 84 |
|
| Taxes other than income taxes | 25 |
| | 31 |
| | 77 |
| | 81 |
| 28 |
| | 27 |
| | 55 |
| | 54 |
|
| Estimated loss on Kemper IGCC | 34 |
| | 88 |
| | 3,155 |
| | 222 |
| 4 |
| | — |
| | 6 |
| | 45 |
|
| Total operating expenses | 290 |
| | 343 |
| | 3,879 |
| | 914 |
| 259 |
| | 243 |
| | 490 |
| | 537 |
|
| Operating Income (Loss) | 51 |
| | 9 |
| | (2,964 | ) | | (29 | ) | |
| Operating Income | | 54 |
| | 54 |
| | 110 |
| | 61 |
|
| 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 | ) | (17 | ) | | (21 | ) | | (35 | ) | | (39 | ) |
| Other income (expense), net | (1 | ) | | (1 | ) | | (3 | ) | | (4 | ) | 5 |
| | 27 |
| | 11 |
| | 27 |
|
| Total other income and (expense) | 13 |
| | 15 |
| | 46 |
| | 40 |
| (12 | ) | | 6 |
| | (24 | ) | | (12 | ) |
| 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 |
| |
| Earnings Before Income Taxes | | 42 |
| | 60 |
| | 86 |
| | 49 |
|
| Income taxes | | 5 |
| | 13 |
| | 12 |
| | 9 |
|
| Net Income | | 37 |
| | 47 |
| | 74 |
| | 40 |
|
| Dividends on Preferred Stock | — |
| | — |
| | 1 |
| | 1 |
| — |
| | 1 |
| | — |
| | 1 |
|
| Net Income (Loss) After Dividends on Preferred Stock | $ | 40 |
| | $ | 26 |
| | $ | (2,034 | ) | | $ | 39 |
| |
| Net Income After Dividends on Preferred Stock | | $ | 37 |
| | $ | 46 |
| | $ | 74 |
| | $ | 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 |
|
|
| | | | | | | | | | | | | | | |
| | For the Three Months
Ended June 30, | | For the Six Months
Ended June 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
| | (in millions) | | (in millions) |
| Net Income | $ | 37 |
| | $ | 47 |
| | $ | 74 |
| | $ | 40 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
| Changes in fair value, net of tax of $-, $-, $-, and $(1), 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 | $ | 37 |
| | $ | 47 |
| | $ | 75 |
| | $ | 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, | For the Six Months
Ended June 30, |
| | 2017 | | 2016 | 2019 | | 2018 |
| | (in millions) | (in millions) |
| Operating Activities: | | | | | | |
| Net income (loss) | $ | (2,033 | ) | | $ | 40 |
| |
| Adjustments to reconcile net income (loss) to net cash provided from operating activities — | | | | |
| Net income | | $ | 74 |
| | $ | 40 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | | |
| Depreciation and amortization, total | 144 |
| | 115 |
| 98 |
| | 86 |
|
| Deferred income taxes | (1,159 | ) | | 34 |
| (16 | ) | | 289 |
|
| Allowance for equity funds used during construction | (72 | ) | | (90 | ) | |
| Settlement of asset retirement obligations | | (17 | ) | | (15 | ) |
| Estimated loss on Kemper IGCC | 3,148 |
| | 222 |
| 11 |
| | 28 |
|
| Other, net | (26 | ) | | (1 | ) | 1 |
| | 2 |
|
| Changes in certain current assets and liabilities — | | | | | | |
| -Receivables | 438 |
| | 3 |
| (8 | ) | | (51 | ) |
| -Fossil fuel stock | 21 |
| | 8 |
| |
| -Other current assets | (9 | ) | | 34 |
| (3 | ) | | (11 | ) |
| -Accounts payable | (21 | ) | | 5 |
| (28 | ) | | (15 | ) |
| -Accrued taxes | 20 |
| | 96 |
| (43 | ) | | (41 | ) |
| -Accrued compensation | (12 | ) | | (5 | ) | (15 | ) | | (14 | ) |
| -Over recovered regulatory clause revenues | (47 | ) | | (20 | ) | |
| -Customer liability associated with Kemper refunds | — |
| | (73 | ) | |
| -Other current liabilities | (31 | ) | | 5 |
| 6 |
| | (1 | ) |
| Net cash provided from operating activities | 361 |
| | 373 |
| 60 |
| | 297 |
|
| Investing Activities: | | | | | | |
| Property additions | (411 | ) | | (592 | ) | (95 | ) | | (74 | ) |
| Construction payables | (47 | ) | | (25 | ) | (12 | ) | | (9 | ) |
| Government grant proceeds | — |
| | 137 |
| |
| Payments pursuant to LTSAs | | (11 | ) | | (13 | ) |
| Other investing activities | (25 | ) | | (29 | ) | (10 | ) | | (12 | ) |
| Net cash used for investing activities | (483 | ) | | (509 | ) | (128 | ) | | (108 | ) |
| Financing Activities: | | | | | | |
| Decrease in notes payable, net | (23 | ) | | — |
| — |
| | (4 | ) |
| Proceeds — | | | | | | |
| Senior notes | | — |
| | 600 |
|
| Short-term borrowings | | — |
| | 300 |
|
| Capital contributions from parent company | 1,002 |
| | 227 |
| 7 |
| | 1 |
|
| Long-term debt to parent company | 40 |
| | 200 |
| |
| Pollution control revenue bonds | | 43 |
| | — |
|
| Redemptions — | | | | |
| Other long-term debt | — |
| | 900 |
| — |
| | (900 | ) |
| Short-term borrowings | 113 |
| | — |
| — |
| | (200 | ) |
| Redemptions — | | | | |
| Short-term borrowings | (109 | ) | | (475 | ) | |
| Long-term debt to parent company | (591 | ) | | (225 | ) | |
| Other long-term debt | (300 | ) | | (425 | ) | |
| Return of capital | | (75 | ) | | — |
|
| Other financing activities | (3 | ) | | (5 | ) | (1 | ) | | (6 | ) |
| 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 |
| |
| Net cash used for financing activities | | (26 | ) | | (209 | ) |
| Net Change in Cash, Cash Equivalents, and Restricted Cash | | (94 | ) | | (20 | ) |
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | | 293 |
| | 248 |
|
| Cash, Cash Equivalents, and Restricted Cash at End of Period | | $ | 199 |
| | $ | 228 |
|
| 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 |
| |
| Interest (net of $(1) and $- capitalized for 2019 and 2018, respectively) | | $ | 36 |
| | $ | 39 |
|
| Income taxes, net | (209 | ) | | (231 | ) | 23 |
| | (257 | ) |
| Noncash transactions — Accrued property additions at end of period | 32 |
| | 80 |
| 23 |
| | 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 September 30, 2017 | | At December 31, 2016 | | At June 30, 2019 | | At December 31, 2018 |
| | | (in millions) | | (in millions) |
| Current Assets: | | | | | | | | |
| Cash and cash equivalents | | $ | 231 |
| | $ | 224 |
| | $ | 199 |
| | $ | 293 |
|
| Receivables — | | | | | | | | |
| Customer accounts receivable | | 38 |
| | 29 |
| | 38 |
| | 34 |
|
| Unbilled revenues | | 41 |
| | 42 |
| | 44 |
| | 41 |
|
| Income taxes receivable, current | | 102 |
| | 544 |
| |
| Affiliated | | | 17 |
| | 21 |
|
| Other accounts and notes receivable | | 15 |
| | 14 |
| | 38 |
| | 31 |
|
| Affiliated | | 15 |
| | 15 |
| |
| Fossil fuel stock | | 20 |
| | 100 |
| | 23 |
| | 20 |
|
| Materials and supplies | | 45 |
| | 76 |
| | 52 |
| | 53 |
|
| Other regulatory assets, current | | 113 |
| | 115 |
| |
| Other regulatory assets | | | 107 |
| | 116 |
|
| Other current assets | | 8 |
| | 8 |
| | 13 |
| | 19 |
|
| Total current assets | | 628 |
| | 1,167 |
| | 531 |
| | 628 |
|
| Property, Plant, and Equipment: | | | | | | | | |
| In service | | 4,836 |
| | 4,865 |
| | 4,800 |
| | 4,900 |
|
| Less: Accumulated provision for depreciation | | 1,312 |
| | 1,289 |
| | 1,427 |
| | 1,429 |
|
| Plant in service, net of depreciation | | 3,524 |
| | 3,576 |
| | 3,373 |
| | 3,471 |
|
| Construction work in progress | | 75 |
| | 2,545 |
| | 113 |
| | 103 |
|
| Total property, plant, and equipment | | 3,599 |
| | 6,121 |
| | 3,486 |
| | 3,574 |
|
| Other Property and Investments | | 28 |
| | 12 |
| | 124 |
| | 24 |
|
| Deferred Charges and Other Assets: | | | | | | | | |
| Deferred charges related to income taxes | | 62 |
| | 361 |
| | 33 |
| | 33 |
|
| Regulatory assets – asset retirement obligations | | | 207 |
| | 143 |
|
| Other regulatory assets, deferred | | 436 |
| | 518 |
| | 328 |
| | 332 |
|
| Accumulated deferred income taxes | | 279 |
| | — |
| | 145 |
| | 150 |
|
| Other deferred charges and assets | | 23 |
| | 56 |
| | 20 |
| | 2 |
|
| Total deferred charges and other assets | | 800 |
| | 935 |
| | 733 |
| | 660 |
|
| Total Assets | | $ | 5,055 |
| | $ | 8,235 |
| | $ | 4,874 |
| | $ | 4,886 |
|
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 | | At June 30, 2019 | | At December 31, 2018 |
| | | (in millions) | | (in millions) |
| Current Liabilities: | | | | | | | | |
| Securities due within one year — | | | | | |
| Parent | | $ | — |
| | $ | 551 |
| |
| Other | | 1,028 |
| | 78 |
| |
| Notes payable | | 4 |
| | 23 |
| |
| Securities due within one year | | | $ | 300 |
| | $ | 40 |
|
| Accounts payable — | | | | | | | | |
| Affiliated | | 56 |
| | 62 |
| | 60 |
| | 60 |
|
| Other | | 82 |
| | 135 |
| | 49 |
| | 90 |
|
| Customer deposits | | 16 |
| | 16 |
| |
| Accrued taxes | | 78 |
| | 99 |
| | 52 |
| | 95 |
|
| Unrecognized tax benefits | | 2 |
| | 383 |
| |
| Accrued interest | | 16 |
| | 46 |
| | 15 |
| | 15 |
|
| Accrued compensation | | 29 |
| | 42 |
| | 23 |
| | 38 |
|
| Asset retirement obligations, current | | 15 |
| | 32 |
| |
| Over recovered fuel clause liabilities | | 4 |
| | 51 |
| |
| Accrued plant closure costs | | | 24 |
| | 29 |
|
| Asset retirement obligations | | | 27 |
| | 34 |
|
| Other regulatory liabilities | | | 20 |
| | 12 |
|
| Over recovered regulatory clause liabilities | | | 12 |
| | 14 |
|
| Other current liabilities | | 67 |
| | 20 |
| | 52 |
| | 28 |
|
| Total current liabilities | | 1,397 |
| | 1,538 |
| | 634 |
| | 455 |
|
| Long-term Debt | | 1,167 |
| | 2,424 |
| | 1,318 |
| | 1,539 |
|
| Deferred Credits and Other Liabilities: | | | | | | | | |
| Accumulated deferred income taxes | | — |
| | 756 |
| | 366 |
| | 378 |
|
| Deferred credits related to income taxes | | | 362 |
| | 382 |
|
| Employee benefit obligations | | 109 |
| | 115 |
| | 110 |
| | 115 |
|
| Asset retirement obligations, deferred | | 150 |
| | 146 |
| | 177 |
| | 126 |
|
| Other cost of removal obligations | | 175 |
| | 170 |
| | 189 |
| | 185 |
|
| Other regulatory liabilities, deferred | | 87 |
| | 84 |
| | 79 |
| | 81 |
|
| Other deferred credits and liabilities | | 23 |
| | 26 |
| | 22 |
| | 16 |
|
| Total deferred credits and other liabilities | | 544 |
| | 1,297 |
| | 1,305 |
| | 1,283 |
|
| Total Liabilities | | 3,108 |
| | 5,259 |
| | 3,257 |
| | 3,277 |
|
| 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 |
| |
Common Stockholder's Equity (See accompanying statements) | | | 1,617 |
| | 1,609 |
|
| Total Liabilities and Stockholder's Equity | | $ | 5,055 |
| | $ | 8,235 |
| | $ | 4,874 |
| | $ | 4,886 |
|
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, 2017 | 1 |
| | $ | 38 |
| | $ | 4,529 |
| | $ | (3,205 | ) | | $ | (4 | ) | | $ | 1,358 |
|
Net loss after dividends on
preferred stock | — |
| | — |
| | — |
| | (7 | ) | | — |
| | (7 | ) |
| Capital contributions from parent company | — |
| | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
| Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | (1 | ) | | (1 | ) |
| Other | — |
| | — |
| | — |
| | (1 | ) | | — |
| | (1 | ) |
| Balance at March 31, 2018 | 1 |
| | 38 |
| | 4,531 |
| | (3,213 | ) | | (5 | ) | | 1,351 |
|
Net income after dividends on
preferred stock | — |
| | — |
| | — |
| | 46 |
| | — |
| | 46 |
|
| Other | — |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
|
| Balance at June 30, 2018 | 1 |
| | $ | 38 |
| | $ | 4,531 |
| | $ | (3,166 | ) | | $ | (5 | ) | | $ | 1,398 |
|
| | | | | | | | | | | | |
| 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 | — |
| | — |
| | — |
| | 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 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRDSECOND QUARTER 20172019 vs. THIRDSECOND QUARTER 20162018
AND
YEAR-TO-DATE 20172019 vs. YEAR-TO-DATE 20162018
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 number of customers 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 ongoingincluding CCR rules, reliability, fuel, capital and operations and maintenance expenditures, required for maintenanceincluding expanding and improving transmission and distribution facilities, and restoration following major storms. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Mississippi Power for the foreseeable future. Mississippi Power is scheduled to file a base rate case in the fourth quarter 2019 (Mississippi Power 2019 Base Rate Case).
TheOn May 7, 2019, the FERC accepted Mississippi Power's March 28, 2019 request for a decrease in wholesale base revenues under the MRA tariff as agreed upon in a settlement agreement reached with its wholesale customers (MRA Settlement Agreement) resolving all matters related to the Kemper IGCC wasCounty energy facility similar to the retail rate settlement agreement approved by the Mississippi PSC in February 2018 and reflecting the 2010 CPCN proceedings, subject to a construction cost capimpacts of $2.88 billion, net of $245 million of grants awardedthe Tax Reform Legislation. Pursuant 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), authorizingMRA Settlement Agreement, base rates that provide for the recovery of approximately $126decreased $3.7 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, see2019. See Note 32 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle""FERC Matters" 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.for additional information.
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.income.
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 |
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(9) | | (19.6) | | $35 | | 89.7 |
Mississippi Power's net income after dividends on preferred stock for the thirdsecond quarter 20172019 was $40$37 million compared to $26$46 million for the corresponding period in 2016. The increase2018. This decrease was primarily due to lower pre-tax charges associated with the Kemper IGCCsettlement of Mississippi Power's Deepwater Horizon claim in May 2018 and a decrease in interest expense, net of amounts capitalized,retail revenues due to a new tolling arrangement accounted for as a sales-type lease, partially offset by an increase in PEP rates that became effective for the first billing cycle of September 2018.
For year-to-date 2019, net 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$74 million compared to net income of $39 million for the corresponding period in 2016. The decrease in net income2018. This increase was relatedprimarily due to higher pre-taxlower charges associated with the Kemper IGCC.
See Note 3IGCC in 2019 and an increase in PEP rates that became effective for the first billing cycle of September 2018, partially offset by a decrease in other income (expense), net due to the financial statementssettlement of Mississippi Power under "Integrated Coal Gasification Combined Cycle"Power's Deepwater Horizon claim in Item 8 of the Form 10-KMay 2018 and Note (B)a decrease in retail revenues due to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" hereina new tolling arrangement accounted for additional information.as a sales-type lease.
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 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $3 | | 1.4 | | $12 | | 3.0 |
In the thirdsecond quarter 2017,2019, retail revenues were $243$215 million compared to $263$212 million for the corresponding period in 2016.2018. For year-to-date 2017,2019, retail revenues were $665$418 million compared to $652$406 million for the corresponding period in 2016.2018.
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. |
| | | | | | | | | | | | | |
| | Second Quarter 2019 | | Year-to-Date 2019 |
| | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | $ | 212 |
| | | | $ | 406 |
| | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 11 |
| | 5.2 | % | | 26 |
| | 6.4 | % |
| Sales decline | (1 | ) | | (0.5 | ) | | — |
| | — |
|
| Weather | — |
| | — |
| | (9 | ) | | (2.2 | ) |
| Fuel and other cost recovery | (7 | ) | | (3.3 | ) | | (5 | ) | | (1.2 | ) |
| Retail – current year | $ | 215 |
| | 1.4 | % | | $ | 418 |
| | 3.0 | % |
Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 20172019 when compared to the corresponding periods in 2018 primarily due to increases in PEP and ECO Plan rates that became effective for the first billing cycle of September 2018, partially offset by a new tolling arrangement accounted for as a sales-type lease effective January 2019. Partially offsetting the year-to-date 2019 increase was a rate decrease related to the Kemper County energy facility that became effective for the first billing cycle of April 2018. See Note 2 to the financial statements under "Mississippi Power – Performance Evaluation Plan," " – Environmental Compliance Overview Plan," and " – Kemper County Energy Facility – Rate Recovery" in Item 8 of the Form 10-K and Note (L) to the Condensed Financial Statements herein for additional information.
Revenues attributable to changes in sales decreased in the second quarter 2019 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 assets2018. Weather-adjusted residential KWH sales increased 0.4% and an ECO Plan rate decrease implemented1.0% in the second quarter 2017.
See Note (B)and year-to-date 2019, respectively, due to increased customer usage. Weather-adjusted commercial KWH sales decreased 2.1% and 2.7% in the Condensed Financial Statements under "Regulatory Matters – Mississippi Power – Environmental Compliance Overview Plan"second quarter and "Integrated Coal Gasification Combined Cycle" herein for additional information.year-to-date 2019, respectively, due to decreased customer usage. Industrial KWH sales decreased 3.1% and 3.5% in the second quarter and year-to-date 2019, respectively, primarily due to decreased customer usage by several large industrial customers.
Revenues attributable to changes in sales increased slightlyassociated with weather decreased for the third quarter 2017year-to-date 2019 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%2018 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.milder weather.
Fuel and other cost recovery revenues decreased in the thirdsecond quarter 2017and year-to-date 2019 when compared to the corresponding periodperiods in 20162018 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.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale Revenues – Non-Affiliates
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(2) | | (3.4) | | $(13) | | (10.2) |
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Mississippi Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. In addition, Mississippi Power provides service under long-term contracts with rural electric cooperative associations and municipalities located in southeastern Mississippi under cost-based electric tariffs which are subject to regulation by the FERC. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Mississippi Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "FERC Matters" herein for additional information.
For year-to-date 2019, wholesale revenues from sales to non-affiliates were $114 million compared to $127 million for the corresponding period in 2018. This decrease primarily resulted from a $6 million decrease in cost-based electric tariff revenues due to decreased customer usage, milder weather, and a decrease in rates due to the MRA Settlement Agreement, a $5 million decrease due to lower PPA capacity and energy sales, and a $3 million decrease due to lower fuel prices, partially offset by a $1 million increase in opportunity sales. See Note (B) to the Condensed Financial Statements under "Mississippi Power – Municipal and Rural Association Tariff" herein 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) |
| $14 | | N/M | | $17 | | 73.9 |
N/M - Not meaningful |
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $18 | | 94.7 | | $4 | | 7.4 |
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.
In the thirdsecond quarter 2017,2019, wholesale revenues from sales to affiliates were $21$37 million compared to $7$19 million for the corresponding period in 2016.2018. The increase was primarily due to a $13$15 million increase inassociated with higher KWH sales as a resultdue to the dispatch of supportingMississippi Power's lower cost generation resources to serve the Southern Company system transmission reliabilitysystem's territorial load and a $1$2 million increase primarily due toassociated with a higher natural gas prices.average sales price.
For year-to-date 2017,2019, wholesale revenues from sales to affiliates were $40$58 million compared to $23$54 million for the corresponding period in 2016.2018. The increase was primarily due to a $25 million increase associated with higher KWH sales as a resultdue to the dispatch of supportingMississippi Power's lower cost generation resources to serve the Southern Company system transmission reliability and highersystem's territorial load, partially offset by a $21 million decrease associated with lower natural gas prices.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel and Purchased Power Expenses
| | | | Third Quarter 2017
vs.
Third Quarter 2016 | | Year-to-Date 2017
vs.
Year-to-Date 2016 | Second Quarter 2019
vs.
Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | 8 |
| | 7.1 | | $ | 33 |
| | 12.3 | $ | 7 |
| | 7.1 | | $ | 1 |
| | 0.5 |
| Purchased power – non-affiliates | 1 |
| | 33.3 | | 3 |
| | 75.0 | |
| Purchased power – affiliates | (3 | ) | | (60.0) | | (1 | ) | | (7.1) | |
| Purchased power | | (1 | ) | | (14.3) | | (7 | ) | | (43.8) |
| Total fuel and purchased power expenses | $ | 6 |
| | $ | 35 |
| | $ | 6 |
| | $ | (6 | ) | |
In the thirdsecond quarter 2017,2019, total fuel and purchased power expenses were $126$111 million compared to $120$105 million for the corresponding period in 2016.2018. The increase was primarily due to a $6$13 million net increase inassociated with the volume of KWHs generated and purchased.purchased, partially offset by a net decrease of $7 million associated with lower average cost of fuel.
For year-to-date 2017,2019, total fuel and purchased power expenses were $321$207 million compared to $286$213 million for the corresponding period in 2016.2018. The increasedecrease was primarily due to a $42$13 million increase indecrease related to the average cost of fuel and purchased power primarily due to a lower average cost of natural gas, and purchased power, partially offset by a $4$7 million decrease in coal prices and a $3 million decrease innet 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.
Details of Mississippi Power's generation and purchased power were as follows:
|
| | | | | | | |
| | Second Quarter 2019 | | Second Quarter 2018 | | Year-to-Date 2019 | | Year-to-Date 2018 |
Total generation (in millions of KWHs) | 4,621 | | 4,081 | | 8,570 | | 8,084 |
Total purchased power (in millions of KWHs) | 88 | | 104 | | 139 | | 207 |
Sources of generation (percent) – | | | | | | | |
| Coal | 8 | | 7 | | 6 | | 6 |
| Gas | 92 | | 93 | | 94 | | 94 |
Cost of fuel, generated (in cents per net KWH) – | | | | | | | |
| Coal | 3.92 | | 3.42 | | 4.06 | | 3.49 |
| Gas | 2.29 | | 2.51 | | 2.37 | | 2.56 |
Average cost of fuel, generated (in cents per net KWH) | 2.43 | | 2.58 | | 2.48 | | 2.61 |
Average cost of purchased power (in cents per net KWH) | 6.53 | | 6.55 | | 6.56 | | 7.77 |
Fuel
In the second quarter 2019, fuel expense was $105 million compared to $98 million for the corresponding period in 2018. For year-to-date 2019, fuel expense was $198 million compared to $197 million for the corresponding period in 2018. These increases were due to a 14% and 6% increase in the volume of KWHs generated in the second quarter and year-to-date 2019, respectively, partially offset by a 9% and 7% decrease in the average cost of natural gas for the second quarter and year-to-date 2019, respectively.
Purchased Power
For year-to-date 2019, purchased power expense was $9 million compared to $16 million for the corresponding period in 2018. The decrease was primarily due to a 33% decrease in the volume of KWHs purchased due to lower territorial load and a 16% decrease due to a lower average cost of purchased power.
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. EnergyThese purchases from affiliates 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) |
| $(8) | | (10.8) | | $(5) | | (2.4) |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1 | | 1.5 | | $(14) | | (9.9) |
In the third quarter 2017,For year-to-date 2019, other operations and maintenance expenses were $66$127 million compared to $74$141 million for the corresponding period in 2016.2018. The decrease was primarily due to a $5decreases of $10 million decrease in transmission and distribution expenses related to generation maintenance, primarily due to planned outages, and $6 million in employee compensation and benefit expenses due to an employee attrition plan implemented in the third quarter 2018, partially offset by a $4 million increase related to additional overhead line maintenance and a $4 million decrease related to decreases in employee compensationvegetation management.
Depreciation and benefitsAmortization
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $4 | | 9.1 | | $11 | | 13.1 |
In the second quarter 2019, depreciation and corporate advertising.
For year-to-date 2017, other operations and maintenance expenses were $206amortization was $48 million compared to $211$44 million for the corresponding period in 2016. The decrease2018. For year-to-date 2019, depreciation and amortization was primarily due$95 million compared to a $6$84 million decreasefor the corresponding period in transmission and distribution expenses2018. These increases were primarily related to overhead line maintenanceincreases in amortization associated with ECO Plan regulatory assets. See Note 2 to the financial statements under "Mississippi Power – Environmental Compliance Overview Plan" in Item 8 of the Form 10-K for additional information.
Estimated Loss on Kemper IGCC
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $4 | | N/M | | $(39) | | (86.7) |
N/M - Not meaningful
In the second quarter and a $5 million decrease related to decreases in employee compensation and benefits and corporate advertising, partially offset by a $5 million increase associated withyear-to-date 2019, estimated losses on the Kemper IGCC in-servicewere $4 million and $6 million, respectively, compared to an immaterial amount and $45 million, respectively, for the corresponding periods in 2018. These charges relate to abandonment and closure activities for the mine and gasifier-related assets.
See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Mississippi Power – Kemper County Energy Facility" herein for additional information.
Interest Expense, Net of Amounts Capitalized
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(4) | | (19.0) | | $(4) | | (10.3) |
In the second quarter 2019, interest expense, net of amounts capitalized was $17 million compared to $21 million for the corresponding period in 2018. For year-to-date 2019, interest expense, net of amounts capitalized was $35
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$39 million for the corresponding period in 2016. The increase2018. These decreases primarily resulted from a decrease in average outstanding debt.
Other Income (Expense), Net
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(22) | | (81.5) | | $(16) | | (59.3) |
In the second quarter 2019, other income (expense), net 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$5 million compared to $114$27 million for the corresponding period in 2016. The increase2018. For year-to-date 2019, other income (expense), net 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$11 million compared to $31$27 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 2016.2018. These decreases were primarily due to a $24 million decrease in franchise taxes of $5 million and $4 million for the thirdsecond quarter and year-to-date 2017, respectively, as well as a decrease2019 due to the settlement of Mississippi Power's Deepwater Horizon claim recorded in payroll taxesMay 2018, partially offset by increases 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$3 million and $3.2 billion were recorded$6 million in the thirdsecond quarter and year-to-date 2017,2019, respectively, compareddue 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 subjecthigher interest income associated with a new tolling arrangement accounted for as a sales-type lease. See Note (L) 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,Condensed Financial Statements herein 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 ofunder "Other Matters – Mississippi Power under "Integrated Coal Gasification Combined Cycle"Power" in Item 8 of the Form 10-K for additional information.
Income Taxes
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(8) | | (61.5) | | $3 | | 33.3 |
In the second quarter 2019, income taxes were $5 million compared to $13 million for the corresponding period in 2018. This decrease was due to lower pre-tax earnings and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" andan increase in the flowback of excess deferred income taxes as a result of the MRA Settlement Agreement.
For year-to-date 2019, income taxes were $12 million compared to $9 million for the corresponding period in 2018. This increase was primarily due to higher pre-tax earnings resulting from lower estimated losses on the Kemper IGCC, partially offset by an increase in the flowback of excess deferred income taxes as a result of the MRA Settlement Agreement.
See 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) |
| $(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)
|
| | | | | | |
| 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"Mississippi Power" 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 continued customer growth.growth and the weak pace of growth in electricity use per customer, especially in residential and commercial markets. 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.transactions, both of which could contribute to a net reduction in customer usage. 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
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FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.RESULTS OF OPERATIONS
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.10-K.
Environmental Matters
ComplianceMississippi Power's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. Mississippi Power maintains comprehensive environmental compliance and GHG strategies to assess upcoming requirements and compliance costs related to federal and stateassociated with these environmental statuteslaws and regulations and to achieve stated goals. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, or changing fuel sources for certain existing units, as well as related upgrades to Mississippi Power's transmission and distribution systems, and may impact future electric generating unit retirement and replacement decisions, results of operations, cash flows, and/or financial condition. A major portion of these costs is expected to be recovered through retail and wholesale rates. The ultimate impact of environmental laws and regulations and GHG goals will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed technology, fuel prices, and the outcome of pending and/or future legal challenges.
New or revised environmental laws and regulations could affect many areas of Mississippi Power's operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs 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, higherincreased costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, andand/or financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Mississippi Power in Item 7 and Note 3 to the financial statements under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Laws and Regulations
Coal Combustion Residuals
In June 2019, Mississippi Power recorded an increase of approximately $58 million to its AROs for higher expected compliance costs related to the CCR Rule (and the related State of Alabama rule, as applicable). Approximately $49 million of the revised cost estimates are associated with an ash pond at Plant Greene County, which is jointly owned with Alabama Power. The additional estimated costs to close this ash pond under the planned closure-in-place methodology primarily relate to cost inputs from contractor bids, internal drainage and dewatering system designs, and an increase in the estimated ash volume.
As further analysis is performed and additional details are developed with respect to ash pond closures, Mississippi Power expects to periodically update its ARO cost estimates. Additionally, the closure designs and plans in the State of Alabama are subject to approval by environmental regulatory agencies. Absent continued recovery of ARO costs through regulated rates, Mississippi Power's results of operations, cash flows, and financial condition could be materially impacted. The ultimate outcome of this matter cannot be determined at this time. See Note 6 to the financial statements in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
Global Climate Issues
On July 8, 2019, the EPA published the final Affordable Clean Energy rule (ACE Rule) to repeal and replace the CPP. Implementation of the CPP has been stayed by the U.S. Supreme Court since 2016. The ACE Rule requires states to develop unit-specific CO2 emission rate standards for existing coal-fired units based on heat-rate efficiency improvements. Combustion turbines, including natural gas combined cycles, are not included as affected sources in
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the ACE Rule. Mississippi Power has ownership interests in Item 7two coal-fired units to which the ACE Rule is applicable. The ultimate impact of the ACE Rule, including the repeal and replacement of the CPP, to Mississippi Power will depend on state implementation plan requirements and the outcome of any associated legal challenges and cannot be determined at this time.
FERC Matters
See Note 32 to the financial statements of Mississippi Power under "Environmental"FERC 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 AssociationsAssociation 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 byOn May 7, 2019, the FERC accepted Mississippi Power's March 28, 2019 request for an increasea decrease in wholesale base revenues under the MRA cost-based electric tariff primarily as a result of placing scrubbers for Plant Daniel Units 1 and 2agreed upon in service in 2015. Thethe MRA Settlement Agreement resolving all matters related to the Kemper County energy facility similar to the retail rate settlement agreement became effective for services rendered beginning May 1, 2016, resultingapproved by the Mississippi PSC in an estimated annual revenue increaseFebruary 2018 and reflecting the impacts of $7 million underthe Tax Reform Legislation. Pursuant to the MRA cost-based electric tariff. Additionally, underSettlement Agreement, base rates decreased $3.7 million annually, effective January 1, 2019.
Open Access Transmission Tariff
On June 28, 2019, the FERC approved a 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 operationalbetween Alabama Municipal Electric Authority and providing service to customersCooperative Energy and other related costs, (ii)
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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 deferredSCS 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) agreeing to an OATT rate reduction based on a 10.6% ROE, with a retroactive effective date of May 10, 2018, 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 responsefive-year moratorium on these parties seeking changes to the traditional electric operating companies' (including Mississippi Power's) and Southern Power's June 30, 2017 triennial updated market power analysis.OATT formula rate. 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.
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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 forOATT settlement agreement will not have a material impact on the purchasefinancial statements 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.Mississippi Power.
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 under PEP 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. Mississippi Power is scheduled to file a base rate case in the fourth quarter 2019.
See Note 32 to the financial statements of Mississippi Power under "Retail Regulatory Matters" and "Integrated Coal Gasification Combined Cycle""Mississippi Power" 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, 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.
On November 15, 2017, Mississippi Power is expected to make its annual PEP filing for 2018. Retail rate adjustments under PEP are limited to 4% of annual retail revenue and are subject to Mississippi PSC approval.
The ultimate outcome of these matters cannot be determined at this time.
Energy Efficiency
On July 6, 2017, the Mississippi PSC issued an order approving Mississippi Power's Energy Efficiency Cost Rider compliance filing, which increased annual retail revenues by approximately $2 million effective with the first billing cycle for August 2017.
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Environmental Compliance Overview Plan
On May 4, 2017,July 9, 2019, Mississippi Power filed a request with the Mississippi PSC approved Mississippi Power's ECO Plan filing for 2017, which requested the maximum 2% annual increase in revenues, approximately $18 million,a Certificate of Public Convenience and Necessity to complete certain environmental compliance projects, primarily related toassociated with the Plant Daniel Units 1 and 2 scrubbers placed in service in 2015.coal units co-owned 50% with Gulf Power. The rates became effectivetotal estimated cost is approximately $125 million, with the first billing cycleMississippi Power's share of approximately $66 million being proposed for June 2017.recovery through its ECO Plan. Approximately $26$17 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. The ultimate outcome of this matter cannot be determined at this time.
Ad Valorem Tax Adjustment
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 millionshare is associated with ash pond closure and is reflected in annual retail revenues, primarily due to increased assessments.
Provision for Property Damage
On October 8, 2017, Hurricane Nate hit the Gulf Coast of Mississippi causing minor damage to Mississippi Power's distribution infrastructure. Preliminary storm damage repair costs have been estimated to be immaterial. These costs may be chargedARO liabilities. See Note (A) to the retail property damage reserveCondensed Financial Statements under "Asset Retirement Obligations" herein for additional information on AROs and addressedNote (C) to the Condensed Financial Statements under "Other Matters – Mississippi Power" herein for additional information on Gulf Power's ownership in a subsequent System Restoration Rider rate filing. The ultimate outcome of this matter cannot be determined at this time.Plant Daniel.
Integrated Coal Gasification Combined CycleKemper County Energy Facility
See Note 32 to the financial statements of Mississippiunder "Mississippi Power under "Integrated Coal Gasification Combined Cycle"– Kemper County Energy Facility" 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 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
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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 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. 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 Company, LLC 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 8As a result 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 scheduleabandonment of the Kemper IGCC, final mine reclamation began in 2018 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 Courtis expected 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 engagebe substantially completed 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.2020,
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On June 9, 2016, Treetop, Greenleaf CO2 Solutions, LLC (Greenleaf), Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC,with monitoring expected to continue through 2027. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.
During the second quarter and Tellus Operating Group filed a complaint againstyear-to-date 2019, Mississippi Power Southern Company,recorded pre-tax charges to income of $4 million ($3 million after tax) and SCS$6 million ($5 million after tax), respectively, primarily resulting from the abandonment and related closure activities and ongoing period costs, net of sales proceeds, for the mine and gasifier-related assets at the Kemper County energy facility. Additional closure costs for the mine and gasifier-related assets, currently estimated at up to $10 million pre-tax (excluding dismantlement costs, net of salvage), may be incurred through the first half of 2020. In addition, period costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the mine and gasifier-related assets, are estimated at $7 million for the remainder of 2019 and $2 million to $6 million annually 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 of2020 through 2023.
In addition, Mississippi Power Southern Company,constructed the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery and SCS and seeks compensatory damagesis currently evaluating its options regarding the final disposition of $100 million, as well as unspecified punitive damages. Southern Company,the CO2 pipeline, including removal of the pipeline. This evaluation is expected to be complete later in 2019. If Mississippi Power and SCS movedultimately decides to compel arbitration pursuant toremove the termsCO2 pipeline, the cost 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 couldremoval would have a material impact on Mississippi Power's results of operations, financial condition, and liquidity.statements.
In December 2018, Mississippi Power will vigorously defend itselffiled with the DOE its request for property closeout certification under the contract related to the $387 million of grants received. Mississippi Power and the DOE are currently in these matters,discussions regarding the requested closeout and property disposition, which may require payment to the DOE for a portion of certain property that is to be retained by Mississippi Power. In connection with the DOE closeout discussions, on April 29, 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 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, thetime; however, they could have a material impact on 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.Power's financial statements.
Income Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Mississippi Power in Item 7 of the Form 10-K and Note (G) to the Condensed Financial Statements under "Section 174 Research and Experimental Deduction" herein for additional information 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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Other Matters
Mississippi Power is involved in various other matters that could affect future earnings, including matters being litigated and regulatory matters that could affect future earnings.matters. 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 regulationlaws and regulations governing air, water, land, and protection of air emissions and water discharges.other natural resources. 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 qualitylaws and water standards,regulations, 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 predicteddetermined at this time; however, for current proceedings not specifically reported in NoteNotes (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 Mississippi Power's financial statements. See NoteNotes (B) and (C) 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.
In conjunction with Southern Company's sale of Gulf Power, Mississippi Power and Gulf Power have committed to seek a restructuring of their 50% undivided ownership interests in Plant Daniel such that each of them would, after the restructuring, own 100% of a generating unit. On January 15, 2019, Gulf Power provided notice to Mississippi Power that Gulf Power will retire its share of the generating capacity of Plant Daniel on January 15, 2024. Mississippi Power has the option to purchase Gulf Power's ownership interest for $1 on January 15, 2024, provided that Mississippi Power exercises the option no later than 120 days prior to that date. Mississippi Power is assessing the potential operational and economic effects of Gulf Power's notice. The SEC is conducting a formal investigationultimate outcome of these matters remains subject to completion of Mississippi Power's evaluations and applicable regulatory approvals, including by
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the FERC and the Mississippi PSC, and cannot be determined at this time. See Note (K) to the Condensed Financial Statements under "Southern Company" herein for information regarding the sale of Gulf Power.
Litigation
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.
In May 2018, Southern Company and Mississippi Power concerningreceived 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 estimatedamount of approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and expected in-service dateinterest. In the first quarter 2019, Mississippi Power and Southern Company filed motions to dismiss, which were denied by the arbitration panel on May 10, 2019.
In November 2018, Ray C. Turnage and 10 other individual plaintiffs filed a putative class action complaint against Mississippi Power and the three current members of the Kemper IGCC.Mississippi PSC in the U.S. District Court for the Southern Company andDistrict of Mississippi. Mississippi Power believe the investigation is focused primarily on periods subsequentreceived Mississippi PSC approval in 2013 to 2010charge a mirror CWIP rate premised upon including in its rate base pre-construction and on accounting matters, disclosure controls and procedures, and internal controls over financial reporting associated withconstruction costs for the Kemper IGCC. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" herein for additional information onIGCC prior to placing the Kemper IGCC.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 on March 14, 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.
Mississippi Power believes these legal challenges have no merit; however, an adverse outcome in either of these proceedings could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity. The ultimate outcome of this matterthese matters cannot be determined at this time; however, it is not expected to have a material impact on the financial statements of Mississippi Power.time.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Mississippi Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in NoteNotes 1, 5, and 6 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.estimates.
Kemper IGCC Rate RecoveryRecently Issued Accounting Standards
For periods priorSee Note (A) 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-KCondensed Financial Statements herein 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 asinformation regarding 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 andrecently adopted accounting standards.
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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 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 Mississippi 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 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
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energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs. Mississippi Power expects that the revenue from contracts with these customers will not result in a significant shift in the timing of revenue recognition for such sales.
Mississippi Power's ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements, such as alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Mississippi Power's financial statements, if material. In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Mississippi Power expects CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Mississippi Power intends to 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.
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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 revisions to the cost estimate for the Kemper IGCC.
Mississippi Power's cash requirements primarily consist of funding ongoing operations, common stock dividends, capital expenditures, and debt maturities are expected to materially exceed operating cash flows through 2022. Projected capitalmaturities. Capital expenditures in that periodand other investing activities include investments to maintain existing generation facilities, to addcomply with environmental regulations including adding environmental modifications to certain existing generating units and closures of ash ponds, to expand and improve transmission and distribution facilities.facilities, and for restoration following major storms.
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$60 million for the first ninesix months of 2017,2019, a decrease of $12$237 million as compared to the corresponding period in 2016.2018. The decrease in net cash provided from operating activities is primarily due to deferred income taxes related to the Kemper IGCC, partially offset bylower income tax and ad valorem tax payments and the timing of payments received from affiliates and customers and the completioncollections 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.receivables. Net cash used for investing activities totaled $483$128 million for the first ninesix months of 20172019 primarily due to gross property additions related to the Kemper IGCC.distribution and transmission facilities. Net cash provided fromused for financing activities totaled $129$26 million for the first ninesix months of 20172019 primarily due to a return of capital contributions fromto Southern Company, partially offset by redemptions$43 million of long-term debt and short-term borrowings.pollution control revenue bonds reoffered to the public. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first ninesix months of 20172019 include an increasea decrease of $221 million 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$300 million in unsecured term loanssenior notes to securities due within one year, partially offset by $43 million in securities reoffered to the public and $40 million in variable rate revenue bonds reclassified from securities due within one year. Other significant changes include decreasesa decrease of $2.5 billion in CWIP, $756$100 million in accumulated deferred income taxes,plant in service and $299an increase of $100 million in deferred charges related to income taxes. All of these changesother property and investments 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 witha new tolling arrangement, effective January 1, 2019, accounted for as a sales-type lease; a decrease of $94 million in cash and cash equivalents; and a decrease of $43 million in accrued taxes primarily due to the IRS Section 174 R&E settlement.payment of ad valorem taxes. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Notes (B) and (G)Note (L) 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.contractual obligations. Approximately $935$300 million will be required through SeptemberJune 30, 20182020 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 costs that may arise from 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 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 statuteslaws 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 electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Sources of Capital
Mississippi Power plans to obtain the funds required for construction and other purposesto meet its future capital needs from operating cash flows, external securitysecurities issuances, term loans, and/or short-term debt, as well as, under certain circumstances,borrowings from financial institutions, including commercial paper to the extent Mississippi Power is eligible to participate, and equity contributions and/or loans from Southern Company. TheHowever, the amount, type, and timing of any future financingsfinancing, if needed, will depend upon regulatory approval, prevailing market conditions, regulatory approval, and other factors, which includes resolution of the Kemper County energy facility cost recovery.factors. 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-K for additional information.
On February 28, 2017, the maturity dates for $551 million in promissory notes to Southern Company were extended to July 31, 2018. 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; 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 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) 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 fundLIQUIDITY – "Capital Requirements and Contractual Obligations" in Item 7 of the Form 10-K for additional information.
As of June 30, 2019, Mississippi Power's short-term capital needs. Specifically, Mississippi Power has been informedcurrent liabilities exceeded current assets 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 concernapproximately $103 million primarily as a result of Southern Company's anticipated ongoing financial support$300 million 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.long-term debt that is due within one year.
At SeptemberJune 30, 2017,2019, Mississippi Power had approximately $231$199 million of cash and cash equivalents. CommittedIn June 2019, Mississippi Power entered into a new credit arrangement of $50 million that matures in 2022 and amended its existing credit arrangements, which, among other things, extended the maturity dates from 2019 to 2022. Mississippi Power's committed credit arrangements with banks totaled $150 million at SeptemberJune 30, 2017 were as follows:2019, all of which was unused.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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 |
|
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)(F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
MostAll of these bank credit arrangements as well as Mississippi Power's term loan agreement, contain covenants that limit debt levels and typically contain cross accelerationcross-acceleration provisions to other indebtedness (including guarantee obligations) of Mississippi Power. Such cross-acceleration provisions to other indebtedness would trigger an event of default if Mississippi Power defaulted on indebtedness, the payment of which was then accelerated. At SeptemberJune 30, 2017,2019, Mississippi Power was in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowing.
Subject to applicable market conditions, Mississippi Power expects to seek to renew or replace its credit arrangements as needed, prior to expiration. In connection therewith, Mississippi Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the $100$150 million unused credit arrangements with banks is allocated to provide liquidity support to Mississippi Power's pollution controlvariable rate revenue bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of SeptemberJune 30, 20172019 was approximately $40 million. In addition,
Short-term debt, including the average amount and maximum amount outstanding, was immaterial at SeptemberJune 30, 2017, 2019 and during the three-month period ended June 30, 2019.
Mississippi Power had approximately $50 millionbelieves the need for working capital can be adequately met by utilizing lines of fixed rate pollution control bonds outstanding that were requiredcredit, short-term bank notes, commercial paper to be remarketed within the next 12 months.
Short-term borrowings are included in notes payable in the balance sheets. Details of short-term borrowings were as follows:
|
| | | | | | | | | | | | | | | | |
| | | Short-term Debt at September 30, 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 |
|
| |
(*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2017. |
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
extent Mississippi Power is eligible to participate, operating cash flows, and other cash.
Credit Rating Risk
At September 30, 2017,See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" of Mississippi Power doesin Item 7 of the Form 10-K for additional information.
At June 30, 2019, Mississippi 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.
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 contracts that have required or could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, energy price risk management, and transmission. At SeptemberJune 30, 2017,2019, the maximum potential collateral requirements at a rating below BBB- and/or Baa3 equaled approximately $255$286 million.
Included in these amounts are certain agreements that could require collateral in the event that either Alabama Power or Georgia Power (affiliate companies of Mississippi Power) has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Mississippi Power to access capital markets and would be likely to impact the cost at which it does so.
On March 1, 2017, Moody's downgraded the senior unsecured debt rating of Mississippi Power to Ba1 from Baa3.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including Mississippi Power) from stable to negative.
On March 30, 2017, Fitch placed the ratings of 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.
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. See Note (G) to the Condensed Financial Statements under "Section 174 Research and Experimental Deduction" herein for additional information.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including Mississippi Power, may be negatively impacted. The settlement agreement approved by the Mississippi PSC in August 2018 with respect to the 2018 PEP filings and all unresolved PEP filings for prior years is expected to help mitigate these potential adverse impacts by allowing Mississippi Power to retain the excess deferred taxes resulting from the Tax Reform Legislation until the conclusion of the Mississippi Power 2019 Base Rate Case. See Note 2 to the financial statements under "Mississippi Power" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Mississippi Power" herein for additional information.
Financing Activities
In March 2019, Mississippi Power reoffered to the public $43 million of Mississippi Business Finance Corporation Pollution Control Revenue Refunding Bonds, Series 2002, which previously had been purchased and held by Mississippi Power.
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, | For the Three Months
Ended June 30, | | For the Six Months
Ended June 30, |
| | 2017 | | 2016 | | 2017 | | 2016 | 2019 | | 2018 | | 2019 | | 2018 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | | | | | | | | |
| Wholesale revenues, non-affiliates | $ | 510 |
| | $ | 387 |
| | $ | 1,293 |
| | $ | 866 |
| $ | 390 |
| | $ | 443 |
| | $ | 743 |
| | $ | 867 |
|
| Wholesale revenues, affiliates | 105 |
| | 110 |
| | 295 |
| | 313 |
| 117 |
| | 109 |
| | 204 |
| | 192 |
|
| Other revenues | 3 |
| | 3 |
| | 9 |
| | 10 |
| 3 |
| | 3 |
| | 6 |
| | 5 |
|
| Total operating revenues | 618 |
| | 500 |
| | 1,597 |
| | 1,189 |
| 510 |
| | 555 |
| | 953 |
| | 1,064 |
|
| Operating Expenses: | | | | | | | | | | | | | | |
| Fuel | 189 |
| | 154 |
| | 460 |
| | 341 |
| 139 |
| | 153 |
| | 284 |
| | 321 |
|
| Purchased power, non-affiliates | 36 |
| | 25 |
| | 90 |
| | 60 |
| |
| Purchased power, affiliates | 7 |
| | 8 |
| | 23 |
| | 16 |
| |
| Purchased power | | 32 |
| | 39 |
| | 55 |
| | 100 |
|
| Other operations and maintenance | 83 |
| | 81 |
| | 272 |
| | 246 |
| 79 |
| | 91 |
| | 166 |
| | 184 |
|
| Depreciation and amortization | 131 |
| | 93 |
| | 379 |
| | 247 |
| 119 |
| | 125 |
| | 237 |
| | 240 |
|
| Taxes other than income taxes | 13 |
| | 5 |
| | 37 |
| | 17 |
| 11 |
| | 12 |
| | 21 |
| | 24 |
|
| Asset impairment | | — |
| | 119 |
| | — |
| | 119 |
|
| Gain on dispositions, net | | (23 | ) | | — |
| | (23 | ) | | — |
|
| Total operating expenses | 459 |
|
| 366 |
| | 1,261 |
| | 927 |
| 357 |
| | 539 |
| | 740 |
| | 988 |
|
| Operating Income | 159 |
| | 134 |
| | 336 |
| | 262 |
| 153 |
| | 16 |
| | 213 |
| | 76 |
|
| Other Income and (Expense): | | | | | | | | | | | | | | |
| Interest expense, net of amounts capitalized | (47 | ) | | (35 | ) | | (144 | ) | | (78 | ) | (41 | ) | | (46 | ) | | (84 | ) | | (93 | ) |
| Other income (expense), net | 3 |
| | 2 |
| | 3 |
| | 3 |
| 40 |
| | 2 |
| | 41 |
| | 5 |
|
| Total other income and (expense) | (44 | ) | | (33 | ) | | (141 | ) | | (75 | ) | (1 | ) | | (44 | ) | | (43 | ) | | (88 | ) |
| Earnings Before Income Taxes | 115 |
| | 101 |
| | 195 |
| | 187 |
| |
| Earnings (Loss) Before Income Taxes | | 152 |
| | (28 | ) | | 170 |
| | (12 | ) |
| Income taxes (benefit) | (39 | ) | | (102 | ) | | (129 | ) | | (167 | ) | (51 | ) | | (73 | ) | | (60 | ) | | (172 | ) |
| Net Income | 154 |
| | 203 |
| | 324 |
| | 354 |
| 203 |
| | 45 |
| | 230 |
| | 160 |
|
| Less: Net income attributable to noncontrolling interests | 30 |
| | 27 |
| | 48 |
| | 39 |
| |
| Net income attributable to noncontrolling interests | | 29 |
| | 23 |
| | — |
| | 17 |
|
| Net Income Attributable to Southern Power | $ | 124 |
| | $ | 176 |
| | $ | 276 |
| | $ | 315 |
| $ | 174 |
| | $ | 22 |
| | $ | 230 |
| | $ | 143 |
|
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
| | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | For the Three Months
Ended June 30, | | For the Six Months
Ended June 30, |
| | 2017 | | 2016 | | 2017 | | 2016 | 2019 | | 2018 | | 2019 | | 2018 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Net Income | $ | 154 |
| | $ | 203 |
| | $ | 324 |
| | $ | 354 |
| $ | 203 |
| | $ | 45 |
| | $ | 230 |
| | $ | 160 |
|
| 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 |
| |
Changes in fair value, net of tax of
$(1), $(19), $(10), and $(3), respectively | | (1 | ) | | (55 | ) | | (30 | ) | | (8 | ) |
Reclassification adjustment for amounts included in net income,
net of tax of $(2), $20, $6, and $12, respectively | | (7 | ) | | 59 |
| | 17 |
| | 35 |
|
| Pension and other postretirement benefit plans: | | | | | | | | |
Reclassification adjustment for amounts included in net income,
net of tax of $-, $-, $-, and $-, respectively | | — |
| | — |
| | — |
| | 1 |
|
| Total other comprehensive income (loss) | 5 |
| | 22 |
| | (10 | ) | | 12 |
| (8 | ) | | 4 |
| | (13 | ) | | 28 |
|
| Comprehensive Income | 159 |
| | 225 |
| | 314 |
| | 366 |
| 195 |
| | 49 |
| | 217 |
| | 188 |
|
| Less: Comprehensive income attributable to noncontrolling interests | 30 |
| | 27 |
| | 48 |
| | 39 |
| |
| Comprehensive income attributable to noncontrolling interests | | 29 |
| | 23 |
| | — |
| | 17 |
|
| Comprehensive Income Attributable to Southern Power | $ | 129 |
| | $ | 198 |
| | $ | 266 |
| | $ | 327 |
| $ | 166 |
| | $ | 26 |
| | $ | 217 |
| | $ | 171 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
| | | | For the Nine Months Ended September 30, | For the Six Months
Ended June 30, |
| | 2017 | | 2016 | 2019 | | 2018 |
| | (in millions) | (in millions) |
| Operating Activities: | | | | | | |
| Net income | $ | 324 |
| | $ | 354 |
| $ | 230 |
| | $ | 160 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | | | | |
| Depreciation and amortization, total | 404 |
| | 262 |
| 251 |
| | 256 |
|
| Deferred income taxes | 240 |
| | (668 | ) | (63 | ) | | (252 | ) |
| Amortization of investment tax credits | (42 | ) | | (25 | ) | (122 | ) | | (29 | ) |
| Collateral deposits | (1 | ) | | (80 | ) | |
| Income taxes receivable, non-current | (42 | ) | | — |
| |
| Asset impairment | | — |
| | 119 |
|
| Other, net | (2 | ) | | 19 |
| (69 | ) | | (10 | ) |
| Changes in certain current assets and liabilities — | | | | | | |
| -Receivables | (77 | ) | | (82 | ) | (9 | ) | | (30 | ) |
| -Prepaid income taxes | | 520 |
| | (36 | ) |
| -Other current assets | 38 |
| | (15 | ) | 4 |
| | 3 |
|
| -Accounts payable | (31 | ) | | 7 |
| (17 | ) | | (41 | ) |
| -Accrued taxes | 79 |
| | 483 |
| |
| -Accrued compensation | | (9 | ) | | (9 | ) |
| -Other current liabilities | 5 |
| | 14 |
| 3 |
| | (4 | ) |
| Net cash provided from operating activities | 895 |
| | 269 |
| 719 |
| | 127 |
|
| Investing Activities: | | | | | | |
| Business acquisitions | (1,032 | ) | | (1,134 | ) | (2 | ) | | (64 | ) |
| Property additions | (218 | ) | | (1,702 | ) | (123 | ) | | (198 | ) |
| Proceeds from dispositions and asset sales | | 540 |
| | — |
|
| Change in construction payables | (166 | ) | | (69 | ) | (23 | ) | | 2 |
|
| Investment in unconsolidated subsidiaries | | (116 | ) | | — |
|
| Payments pursuant to LTSAs | (99 | ) | | (58 | ) | (31 | ) | | (32 | ) |
| Investment in restricted cash | (16 | ) | | (750 | ) | |
| Distribution of restricted cash | 33 |
| | 746 |
| |
| Other investing activities | 7 |
| | (41 | ) | 9 |
| | 15 |
|
| Net cash used for investing activities | (1,491 | ) | | (3,008 | ) | |
| Net cash provided from (used for) investing activities | | 254 |
| | (277 | ) |
| Financing Activities: | | | | | | |
| Increase (decrease) in notes payable, net | (89 | ) | | 692 |
| |
| Decrease in notes payable, net | | — |
| | (41 | ) |
| Proceeds — | | | | | | |
| Short-term borrowings | | — |
| | 200 |
|
| Capital contributions from parent company | | 6 |
| | 16 |
|
| Redemptions — | | | | |
| Short-term borrowings | | (100 | ) | | — |
|
| Senior notes | — |
| | 1,531 |
| — |
| | (350 | ) |
| Capital contributions from parent company | — |
| | 800 |
| |
| Other long-term debt | 43 |
| | 63 |
| — |
| | (420 | ) |
| Redemptions — Other long-term debt | (4 | ) | | (84 | ) | |
| Return of capital | | (505 | ) | | (250 | ) |
| Distributions to noncontrolling interests | (89 | ) | | (22 | ) | (82 | ) | | (42 | ) |
| Capital contributions from noncontrolling interests | 79 |
| | 367 |
| 5 |
| | 1,210 |
|
| Purchase of membership interests from noncontrolling interests | — |
| | (129 | ) | |
| Payment of common stock dividends | (238 | ) | | (204 | ) | (103 | ) | | (156 | ) |
| Other financing activities | (27 | ) | | (14 | ) | (5 | ) | | (15 | ) |
| Net cash provided from (used for) financing activities | (325 | ) | | 3,000 |
| (784 | ) | | 152 |
|
| 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 |
| |
| Net Change in Cash, Cash Equivalents, and Restricted Cash | | 189 |
| | 2 |
|
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | | 181 |
| | 140 |
|
| Cash, Cash Equivalents, and Restricted Cash at End of Period | | $ | 370 |
| | $ | 142 |
|
| 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 |
| |
| Interest (net of $7 and $10 capitalized for 2019 and 2018, respectively) | | $ | 106 |
| | $ | 109 |
|
| Income taxes, net | (343 | ) | | 71 |
| (421 | ) | | 109 |
|
| Noncash transactions — Accrued property additions at end of period | 16 |
| | 210 |
| 31 |
| | 33 |
|
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 | | At June 30, 2019 | | At December 31, 2018 |
| | | (in millions) | | (in millions) |
| Current Assets: | | | | | | | | |
| Cash and cash equivalents | | $ | 178 |
| | $ | 1,099 |
| | $ | 370 |
| | $ | 181 |
|
| Receivables — | | | | | | | | |
| Customer accounts receivable | | 148 |
| | 102 |
| | 153 |
| | 111 |
|
| Affiliated | | | 49 |
| | 55 |
|
| Other | | 61 |
| | 34 |
| | 59 |
| | 116 |
|
| Affiliated | | 74 |
| | 57 |
| |
| Fossil fuel stock | | 15 |
| | 15 |
| |
| Materials and supplies | | 351 |
| | 337 |
| | 185 |
| | 220 |
|
| Prepaid income taxes | | 51 |
| | 74 |
| | 489 |
| | 25 |
|
| Other current assets | | 26 |
| | 39 |
| | 33 |
| | 37 |
|
| Total current assets | | 904 |
| | 1,757 |
| | 1,338 |
| | 745 |
|
| Property, Plant, and Equipment: | | | | | | | | |
| In service | | 13,734 |
| | 12,728 |
| | 12,862 |
| | 13,271 |
|
| Less: Accumulated provision for depreciation | | 1,823 |
| | 1,484 |
| | 2,255 |
| | 2,171 |
|
| Plant in service, net of depreciation | | 11,911 |
| | 11,244 |
| | 10,607 |
| | 11,100 |
|
| Construction work in progress | | 425 |
| | 398 |
| | 419 |
| | 430 |
|
| Total property, plant, and equipment | | 12,336 |
| | 11,642 |
| | 11,026 |
| | 11,530 |
|
| Other Property and Investments: | | | | | | | | |
Intangible assets, net of amortization of $41 and $22
at September 30, 2017 and December 31, 2016, respectively | | 417 |
| | 436 |
| |
Intangible assets, net of amortization of $60 and $61
at June 30, 2019 and December 31, 2018, respectively | | | 313 |
| | 345 |
|
| Other investments | | | 144 |
| | — |
|
| Total other property and investments | | 417 |
| | 436 |
| | 457 |
| | 345 |
|
| Deferred Charges and Other Assets: | | | | | | | | |
| Operating lease right-of-use assets, net of amortization | | | 370 |
| | — |
|
| Prepaid LTSAs | | 77 |
| | 101 |
| | 107 |
| | 98 |
|
| Accumulated deferred income taxes | | 400 |
| | 594 |
| | 296 |
| | 1,186 |
|
| Income taxes receivable, non-current | | 53 |
| | 11 |
| | 36 |
| | 30 |
|
| Other deferred charges and assets — affiliated | | 6 |
| | 13 |
| |
| Other deferred charges and assets — non-affiliated | | 455 |
| | 615 |
| |
| Assets held for sale | | | 599 |
| | 576 |
|
| Other deferred charges and assets | | | 289 |
| | 373 |
|
| Total deferred charges and other assets | | 991 |
| | 1,334 |
| | 1,697 |
| | 2,263 |
|
| Total Assets | | $ | 14,648 |
| | $ | 15,169 |
| | $ | 14,518 |
| | $ | 14,883 |
|
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 | | At June 30, 2019 | | At December 31, 2018 |
| | | (in millions) | | (in millions) |
| Current Liabilities: | | | | | | | | |
| Securities due within one year | | $ | 864 |
| | $ | 560 |
| | $ | 899 |
| | $ | 599 |
|
| Notes payable | | 120 |
| | 209 |
| | — |
| | 100 |
|
| Accounts payable — | | | | | | | | |
| Affiliated | | 93 |
| | 88 |
| | 72 |
| | 92 |
|
| Other | | 84 |
| | 278 |
| | 60 |
| | 77 |
|
| Accrued taxes — | | | | | |
| Accrued income taxes | | 101 |
| | 148 |
| | 23 |
| | 6 |
|
| Other accrued taxes | | 30 |
| | 7 |
| |
| Accrued interest | | 36 |
| | 36 |
| | 23 |
| | 36 |
|
| Acquisitions payable | | — |
| | 461 |
| |
| Contingent consideration | | 15 |
| | 46 |
| |
| Liabilities held for sale | | | 10 |
| | 15 |
|
| Other current liabilities | | 58 |
| | 70 |
| | 116 |
| | 106 |
|
| Total current liabilities | | 1,401 |
| | 1,903 |
| | 1,203 |
| | 1,031 |
|
| Long-term Debt | | 4,946 |
| | 5,068 |
| | 4,112 |
| | 4,418 |
|
| Deferred Credits and Other Liabilities: | | | | | | | | |
| Accumulated deferred income taxes | | 191 |
| | 152 |
| | 106 |
| | 105 |
|
| Accumulated deferred ITCs | | 1,900 |
| | 1,839 |
| | 1,737 |
| | 1,832 |
|
| Asset retirement obligations | | 76 |
| | 64 |
| |
| Operating lease obligations | | | 373 |
| | — |
|
| Other deferred credits and liabilities | | 232 |
| | 304 |
| | 169 |
| | 213 |
|
| Total deferred credits and other liabilities | | 2,399 |
| | 2,359 |
| | 2,385 |
| | 2,150 |
|
| Total Liabilities | | 8,746 |
| | 9,330 |
| | 7,700 |
| | 7,599 |
|
| 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 Stockholders' Equity (See accompanying statements) | | | 6,818 |
| | 7,284 |
|
| Total Liabilities and Stockholders' Equity | | $ | 14,648 |
| | $ | 15,169 |
| | $ | 14,518 |
| | $ | 14,883 |
|
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, 2017 | $ | 3,662 |
| | $ | 1,478 |
| | $ | (2 | ) | | $ | 5,138 |
| | $ | 1,360 |
| | $ | 6,498 |
|
| Net income attributable to Southern Power | — |
| | 121 |
| | — |
| | 121 |
| | — |
| | 121 |
|
| Capital contributions from parent company | 1 |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
|
| Other comprehensive income (loss) | — |
| | — |
| | 24 |
| | 24 |
| | — |
| | 24 |
|
| Cash dividends on common stock | — |
| | (78 | ) | | — |
| | (78 | ) | | — |
| | (78 | ) |
Capital contributions from
noncontrolling interests | — |
| | — |
| | — |
| | — |
| | 9 |
| | 9 |
|
| Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | (13 | ) | | (13 | ) |
Net income (loss) attributable
to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | (6 | ) | | (6 | ) |
| Other | — |
| | (2 | ) | | 5 |
| | 3 |
| | (1 | ) | | 2 |
|
| Balance at March 31, 2018 | 3,663 |
| | 1,519 |
| | 27 |
| | 5,209 |
| | 1,349 |
| | 6,558 |
|
| Net income attributable to Southern Power | — |
| | 22 |
| | — |
| | 22 |
| | — |
| | 22 |
|
| Return of capital to parent company | (250 | ) | | — |
| | — |
| | (250 | ) | | — |
| | (250 | ) |
| Capital contributions from parent company | 17 |
| | — |
| | — |
| | 17 |
| | — |
| | 17 |
|
| Other comprehensive income (loss) | — |
| | — |
| | 4 |
| | 4 |
| | — |
| | 4 |
|
| Cash dividends on common stock | — |
| | (78 | ) | | — |
| | (78 | ) | | — |
| | (78 | ) |
Capital contributions from
noncontrolling interests | — |
| | — |
| | — |
| | — |
| | 22 |
| | 22 |
|
| Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | (29 | ) | | (29 | ) |
Net income attributable
to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | 23 |
| | 23 |
|
| Sale of noncontrolling interests | (407 | ) | | — |
| | — |
| | (407 | ) | | 1,690 |
| | 1,283 |
|
| Other | — |
| | 1 |
| | — |
| | 1 |
| | 1 |
| | 2 |
|
| Balance at June 30, 2018 | $ | 3,023 |
| | $ | 1,464 |
| | $ | 31 |
| | $ | 4,518 |
| | $ | 3,056 |
| | $ | 7,574 |
|
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 attributable to Southern Power | — |
| | 56 |
| | — |
| | 56 |
| | — |
| | 56 |
|
| 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 | ) |
Net income (loss) attributable
to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | (29 | ) | | (29 | ) |
| Other | (1 | ) | | (1 | ) | | — |
| | (2 | ) | | 1 |
| | (1 | ) |
| Balance at March 31, 2019 | 1,600 |
| | 1,356 |
| | 12 |
| | 2,968 |
| | 4,250 |
| | 7,218 |
|
| Net income attributable to Southern Power | — |
| | 174 |
| | — |
| | 174 |
| | — |
| | 174 |
|
| 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 | ) |
Net income attributable
to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | 29 |
| | 29 |
|
| Other | — |
| | 1 |
| | — |
| | 1 |
| | (1 | ) | | — |
|
| Balance at June 30, 2019 | $ | 1,102 |
| | $ | 1,479 |
| | $ | 4 |
| | $ | 2,585 |
| | $ | 4,233 |
| | $ | 6,818 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRDSECOND QUARTER 20172019 vs. THIRDSECOND QUARTER 20162018
AND
YEAR-TO-DATE 20172019 vs. YEAR-TO-DATE 20162018
OVERVIEW
Southern Power develops, 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, dispositions, and sales of assets,partnership interests, development and construction and development of new generating facilities, and entry into PPAs primarily with investor-owned utilities, independent power producers, municipalities, electric cooperatives, and other load-serving entities, as well as commercial and industrial customers. In general, Southern Power has constructedcommits to the construction or acquiredacquisition of new generating capacity only after entering into or assuming long-term PPAs for the new facilities.
During the nine months ended September 30, 2017,On June 13, 2019, 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 upits equity interests in Nacogdoches Power, LLC, the owner of an approximately 115-MW biomass facility located in Nacogdoches County, Texas, to Austin Energy, for an aggregate cash purchase price of approximately $461 million, including working capital adjustments.
On June 14, 2019, Southern Power entered into an agreement with Bloom Energy to acquire a one-third equitymajority interest in its solar asset portfolio.affiliate DSGP, which owns and operates fuel cell generation facilities in Delaware, for a total amount not to exceed $173 million. FERC approval of the transfer of the facilities is expected to occur in the third quarter 2019; however, the ultimate outcome of this matter cannot be determined at this time.
On May 4, 2019, Southern Power achieved commercial operation of the 385-MW natural gas expansion unit at Plant Mankato and started providing energy under a PPA with Northern States Power on June 1, 2019. The sale of Plant Mankato to Northern States Power remains subject to state commission approvals and is expected to close in fall 2019. If these state commission approvals are not obtained by October 1, 2019, either party has the option to terminate the sale, which, if elected, would result in the payment of a $15 million termination fee by Northern States Power to Southern Power. The ultimate outcome of this matter cannot be determined at this time.
At SeptemberDuring the six months ended June 30, 2017,2019, Southern Power had ancontinued construction of the 100-MW Wildhorse Mountain and the 200-MW Reading wind facilities. See FUTURE EARNINGS POTENTIAL – "Construction Projects" herein for additional information.
At June 30, 2019, Southern Power's average investment coverage ratio for its generating assets (including Plant Mankato), 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 93% through 2023 and 91% through 2021 and 90% through 2026,2028, with an average remaining contract duration of approximately 1615 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, but not limited to, peak season equivalent forced outage rate, contract availability, and net income.
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) |
| $(52) | | (29.5) | | $(39) | | (12.4) |
Net income attributable to Southern Power for the third quarter 2017 was $124 million compared to $176 million for the corresponding period in 2016. The decrease was primarily due to decreased income tax benefits from solar ITCs and increased interest expense primarily due 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"RESULTS OF OPERATIONS
Net Income Attributable to Southern Power
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $152 | | N/M | | $87 | | 60.8 |
N/M - Not meaningful
Net income attributable to Southern Power for the second quarter 2019 was $174 million compared to $22 million for the corresponding period in 2018. The increase is primarily due to net impacts from the dispositions of Plant Oleander and Plant Stanton Unit A (together, the Florida Plants) in 2018 and Plant Nacogdoches in 2019 (including an asset impairment charge in 2018 and gains on sale, partially offset by decreases in 2019 operating income primarily from PPA capacity revenues) totaling approximately $168 million and net income increases totaling $22 million from a litigation settlement relating to the Roserock solar facility and sales of wind equipment. The increases were partially offset by reductions in net income of approximately $22 million, net, related to the SP Wind tax equity partnership entered into in 2018.
Net income attributable to Southern Power for year-to-date 2019 was $230 million compared to $143 million for the corresponding period in 2018. The increase is primarily due to net impacts from the dispositions of the Florida Plants in 2018 and Plant Nacogdoches in 2019 (including an asset impairment charge in 2018 and gains on sale, partially offset by decreases in 2019 operating income primarily from PPA capacity revenues) totaling approximately $162 million and net income increases totaling $23 million from a litigation settlement relating to the Roserock solar facility and sales of wind equipment. The increases were partially offset by $54 million in state income tax benefits recorded in 2018 arising from the reorganization of Southern PowerPower's legal entities that own and operate certain solar facilities and reductions in net income of approximately $43 million, net, related to the SP Wind tax equity partnership entered into in 2018.
See Notes 7, 10, and 15 to the financial statements in Item 78 of the Form 10-K for additional information on the tax equity partnerships, the legal entity reorganization, and FUTURE EARNINGS POTENTIAL – "Acquisitions"the Florida Plants dispositions, respectively. Also see Note (C) to the Condensed Financial Statements herein for additional information on the Roserock solar facility litigation settlement and "Construction Projects" herein.Note (K) to the Condensed Financial Statements herein for additional information on the disposition of Plant Nacogdoches and sales of wind equipment.
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 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(45) | | (8.1) | | $(111) | | (10.4) |
Total operating revenues include PPA capacity revenues, which are derived primarily from long-term contracts involving natural gas facilities and a biomass generating facilities,facility (through the sale of Plant Nacogdoches), and PPA energy revenues which include sales from Southern Power's natural gas, biomass, solar, and windgeneration facilities. To the extent Southern Power has capacity not contracted under a PPA, it may sell power into thean accessible wholesale market, and,or, to the extent thethose generation assets are part of the FERC-approved 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 netoperating 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
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 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 generated from the respective facility and 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, transmission constraints, 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 | Second Quarter 2019 | | Second Quarter 2018 | | Year-to-Date 2019 | | Year-to-Date 2018 |
| | (in millions) | (in millions) |
| PPA capacity revenues | $ | 169 |
| | $ | 149 |
| | $ | 466 |
| | $ | 406 |
| $ | 125 |
| | $ | 144 |
| | $ | 252 |
| | $ | 282 |
|
| PPA energy revenues | 299 |
| | 247 |
| | 765 |
| | 532 |
| 291 |
| | 302 |
| | 518 |
| | 556 |
|
| Total PPA revenues | 468 |
| | 396 |
| | 1,231 |
| | 938 |
| 416 |
| | 446 |
| | 770 |
| | 838 |
|
| Non-PPA revenues | 147 |
| | 101 |
| | 357 |
| | 241 |
| 91 |
| | 106 |
| | 177 |
| | 221 |
|
| Other revenues | 3 |
| | 3 |
| | 9 |
| | 10 |
| 3 |
| | 3 |
| | 6 |
| | 5 |
|
| Total operating revenues | $ | 618 |
| | $ | 500 |
| | $ | 1,597 |
| | $ | 1,189 |
| $ | 510 |
| | $ | 555 |
| | $ | 953 |
| | $ | 1,064 |
|
In the second quarter 2019, total operating revenues were $510 million, reflecting a $45 million, or 8%, decrease from the corresponding period in 2018. The decrease in operating revenues was primarily due to the following:
PPA capacity revenues decreased $19 million, or 13%, primarily due to decreases totaling $21 million attributable to the sales of the Florida Plants in December 2018 and Plant Nacogdoches in June 2019 and $5 million from the contractual expiration of an affiliate natural gas PPA, partially offset by a $6 million increase in new PPA capacity revenues from existing gas facilities.
PPA energy revenues decreased $11 million, or 4%, due to a $7 million decrease related to a decrease in the average cost of fuel and purchased power and a $4 million decrease in sales related to solar and wind facilities primarily driven by a decrease in the volume of KWHs generated.
Non-PPA revenues decreased $15 million, or 14%, due to a $16 million decrease in the volume of KWHs sold through short-term sales.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In the third quarter 2017,For year-to-date 2019, total operating revenues were $618$953 million, reflecting a $118$111 million, or 24%10%, increasedecrease from the corresponding period in 2016.2018. The increasedecrease in operating revenues was primarily due to the following:
PPA capacity revenues increased $20decreased $30 million, or 13%11%, primarily due to additional customer capacity requirementsdecreases of $38 million attributable to the sales of the Florida Plants in December 2018 and aPlant Nacogdoches in June 2019 and $5 million from the contractual expiration of an affiliate natural gas PPA, partially offset by an $11 million increase in new PPA related tocapacity revenues from existing natural gas facilities.
PPA energy revenues increased $52decreased $38 million, or 21%7%, primarily due to a $55 million increase in sales from new solar and wind facilities, partially offset by a $3$30 million decrease in sales from natural gas PPAs due to a $24 million decrease in volumefacilities, primarily due to the expiration of a PPA and reduced customer load, partially offsetdriven by a $21$51 million increasedecrease in the average cost of fuel.
Non-PPA revenues increased $46 million, or 46%, due tofuel and purchased power, partially offset by a $58$23 million increase in the volume of KWHs sold primarily from uncovered natural gas capacity through short-term opportunity sales, offset by a $12due to increased customer load, and an $8 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 PPAsales 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 andprimarily driven by a $35 million increase in sales from natural gas PPAs primarily due to a $69 million increasedecrease in the average costvolume of fuel, partially offset by a $34 million decrease in volume primarily due to the expiration of a PPA and reduced customer load.KWHs generated.
Non-PPA revenues increased $116decreased $44 million, or 48%20%, due to a $104$36 million increasedecrease in the volume of KWHs sold primarily from uncovered natural gas capacity through short-term opportunity sales as well as a $12and an $8 million increasedecrease in the market price of energy in the wholesale markets.energy.
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 | Second Quarter 2019 | Second Quarter 2018 | | Year-to-Date 2019 | Year-to-Date 2018 |
| | (in billions of KWHs) | (in billions of KWHs) |
| Generation | 12.5 | 11.1 | | 33.2 | 27.9 | 11.7 | 12.2 | | 21.9 | 22.0 |
| Purchased power | 1.2 | 0.9 | | 3.4 | 2.5 | 1.0 | 1.2 | | 1.8 | 2.2 |
| Total generation and purchased power | 13.7 | 12.0 | | 36.6 | 30.4 | 12.7 | 13.4 | | 23.7 | 24.2 |
| | | |
| Total generation and purchased power, excluding solar, wind, and tolling agreements | 7.2 | 6.7 | | 17.8 | 17.7 | 7.1 | 7.2 | | 13.7 | 13.9 |
Southern Power's PPAs for natural gas and biomass generation generally provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing Southern Power for substantially all of the cost of fuel relating to the energy delivered under such PPAs. Consequently, changes in such fuel costs are generally accompanied by a corresponding change in related fuel revenues and do not have a significant impact on net income. Southern Power is responsible for the cost of fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the wholesale market or into the power pool for capacity owned directly by Southern Power.
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 | Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | 35 |
| | 22.7 | | $ | 119 |
| | 34.9 | $ | (14 | ) | | (9.2) | | $ | (37 | ) | | (11.5) |
| Purchased power | 10 |
| | 30.3 | | 37 |
| | 48.7 | (7 | ) | | (17.9) | | (45 | ) | | (45.0) |
| Total fuel and purchased power expenses | $ | 45 |
| | $ | 156 |
| | $ | (21 | ) | | $ | (82 | ) | |
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
DepreciationIn the second quarter 2019, total fuel and Amortizationpurchased power expenses decreased $21 million, or 10.9%, compared to the corresponding period in 2018. Fuel expense decreased $14 million primarily due to a decrease in the average cost of fuel per KWH generated. Purchased power expense decreased $7 million associated with the volume of KWHs purchased.
For year-to-date 2019, total fuel and purchased power expenses decreased $82 million, or 19%, compared to the corresponding period in 2018. Fuel expense decreased $37 million primarily due to a decrease in the average cost of fuel per KWH generated. Purchased power expense decreased $45 million due to a $25 million decrease associated with the average cost of purchased power and a $20 million decrease associated with the volume of KWHs purchased.
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) |
| $38 | | 40.9 | | $132 | | 53.4 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(12) | | (13.2) | | $(18) | | (9.8) |
In the thirdsecond quarter 2017, depreciation2019, other operations and amortization was $131maintenance expenses were $79 million compared to $93$91 million for the corresponding period in 2016. 2018. The decrease was primarily due to a $14 million gain on the sale of wind turbine equipment in the second quarter 2019.
For year-to-date 2017, depreciation2019, other operations and amortization was $379maintenance expenses were $166 million compared to $247$184 million for the corresponding period in 2016.2018. The increases weredecrease was primarily due to newa $14 million gain on the sale of wind turbine equipment in the second quarter 2019, lower scheduled outage and maintenance expenses, and the recovery of legal costs related to the Roserock litigation settlement in the first quarter 2019.
See Note (K) to the Condensed Financial Statements under "Southern Power – Development Projects" herein for additional information on the sale of wind turbine equipment. Also see Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein for additional information on the Roserock solar wind, and gas facilities placedfacility litigation settlement.
Asset Impairment
In the second quarter 2018, a $119 million asset impairment charge was recorded in service.anticipation of the sale of the Florida Plants. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power – Sale of Natural Gas Plants" for additional information.
Gain on Dispositions, net Taxes In the second quarter 2019, the sale of Plant Nacogdoches resulted in a $23 million gain. See Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information.
Other Than Income Taxes(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) |
| $8 | | 160.0 | | $20 | | 117.6 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $38 | | N/M | | $36 | | N/M |
N/M - Not meaningful
In the thirdsecond quarter 2017, taxes2019, other than income taxes were $13(expense), net was $40 million compared to $2 million for the corresponding period in 2018. For year-to date 2019, other income (expense), net was $41 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. These2018. The 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 lossesgain arising from translationthe settlement of €1.1 billion euro-denominated fixed-rate notes into U.S. dollars forlitigation related to 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.Roserock solar facility. See Note (H)(C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" 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 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $22 | | 30.1 | | $112 | | 65.1 |
In the thirdsecond quarter 2017,2019, income tax benefit was $39$51 million compared to $102$73 million for the corresponding period in 2016. The decrease2018. This change was primarily due to a $61$43 million decreaseincrease in income tax expense as a result of higher pre-tax earnings and a $41 million reduction of tax benefits from solar ITCs.wind PTCs primarily as a result of the 2018 sale of a noncontrolling tax equity interest in SP Wind, partially offset by a $75 million tax benefit resulting from the recognition of deferred ITCs remaining from the original construction of Plant Nacogdoches.
For year-to-date 2017,2019, income tax benefit was $129$60 million compared to $167$172 million for the corresponding period in 2016. The decrease2018. This change was primarily due to an $80 million reduction of tax benefits from wind PTCs primarily as a $102result of the sale of a noncontrolling tax equity interest in SP Wind, $54 million decreasein tax benefits recorded in 2018 related to changes in state apportionment rates following the reorganization of Southern Power's legal entities that own and operate certain solar facilities, and a $51 million increase in income tax benefits from solar ITCs,expense as a result of higher pre-tax earnings, partially offset by a $58$75 million increase in wind PTCs and a $4 million increasetax benefit resulting from state apportionment rate changes.the recognition of deferred ITCs remaining from the original construction of Plant Nacogdoches.
See Note (G) to the Condensed Financial Statements herein for additional information oninformation.
Net Income Attributable to Noncontrolling Interests
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $6 | | 26.1 | | $(17) | | N/M |
N/M - Not meaningful
In the second quarter 2019, net income taxesattributable to noncontrolling interests was $29 million compared to $23 million for the corresponding period in 2018. The increase was primarily due to an allocation of approximately $26 million of income to the noncontrolling interest partner related to the Roserock solar facility litigation settlement, partially offset by $25 million of losses attributable to noncontrolling interests related to the tax equity partnerships entered into in 2018.
For year-to-date 2019, net income attributable to noncontrolling interests was immaterial compared to $17 million for the corresponding period in 2018. The decrease was primarily due to $48 million of losses attributable to noncontrolling interests related to the tax equity partnerships entered into in 2018, partially offset by an allocation of approximately $29 million of income to the noncontrolling interest partner related to the Roserock solar facility litigation settlement.
See Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein and NoteNotes 1 and 7 to the financial statements of Southern Power under "Income and Other Taxes" in Item 8 of the Form 10-K under "General" and "Southern Power," respectively, for additional information on ITCs and PTCs.information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern Power's future earnings potential. Future earnings potential will be impacted by the sales of noncontrolling renewable facility interests and the sale of the Florida Plants in 2018, the sale of Plant Nacogdoches in the second quarter 2019, and the pending disposition of Plant Mankato expected in fall 2019. 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
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
successful remarketing of capacity as current contracts expire; and Southern Power's ability to execute its growth strategy including successful additional investments inthrough the development or acquisition of renewable facilities and other energy projects, andprojects.
On June 13, 2019, Southern Power completed the sale of its equity interests in Nacogdoches Power, LLC, the owner of an approximately 115-MW biomass facility located in Nacogdoches County, Texas, to develop and construct generating facilities. Current proposalsAustin Energy, for an aggregate cash purchase price of approximately $461 million, including working capital adjustments. The pre-tax income related to potential federal tax reform legislation are primarily focused on reducingPlant Nacogdoches was $16 million and $13 million for the corporate income tax rate, allowing 100%six months ended June 30, 2019 and 2018, respectively.
On June 14, 2019, Southern Power entered into an agreement with Bloom Energy to acquire a majority interest in its affiliate DSGP, which owns and operates fuel cell generation facilities in Delaware, for a total amount not to exceed $173 million. FERC approval of capital expendituresthe transfer of the facilities is expected to be deducted, and eliminatingoccur in the interest deduction. Thethird quarter 2019; however, the ultimate impactoutcome 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, andthis matter cannot be determined at this time, but could havetime. See Notes (E) and (K) to the Condensed Financial Statements under "Southern Power – Equity Method Investments" and "Southern Power – Development Projects," respectively, herein for additional information.
On May 4, 2019, Southern Power achieved commercial operation of the 385-MW natural gas expansion unit at Plant Mankato and started providing energy under a material impactPPA with Northern States Power on June 1, 2019. The sale of Plant Mankato to Northern States Power remains subject to state commission approvals and is expected to close in fall 2019. If these state commission approvals are not obtained by October 1, 2019, either party has the option to terminate the sale, which, if elected, would result in the payment of a $15 million termination fee by Northern States Power to Southern Power's consolidated financial statements.Power. The ultimate outcome of this matter cannot be determined at this time. Pre-tax income for Plant Mankato was immaterial for both the six months ended June 30, 2019 and 2018.
Southern Power entered into a tax equity partnership in June 2019 for the Wildhorse Mountain wind facility, with funding of tax equity amounts expected to occur upon commercial operation, which is consideringexpected to occur in the sale of up to a one-third equity interest in its solar asset portfolio.fourth quarter 2019. 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,transmission constraints, cost of generation from facilitiesunits 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,2019, Southern Power completed construction of and placed in service orthe 385-MW Plant Mankato expansion and continued construction of thetwo other projects set forthas described in the following table. Through Septembertable below. Total aggregate construction costs, excluding acquisition costs, are expected to be between $405 million and $450 million for the Wildhorse Mountain and Reading facilities. At June 30, 2017,2019, 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$186 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, 2017 |
East Pecos | Solar | 120 | Pecos County, TX | March 2017 | Austin Energy | 15 years |
Lamesa | Solar | 102 | Dawson County, TX | April 2017 | City of Garland, Texas | 15 years |
| | | | 2019 | | |
Projects Under Construction as of September 30, 2017 |
Cactus FlatsMankato expansion(*)(a)
| Wind | 148 | Concho County, TX | Third quarter 2018 | General Motors, LLC
and
General Mills Operations, LLC | 12 years
and
15 years |
Mankato | Natural Gas | 345385 | Mankato, MN | Second quarterMay 2019 | Northern States Power Company | 20 years |
| Projects Under Construction as of June 30, 2019 | | |
Wildhorse Mountain(b) | Wind | 100 | Pushmataha County, OK | Fourth quarter 2019 | Arkansas Electric Cooperative | 20 years |
Reading(c) | Wind | 200 | Osage and Lyon Counties, KS | Second quarter 2020 | Royal Caribbean Cruises LTD | 12 years |
| |
(*)(a) | On July 31, 2017,In November 2018, Southern Power acquiredentered into an agreement to sell all of its equity interests in Plant Mankato, including this expansion that was completed during May 2019. This transaction is subject to state commission approvals and is expected to close in fall 2019. The expansion unit started providing energy under a PPA with Northern States Power on June 1, 2019. |
| |
| (b) | In May 2018, Southern Power purchased 100% ownership interest of the Wildhorse Mountain facility. Southern Power entered into a tax equity partnership in June 2019 with funding of tax equity amounts expected to occur upon commercial operation. |
| |
| (c) | In August 2018, Southern Power purchased 100% of the Cactus Flatsmembership interests of the Reading facility from the joint development arrangement with Renewable Energy Systems Americas, Inc. Southern Power may enter into a tax equity partnership, in which is incase it would then own 100% of the early stages of construction, from RES America Developments, Inc.class B membership interests. |
Development Projects
In December 2016, as partSee Note 15 to the financial statements under "Southern Power – Development Projects" in Item 8 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, the Form 10-K for additional information.
Southern Power signed agreementscontinues to evaluate and made payments to purchaserefine the deployment of wind turbine equipment from Siemens Wind Power, Inc.purchased in 2016 and Vestas-American Wind Technology, Inc.2017 to potential joint development and construction projects as well as the amount of MW capacity to be used for construction ofconstructed. During the facilities. All of thesix months ended June 30, 2019, certain wind turbine equipment was delivered by April 2017, which allowssold, resulting in a gain on the projects to qualify for 100% PTCs for 10 years following their expected commercial operation dates between 2018 and 2020. The ultimate outcomesale of these matters cannot be determined at this time.approximately $14 million.
Income TaxOther Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" and "Power Sales Agreements – "Income Tax Matters"General" 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 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 Power is involved in various other matters being litigated and regulatory matters that could affect future earnings.earnings, including matters being litigated, as well as other regulatory and business matters. In addition, Southern Power is subject to certain claims and legal actions arising in the ordinary course of business. Southern Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulationlaws and regulations governing air, water, land, and protection of air emissions and water discharges.other natural resources. 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 qualitylaws and water standards,regulations, 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
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, regulatory matters, or other business matters cannot be determined at this time; however, for current proceedings not specifically reported 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 Southern Power's financial statements.
During 2015, Southern Power indirectly acquiredowns 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 subsequentlyTexas. Prior to the facility being placed in service in November 2016. Prior to placing the facility in service,2016, certain solar panels were damaged during installation. Whileinstallation by the facility currently is generating energy consistent with operational expectationsconstruction contractor, McCarthy Building Companies, Inc. (McCarthy), and PPA obligations, Southern Power is pursuing remedies under its insurance policies and other contracts to repair or replace thesecertain solar panels.panels were damaged by a hail event that also occurred during construction. In connection therewith, Southern Power is withholding paymentswithheld payment of approximately $26 million fromto the construction contractor, who haswhich 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,In 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas against X.L.XL Insurance America, Inc. (XL) and North American Elite Insurance Company (North American Elite) seeking recovery from an insurance policy for damages resulting from athe hail stormevent and certainMcCarthy's installation practices bypractices. In June 2018, the construction contractor, McCarthy Building Companies, Inc. (McCarthy). On May 19, 2017, Roserock filed a separate lawsuit against McCarthycourt granted Roserock's motion for partial summary judgment, finding that the insurers were in the state district court in Travis County, Texas alleging breach of contract and breachin violation of warrantythe Texas Insurance Code for failing to pay any monies owed for the damages sustained at thehail claim. Separate lawsuits were filed between Roserock facility, which has since been moved toand McCarthy, as well as other parties, and that litigation was consolidated in the U.S. District Court for the Western District of Texas. On May 22, 2017, McCarthy filedApril 18, 2019, Roserock and the parties to the state and federal lawsuits executed a counter lawsuit against Roserock, Array Technologies, Inc., Canadian Solar (USA), Inc., XL,settlement agreement and North American Elite inmutual release that resolved both lawsuits. Following execution of the U.S. District Court foragreement, 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.lawsuits were dismissed, Southern Power intendspaid McCarthy the amounts previously withheld, and McCarthy released its lien. As part of the settlement, Roserock received funds that covered all related legal costs, damages, and the replacement costs of certain solar panels. Funds received by Southern Power in excess of the initial replacement costs were recognized as a gain and included in other income (expense), net in 2019. A portion of the pre-tax gain was allocated to vigorously pursuenoncontrolling interests and defend these matters, the ultimate outcome of which cannot be determined at this time.Southern Power recognized a $12 million after-tax gain.
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 NoteNotes 1, 4, and 10 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.estimates.
Recently Issued Accounting Standards
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Southern Power in Item 7 ofNote (A) to the Form 10-KCondensed Financial Statements herein 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 disclosuresinformation 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 hedgerecently adopted 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.standards.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Power in Item 7 of the Form 10-K for additional information. Southern Power's financial condition remained stable at SeptemberJune 30, 2017.2019. 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 COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Power anticipates utilizing third-partyalso utilizes tax equity as onepartnerships, where the tax partner takes significantly all of the federal tax benefits, as a financing sources to fund its renewable growth strategy; however, the use of third-partysource. These tax equity structures is not expectedpartnerships are consolidated in Southern Power's financial statements and are accounted for using a HLBV methodology to have a material impact on future earnings. Subsequent to September 30, 2017,allocate partnership gains and losses. During the first six months of 2019, Southern Power secured third-partydid not receive any material tax equity funding amounts. See Note 1 to the financial statements under "Hypothetical Liquidation at Book Value" in Item 8 of the Form 10-K for additional information on 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.HLBV methodology.
Net cash provided from operating activities totaled $895$719 million for the first ninesix months of 20172019 compared to $269$127 million for the first ninesix months of 2016.2018. The increase in net cash provided from operating activities was primarily due to the utilization of income tax refunds received and an increasecredits of $520 million in energy sales arising2019. Net cash provided from new solarinvesting activities totaled $254 million for the first six months of 2019 primarily due to proceeds from the disposition of Plant Nacogdoches and wind facilities,equipment sales, partially offset by an increaseSouthern Power's investment in interest paid. See FUTURE EARNINGS POTENTIAL – "Income Tax 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 acquisitionsDSGP and theongoing construction of generating facilities.activities. Net cash used for financing activities totaled $325$784 million for the first ninesix months of 20172019 primarily due to returns of capital to Southern Company, common stock dividend payments,dividends, the repayment of a decrease in notes payable,short-term bank loan, 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 ninesix months of 20172019 include a $1.0 billion$464 million increase in property,prepaid income taxes due to the expected utilization of tax credits for the remainder of the 2019 tax year, a $493 million decrease in plant
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
and equipment in-servicethe sale of Plant Nacogdoches, a $370 million increase in operating lease right-of-use assets along with a corresponding increase in operating lease obligations of $373 million due to the adoption of ASU No. 2016-02, a $144 million increase in other investments primarily related to acquisitionsSouthern Power's investment in DSGP, and completing construction of and placing in service solar facilities, a $921$466 million decrease in cashstockholder's equity primarily due to returns of capital to Southern Company. See Note (K) under "Southern Power" and cash equivalents, and a $461 million decrease in acquisitions payable.Note (L) to the Condensed Financial Statements herein for additional information.
See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Power in Item 7 of the Form 10-K for a description of Southern Power's capital requirements for its construction program, scheduled maturities of long-term debt, as well as the related interest, derivative obligations, leases, unrecognized tax benefits, and other purchase commitments.contractual obligations. Approximately $864$900 million will be required through June 30, 2020 to repayfund maturities of long-term debt through September 30, 2018.debt. See "Sources of Capital" herein for additional information.
Southern Power's construction program includes estimates for potential plant acquisitions and placeholder growth, new construction and development, capital improvements, and work to be performed under LTSAs and is subject to periodic review and revision. Planned expenditures for plantActual construction costs, including 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 statuteslaws 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 StatementsFUTURE EARNINGS POTENTIAL – "Construction Projects" 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,external securities issuances, term loans,borrowings from financial institutions, tax equity partnership contributions, divestitures, 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
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Power's current liabilities exceededsometimes exceed 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 construction payables, as well as fluctuations in cash needs due to both seasonality and the stage of acquisitions and construction projects.seasonality. 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,borrowings from financial institutions, equity contributions from Southern Company, external securities issuances, and operating cash flows.
As of SeptemberJune 30, 2017,2019, Southern Power had cash and cash equivalents of approximately $178$370 million.
Southern Power's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes, and to financeincluding 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
sheets.
Details of commercial papershort-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 | $ | 120 |
| 1.5 | % | | $ | 322 |
| | 1.5 | % | | $ | 416 |
|
|
| | | | | | | | | | |
| | Short-term Borrowings During the Period (*) |
| | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | (in millions) | | | | (in millions) |
| Commercial paper | $ | 7 |
| | 2.6 | % | | $ | 75 |
|
| Short-term loans | 58 |
| | 3.1 | % | | 100 |
|
| Total | $ | 65 |
| | 3.0 | % | |
|
|
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended SeptemberJune 30, 2017.2019. No short-term debt was outstanding at June 30, 2019. |
At September 30, 2017,In May 2019, Southern Power had aamended and restated its committed credit facility (Facility) ofto extend the maturity date to 2024 and decrease the borrowing capacity from $750 million to $600 million. At June 30, 2019, $39 million of which $22 million hasthe Facility had been used for letters of credit and $728$561 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 68 to the financial statements of Southern Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E)(F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
The Facility as well as Southern Power's term loan agreement, contains a covenant that limits the ratio of debt to capitalization (as defined in the Facility) to a maximum of 65% and contains a cross-default provision that is restricted only to indebtedness of Southern Power. For purposes of this definition, debt excludes any project debt incurred by certain subsidiaries of Southern Power to the extent such debt is non-recourse to Southern Power, and capitalization excludes the capital stock or other equity attributable to such subsidiary. Southern Power is currently in compliance with all covenants in the Facility.
Southern Power also has a $120 million continuing letter of credit facility expiring in 2021 for standby letters of credit expiring in 2019.credit. At SeptemberJune 30, 2017, $1112019, $90 million has been used for letters of credit, primarily as credit support for PPA requirements, and $9$30 million remains unused.
In addition, at June 30, 2019, Southern Power had $104 million of cash collateral posted related to PPA requirements.
Southern Power's subsidiaries do not borrow under the commercial paper program and 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.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2, or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, energy price risk management, and transmission.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The maximum potential collateral requirements under these contracts at SeptemberJune 30, 20172019 were as follows:
| | | Credit Ratings | Maximum Potential
Collateral
Requirements | Maximum Potential
Collateral
Requirements |
| | (in millions) | (in millions) |
| At BBB and/or Baa2 | $ | 37 |
| $ | 29 |
|
| At BBB- and/or Baa3 | $ | 398 |
| $ | 339 |
|
At BB+ and/or Ba1(*) | $ | 1,124 |
| $ | 1,054 |
|
| |
| (*) | Any additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $38 million. |
Included in these amounts are certain agreements that could require collateral in the event that either Alabama Power or Georgia Power (affiliate companies of Southern Power) has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Power to access capital markets and would be likely to impact the cost at which it does so.
In addition, Southern Power has a PPA that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power's credit. The PPA requires credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses resulting from a credit downgrade.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including Southern Power) from stable to negative.
Financing Activities
In September 2017,May 2019, Southern Power amended its $60repaid at maturity a $100 million aggregate principal amountshort-term 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.loan.
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)
| | | | 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, | For the Three Months
Ended June 30, | | For the Six Months
Ended June 30, |
| | 2017 | | 2016 | | 2017 | | 2016 | | | 2016 | 2019 | | 2018 | | 2019 | | 2018 |
| | (in millions) | | | (in millions) | (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 |
| |
Natural gas revenues (includes revenue taxes of
$23, $23, $78, and $74, respectively) | | $ | 688 |
| | $ | 710 |
| | $ | 2,163 |
| | $ | 2,341 |
|
| Alternative revenue programs | | 1 |
| | (4 | ) | | — |
| | (27 | ) |
| Other revenues | 33 |
| | 25 |
| | 95 |
| | 25 |
| | | 64 |
| — |
| | 24 |
| | — |
| | 55 |
|
| Total operating revenues | 565 |
| | 543 |
| | 2,841 |
| | 543 |
| | | 1,905 |
| 689 |
| | 730 |
| | 2,163 |
| | 2,369 |
|
| Operating Expenses: | | | | | | | | | | | | | | | | | |
| Cost of natural gas | 134 |
| | 133 |
| | 1,085 |
| | 133 |
| | | 755 |
| 191 |
| | 228 |
| | 877 |
| | 949 |
|
| Cost of other sales | 7 |
| | 2 |
| | 20 |
| | 2 |
| | | 14 |
| — |
| | 5 |
| | — |
| | 12 |
|
| Other operations and maintenance | 205 |
| | 216 |
| | 671 |
| | 216 |
| | | 454 |
| 199 |
| | 238 |
| | 433 |
| | 514 |
|
| Depreciation and amortization | 125 |
| | 116 |
| | 370 |
| | 116 |
| | | 206 |
| 119 |
| | 126 |
| | 238 |
| | 255 |
|
| Taxes other than income taxes | 26 |
| | 29 |
| | 140 |
| | 29 |
| | | 99 |
| 46 |
| | 48 |
| | 128 |
| | 125 |
|
| Merger-related expenses | — |
| | 35 |
| | — |
| | 35 |
| | | 56 |
| |
| Goodwill impairment | | — |
| | — |
| | — |
| | 42 |
|
| Loss on disposition | | — |
| | 36 |
| | — |
| | 36 |
|
| Total operating expenses | 497 |
| | 531 |
| | 2,286 |
| | 531 |
| | | 1,584 |
| 555 |
| | 681 |
| | 1,676 |
| | 1,933 |
|
| Operating Income | 68 |
| | 12 |
| | 555 |
| | 12 |
| | | 321 |
| 134 |
| | 49 |
| | 487 |
| | 436 |
|
| Other Income and (Expense): | | | | | | | | | | | | | | | | | |
| Earnings from equity method investments | 32 |
| | 29 |
| | 100 |
| | 29 |
| | | 2 |
| 31 |
| | 31 |
| | 80 |
| | 74 |
|
| Interest expense, net of amounts capitalized | (51 | ) | | (39 | ) | | (145 | ) | | (39 | ) | | | (96 | ) | (59 | ) | | (59 | ) | | (118 | ) | | (118 | ) |
| Other income (expense), net | 18 |
| | 9 |
| | 26 |
| | 9 |
| | | 5 |
| 6 |
| | 3 |
| | 10 |
| | 15 |
|
| Total other income and (expense) | (1 | ) | | (1 | ) | | (19 | ) | | (1 | ) | | | (89 | ) | (22 | ) | | (25 | ) | | (28 | ) | | (29 | ) |
| Earnings Before Income Taxes | 67 |
| | 11 |
| | 536 |
| | 11 |
| | | 232 |
| 112 |
| | 24 |
| | 459 |
| | 407 |
|
| Income taxes | 52 |
| | 7 |
| | 233 |
| | 7 |
| | | 87 |
| 6 |
| | 55 |
| | 83 |
| | 159 |
|
| 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 |
| |
| Net Income (Loss) | | $ | 106 |
| | $ | (31 | ) | | $ | 376 |
| | $ | 248 |
|
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months
Ended June 30, | | For the Six Months
Ended June 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
| | (in millions) | �� | (in millions) |
| Net Income (Loss) | $ | 106 |
| | $ | (31 | ) | | $ | 376 |
| | $ | 248 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
Changes in fair value, net of tax of
$(1), $-, $(1), and $-, respectively | (3 | ) | | 1 |
| | (3 | ) | | 1 |
|
Reclassification adjustment for amounts included in net income,
net of tax of $-, $-, $-, and $1, respectively | — |
| | — |
| | — |
| | 2 |
|
| Pension and other postretirement benefit plans: | | | | | | | |
Reclassification adjustment for amounts included in net income,
net of tax of $(1), $-, $(1), and $-, respectively | — |
| | — |
| | (1 | ) | | — |
|
| Total other comprehensive income (loss) | (3 | ) | | 1 |
| | (4 | ) | | 3 |
|
| Comprehensive Income (Loss) | $ | 103 |
| | $ | (30 | ) | | $ | 372 |
| | $ | 251 |
|
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOMECASH FLOWS (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 |
|
|
| | | | | | | |
| | For the Six Months
Ended June 30, |
| | 2019 | | 2018 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 376 |
| | $ | 248 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 238 |
| | 255 |
|
| Deferred income taxes | 59 |
| | (12 | ) |
| Mark-to-market adjustments | 30 |
| | 2 |
|
| Goodwill impairment | — |
| | 42 |
|
| Loss on disposition | — |
| | 36 |
|
| Other, net | (26 | ) | | (24 | ) |
| Changes in certain current assets and liabilities — | | | |
| -Receivables | 717 |
| | 504 |
|
| -Natural gas for sale, net of temporary LIFO liquidation | 256 |
| | 295 |
|
| -Other current assets | 29 |
| | 41 |
|
| -Accounts payable | (604 | ) | | (125 | ) |
| -Accrued taxes | (54 | ) | | 38 |
|
| -Accrued compensation | (34 | ) | | (6 | ) |
| -Other current liabilities | (56 | ) | | 24 |
|
| Net cash provided from operating activities | 931 |
| | 1,318 |
|
| Investing Activities: | | | |
| Property additions | (603 | ) | | (679 | ) |
| Cost of removal, net of salvage | (33 | ) | | (18 | ) |
| Change in construction payables, net | 26 |
| | (6 | ) |
| Investment in unconsolidated subsidiaries | (18 | ) | | (60 | ) |
| Proceeds from dispositions and asset sales | 32 |
| | 364 |
|
| Other investing activities | 10 |
| | 18 |
|
| Net cash used for investing activities | (586 | ) | | (381 | ) |
| Financing Activities: | | | |
| Decrease in notes payable, net | (158 | ) | | (515 | ) |
| Redemptions — Gas facility revenue bonds | — |
| | (200 | ) |
| Payment of common stock dividends | (235 | ) | | (235 | ) |
| Other financing activities | 38 |
| | 10 |
|
| Net cash used for financing activities | (355 | ) | | (940 | ) |
| Net Change in Cash, Cash Equivalents, and Restricted Cash | (10 | ) | | (3 | ) |
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 70 |
| | 78 |
|
| Cash, Cash Equivalents, and Restricted Cash at End of Period | $ | 60 |
| | $ | 75 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid during the period for — | | | |
| Interest (net of $3 and $3 capitalized for 2019 and 2018, respectively) | $ | 125 |
| | $ | 129 |
|
| Income taxes, net | 96 |
| | 106 |
|
| Noncash transactions — Accrued property additions at end of period | 123 |
| | 129 |
|
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 FLOWSBALANCE SHEETS (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 |
|
|
| | | | | | | | |
| Assets | | At June 30, 2019 | | At December 31, 2018 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 56 |
| | $ | 64 |
|
| Receivables — | | | | |
| Energy marketing receivables | | 361 |
| | 801 |
|
| Customer accounts receivable | | 281 |
| | 370 |
|
| Unbilled revenues | | 63 |
| | 213 |
|
| Affiliated | | 10 |
| | 11 |
|
| Other accounts and notes receivable | | 100 |
| | 142 |
|
| Accumulated provision for uncollectible accounts | | (31 | ) | | (30 | ) |
| Natural gas for sale | | 268 |
| | 524 |
|
| Prepaid expenses | | 120 |
| | 118 |
|
| Assets from risk management activities, net of collateral | | 101 |
| | 219 |
|
| Other regulatory assets | | 56 |
| | 73 |
|
| Other current assets | | 44 |
| | 50 |
|
| Total current assets | | 1,429 |
| | 2,555 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 15,680 |
| | 15,177 |
|
| Less: Accumulated depreciation | | 4,522 |
| | 4,400 |
|
| Plant in service, net of depreciation | | 11,158 |
| | 10,777 |
|
| Construction work in progress | | 628 |
| | 580 |
|
| Total property, plant, and equipment | | 11,786 |
| | 11,357 |
|
| Other Property and Investments: | | | | |
| Goodwill | | 5,015 |
| | 5,015 |
|
| Equity investments in unconsolidated subsidiaries | | 1,509 |
| | 1,538 |
|
Other intangible assets, net of amortization of $161 and $145
at June 30, 2019 and December 31, 2018, respectively | | 85 |
| | 101 |
|
| Miscellaneous property and investments | | 20 |
| | 20 |
|
| Total other property and investments | | 6,629 |
| | 6,674 |
|
| Deferred Charges and Other Assets: | | | | |
| Operating lease right-of-use assets, net of amortization | | 95 |
| | — |
|
| Other regulatory assets, deferred | | 636 |
| | 669 |
|
| Other deferred charges and assets | | 186 |
| | 193 |
|
| Total deferred charges and other assets | | 917 |
| | 862 |
|
| Total Assets | | $ | 20,761 |
| | $ | 21,448 |
|
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 |
|
|
| | | | | | | | |
| Liabilities and Stockholder's Equity | | At June 30, 2019 | | At December 31, 2018 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 351 |
| | $ | 357 |
|
| Notes payable | | 492 |
| | 650 |
|
| Energy marketing trade payables | | 393 |
| | 856 |
|
| Accounts payable — | | | | |
| Affiliated | | 38 |
| | 45 |
|
| Other | | 294 |
| | 402 |
|
| Customer deposits | | 92 |
| | 133 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 17 |
| | 66 |
|
| Other accrued taxes | | 70 |
| | 75 |
|
| Accrued interest | | 57 |
| | 55 |
|
| Accrued compensation | | 64 |
| | 100 |
|
| Liabilities from risk management activities, net of collateral | | 22 |
| | 76 |
|
| Other regulatory liabilities | | 97 |
| | 79 |
|
| Other current liabilities | | 124 |
| | 130 |
|
| Total current liabilities | | 2,111 |
| | 3,024 |
|
| Long-term Debt | | 5,565 |
| | 5,583 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 1,088 |
| | 1,016 |
|
| Deferred credits related to income taxes | | 910 |
| | 940 |
|
| Employee benefit obligations | | 354 |
| | 357 |
|
| Operating lease obligations | | 79 |
| | — |
|
| Other cost of removal obligations | | 1,598 |
| | 1,585 |
|
| Accrued environmental remediation | | 247 |
| | 268 |
|
| Other deferred credits and liabilities | | 50 |
| | 105 |
|
| Total deferred credits and other liabilities | | 4,326 |
| | 4,271 |
|
| Total Liabilities | | 12,002 |
| | 12,878 |
|
Common Stockholder's Equity (See accompanying statements) | | 8,759 |
| | 8,570 |
|
| Total Liabilities and Stockholder's Equity | | $ | 20,761 |
| | $ | 21,448 |
|
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 COMPANIESSUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETSSTATEMENTS OF STOCKHOLDER'S EQUITY (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 |
|
|
| | | | | | | | | | | | | | | |
| | Paid-In
Capital | | Retained
Earnings (Accumulated Deficit) | | Accumulated
Other
Comprehensive
Income (Loss) | | Total |
| | (in millions) |
| Balance at December 31, 2017 | $ | 9,214 |
| | $ | (212 | ) | | $ | 20 |
| | $ | 9,022 |
|
| Net income | — |
| | 279 |
| | — |
| | 279 |
|
| Capital contributions from parent company | 14 |
| | — |
| | — |
| | 14 |
|
| Other comprehensive income (loss) | — |
| | — |
| | 2 |
| | 2 |
|
| Cash dividends on common stock | — |
| | (118 | ) | | — |
| | (118 | ) |
| Other | — |
| | (4 | ) | | 4 |
| | — |
|
| Balance at March 31, 2018 | 9,228 |
| | (55 | ) | | 26 |
| | 9,199 |
|
| Net loss | — |
| | (31 | ) | | — |
| | (31 | ) |
| Capital contributions from parent company | 8 |
| | — |
| | — |
| | 8 |
|
| Other comprehensive income (loss) | — |
| | — |
| | 1 |
| | 1 |
|
| Cash dividends on common stock | — |
| | (117 | ) | | — |
| | (117 | ) |
| Other | — |
| | 1 |
| | — |
| | 1 |
|
| Balance at June 30, 2018 | $ | 9,236 |
| | $ | (202 | ) | | $ | 27 |
| | $ | 9,061 |
|
| | | | | | | | |
| 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 |
|
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
SECOND QUARTER 2019 vs. SECOND QUARTER 2018
AND
YEAR-TO-DATE 2019 vs. YEAR-TO-DATE 2018
OVERVIEW
Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through utilities in sevenfour states – Nicor Gas in Illinois, Atlanta Gas Light in Georgia, Virginia New Jersey, Florida, Tennessee,Natural Gas in Virginia, and Maryland.Chattanooga Gas in Tennessee. Southern Company Gas and its subsidiaries areis also involved in several other complementary businesses.
Southern Company Gas hasmanages its business through four reportable segments – gas distribution operations, gas marketing services,pipeline investments, wholesale gas services, and gas midstream operationsmarketing services – and one non-reportable segment, – all other. For additional information on these segments, seeSee Note (K)(M) to the Condensed Financial Statements herein and "BUSINESS – The Southern Company System – Southern Company Gas" in Item 1 of the Form 10-K.10-K for additional information.
Many factors affect the opportunities, challenges, and risks of Southern Company Gas' business. These factors include the ability to maintain safety, to maintain constructive regulatory environments, to maintain and grow natural gas sales and number of customers, and to effectively manage and secure timely recovery of costs. Southern Company Gas hasThese costs include those related to projected long-term demand growth, environmental standards, safety, reliability, resilience, natural gas, and capital expenditures, including updating and expanding the natural gas distribution systems. The natural gas distribution utilities have 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,Atlanta Gas Light filed a rate case on June 3, 2019 and Disposition Activities
On July 1, 2016, Southern CompanyNicor Gas completed the Merger, which was accounted for by Southern Company using the acquisition methodfiled a rate case in November 2018. Both rate cases are expected to be finalized in 2019. The ultimate outcome of accounting whereby the assets acquired and liabilities assumed were recognizedthese matters cannot be determined 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.this time. See Note (I) to the Condensed Financial Statements herein for additional information relating to the Merger.
In September 2016, Southern Company Gas paid approximately $1.4 billion to acquire a 50% equity interest in SNG. On March 31, 2017, Southern Company Gas made an additional $50 million contribution to maintain its 50% equity interest in SNG. Southern Company Gas recorded equity investment income of $28 million and $86 million from this investment in the successor third quarter and year-to-date 2017, respectively, and $27 million in September 2016. See Note (J) to the Condensed Financial StatementsFUTURE EARNINGS POTENTIAL – "Regulatory Matters" herein and Notes 4 and 11Note 2 to the financial statements of Southernunder "Southern Company Gas under "Equity Method Investments – SNG" and "Investment in SNG," respectively,Rate Proceedings" in Item 8 of the Form 10-K for additional information.
In October 2016,During 2018, Southern Company Gas completed its purchase of Piedmont's 15% interestthe following sales, resulting in SouthStar, which eliminated the noncontrolling interest associated with SouthStar. See Noteapproximately $2.7 billion in aggregate proceeds.
On June 4, to the financial statements of2018, Southern Company Gas under "Variable Interest Entities" in Item 8completed the stock sale of the Form 10-K for additional information.Pivotal Home Solutions to American Water Enterprises LLC.
On October 15, 2017,July 1, 2018, a Southern Company Gas subsidiary, Pivotal Utility Holdings, entered into agreements forcompleted the salesales 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,
On July 29, 2018, Southern Company Gas intendsand its wholly-owned direct subsidiary, NUI Corporation, completed the stock sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to invest approximately $0.1 billion in capital expenditures which are required for ordinary business operations. The completion of each sale is subjectNextEra Energy.
See Note 15 to the satisfaction or waiver of certain closing conditions, including, among others, (i) the expiration or terminationfinancial statements in Item 8 of the waiting periodForm 10-K 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"Southern Company Gas" for additional information on these matters cannot be determined at this time.dispositions.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Operating Metrics
Southern Company Gas continues to focus on several operating metrics, including Heating Degree Days, customer count, and volumes of natural gas sold. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – "Operating Metrics" of Southern Company Gas in Item 7 of the Form 10-K.
Southern Company Gas measures weather and the effect on its business using Heating Degree Days. Generally, increased Heating Degree Days result in higher demand for natural gas on Southern Company Gas' distribution
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
system. With the exception of Southern Company Gas' utilities in Illinois and Florida,Nicor Gas, Southern Company Gas has various regulatory mechanisms, such as weather normalization mechanisms,and straight-fixed-variable rate design, which limit its exposure to weather changes within typical ranges in each of its utilities' respective service territory. However, the operating revenues from 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 reducelimit the negative earnings impactincome impacts in the event of warmer-than-normal weather, while retaining mosta significant portion of the earnings upside.positive benefits of colder-than-normal weather for these businesses.
The number of customers atserved by 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.
See RESULTS OF OPERATIONS herein for additional information on these operating metrics.
Seasonality of Results
During the Heating Season, is the period from November through March when 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.payables. However, these items are comparable when reviewing Southern Company Gas' annual results. Operating results for the interim periods presented are not necessarily indicative of annual results and can vary significantly from quarter to quarter.
RESULTS OF OPERATIONS
Net Income (Loss)
|
| | |
Successor |
Third Quarter 2017 vs. Third Quarter 2016 |
(change in millions) | | (% change) |
$11 | | N/M |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $137 | | N/M | | $128 | | 51.6 |
N/M - Not meaningful
NetIn the second quarter 2019, net income attributable to Southern Company Gas was $15$106 million for the third quarter 2017 compared to $4a net loss of $31 million for the corresponding period in 2016.2018. Excluding a $73 million net loss in 2018 from the Southern Company Gas Dispositions and $7 million net income in 2019 from the sale of Triton, net income increased $57 million. This increase was primarily due to $11an increase of $44 million at wholesale gas services primarily due to significant gas price volatility during the second quarter 2018, continued investment in infrastructure replacement programs, and lower income taxes, primarily at Atlanta Gas Light due to increased flowback of additionalexcess deferred income taxes in lieu of a rate increase as previously authorized by the Georgia PSC.
For year-to-date 2019, net income was $376 million compared to $248 million for the corresponding period in 2018. Excluding an $81 million net loss in 2018 from the Southern Company Gas Dispositions and $7 million net income in 2019 from the sale of Triton, net income increased $40 million. This increase was primarily due to continued investment in infrastructure replacement programs and base rate changes, lower income taxes primarily at Atlanta Gas Light due to increased flowback of excess deferred income taxes in lieu of a rate increase as previously authorized by the Georgia PSC, the impact of adopting a new paid time off policy to align with the Southern Company system in first quarter 2018, and an increase in earnings from equity method investments in 2019. Partially offsetting these increases netwere a decrease of associated depreciation, and a $7$13 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 expenses in the third quarter 2016, partially offset by $23 million of additional deferred income tax expense in the third quarter 2017.services, a contractor litigation
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
settlement recorded in the first quarter 2018, and increased depreciation and amortization primarily due to continued infrastructure investments at gas distribution operations. |
| | | | | | | | | | | | | |
| | | 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 attributableSee Note 2 to Southernthe financial statements under "Southern Company Gas for the successor year-to-date 2017 included $28 million of net income from wholesale gas services– Rate Proceedings – Atlanta Gas Light" 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" – Infrastructure Replacement Programs and base rate increases, primarily atCapital Projects – Atlanta Gas Light effective March 1, 2017, less– PRP" in Item 8 of the associated increases in depreciation. ForForm 10-K for additional information see FUTURE EARNINGS POTENTIAL– "Regulatory Matters – Base Rate Cases" herein. These increases were partially offset by $23 millionon Atlanta Gas Light's stipulation reflecting the impacts of additional deferred income tax expense.
Net income attributable to Southern Company Gas for the successor period of July 1, 2016 through September 30, 2016Tax Reform Legislation 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 interest 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 Gas in the successor periods.contractor litigation settlement, respectively.
Natural Gas Revenues, including Alternative Revenue Programs
|
| | |
| Successor |
| Third Quarter 2017 vs. Third Quarter 2016 |
| (change in millions) | | (% change) |
| $14 | | 2.7 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(17) | | (2.4) | | $(151) | | (6.5) |
In the thirdsecond quarter 2017,2019, natural gas revenues, including alternative revenue programs, were $532$689 million compared to $518$706 million for the corresponding period in 2016.2018. For year-to-date 2019, natural gas revenues, including alternative revenue programs, were $2.2 billion compared to $2.3 billion for the corresponding period in 2018.
Details of the changes in natural gas revenues, including alternative revenue programs, were as follows:
| | | | | Third Quarter 2017 | Second Quarter 2019 | | Year-to-Date 2019 |
| | | (in millions) | | (% change) | (in millions) | | (% change) | | (in millions) | | (% change) |
| Natural gas – prior year | | $ | 518 |
| | | |
| Natural gas revenues – prior year | | $ | 706 |
|
|
|
| $ | 2,314 |
|
|
|
|
| Estimated change resulting from – | | | | | | | | | | | |
| Infrastructure replacement programs and base rate increases | | 25 |
| | 4.8 | % | |
| Infrastructure replacement programs and base rate changes | | 10 |
|
| 1.4 | % |
| 42 |
|
| 1.8 | % |
| Gas costs and other cost recovery | | 1 |
| | 0.2 |
| (13 | ) |
| (1.8 | ) |
| 49 |
|
| 2.1 |
|
| Mark-to-market adjustments at gas marketing services | | 3 |
| | 0.6 |
| |
| Weather | | (7 | ) |
| (1.1 | ) |
| — |
|
| — |
|
| Wholesale gas services | | (16 | ) | | (3.1 | ) | 64 |
|
| 9.1 |
|
| (16 | ) |
| (0.7 | ) |
| Southern Company Gas Dispositions | | (70 | ) | | (9.9 | ) | | (237 | ) | | (10.2 | ) |
| Other | | 1 |
| | 0.2 |
| (1 | ) |
| (0.1 | ) |
| 11 |
|
| 0.5 |
|
| Natural gas – current year | | $ | 532 |
| | 2.7 | % | |
| Natural gas revenues – current year | | $ | 689 |
| | (2.4 | )% | | $ | 2,163 |
| | (6.5 | )% |
The increaseRevenues from infrastructure replacement programs and base rate changes increased in natural gas revenuethe second quarter and year-to-date 2019 compared to the corresponding periods in 2018 primarily relatesdue to increases of $4 million and $25 million, respectively, at Nicor Gas and $5 million and $14 million, respectively, at Atlanta Gas Light. These amounts include gas distribution operationsoperations' continued investments recovered through infrastructure replacement programs and base rate increases as well as the effect of revenues deferred in 2018 as a result of continued investmentthe Tax Reform Legislation. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" in infrastructure replacement programsItem 8 of the Form 10-K for additional information.
Revenues associated with gas costs and increases in base rate revenues, primarily at Atlanta Gas Light effective March 1, 2017, as well as the positive impact from the amortization of assets establishedother cost recovery decreased in the applicationsecond quarter 2019 and increased year-to-date 2019 compared to the corresponding periods in 2018. The decrease in the second quarter 2019 is primarily due to lower natural gas prices and decreased volumes of acquisition accounting atnatural gas marketing services. These increases weresold. The increase for year-to-date 2019 is primarily due to increased natural gas prices in the first quarter 2019, partially offset by mark-to-decreased volumes of natural gas sold year-to-date 2019. 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.
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 services and gas marketing servicesRevenues decreased in the second quarter 2019 due to changeswarmer weather in natural gas pricesIllinois and a decreaseGeorgia compared to the corresponding period 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.2018. See the weather discussion 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) |
| 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 cost of natural gas and $95 million in net revenuesRevenues from wholesale gas services net of $14 million of amortization associated with assets establishedincreased in the application of acquisition accounting. Also includedsecond quarter 2019 and decreased year-to-date 2019 compared to the corresponding periods in natural gas revenues were $69 million2018. The increase in additional revenues generated from gas distribution operations as a result of continued investment in infrastructure replacement programs and increases in base rate revenues,the second quarter 2019 is primarily at Atlanta Gas Light effective March 1, 2017,due to derivative gains, partially offset by a $16 milliondecreased commercial activity. For year-to-date 2019, the decrease attributableis primarily due 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.
decreased commercial activity, partially offset by derivative gains. See "Segment Information" herein for additional information on wholesale gas services' revenues and losses.
Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, recoverable natural gas revenues generally equal the cost of natural gas and do not affect net income from gas distribution operations. See "Cost of Natural – Wholesale Gas Services" herein for additional information. Revenue impacts from weather and customer growth are described further below.
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.
| | | | | Year-to-Date | | 2017
vs.
2016 | | 2017
vs.
normal | Second Quarter | | 2019
vs.
2018 | 2019
vs.
normal | | Year-to-Date | | 2019 vs. 2018 | 2019 vs. normal |
| | | Normal(a) | | 2017 | | 2016 | | (warmer) | | (warmer) | Normal(*) | 2019 | 2018 | | (warmer) | colder (warmer) | | Normal(*) | 2019 | 2018 | | colder (warmer) |
Illinois(b) | | 3,817 |
| | 3,146 |
| | 3,353 |
| | (6.2 | )% | | (17.6 | )% | 635 |
| 659 |
| 767 |
| | (14.1 | )% | 3.8 | % | | 3,679 |
| 3,956 |
| 3,809 |
| | 3.9 | % | 7.5 | % |
| Georgia | | 1,631 |
| | 1,008 |
| | 1,449 |
| | (30.4 | )% | | (38.2 | )% | 124 |
| 86 |
| 175 |
| | (50.9 | )% | (30.6 | )% | | 1,566 |
| 1,298 |
| 1,539 |
| | (15.7 | )% | (17.1 | )% |
| |
(a)(*) | Normal represents the 10-year average from January 1, 20072009 through SeptemberJune 30, 20162018 for Illinois at Chicago Midway International Airport and for Georgia at Atlanta Hartsfield-Jackson International Airport, based on information obtained from the National Oceanic and Atmospheric Administration, National Climatic Data Center. |
| |
(b) | The 10-year average Heating Degree Days established by the Illinois Commission in Nicor Gas' 2009 rate case is 3,580 for the first nine months from 1998 through 2007. |
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 onIllinois for gas distribution operations was limited to $6 million ($3 million after tax) and $7 million ($5 million after tax)in Illinois and Georgia for year-to-date 2017 and 2016, respectively.gas marketing services. The remaining impacts of weather on earnings are reflected in the chart below.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Gas Distribution Operations | | Gas Marketing Services |
| | Second Quarter | | Year-to-Date | | Second Quarter | | Year-to-Date |
| | 2019 | 2018 | | 2019 | 2018 | | 2019 | 2018 | | 2019 | 2018 |
| | (in millions) | | (in millions) |
| Pre-tax | $ | — |
| $ | 4 |
| | $ | 2 |
| $ | 2 |
| | $ | (1 | ) | $ | 2 |
| | $ | (1 | ) | $ | (1 | ) |
| After tax | — |
| 3 |
| | 2 |
| 2 |
| | (1 | ) | 1 |
| | (1 | ) | (1 | ) |
The following table provides the number of customers served by Southern Company Gas also hedged its exposure at gas marketing services to warmer-than-normal weather in GeorgiaJune 30, 2019 and Illinois;
2018:
|
| | | | | | | | |
| | June 30, | | |
| | 2019 | | 2018 | | 2019 vs. 2018 |
| | (in thousands, except market share %) | | (% change) |
Gas distribution operations(a) | 4,231 |
| | 4,609 |
| | (8.2 | )% |
| Gas marketing services | | | | | |
Energy customers(b) | 622 |
| | 696 |
| | (10.6 | )% |
| Market share of energy customers in Georgia | 28.8 | % | | 29.4 | % | |
|
|
| |
| (a) | Includes total customers of approximately 407,000 at June 30, 2018 related to Elizabethtown Gas, Elkton Gas, and Florida City Gas, which were sold in July 2018. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information. |
| |
| (b) | Gas marketing services' customers are primarily located in Georgia and Illinois. Also included as of June 30, 2018 were approximately 70,000 customers in Ohio contracted through an annual auction process to serve for 12 months beginning April 1, 2018. |
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 September 30, 2017 and 2016:
|
| | | | | | | | |
| | September 30, | | |
| | 2017 | | 2016 | | 2017 vs. 2016 |
| | (in thousands, except market share %) | | (% change) |
| Gas distribution operations | 4,555 |
| | 4,522 |
| | 0.7 | % |
| Gas marketing services | | | | | |
Energy customers(*) | 756 |
| | 626 |
| | 20.8 | % |
| Market share of energy customers in Georgia | 28.8 | % | | 29.4 | % | | |
| Service contracts | 1,183 |
| | 1,189 |
| | (0.5 | )% |
| |
(*) | Includes approximately 140,000 customers as of September 30, 2017 that were contracted to serve beginning April 1, 2017. |
Southern Company Gas anticipates overall customer growth trends at the remaining four natural gas distribution utilities in 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 forattract new customers and to retain existing customers.
Other Revenues
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(24) | | (100.0) | | $(55) | | (100.0) |
Other revenues related to Pivotal Home Solutions, which was sold in June 2018. See Note 15 to the foreseeable future. Southernfinancial statements in Item 8 of the Form 10-K under "Southern Company Gas will continue efforts at gas marketing services to enter into targeted markets and expand its energy customers and service contracts.– Sale of Pivotal Home Solutions" for additional information.
Cost of Natural Gas
|
| | |
| Successor |
| Third Quarter 2017 vs. Third Quarter 2016 |
| (change in millions) | | (% change) |
| $1 | | 0.8 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(37) | | (16.2) | | $(72) | | (7.6) |
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%80% and 85% of total cost of natural gas for the second quarter and year-to-date 2017 and will be recovered in this manner. For additional information, see2019, respectively. See MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – "Cost of Natural Gas" of Southern Company Gas in Item 7 of the Form 10-K and "Natural Gas Revenues, including Alternative Revenue Programs" herein.herein for additional information.
In the second quarter 2019, cost of natural gas was $191 million compared to $228 million for the corresponding period in 2018. Excluding a $25 million decrease related to the Southern Company Gas Dispositions, cost of natural gas decreased $12 million. This decrease reflects a 5.7% decrease in natural gas prices and a decrease in the volume of natural gas sold in the second quarter 2019 primarily as a result of warmer weather in Illinois and Georgia compared to the corresponding period in 2018.
For year-to-date 2019, cost of natural gas was $877 million compared to $949 million for the corresponding period in 2018. Excluding a $104 million decrease related to the Southern Company Gas Dispositions, cost of natural gas increased $32 million. This increase reflects an increase in natural gas prices, partially offset by a decrease in the volume of natural gas sold year-to-date 2019 compared to the corresponding period in 2018.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following table details the volumes of natural gas sold during all periods presented.
| | | | Third Quarter | | 2017
vs.
2016 | | Year-to-Date | | 2017
vs.
2016 | Second Quarter | 2019
vs.
2018 | | Year-to-Date | 2019
vs.
2018 |
| | 2017 | | 2016 | | % Change | | 2017 | | 2016 | | % Change | 2019 | 2018 | | 2019 | 2018 |
Gas distribution operations
(mmBtu in millions) | | | | | | | | | | | | Gas distribution operations (mmBtu in millions) | | | |
| Firm | 73 |
| | 71 |
| | 2.8 | % | | 438 |
| | 467 |
| | (6.2 | )% | 99 |
| 119 |
| (16.8 | )% | | 396 |
| 434 |
| (8.8 | )% |
| Interruptible | 22 |
| | 22 |
| | — | % | | 71 |
| | 71 |
| | — | % | 22 |
| 25 |
| (12.0 | )% | | 46 |
| 49 |
| (6.1 | )% |
| Total | 95 |
| | 93 |
| | 2.2 | % | | 509 |
| | 538 |
| | (5.4 | )% | |
Total(*) | | 121 |
| 144 |
| (16.0 | )% | | 442 |
| 483 |
| (8.5 | )% |
Wholesale gas services (mmBtu in millions/day) | | Wholesale gas services (mmBtu in millions/day) | | | |
| Daily physical sales | | 5.7 |
| 6.4 |
| (10.9 | )% | | 6.3 |
| 6.6 |
| (4.5 | )% |
Gas marketing services
(mmBtu in millions) | | | | | | | | | | | | Gas marketing services (mmBtu in millions) | |
| | |
|
| Firm: | | | | | | | | | | | | |
|
| | |
|
|
| Georgia | 3 |
| | 3 |
| | — | % | | 11 |
| | 25 |
| | (56.0 | )% | 4 |
| 5 |
| (20.0 | )% | | 19 |
| 22 |
| (13.6 | )% |
| Illinois | 1 |
| | 1 |
| | — | % | | 4 |
| | 8 |
| | (50.0 | )% | 2 |
| 2 |
| — |
| | 8 |
| 8 |
| — |
|
| Other emerging markets | 2 |
| | 2 |
| | — | % | | 7 |
| | 9 |
| | (22.2 | )% | |
| Interruptible: | | | | | | | | | | | | |
| Large commercial and industrial | 3 |
| | 3 |
| | — | % | | 8 |
| | 10 |
| | (20.0 | )% | |
| Ohio | | 1 |
| 2 |
| (50.0 | )% | | 8 |
| 11 |
| (27.3 | )% |
| Other | | 1 |
| 1 |
| — |
| | 2 |
| 2 |
| — |
|
| Interruptible large commercial and industrial | | 3 |
| 3 |
| — |
| | 7 |
| 7 |
| — |
|
| Total | 9 |
| | 9 |
| | — | % | | 30 |
| | 52 |
| | (42.3 | )% | 11 |
| 13 |
| (15.4 | )% | | 44 |
| 50 |
| (12.0 | )% |
Wholesale gas services
(mmBtu in millions/day) | | | | | | | | | | | | |
| Daily physical sales | 6.3 |
| | 7.6 |
| | (17.1 | )% | | 6.4 |
| | 7.6 |
| | (15.8 | )% | |
| |
| (*) | Includes total volumes of natural gas sold of 12 mmBtu and 38 mmBtu for the three and six months ended June 30, 2018 related to Elizabethtown Gas, Elkton Gas, and Florida City Gas, which were sold in July 2018. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas – Sale of Elizabethtown Gas and Elkton Gas" and " – Sale of Florida City Gas" for additional information. |
Cost of Other Sales
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(5) | | (100.0) | | $(12) | | (100.0) |
Cost of other sales related to Pivotal Home Solutions, which was sold in June 2018. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.
Other Operations and Maintenance Expenses
|
| | |
| Successor |
| Third Quarter 2017 vs. Third Quarter 2016 |
| (change in millions) | | (% change) |
| $(11) | | (5.1) |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(39) | | (16.4) | | $(81) | | (15.8) |
In the thirdsecond quarter 2017,2019, other operations and maintenance expenses were $205$199 million compared to $216$238 million for the corresponding period in 2016. The2018. Excluding a $34 million 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 successor year-to-date 2017 reflected increased compensation expenses due to timing, partially offset by low bad debt expense. For all periods presented,Southern Company Gas Dispositions, other operations and maintenance expenses decreased $5 million. This decrease was primarily includes professional services, includingdue to disposition-related costs incurred during 2018 and decreased compensation and benefit costs, partially offset by an increase in expenses associated with pipeline compliance and maintenance activities.
For year-to-date 2019, other operations and legal services, as well as compensationmaintenance expenses were $433 million compared to $514 million for the corresponding period in 2018. Excluding a $63 million decrease related to the Southern Company Gas Dispositions, other operations and benefit costs.maintenance expenses decreased $18 million. This decrease was primarily due to
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
a one-time adjustment in 2018 for the adoption of a new paid time off policy, disposition-related costs incurred during 2018, and decreased compensation and benefits costs, partially offset by an increase in expenses associated with pipeline compliance and maintenance activities. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Southern Company Gas in Item 7 of the Form 10-K for additional information.
Depreciation and Amortization
|
| | |
| Successor |
| Third Quarter 2017 vs. Third Quarter 2016 |
| (change in millions) | | (% change) |
| $9 | | 7.8 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(7) | | (5.6) | | $(17) | | (6.7) |
In the thirdsecond quarter 2017,2019, depreciation and amortization was $125$119 million compared to $116$126 million for the corresponding period in 2016. The2018. Excluding a $10 million decrease related to the Southern Company Gas Dispositions, depreciation and amortization increased $3 million. This increase was primarily due to $7 million in additional depreciationcontinued infrastructure investments at gas distribution operations associated with additional plantoperations.
For year-to-date 2019, depreciation and amortization was $238 million compared to $255 million for the corresponding period in service primarily2018. Excluding a $26 million decrease 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 |
|
Depreciationthe Southern Company Gas Dispositions, depreciation and amortization for the successor year-to-date 2017 included $29 million of additional amortization of intangible assets established in the application of acquisition accountingincreased $9 million. This increase was primarily at gas marketing services, $21 million in additional depreciationdue to continued infrastructure investments 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.operations.
Taxes Other Than Income Taxes
|
| | |
| Successor |
| Third Quarter 2017 vs. Third Quarter 2016 |
| (change in millions) | | (% change) |
| $(3) | | (10.3) |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(2) | | (4.2) | | $3 | | 2.4 |
In the thirdsecond quarter 2017,2019, taxes other than income taxes were $26$46 million compared to $29$48 million for the corresponding period in 2016. The2018. Excluding a $2 million decrease related to the Southern Company Gas Dispositions, taxes other than income taxes remained unchanged.
For year-to-date 2019, taxes other than income taxes were $128 million compared to $125 million for the corresponding period in 2018. Excluding a $6 million decrease related to the Southern Company Gas Dispositions, taxes other than income taxes increased $9 million. This increase primarily reflects establishing a regulatory asset related toincreases in Nicor Gas' invested capital tax. For additional information, see FUTURE EARNINGS POTENTIAL– "Regulatory Matters – Riders" herein.tax as a result of increased infrastructure investments and increased revenue tax expenses as a result of higher natural gas revenues at Nicor Gas, both of which are passed through to customers.
Goodwill Impairment
|
| | | | | | | | | | | | | |
| | | 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 |
|
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $— | | N/M | | $(42) | | N/M |
Taxes other than income taxes in the successor periods reflected increased revenue-based taxes due to higher revenues at gas distribution operationsN/M - Not meaningful
A goodwill impairment charge of $42 million was recorded during the successor periods.first quarter 2018 in contemplation of the sale of Pivotal Home Solutions. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Loss on Disposition
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(36) | | N/M | | $(36) | | N/M |
N/M - Not meaningful
As a result of the sale of Pivotal Home Solutions in June 2018, a $36 million pre-tax loss was recorded in the second quarter 2018. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.
Earnings from Equity Method Investments
|
| | |
| Successor |
| Third Quarter 2017 vs. Third Quarter 2016 |
| (change in millions) | | (% change) |
| $3 | | 10.3 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $— | | — | | $6 | | 8.1 |
In the thirdsecond quarter 2017,2019 and 2018, earnings from equity method investments were $32$31 million. For year-to-date 2019, earnings from equity method investments were $80 million compared to $29$74 million for the corresponding period in 2016. The increase was primarily due to2018. For both the second quarter and year-to-date 2019, earnings from equity method investments reflect higher earnings from SNG PennEast 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 investmentsas a result of rate increases implemented by SNG that became effective September 2018, partially offset by a $6 million pre-tax loss on the sale of Triton in the successor year-to-date 2017 consisted of $86 million in earnings from SNG and $14 million in earnings from all other investments.
May 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 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $3 | | 100.0 | | $(5) | | (33.3) |
In the third quarter 2017,For year-to-date 2019, other income (expense), net was $18$10 million compared to $9$15 million for the corresponding period in 2016. The increase2018. This decrease was primarily due to a $14 million gain from the settlement of contractor litigation claims.settlement in the first quarter 2018. See Note 2 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects – Atlanta Gas Light – PRP" in Item 8 of the Form 10-K for additional information.
Income Taxes
|
| | | | | | | | | | | | | |
| | | 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 |
|
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(49) | | (89.1) | | $(76) | | (47.8) |
In the second quarter 2019, income taxes were $6 million compared to $55 million for the corresponding period in 2018. Excluding a $38 million decrease related to the Southern Company Gas Dispositions, income taxes decreased $11 million. The successor year-to-date 2017 reflects a $16 million gain fromdecrease was primarily due to an increase in the settlementflowback of contractor litigation claims. The successor period of July 1, 2016 through September 30, 2016excess deferred income taxes in 2019 primarily at Atlanta Gas Light as previously authorized by the Georgia PSC and the predecessorreversal of a $13 million federal income tax valuation allowance in connection with the sale of Triton in May 2019, partially offset by higher pre-tax earnings.
For year-to-date 2019, income taxes were $83 million compared to $159 million for the corresponding period in 2018. Excluding a $51 million decrease related to the Southern Company Gas Dispositions, income taxes decreased $25 million. This decrease was primarily due to an increase in the flowback of January 1, 2016 through June 30, 2016excess deferred income taxes in 2019 primarily representat Atlanta Gas Light as previously authorized by the Georgia PSC and the reversal of a $13 million federal income tax gross-up on contributionsvaluation allowance in aidconnection with the sale of construction and AFUDC.Triton in May 2019.
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 |
InSee Note (E) to the third quarter 2017, interest expense, net of amounts capitalized was $51 million compared to $39 million for the corresponding period in 2016. The increase was primarily due to 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.
Income Taxes
|
| | |
Successor |
Third Quarter 2017 vs. Third Quarter 2016 |
(change in millions) | | (% change) |
$45 | | N/M |
N/M - Not meaningful
In the third quarter 2017, income taxes were $52 million compared to $7 million for the corresponding period in 2016. The increase reflects $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, as well as higher pre-tax earnings. See FUTURE EARNINGS POTENTIALCondensed Financial Statements 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 millioninformation on the sale of Triton and Note 2 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional deferred income tax expense associated with Stateinformation on the Atlanta Gas Light stipulation reflecting the impacts of Illinois tax legislation and the allocation of new tax apportionment factors, as well as increased income taxes from higher pre-tax earnings. See FUTURE EARNINGS POTENTIALTax Reform Legislation. Also see Note (G) to the Condensed 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, taxes other than income taxes, goodwill impairment, and Merger-related expenses,loss on disposition, 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.
| | | | | 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 2019 | Second Quarter 2018 | | Year-to-Date 2019 | Year-to-Date 2018 |
| | | (in millions) | | | (in millions) | (in millions) |
| Operating Income | | $ | 68 |
| | $ | 12 |
| | $ | 555 |
| | $ | 12 |
| | | $ | 321 |
| $ | 134 |
| $ | 49 |
| | $ | 487 |
| $ | 436 |
|
Other operating expenses(a) | | 356 |
| | 396 |
| | 1,181 |
| | 396 |
| | | 815 |
| 364 |
| 448 |
| | 799 |
| 972 |
|
Revenue taxes(b) | | (8 | ) | | (8 | ) | | (74 | ) | | (8 | ) | | | (56 | ) | (22 | ) | (23 | ) | | (76 | ) | (73 | ) |
| Adjusted Operating Margin | | $ | 416 |
| | $ | 400 |
| | $ | 1,662 |
| | $ | 400 |
| | | $ | 1,080 |
| $ | 476 |
| $ | 474 |
| | $ | 1,210 |
| $ | 1,335 |
|
| |
| (a) | Includes other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, goodwill impairment, and Merger-related expenses.loss on disposition. |
| |
| (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
|
| | | | | | | | | | | | | | | | | | | | | |
| | | 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 |
|
| |
(*) | 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 metricnet income for each segment is illustratedare provided in the tablestable below. See Note (K)(M) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
| |
| Successor | |
| | Third Quarter 2017 |
| Third Quarter 2016 | | | | | | | | | | | | | |
| Adjusted Operating |
| Operating |
| Net Income |
| Adjusted Operating |
| Operating |
| Net Income | Second Quarter 2019 |
| Second Quarter 2018 |
| Margin(*) |
| Expenses(*) |
| (Loss) |
| Margin(*) |
| Expenses(*) |
| (Loss) | Adjusted Operating Margin(a) | | Operating Expenses(a) | | Net Income (Loss) | | Adjusted Operating Margin(a)(b) | | Operating Expenses(a)(b) | | Net Income (Loss)(b) |
| (in millions) |
| (in millions) | (in millions) | | (in millions) |
| Gas distribution operations | $ | 379 |
|
| $ | 271 |
|
| $ | 52 |
|
| $ | 353 |
|
| $ | 284 |
|
| $ | 27 |
| $ | 394 |
|
| $ | 287 |
|
| $ | 58 |
|
| $ | 429 |
|
| $ | 296 |
|
| $ | 68 |
|
| Gas pipeline investments | | 8 |
|
| 3 |
|
| 25 |
|
| 8 |
| | 3 |
| | 21 |
|
| Wholesale gas services | | 41 |
|
| 10 |
|
| 23 |
|
| (16 | ) |
| 14 |
|
| (21 | ) |
| Gas marketing services | 51 |
|
| 48 |
|
| 1 |
|
| 45 |
|
| 51 |
|
| (4 | ) | 27 |
|
| 31 |
|
| (3 | ) |
| 48 |
| | 87 |
| | (76 | ) |
| 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 | ) | 7 |
|
| 12 |
|
| 3 |
|
| 6 |
|
| 26 |
|
| (23 | ) |
| Intercompany eliminations | (3 | ) |
| (3 | ) |
| — |
|
| (1 | ) |
| (1 | ) |
| — |
| (1 | ) |
| (1 | ) |
| — |
|
| (1 | ) |
| (1 | ) |
| — |
|
| Consolidated | $ | 416 |
|
| $ | 348 |
|
| $ | 15 |
|
| $ | 400 |
|
| $ | 388 |
|
| $ | 4 |
| $ | 476 |
| | $ | 342 |
| | $ | 106 |
| | $ | 474 |
| | $ | 425 |
| | $ | (31 | ) |
| |
(*)(a) | OperatingAdjusted 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
| |
| (b) | 2018 adjusted operating margin, operating expenses, and net income for gas distribution operations and gas marketing services include the impacts of the Southern Company Gas Dispositions. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information. |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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 2019 | | Year-to-Date 2018 |
| | Adjusted Operating Margin(a) | | Operating Expenses(a) | | Net Income (Loss) | | Adjusted Operating Margin(a)(b) | | Operating Expenses(a)(b) | | Net Income (Loss)(b) |
| | (in millions) | | (in millions) |
| Gas distribution operations | $ | 918 |
| | $ | 601 |
| | $ | 191 |
| | $ | 986 |
| | $ | 620 |
| | $ | 216 |
|
| Gas pipeline investments | 16 |
| | 6 |
| | 57 |
| | 16 |
| | 6 |
| | 48 |
|
| Wholesale gas services | 125 |
| | 29 |
| | 70 |
| | 147 |
| | 36 |
| | 83 |
|
| Gas marketing services | 142 |
| | 62 |
| | 58 |
| | 175 |
| | 181 |
| | (63 | ) |
| All other | 13 |
| | 29 |
| | — |
| | 15 |
| | 60 |
| | (36 | ) |
| Intercompany eliminations | (4 | ) | | (4 | ) | | — |
| | (4 | ) | | (4 | ) | | — |
|
| Consolidated | $ | 1,210 |
| | $ | 723 |
| | $ | 376 |
| | $ | 1,335 |
| | $ | 899 |
| | $ | 248 |
|
| |
(*)(a) | OperatingAdjusted operating margin and operating expenses are adjusted for Nicor Gas' revenue tax expenses, which are passed through directly to customers. |
| |
| (b) | 2018 adjusted operating margin, operating expenses, and net income for gas distribution operations and gas marketing services include the impacts of the Southern Company Gas Dispositions. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information. |
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, 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
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
revenues based on consumption, the earnings of the natural gas distribution utilities can be affected by customer consumption patterns that are a function of weather conditions, price levels for natural gas, and general economic conditions that may impact customers' ability to pay for natural gas consumed. Southern Company Gas has various weather mechanisms, such as weather normalization mechanisms and weather derivative instruments, that limit its exposure to weather changes within typical ranges in its natural gas distribution utilities' service territories.
Successor ThirdIn July 2018, a Southern Company Gas subsidiary, Pivotal Utility Holdings, completed the sales of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. Also in July 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI Corporation, completed the sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energy. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information.
Excluding the impact of the utilities sold in 2018, the second quarter and year-to-date 2019 results of gas distribution operations are as follows:
|
| | | | | | | | | | | | | | | | | | | |
| | Second Quarter 2019 | | Year-to-Date 2019 |
| Favorable (Unfavorable) | Variance to Prior Period | Impact of Utilities Sold in 2018 | Variance Excluding Utilities Sold in 2018 | | Variance to Prior Period | Impact of Utilities Sold in 2018 | Variance Excluding Utilities Sold in 2018 |
| | (in millions) | | (in millions) |
| Adjusted Operating Margin | $ | (35 | ) | $ | 45 |
| $ | 10 |
| | $ | (68 | ) | $ | 133 |
| $ | 65 |
|
| Operating expenses | 9 |
| (35 | ) | (26 | ) | | 19 |
| (75 | ) | (56 | ) |
| Other income (expense), net | — |
| — |
| — |
| | (7 | ) | — |
| (7 | ) |
| Interest expense | (3 | ) | (6 | ) | (9 | ) | | (4 | ) | (13 | ) | (17 | ) |
| Income tax expense | 19 |
| (1 | ) | 18 |
| | 35 |
| (12 | ) | 23 |
|
| Net Income | $ | (10 | ) | $ | 3 |
| $ | (7 | ) | | $ | (25 | ) | $ | 33 |
| $ | 8 |
|
Second Quarter 20172019 vs. ThirdSecond Quarter 20162018
In the thirdsecond quarter 2017,2019, net income was $52decreased $7 million, or 10.8%, compared to $27 million for the corresponding period in 2016.2018. The increase in net income relates to an increase of $26$10 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 ininvestments recovered through infrastructure replacement programs, and base rate increases, primarily at Atlanta Gas Light effective March 1, 2017.partially offset by warmer weather in Illinois during the second quarter 2019 compared to the corresponding period in 2018. The decrease$26 million increase in operating expenses primarily reflects $18 million in rate credits providedincludes increased compensation and benefit costs, higher expenses passed through directly to customers, of Elizabethtown Gas in 2016 as a condition of the Merger, partially offset by $7 million inincreased expenses for pipeline compliance and maintenance activities, and additional depreciation primarily due to continued investmentadditional assets placed in infrastructure programs.service. The increase in other income (expense), net primarily reflects a $14$9 million gain from the settlement of contractor litigation claims in 2017. The increase in interest expense includes the impact of intercompany promissory notes executed in December 2016 andresults from the issuance of first mortgage bonds at Nicor Gas on August 10, 2017. Thein the prior year. Income tax expense decreased $18 million primarily due to an increase in the flowback of excess deferred income tax expense relates primarily to highertaxes at Atlanta Gas Light in 2019 and lower pre-tax earnings.
Successor Year-to-Date 20172019 vs. Year-to-Date 2018
NetFor year-to-date 2019, net income of $223increased $8 million, includes $1.3 billionor 4.4%, compared to the corresponding period in 2018. The $65 million increase in adjusted operating margin $866primarily reflects additional revenue from continued investments recovered through infrastructure replacement programs and base rate increases, the effect of revenues deferred in 2018 as a result of the Tax Reform Legislation, and colder weather in Illinois during the first quarter 2019 compared to the corresponding period in 2018. The $56 million increase in operating expenses includes increased compensation and $23 millionbenefit costs, higher expenses passed through directly to customers, increased expenses for pipeline compliance and maintenance activities, and additional depreciation primarily due to additional assets placed in service. The decrease in other income (expense), net which resultedis primarily due to a contractor litigation settlement in EBITthe first quarter 2018. The $17 million increase in interest expense is primarily from the issuance of $486 million. Netfirst mortgage bonds at Nicor Gas in the prior year. The $23 million decrease in income also includestax expense is primarily due to
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
$119 millionan increase in interest expense, netthe flowback of amounts capitalized and $144 millionexcess deferred income taxes in income tax expense. Adjusted operating margin reflects $69 million in additional revenue from continued investment in infrastructure replacement programs and base rate increases,2019, primarily at Atlanta Gas Light effective March 1, 2017. Also includedand lower pre-tax earnings.
See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings – Atlanta Gas Light" and " – Infrastructure Replacement Programs and Capital Projects – Atlanta Gas Light – PRP" in Item 8 of the Form 10-K for additional information on Atlanta Gas Light's stipulation reflecting the impacts of the Tax Reform Legislation and the contractor litigation settlement, respectively.
Gas Pipeline Investments
Gas pipeline investments consists primarily of joint ventures in natural gas pipeline investments including SNG, Atlantic Coast Pipeline, PennEast Pipeline, and a 50% joint ownership interest in the Dalton Pipeline. See Note (E) to the Condensed Financial Statements 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 2019, net income increased $4 million, or 19.0%, and $9 million, or 18.8%, respectively, compared to the corresponding periods in 2018. These increases primarily relate to higher earnings from 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 factors. When market price volatility increases, wholesale gas services is well positioned to capture significant value and generate stronger results. Operating expenses primarily reflect employee compensation and benefits.
In the second quarter 2019, net income increased $44 million, or 209.5%, compared to the corresponding period in 2018. This increase primarily relates to a $57 million increase in adjusted operating margin was increased customer growth,and a $4 million decrease in operating expenses, partially offset by a $6 million negative impactan increase of warmer-than-normal weather, net of hedging. Operating expenses reflect a $21 million increase in depreciation associated with additional assets placed in service, as well as increased compensation expense, legal expenses, and pipeline compliance and maintenance activities. Other income (expense), net reflects a $16 million gain from the settlement of contractor litigation claims. Interest expense reflects the impact of intercompany promissory notes executed in December 2016 and the issuance of first mortgage bonds 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, 2016
EBIT of $353expense due to higher pre-tax earnings. For year-to-date 2019, net income decreased $13 million, includes $911or 15.7%, compared to the corresponding period in 2018. This decrease primarily relates to a $22 million decrease 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 negativedecrease in operating expenses.
Details of the changes in adjusted operating margin are provided in the table below. The decreases in operating expenses primarily reflect lower compensation and benefit expenses.
|
| | | | | | | | | | | | | |
| | Second Quarter 2019 | Second Quarter 2018 | | Year-to-Date 2019 | Year-to-Date 2018 |
| | (in millions) |
| Commercial activity recognized | $ | (1 | ) | $ | 17 |
| | $ | 37 |
| $ | 189 |
|
| Gain on storage derivatives | 2 |
| — |
| | 5 |
| 1 |
|
| Gain (loss) on transportation and forward commodity derivatives | 48 |
| (28 | ) | | 77 |
| (44 | ) |
| LOCOM adjustments, net of current period recoveries | (6 | ) | — |
| | (8 | ) | (3 | ) |
| Purchase accounting adjustments to fair value inventory and contracts | (2 | ) | (5 | ) | | 14 |
| 4 |
|
| Adjusted operating margin | $ | 41 |
| $ | (16 | ) | | $ | 125 |
| $ | 147 |
|
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 warmer-than-normalprior period hedge gains and losses as associated physical transactions occur. The decrease in commercial activity in the second quarter and year-to-date 2019 compared to the corresponding period in 2018 was primarily due to significant natural gas price volatility that resulted from prolonged cold weather netduring the first quarter 2018 coupled with low natural gas supply.
Change in Storage and Transportation Derivatives
Volatility in the natural gas market arises from a number of hedging. Operating expenses reflect depreciationfactors, 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 2019 resulted in storage derivative gains. Transportation and forward commodity derivative gains in 2019 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 other variable fuel, withdrawal, receipt, and delivery charges, and exclude estimated profit sharing under asset management agreements. Further, the amounts that are realizable in future periods are based on the inventory withdrawal schedule, planned physical flow of natural gas between the transportation receipt and delivery points, and forward natural gas prices at June 30, 2019. A portion of wholesale gas services' storage inventory and transportation capacity is economically hedged with futures contracts, which results in the realization of substantially fixed net operating revenues.
|
| | | | | | | | | | |
| | Storage withdrawal schedule | | |
| | Total storage(a) | | Expected net operating gains(b) | | Physical transportation transactions – expected net operating losses(c) |
| | (in mmBtu in millions) | | (in millions) | | (in millions) |
| 2019 | 16 |
| | $ | 2 |
| | $ | (15 | ) |
| 2020 and thereafter | 18 |
| | 8 |
| | (62 | ) |
| Total at June 30, 2019 | 34 |
| | $ | 10 |
| | $ | (77 | ) |
| |
| (a) | At June 30, 2019, the WACOG of wholesale gas services' expected natural gas withdrawals from storage was $2.05 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" of Southern Company Gas in Item 7 of the Form 10-K.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 2019 resulted in storage derivative instrumentsgains. Transportation and forward commodity derivative gains in 2019 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 the transportation portfolio of wholesale gas services are presented in the following table, along with the net operating revenues expected at the time of withdrawal from storage and the physical flow of natural gas between contracted transportation receipt and delivery points. Wholesale gas services' expected net operating revenues exclude storage and transportation demand charges, as well as other variable fuel, withdrawal, receipt, and delivery charges, and exclude estimated profit sharing under asset management agreements. Further, the amounts that are realizable in future periods are based on the inventory withdrawal schedule, planned physical flow of natural gas between the transportation receipt and delivery points, and forward natural gas prices at June 30, 2019. A portion of wholesale gas services' storage inventory and transportation capacity is economically hedged with futures contracts, which results in the realization of substantially fixed net operating revenues.
|
| | | | | | | | | | |
| | Storage withdrawal schedule | | |
| | Total storage(a) | | Expected net operating gains(b) | | Physical transportation transactions – expected net operating losses(c) |
| | (in mmBtu in millions) | | (in millions) | | (in millions) |
| 2019 | 16 |
| | $ | 2 |
| | $ | (15 | ) |
| 2020 and thereafter | 18 |
| | 8 |
| | (62 | ) |
| Total at June 30, 2019 | 34 |
| | $ | 10 |
| | $ | (77 | ) |
| |
| (a) | At June 30, 2019, the WACOG of wholesale gas services' expected natural gas withdrawals from storage was $2.05 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 tools, to partially mitigate potential weather impacts. Operating expenses primarily reflect employee costs, marketing, and bad debt expenses.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.
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 2016 from the application of acquisition accounting. Operating expenses reflect decreased amortization of intangible assets established in the application of acquisition accounting.
Successor Year-to-Date 2017
Net income of $36 million includes $213 million in adjusted operating margin and $149 million in operating expenses, 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 established in the application of acquisition accounting.
Successor Period of July 1, 2016 through September 30, 2016
Net loss of $4 million includes $45 million in adjusted 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.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Predecessor Period 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 positioned the business to generate positive economic earnings on an annual basis even under low volatility market conditions that can result from a number of factors. When market price volatility increases, wholesale gas services is well positioned to capture significant value and generate stronger results. Operating expenses primarily reflect employee compensation and benefits.
Successor 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
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following table illustrates the components of wholesale gas services' adjusted operating margin for the periods presented.
|
| | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | 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 2019 resulted in storage derivative gains. Transportation and forward commodity derivative gains in 2019 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, 2017.2019. A portion of wholesale gas services' storage inventory and transportation capacity is economically hedged with futures contracts, which results in the realization of substantially fixed net operating revenues.
|
| | | | | | | | | | |
| | Storage withdrawal schedule | | |
| | Total storage
(WACOG $2.67) | | 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) |
| 2019 | 16 |
| | $ | 2 |
| | $ | (15 | ) |
| 2020 and thereafter | 18 |
| | 8 |
| | (62 | ) |
| Total at June 30, 2019 | 34 |
| | $ | 10 |
| | $ | (77 | ) |
| |
| (a) | At June 30, 2019, the WACOG of wholesale gas services' expected natural gas withdrawals from storage was $2.05 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 Operations
Gas midstream operations consists primarily of gas pipeline investments, with storage 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) 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 2016
In both the third quarter 2017 and the corresponding period in 2016 net income was $14 million. Net income reflects a $3 million increase in adjusted operating margin 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 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, and $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 million in income tax expense.
Successor Period of July 1, 2016 through September 30, 2016
Net income of $14 million includes $9 million in adjusted operating margin, $13 million 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,Gas Marketing Services
Gas marketing services provides energy-related products and $1services 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 hedging strategies, such as weather derivative instruments and other risk management tools, to partially mitigate potential weather impacts.
On June 4, 2018, Southern Company Gas completed the sale of Pivotal Home Solutions to American Water Enterprises LLC. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information.
Second Quarter 2019 vs. Second Quarter 2018
In the second quarter 2019, net loss decreased $73 million compared to the corresponding period in other income (expense), net, which resulted in EBIT of $25 million. Also included in net income is $112018. This decrease primarily relates to a $56 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 milliondecrease in operating expenses and $3a $36 million decrease in income tax expense, partially offset by a $21 million decrease in adjusted operating margin. The decrease in net loss is primarily attributable to the 2018 disposition of otherPivotal Home Solutions.
Year-to-Date 2019 vs. Year-to-Date 2018
For year-to-date 2019, net income (expense), net.increased $121 million compared to the corresponding period in 2018. This increase primarily relates to a $119 million decrease in operating expenses and a $33 million decrease in income tax expense, partially offset by a $33 million decrease in adjusted operating margin.
Excluding a $43 million decrease attributable to the 2018 disposition of Pivotal Home Solutions, adjusted operating margin increased $10 million, which primarily reflects favorable margins and recovery of prior period hedge losses. Excluding a $118 million decrease attributable to the 2018 disposition of Pivotal Home Solutions that includes the related goodwill impairment charge, operating expense decreased $1 million.
All Other
All other includes Southern Company Gas' storage and fuels operations and its investment in Triton through completion of 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 ThirdSecond Quarter 20172019 vs. ThirdSecond Quarter 20162018
In the thirdsecond quarter 2017,2019, net loss was $29income increased $26 million compared to $22 million in the corresponding period in 2016. The2018. This increase in net lossprimarily reflects a $23$14 million decrease in operating expenses and a decrease of $2$13 million in other income (expense), net. Net loss also reflected a $6 million increase in interest expense, net of amounts capitalized and an increase of $34 milliondecrease in income taxes. The decrease in operating expenses was primarily due to disposition-related costs incurred during 2018. The decrease in income taxes reflects lower taxes due to the reversal of a federal income tax valuation allowance in connection with the sale of Triton.
Year-to-Date 2019 vs. Year-to-Date 2018
For year-to-date 2019, net income increased $36 million compared to the corresponding period in 2018. This increase primarily reflects a $35$31 million decrease in Merger-relatedoperating expenses and a $10 million decrease in income taxes, partially offset by a $10$2 million increasedecrease in other operations and maintenanceadjusted operating margin. The decrease in operating expenses primarily reflects a one-time adjustment in the first quarter 2018 for the adoption of a new paid time off policy, disposition-related costs incurred during 2018, and a $3 million increase from the acceleration ofdecrease in depreciation relating to certain assets. Interest expense decreased as a result of intercompany promissory notes executed in December 2016.and amortization. The increasedecrease in income taxes primarily reflects additional deferredlower taxes due to the reversal of a federal income tax expenses associatedvaluation allowance in connection with Statethe sale 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.Triton.
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 2019 and 2018 are reflected in the following tables. See Note (K)(M) 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 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 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| | 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 2018 |
| | Gas Distribution Operations | Gas Pipeline Investments | Wholesale Gas Services | Gas Marketing Services | All Other | Intercompany Elimination | Consolidated |
| | (in millions) |
| Operating Income (Loss) | $ | 133 |
| $ | 5 |
| $ | (30 | ) | $ | (39 | ) | $ | (20 | ) | $ | — |
| $ | 49 |
|
Other operating expenses(a) | 319 |
| 3 |
| 14 |
| 87 |
| 26 |
| (1 | ) | 448 |
|
Revenue tax expense(b) | (23 | ) | — |
| — |
| — |
| — |
| — |
| (23 | ) |
| Adjusted Operating Margin | $ | 429 |
| $ | 8 |
| $ | (16 | ) | $ | 48 |
| $ | 6 |
| $ | (1 | ) | $ | 474 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| | Year-to-Date 2019 |
| | Gas Distribution Operations | Gas Pipeline Investments | Wholesale Gas Services | Gas Marketing Services | All Other | Intercompany Elimination | Consolidated |
| | (in millions) |
| Operating Income (Loss) | $ | 317 |
| $ | 10 |
| $ | 96 |
| $ | 80 |
| $ | (16 | ) | $ | — |
| $ | 487 |
|
Other operating expenses(a) | 677 |
| 6 |
| 29 |
| 62 |
| 29 |
| (4 | ) | 799 |
|
Revenue tax expense(b) | (76 | ) | — |
| — |
| — |
| — |
| — |
| (76 | ) |
| Adjusted Operating Margin | $ | 918 |
| $ | 16 |
| $ | 125 |
| $ | 142 |
| $ | 13 |
| $ | (4 | ) | $ | 1,210 |
|
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
| | | | | | | | | | | | | | | | | | | | | |
| 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 2018 |
| | 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 |
| $ | 366 |
| $ | 10 |
| $ | 111 |
| $ | (6 | ) | $ | (45 | ) | $ | — |
| $ | 436 |
|
Other operating expenses(a) | 616 |
| 81 |
| 33 |
| 24 |
| 65 |
| (4 | ) | 815 |
| 693 |
| 6 |
| 36 |
| 181 |
| 60 |
| (4 | ) | 972 |
|
Revenue tax expense(b) | (56 | ) | — |
| — |
| — |
| — |
| — |
| (56 | ) | (73 | ) | — |
| — |
| — |
| — |
| — |
| (73 | ) |
| Adjusted Operating Margin | $ | 911 |
| $ | 190 |
| $ | (36 | ) | $ | 15 |
| $ | 4 |
| $ | (4 | ) | $ | 1,080 |
| $ | 986 |
| $ | 16 |
| $ | 147 |
| $ | 175 |
| $ | 15 |
| $ | (4 | ) | $ | 1,335 |
|
| |
| (a) | Includes other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, goodwill impairment, and Merger-related expenses.loss on disposition. |
| |
| (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
The results of operations discussed above are not necessarily indicative of Southern Company Gas' future earnings potential. The Southern Company Gas Dispositions are expected to materially decrease future earnings and cash flows to Southern Company Gas. In the second quarter and year-to-date 2018,net income attributable to these dispositions, excluding the related goodwill impairment and loss on disposition, was $38 million and $3 million, respectively.The level of Southern Company Gas' future earnings depends on numerous factors that affect the opportunities, challenges, and risks of itsSouthern Company Gas' primary business of natural gas distribution and its complementary businesses in the gas marketing services,pipeline investments, wholesale gas services, and gas midstream operationsmarketing services sectors. These factors include Southern Company Gas' 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, Southern Company Gas'its 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 maintainingbe driven by customer growth and growing sales and customers which are subject to a numbervariety of other factors. These factors include weather, competition, new energy contracts with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the 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.
Volatility of natural gas prices has a significant impact on Southern Company Gas' customer rates, its long-term competitive position against other energy sources, and the ability of its gas marketing services and wholesale gas services segments to capture value from locational and seasonal spreads. Additionally, changes in commodity prices subject a significant portion of Southern Company Gas' operations to earnings variability. Over the longer-term,longer term, volatility is expected to be low to moderate and locational and/or transportation spreads are expected to decrease as new pipelines are built to reduce the existing supply constraints in the shale areas of the Northeast U.S. To the extent these pipelines are delayed or not built, volatility could increase. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Southern Company Gas in Item 7 of the Form 10-K for additional information on permitting challenges experienced by the Atlantic Coast 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, if economic conditions continue to improve, including the new housing market, the demand for natural gas may increase, which may cause natural gas prices to rise and drive higher volatility in the natural gas markets on a longer-term basis.
As part of its business strategy, Southern Company Gas regularly considers and evaluates joint development arrangements as well as acquisitions and dispositions of businesses and assets.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For additional information relatingDue to these issues, see "Risk Factors"the seasonal nature of the natural gas business and other factors including, but not limited to, weather, regulation, competition, customer demand, and general economic conditions, the second quarter and year-to-date 2019 results are not necessarily indicative of the results to be expected for any other period.
Environmental Matters
New or revised environmental laws and regulations could affect many areas of Southern Company Gas in Item 1AGas' operations. The impact of the Form 10-K.
any such changes cannot be determined at this time. Environmental Matters
Compliancecompliance 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.basis. Further, higherincreased costs that are recovered through regulated rates could contribute to reduced demand for natural gas, which could negatively affect results of operations, cash flows, andand/or financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for natural gas. See Note (B) under "Environmental Matters –Environmental Remediation"(C) to the Condensed Financial Statements under "Environmental Remediation" 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 for additional information.
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 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 material impact on Southern Company Gas' financial statements.
FERCRegulatory Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Southern Company Gas in Item 7 and Note 42 to the financial statements of Southernunder "Southern Company Gas in Item 8 of the Form 10-K for additional information regarding the Dalton Pipeline project.
On August 1, 2017, the Dalton Pipeline was placed in service as authorized by the FERC and transportation service for customers commenced.
On October 13, 2017, the Atlantic Coast Pipeline project received FERC approval.
Regulatory Matters
See Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters"Gas" 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.
RidersRate Proceedings
Nicor Gas has established
In November 2018, Nicor Gas filed a variable tax cost adjustment rider, which was approved bygeneral base rate case with the Illinois Commission effective July 16, 2017. This rider providesrequesting a $230 million increase in annual base rate revenues. The requested increase is based on a projected test year for recoverythe 12-month period ending September 30, 2020, a ROE of 10.6%, and an increase in the equity ratio from 52% to 54% to address the negative cash flow and credit metric impacts of the invested capital tax imposed onTax Reform Legislation.
On April 16, 2019, Nicor Gas throughentered into a stipulation agreement to resolve all related issues with the Staff of the Illinois Commission, including a ROE of 9.86% and an equity ratio of 54%. Also on April 16, 2019, Nicor Gas filed its rebuttal testimony with the Illinois Commission incorporating the stipulation agreement and addressing the remaining items outstanding with the other two intervenors. As a result of the stipulation agreement and rebuttal testimony, the revised requested annual true-up and reconciliation mechanismrevenue increase is $180 million.
The Illinois Commission is expected to rule on the requested increase by early October 2019, after which rate adjustments will be effective. The ultimate outcome of this matter cannot be determined at this time.
Atlanta Gas Light
On June 3, 2019, Atlanta Gas Light filed a general base rate case with the Georgia PSC requesting a $96 million increase in annual base rate revenues. The requested increase is based on amountsa forward-looking test year for the 12-month period ending July 31, 2020, a ROE of 10.75% with an earnings band based on a ROE between 10.55% and 10.95%, and a continued equity ratio of 55%. The filing also requests the continuation of the Georgia rate adjustment mechanism, as previously authorized. Atlanta Gas Light expects the Georgia PSC to issue a final order on this matter on December 19, 2019 with the new rates becoming effective January 1, 2020. The ultimate outcome of this matter cannot be determined at this time.
Virginia Natural Gas
In December 2018, the Virginia Commission approved in prior rate cases. Accordingly, this rider will not haveVirginia Natural Gas' annual information form filing, which reduced annual base rates by $14 million effective January 1, 2019 due to lower tax expense as a significant effect on Southern Company Gas' net income.result of the Tax Reform Legislation. This approval also required Virginia Natural Gas to issue customer refunds, via bill credits, for
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
$14 million related to 2018 tax benefits deferred as a regulatory liability, current, on the balance sheet at December 31, 2018. These customer refunds were completed in the first quarter 2019.
Regulatory Infrastructure Programs
In addition to capital expenditures recovered through base rates by each of the natural gas distribution utilities, Nicor Gas and Virginia Natural Gas Cost Recovery
Southern Company Gas has established natural gas costhave separate rate riders that provide for timely recovery rates approved by the relevant state regulatory agenciesof capital expenditures for specific infrastructure replacement programs. Infrastructure expenditures incurred under these programs in the states in which it serves. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on Southern Company Gas' revenues or net income, but will affect cash flows.first six months of 2019 were as follows:
Settled Base Rate Cases |
| | | | |
| Utility | Program | Year-to-Date 2019 |
| | | (in millions) |
| Nicor Gas | Investing in Illinois | $ | 107 |
|
| Virginia Natural Gas | Steps to Advance Virginia's Energy (SAVE) | 21 |
|
| Total | | $ | 128 |
|
On February 21, 2017, the Georgia PSC approved the Georgia Rate Adjustment Mechanism (GRAM) and a $20 million increase in annual base rate revenues for AtlantaApril 8, 2019, Virginia Natural 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.
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.
Beginningfiled an application with the next rate adjustmentVirginia Commission to amend and extend its SAVE program. The proposal would allow Virginia Natural Gas to continue replacing aging pipeline infrastructure and increase its authorized investment under the currently-approved plan. Virginia Natural Gas seeks to amend its currently-approved plan by increasing the authorized investment in June 2018, Atlanta Gas Light's recovery2019 from $35 million to $40 million and to extend the plan for an additional five years until 2024, with proposed annual investments of the previously unrecovered Pipeline Replacement Program revenue$50 million in 2020, $60 million in 2021, and $70 million in each year from 2022 through 2014, as well as the mitigation costs associated with the Pipeline Replacement Program that were not previously included in its rates, will also be included in GRAM. In connection with the GRAM approval, the last monthly Pipeline Replacement Program surcharge increase became effective March 1, 2017.
In September 2016, Elizabethtown Gas filed a general base rate case with the New Jersey BPU requesting a $19 million increase in annual base rate revenues. The requested increase was based on a projected 12-month test year ending March 31, 2017 and a ROE of 10.25%. On June 30, 2017, the New Jersey BPU approved a settlement that provides2024, for a $13maximum total investment over the six-year term (2019 through 2024) of $370 million. The proposed investment schedule would also allow for variances of up to $6 million increase in annual base rate revenues, effective July 1, 2017, based on2019, $8 million in 2020, $9 million in 2021, and $10 million in each year from 2022 through 2024, with a ROEtotal potential net variance of 9.6%. Also included inup to $10 million allowed for the settlement was a new composite depreciation rate that is expected to result in a $3 million annual reduction of depreciation. See OVERVIEW – "Merger, Acquisition, and Disposition Activities" and Note (I) 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.program. 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 increaserequest in December 2017, after which rate adjustments willthe fourth quarter 2019. The ultimate outcome of this matter cannot be effective.determined at this time.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Infrastructure Replacement Programs and Capital Projects" of Southern Company Gas in Item 7 and Note 2 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" in Item 8 of the Form 10-K for additional information.
Affiliate Asset Management Agreements
On March 31, 2017, Virginia Natural Gas filed a general base rate case with15, 2019, the Virginia Commission requestingapproved an extension of Virginia Natural Gas' asset management agreement with Sequent to March 31, 2021. Southern Company Gas does not expect this new agreement to have a $44 million increasematerial impact on its financial statements.
FERC Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Southern Company Gas in annual base rate revenues. The requested increase was based on a projected 12-month test year beginning September 1, 2017Item 7 of the Form 10-K and a ROE of 10.25%. The requested increase included $13 million relatedNotes 7 and 9 to the recovery of investmentsfinancial statements under the Steps to Advance Virginia's Energy (SAVE) program. On October 3, 2017, Virginia Natural"Southern Company Gas entered into a proposed stipulation with the Staff– Equity Method Investments" and "Guarantees," respectively, in Item 8 of the Virginia Commission, the OfficeForm 10-K for additional information regarding Southern Company Gas' gas pipeline construction projects.
Other Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" and "FERC Matters" of Southern Company Gas in Item 7 of the Attorney General, DivisionForm 10-K for additional information.
Southern Company Gas is involved in various other matters that could affect future earnings, including matters being litigated, as well as other regulatory matters and matters that could result in asset impairments. In addition, Southern Company Gas is subject to certain claims and legal actions arising in the ordinary course of Consumer Counsel, and the Virginia Industrial Gas Users' Association resolving all related issues.business. 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
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
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.
Other Matters
Southern Company Gas is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company Gas is subject to certain claims and legal actions arising in the
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ordinary course of business. The ultimate outcome of such pending or potential litigation, or regulatory matters, or potential asset impairments cannot be predicteddetermined at this time; however, for current proceedings not specifically reported in NoteNotes (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 Southern Company Gas' financial statements. See NoteNotes (B) and (C) 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 GasSee Note 3 to the financial statements in Item 8 of the Form 10-K under "Other Matters – Southern Company Gas" for information on a natural gas storage facility consisting of two salt dome caverns in Louisiana. The future performance of this facility, as well as Southern Company Gas' two other natural gas storage facilities located in California and Nicor Energy Services Company, wholly-owned subsidiariesTexas, could be impacted by ongoing changes in the U.S. natural gas storage market. Recent sales of natural gas storage facilities have resulted in losses for the sellers and may imply an impact on future rates and/or asset values. 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 purportedis evaluating these recent market transactions for impacts on its plans to represent a classreturn one of the customers who purchased the Gas Line Comfort Guard product from Nicor Energy Services Company and variously alleged that the marketing, sale, and billingsalt dome caverns in Louisiana back to service in 2021. Sustained diminished natural gas storage values could trigger impairment 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 enrichmentone or all of these entities.natural gas storage facilities, which have a combined net book value of $438 million at June 30, 2019. The plaintiffs sought, on behalfultimate outcome 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 notthese matters cannot be determined at this time, but could have a material impact on Southern Company Gas' financial statements.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company Gas prepares its financial statements in accordance with GAAP. Significant accounting policies are described in NoteNotes 1, 5, and 6 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.estimates.
Recently Issued Accounting Standards
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Southern Company Gas in Item 7 ofNote (A) to the Form 10-KCondensed Financial Statements herein 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 disclosuresinformation regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
While Southern Company Gas expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Southern Company Gas' revenue, including energy provided to customers, is from tariff offerings that provide natural gas without a defined contractual term, as well as longer-term contractual agreements, including non-derivative natural gas asset management and optimization arrangements. Southern Company Gas expects that the revenue from contracts with these customers will not result in a significant shift in the timing of revenue recognition for such sales.
Southern Company Gas' ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements, such as energy-related derivatives and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Southern Company Gas' financial statements. In addition, the power
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Southern Company Gas expects CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Southern Company Gas intends to use the modified retrospective method of adoption effective January 1, 2018. Southern Company Gas has also elected to utilize practical expedients which allow it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Southern Company Gas' financial statements, Southern Company Gas will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.
On January 26, 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for annual and interim periods beginning on or after December 15, 2019, and early adoption is permitted on testing dates after January 1, 2017. 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 hedgerecently adopted 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.standards.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company 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 Gas" herein for additional information.
Southern Company Gas' financial condition remained stable at SeptemberJune 30, 2017.2019. Southern Company Gas intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. Due to the increased working capital requirements associated with Nicor Gas' Investing in Illinois infrastructure replacement program, since 2015, Nicor Gas has temporarily ceased distributing dividends to Southern Company Gas. Elizabethtown Gas is restricted by its dividend policy as established by the New Jersey BPU in the amount it can dividend to its parent company to the extent of 70% of its quarterly net income. Additionally, as stipulated in the New Jersey BPU's order approving the Merger, Southern Company Gas is prohibited from paying dividends to its parent company, Southern Company, if Southern Company Gas' senior unsecured debt rating falls below investment grade. As of SeptemberAt June 30, 2017,2019, the amount of subsidiary retained earnings and net income availablerestricted to dividend totaled $752$888 million. These restrictionsThis restriction 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)$931 million for the successorfirst six months of 2019, a decrease of $387 million from the corresponding period in 2018. The decrease was primarily due to the impacts of July 1, 2016 through September 30, 2016,the Southern Company Gas Dispositions and $1.1 billion for the predecessor periodtiming of January 1, 2016 through June 30, 2016. These cash flows were primarily drivenvendor payments, partially offset by the saletiming of natural gas inventory during the respective periods.
collection of customer receivables. Net cash used for investing activities totaled $1.2 billion$586 million for the successor first ninesix months of 2017, 2019
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
primarily due to gross property additions related to utility capital expenditures forand infrastructure investments recovered through replacement programs at gas distribution operations and capital contributed to equity method pipeline investments, in pipelines.partially offset by proceeds from the sale of Triton. Net cash used for investingfinancing activities totaled $1.7 billion for the successor period of July 1, 2016 through September 30, 2016 and $559$355 million for the predecessor periodfirst six months of January 1, 2016 through June 30, 20162019 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 a common stock dividend paymentspayment 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
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Significant balance sheet changes at September 30, 2017for the first six months of 2019 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$256 million in natural gas for sale due to the use of stored natural gas and a $158 million decrease in notes payable primarily related primarily to net repayments of commercial paper borrowings at Nicor Gas.borrowings. 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$440 million and $146$463 million in energy marketing receivables and payables, respectively, due to lower natural gas prices.prices and volumes of natural gas sold, and an increase of $429 million in total property, plant, and equipment primarily due to utility capital expenditures and infrastructure investments recovered through replacement programs. Balance sheet changes for the first six months of 2019 also include recording $95 million in operating lease right-of use assets and $94 million in operating lease obligations related to the adoption of ASU No. 2016-02, Leases (Topic 842) (ASC 842). See Note (L) to the Condensed Financial Statements herein for additional information on the adoption of ASC 842.
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, scheduledand contractual obligations. Subsequent to June 30, 2019, Nicor Gas repaid at maturity $50 million aggregate principal amount of first mortgage bonds due July 30, 2019. An additional $300 million will be required through June 30, 2020 to fund 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.debt. See "Sources of Capital" herein for additional information.
The regulatory infrastructure programs and other construction programs are subject to periodic review and revision, and actual costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in FERC rules and regulations; state regulatory approvals; changes in legislation; the cost and efficiency of labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. See Note 32 to the consolidated financial statements of Southernunder "Southern Company GasGas" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for information regarding additional factors that may impact infrastructure investment expenditures.
Sources of Capital
Southern Company Gas plans to obtain the funds to meet its future capital needs throughfrom sources similar to those used in the past, which were primarily from operating cash flows, short-term debt borrowings under its commercial paper programs, external securities issuances, borrowings from financial institutions, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, depend upon regulatory approval, prevailing market conditions, regulatory approval, and other factors. The issuance of securities by Nicor Gas is generally subject to the approval of the Illinois Commission. 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 SeptemberSubsequent to June 30, 2017, 2019, Southern Company Gas received a $400 million capital contribution from Southern Company.
Southern Company Gas' current liabilities exceeded current assets by $645$682 million primarily as a result of $934$492 million in notes payable.payable and $351 million in securities due within one year. 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 SeptemberJune 30, 2017,2019, Southern Company Gas had approximately $21$56 million of cash and cash equivalents. Committed credit arrangements with banks at SeptemberJune 30, 20172019 were as follows:
| | | Company | | Expires 2022 | | Unused | Expires 2024 | | Unused |
| | | (millions) | (in millions) |
Southern Company Gas Capital | | $ | 1,200 |
| | $ | 1,161 |
| $ | 1,250 |
| | $ | 1,245 |
|
| Nicor Gas | | 700 |
| | 700 |
| 500 |
| | 500 |
|
Total | | $ | 1,900 |
| | $ | 1,861 |
| $ | 1,750 |
| | $ | 1,745 |
|
| |
| (a) | Southern Company Gas guarantees the obligations of Southern Company Gas Capital. |
| |
| (b) | Pursuant to the credit arrangement, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted. |
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 68 to the consolidated financial statements of Southern Company Gas under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E)(F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
In May 2017,2019, Southern Company Gas Capital, along with Nicor Gas, amended and restated its multi-year credit arrangement to extend the maturity date to 2024 and decrease the aggregate borrowing capacity from $1.9 billion to $1.75 billion.
The multi-year credit arrangement of 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 Gaslevels 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 SeptemberJune 30, 2017,2019, 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. A portion of unused credit with banks provides liquidity support to Southern Company Gas.
Southern Company Gas has substantial cash flow from operating activities and access to capital markets, including the commercial paper programs, and financial institutions to meet liquidity needs. 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 paperShort-term borrowings are included in notes payable in the balance sheets.
Details of commercial papershort-term borrowings were as follows:
| | | | Commercial Paper at September 30, 2017 | | Commercial Paper During the Period(*) | Short-Term Debt at June 30, 2019 | | Short-Term Debt During the Period(*) |
| | Amount
Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding | Amount
Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| Commercial paper: | (in millions) | | | | (in millions) | | | | (in millions) | (in millions) | | | | (in millions) | | | | (in millions) |
| Southern Company Gas Capital | $ | 836 |
| | 1.5 | % | | $ | 680 |
| | 1.5 | % | | $ | 838 |
| $ | 372 |
| | 2.6 | % | | $ | 297 |
| | 2.7 | % | | $ | 436 |
|
| Nicor Gas | 98 |
| | 1.3 |
| | 40 |
| | 1.3 |
| | 120 |
| 120 |
| | 2.6 |
| | 27 |
| | 2.6 |
| | 120 |
|
| Total | $ | 934 |
| | 1.5 | % | | $ | 720 |
| | 1.5 | % | | | $ | 492 |
| | 2.6 | % | | $ | 324 |
| | 2.7 | % | | |
| |
| (*) | Average and maximum amounts are based upon daily balances during the successor three-month period ended SeptemberJune 30, 2017.2019. |
Southern Company Gas believes that 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 natural gas purchases and sales, fuel transportation and storage, and energy price risk management. The maximum potential collateral requirementsrequirement under these contracts at SeptemberJune 30, 2017 were $122019 was approximately $13 million.
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Company Gas to access capital markets and would be likely to impact the cost at which it does so.
On March 24, 2017, S&P revised its consolidatedAs a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating outlook foragencies to assess Southern Company and its subsidiaries, (includingincluding Southern Company Gas, may be negatively impacted. Southern Company Gas Capital,and its regulated subsidiaries have taken actions to mitigate the resulting impacts, which, among other alternatives, include adjusting capital structure. Absent actions by Southern Company and its subsidiaries that fully mitigate the impacts, Southern Company Gas', Southern Company Gas Capital's, and Nicor Gas) from stableGas' credit ratings could be negatively affected. The Georgia PSC's May 15, 2018 approval of a stipulation for Atlanta Gas Light's annual rate adjustment maintained the previously authorized earnings band and increased the equity ratio to negative.address the negative cash flow and credit metric impacts of the Tax Reform Legislation. See Note 2 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Southern Company Gas" herein for information on additional requests for increased equity ratios included in rate case proceedings for Nicor Gas and Atlanta Gas Light expected to conclude later in 2019.
Financing Activities
The long-term debt on Southern Company Gas' consolidated balance sheets includes both principal and non-principal components. As of SeptemberJune 30, 2017,2019, the non-principal components totaled $523$432 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 notesdid not issue or redeem any securities during the six months ended June 30, 2019.
Subsequent to further allocate interest expense to its reportable segments that previously remained in the "all other" segment. These intercompany promissory notes allow Southern CompanyJune 30, 2019, Nicor Gas to calculate net income, which is its performance measure subsequent to the Merger,repaid at the segment level that incorporates the full impact of interest costs.
In May 2017, Southern Company Gas Capital issued $450maturity $50 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 of4.7% 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.July 30, 2019.
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 thirdsecond quarter and year-to-date 2017.2019. 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)(I) and (H)(J) 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 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. For the weather risk associated with Nicor Gas, Southern Company
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 illustratesFor the changeperiods presented below, the changes 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 outstandingwere as of the dates presented.follows:
| | | | | 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 | | | | Second Quarter 2019 | Second Quarter 2018 | | Year-to-Date 2019 | Year-to-Date 2018 |
| | | (in millions) | | | (in millions) | (in millions) |
Contracts outstanding at beginning of period,
assets (liabilities), net | | $ | 51 |
| | $ | (54 | ) | | $ | 12 |
| | $ | (54 | ) | | | $ | 75 |
| $ | (128 | ) | $ | (70 | ) | | $ | (167 | ) | $ | (106 | ) |
| Contracts realized or otherwise settled | | (6 | ) | | (3 | ) | | (22 | ) | | (3 | ) | | | (77 | ) | 5 |
| 2 |
| | — |
| 51 |
|
Current period changes(a) | | (16 | ) | | — |
| | 39 |
| | — |
| | | (82 | ) | 33 |
| (22 | ) | | 77 |
| (35 | ) |
Contracts outstanding at the end of period,
assets (liabilities), net | | 29 |
| | (57 | ) | | 29 |
| | (57 | ) | | | (84 | ) | $ | (90 | ) | $ | (90 | ) |
| $ | (90 | ) | $ | (90 | ) |
| Netting of cash collateral | | 76 |
| | 111 |
| | 76 |
| | 111 |
| | | 120 |
| 178 |
| 183 |
| | 178 |
| 183 |
|
Cash collateral and net fair value of contracts
outstanding at end of period(b) | | $ | 105 |
| | $ | 54 |
| | $ | 105 |
| | $ | 54 |
| | | $ | 36 |
| $ | 88 |
| $ | 93 |
|
| $ | 88 |
| $ | 93 |
|
| |
| (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 instrumentscontracts outstanding includes premiumsexcludes premium and the intrinsic valuesvalue associated with weather derivatives of $13$0 million and $3 million at SeptemberJune 30, 20172019 and $7 million at September 30, 2016.2018, respectively. |
The maturities of Southern Company Gas' energy-related derivative contracts at SeptemberJune 30, 20172019 were as follows:
| | | | | | Fair Value Measurements | | | Fair Value Measurements |
| | | | Successor – September 30, 2017 | | | June 30, 2019 |
| | Total
Fair Value | | Maturity | Total
Fair Value | | Maturity |
| | | Year 1 | | Years 2 & 3 | | Years 4 and thereafter | | Year 1 | | Years 2 & 3 | | Years 4 and thereafter |
| | (in millions) | (in millions) |
Level 1(a) | $ | (35 | ) | | $ | (10 | ) | | $ | (20 | ) | | $ | (5 | ) | $ | (135 | ) | | $ | (46 | ) | | $ | (62 | ) | | $ | (27 | ) |
Level 2(b) | 64 |
| | 12 |
| | 45 |
| | 7 |
| 55 |
| | 27 |
| | 25 |
| | 3 |
|
Fair value of contracts outstanding at end of period(c) | $ | 29 |
| | $ | 2 |
| | $ | 25 |
| | $ | 2 |
| |
Level 3(c) | | (10 | ) | | 1 |
| | — |
| | (11 | ) |
Fair value of contracts outstanding at end of period(d) | | $ | (90 | ) | | $ | (18 | ) | | $ | (37 | ) | | $ | (35 | ) |
| |
| (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 $76$178 million as well as premium and associated intrinsic value associated with weather derivatives of $0 million at SeptemberJune 30, 2017.2019. |
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 | | |
| L | | |
| M | | |
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, L, M |
| Alabama Power | A, B, C, E,D, F, G, H, I, J, L |
| Georgia Power | A, B, C, E,D, F, G, H, |
Gulf Power | A, B, C, E, F, G, H I, J, L |
| Mississippi Power | A, B, C, E,D, F, G, H, I, J, L |
| Southern Power | A, B, C, D, E, F, G, H, I, J, K, L |
| Southern Company Gas | A, B, C, D, E, F, G, H, I, J, K, L, M |
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)
(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, 20162018 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended SeptemberJune 30, 20172019 and 2016.2018. 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.
Recently Adopted Accounting Standards
In 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for existing leveraged leases. The registrants adopted the new standard effective January 1, 2019. See Note (L) for additional information and related disclosures.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Recently Issued Accounting Standards
See Note 1 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 SeptemberGoodwill at June 30, 20172019 and December 31, 2016, goodwill2018 was as follows: |
| | | | | | |
| | At June 30, 2019 | At December 31, 2018 |
| | (in millions) |
| Southern Company | $ | 5,282 |
| $ | 5,315 |
|
| Southern Company Gas: | | |
| Gas distribution operations | $ | 4,034 |
| $ | 4,034 |
|
| Gas marketing services | 981 |
| 981 |
|
| Southern Company Gas total | $ | 5,015 |
| $ | 5,015 |
|
|
| | | | | | |
| | 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. A goodwill impairment charge of $32 million was recorded in the second quarter 2019 in contemplation of the July 22, 2019 sale of one of PowerSecure's business units. See Note (K) under "Southern Company" for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Other intangible assets were as follows:
|
| | | | | | | | | | | | | | | | | | | |
| | At June 30, 2019 | | At December 31, 2018 |
| | 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 | $ | 211 |
| $ | (105 | ) | $ | 106 |
| | $ | 223 |
| $ | (94 | ) | $ | 129 |
|
| Trade names | 70 |
| (23 | ) | 47 |
| | 70 |
| (21 | ) | 49 |
|
| Storage and transportation contracts | 64 |
| (58 | ) | 6 |
| | 64 |
| (54 | ) | 10 |
|
| PPA fair value adjustments | 371 |
| (60 | ) | 311 |
| | 405 |
| (61 | ) | 344 |
|
| Other | 12 |
| (7 | ) | 5 |
| | 11 |
| (5 | ) | 6 |
|
| Total other intangible assets subject to amortization | $ | 728 |
| $ | (253 | ) | $ | 475 |
|
| $ | 773 |
| $ | (235 | ) | $ | 538 |
|
| Other intangible assets not subject to amortization: | | | | | | | |
| Federal Communications Commission licenses | 75 |
| — |
| 75 |
| | 75 |
| — |
| 75 |
|
| Total other intangible assets | $ | 803 |
| $ | (253 | ) | $ | 550 |
| | $ | 848 |
| $ | (235 | ) | $ | 613 |
|
| | | | | | | | |
| Southern Power | | | | | | | |
| Other intangible assets subject to amortization: | | | | | | | |
| PPA fair value adjustments | $ | 371 |
| $ | (60 | ) | $ | 311 |
| | $ | 405 |
| $ | (61 | ) | $ | 344 |
|
| | | | | | | | |
| Southern Company Gas | | | | | | | |
| Other intangible assets subject to amortization: | | | | | | | |
| Gas marketing services | | | | | | | |
| Customer relationships | $ | 156 |
| $ | (95 | ) | $ | 61 |
| | $ | 156 |
| $ | (84 | ) | $ | 72 |
|
| Trade names | 26 |
| (8 | ) | 18 |
| | 26 |
| (7 | ) | 19 |
|
| Wholesale gas services | | | | | | | |
| Storage and transportation contracts | 64 |
| (58 | ) | 6 |
| | 64 |
| (54 | ) | 10 |
|
| Total other intangible assets subject to amortization | $ | 246 |
| $ | (161 | ) | $ | 85 |
| | $ | 246 |
| $ | (145 | ) | $ | 101 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | 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 | Six Months Ended |
| | June 30, 2019 |
| | (in millions) |
| Southern Company | $ | 15 |
| $ | 32 |
|
Southern Power(a) | $ | 4 |
| $ | 10 |
|
| Southern Company Gas |
|
| |
Gas marketing services(b) | $ | 6 |
| $ | 12 |
|
Wholesale gas services(a) | 2 |
| 4 |
|
| Southern Company Gas total | $ | 8 |
| $ | 16 |
|
| |
| (a) | Recorded as a reduction to operating revenues. |
| |
| (b) | Included in depreciation and amortization. |
Restricted Cash
|
| | | | | | |
| | Three Months Ended | Nine Months Ended |
| | September 30, 2017 |
| | (in millions) |
| Southern Company | $ | 29 |
| $ | 94 |
|
| Southern Power | $ | 6 |
| $ | 19 |
|
| Southern Company Gas | $ | 20 |
| $ | 66 |
|
At December 31, 2018, Georgia Power had restricted cash related to the redemption of pollution control revenue bonds, which were redeemed in January 2019. See Note 12 to the financial statements of Southern Company(F) under "Southern Power" and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information regarding Southern Power's PPA fair value adjustments related to its business acquisitions. Also see Note (I) under "Southern Company– Acquisition of PowerSecure" and " –Merger with Southern Company GasFinancing Activities" for additional information. At both June 30, 2019 and December 31, 2018, Southern Company Gas had restricted cash held as collateral for worker's compensation, life insurance, and long-term disability insurance.
Property Damage Reserve
See Note 1The following tables provide a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed balance sheets that total to the financialamounts shown in the condensed statements of Gulf Power under "Property Damage Reserve" in Item 8cash flows for the registrants that had restricted cash at June 30, 2019 and/or December 31, 2018:
|
| | | | | | | |
| | Southern Company | | Southern Company Gas |
| | (in millions) |
| At June 30, 2019 | | | |
| Cash and cash equivalents | $ | 1,383 |
| | $ | 56 |
|
| Restricted cash: | | | |
| Other accounts and notes receivable | 4 |
| | 4 |
|
| Total cash, cash equivalents, and restricted cash | $ | 1,386 |
| (*) | $ | 60 |
|
| |
| (*) | Total does not add due to rounding. |
|
| | | | | | | | | |
| | Southern Company | Georgia Power | Southern Company Gas |
| | (in millions) |
| At December 31, 2018 | | | |
| Cash and cash equivalents | $ | 1,396 |
| $ | 4 |
| $ | 64 |
|
| Cash and cash equivalents held for sale | 9 |
| — |
| — |
|
| Restricted cash: | | | |
| Restricted cash | — |
| 108 |
| — |
|
| Other accounts and notes receivable | 114 |
| — |
| 6 |
|
| Total cash, cash equivalents, and restricted cash | $ | 1,519 |
| $ | 112 |
| $ | 70 |
|
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 events that reduce the property damage reserve in the aggregate by approximately $31 million (75% of the April 1, 2017 balance) or more. The storm surcharge would begin, on an interim basis, 60 days following the filing of a cost recovery petition, would be limited to $4.00/month for a 1,000 KWH residential customer unless Gulf Power incurs in excess of $100 million in qualified storm recovery costs in a calendar year, and would replenish the 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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Natural Gas for Sale
Southern Company Gas' natural gas distribution utilities,Gas, with the exception of Nicor Gas, carrycarries 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 adjustments of $7 million and $10 million for the three and six months ended June 30, 2019, respectively, and no material adjustments for the comparable periods in 2018.
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 CompanyNicor Gas had no inventory decrement at SeptemberJune 30, 2017.2019.
Asset Retirement Obligations
See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information regarding AROs.
Details of the AROs included in the condensed balance sheets of Southern Company, Alabama Power, and Mississippi Power at June 30, 2019 are shown in the following table. There were no material changes in the AROs of Georgia Power or Southern Power during the first six months of 2019.
|
| | | | | | | | | |
| | Southern Company | Alabama Power | Mississippi Power |
| | (in millions) |
| Balance at December 31, 2018 | $ | 9,394 |
| $ | 3,210 |
| $ | 160 |
|
| Liabilities incurred | 6 |
| — |
| — |
|
| Liabilities settled | (142 | ) | (43 | ) | (17 | ) |
| Accretion | 197 |
| 70 |
| 2 |
|
| Cash flow revisions | 452 |
| 308 |
| 59 |
|
| Balance at June 30, 2019 | $ | 9,907 |
| $ | 3,545 |
| $ | 204 |
|
In June 2019, Alabama Power recorded an increase of approximately $308 million to its AROs primarily related to the CCR Rule and the related state rule based on management's completion of closure designs during the second quarter 2019 for all but two of its ash pond facilities. Mississippi Power also recorded an increase of approximately $58 million to its AROs related to the CCR Rule, primarily associated with the ash pond facility at Plant Greene County, which is jointly owned with Alabama Power. The additional estimated costs to close these ash ponds under the planned closure-in-place methodology primarily relate to cost inputs from contractor bids, internal drainage and dewatering system designs, and increases in the estimated ash volumes. The cost estimate for the remaining Alabama Power ash pond facilities will be updated within the next 12 months and the change could be material.
As further analysis is performed and additional details are developed with respect to ash pond closures, the traditional electric operating companies expect to periodically update their ARO cost estimates. Additionally, the closure designs and plans in the States of natural gas, including inventoryAlabama and Georgia are subject to approval by environmental regulatory agencies. Absent continued recovery of ARO 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 onthrough regulated rates, Southern Company's or Southern Company Gas' net income.and the traditional electric operating companies' results of operations, cash flows, and financial condition could be materially impacted. The ultimate outcome of these matters cannot be determined at this time.
Natural gas inventories for Southern Company Gas' non-utility businesses are carried at the lower
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
(B) REGULATORY MATTERS
See Note 2 to the financial statements in Item 8 of the Form 10-K for additional information relating to regulatory matters.
The recovery balances for certain of Alabama Power's, Georgia Power's, and Mississippi Power's regulatory clauses at June 30, 2019 and December 31, 2018 were as follows:
|
| | | | | | | |
| Regulatory Clause | Balance Sheet Line Item | June 30,
2019 | December 31,
2018 |
| | | (in millions) |
| Alabama Power | | | |
| Rate CNP Compliance | Deferred under recovered regulatory clause revenues | $ | — |
| $ | 42 |
|
| | Customer accounts receivable | 10 |
| — |
|
| Rate CNP PPA | Deferred under recovered regulatory clause revenues | 25 |
| 25 |
|
Retail Energy Cost Recovery(*) | Deferred under recovered regulatory clause revenues | — |
| 109 |
|
| | Customer accounts receivable | 8 |
| — |
|
| Natural Disaster Reserve | Other regulatory liabilities, deferred | 19 |
| 20 |
|
| Georgia Power | | | |
| Fuel Cost Recovery | Receivables – under recovered fuel clause revenues | $ | 69 |
| $ | 115 |
|
| Mississippi Power | | | |
| Fuel Cost Recovery | Over recovered regulatory clause liabilities | $ | 9 |
| $ | 8 |
|
| |
(B)(*) | CONTINGENCIES AND REGULATORY MATTERSIn accordance with an accounting order issued on February 5, 2019 by the Alabama PSC, Alabama Power utilized $75 million of the 2018 Rate RSE refund liability to reduce the Rate ECR under recovered balance. See Note 2 to the financial statements under "Alabama Power – Rate ECR" in Item 8 of the Form 10-K for additional information. |
Alabama Power
Environmental Accounting Order
On April 15, 2019, Alabama Power retired Plant Gorgas Units 8, 9, and 10 and reclassified approximately $654 million of the unrecovered asset balances to regulatory assets, which are being recovered over the units' remaining useful lives, the latest being through 2037, as established prior to the decision to retire. Additionally, approximately $700 million of net capitalized asset retirement costs were reclassified to a regulatory asset in accordance with accounting guidance provided by the Alabama PSC. The asset retirement costs are being recovered through 2055. See Note 2 to the financial statements under "Alabama Power – Environmental Accounting Order" and Note 6 in Item 8 of the Form 10-K for additional information.
Georgia Power
Rate Plans
On June 28, 2019, Georgia Power filed a base rate case (Georgia Power 2019 Base Rate Case) with the Georgia PSC. The filing includes a three-year Alternate Rate Plan with requested rate increases totaling $563 million, $145 million, and $234 million effective January 1, 2020, January 1, 2021, and January 1, 2022, respectively. These increases are based on a proposed retail ROE of 10.90% and a proposed equity ratio of 56% and reflect levelized revenue requirements during the three-year period, with the exception of incremental compliance costs related to CCR AROs, Demand-Side Management programs, and adjustments to the Municipal Franchise Fee tariff.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Georgia Power has requested recovery of the proposed increases through its existing base rate tariffs as follows:
|
| | | | | | | | | |
| Tariff | 2020 | 2021 | 2022 |
| | (in millions) |
| Traditional base: | | | |
| Levelized | $ | 209 |
| $ | — |
| $ | — |
|
| CCR AROs | 158 |
| 140 |
| 227 |
|
| Environmental Compliance Cost Recovery | 165 |
| — |
| — |
|
| Demand-Side Management | 14 |
| 2 |
| 1 |
|
| Municipal Franchise Fee | 17 |
| 3 |
| 5 |
|
Total(*) | $ | 563 |
| $ | 145 |
| $ | 234 |
|
| |
| (*) | Totals may not add due to rounding. |
Georgia Power's filing primarily reflects requests to (i) address the impacts of the Tax Reform Legislation, (ii) recover the costs of recent and future capital investments in infrastructure designed to maintain high levels of reliability and superior customer service with updated depreciation rates, (iii) recover substantial storm damage expenses incurred and deferred since 2013 along with a reasonable level of storm damage expenses expected to be incurred during the three years ending December 31, 2022, and (iv) recover the costs necessary to comply with federal and state regulations for CCR AROs. In addition, the filing includes the following provisions:
Continuation of an allowed retail ROE range of 10.00% to 12.00%.
Continuation of the process whereby two-thirds of any earnings above the top of the allowed ROE range are shared with Georgia Power's customers and the remaining one-third are retained by Georgia Power.
Continuation of the option to file an Interim Cost Recovery tariff in the event earnings are projected to fall below the bottom of the ROE range during the three-year term of the plan.
Georgia Power expects the Georgia PSC to issue a final order in this matter on December 17, 2019. The ultimate outcome of this matter cannot be determined at this time.
Integrated Resource Plan
In 2016, the Georgia PSC approved Georgia Power's triennial Integrated Resource Plan, including recovery of costs up to $99 million through June 30, 2019 to preserve nuclear generation as an option at a future generation site in Stewart County, Georgia. In 2017, the Georgia PSC approved Georgia Power's decision to suspend work at the site due to changing economics, including lower load forecasts and fuel costs. In accordance with the Georgia PSC's order, costs incurred of approximately $50 million have been recorded as a regulatory asset.
On July 16, 2019, the Georgia PSC voted to approve Georgia Power's triennial Integrated Resource Plan (2019 IRP) as modified by a stipulated agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors and further modified by the Georgia PSC.
In the 2019 IRP, the Georgia PSC approved the decertification and retirement of Plant Hammond Units 1 through 4 (840 MWs) and Plant McIntosh Unit 1 (142.5 MWs) effective July 29, 2019. The Georgia PSC also approved the reclassification of the remaining net book values of the Plant Hammond and Plant McIntosh units (approximately $500 million and $40 million, respectively, at June 30, 2019), as well as any unusable materials and supplies inventory balances, upon retirement to a regulatory asset. Recovery of each unit's net book value will continue through December 31, 2019 as provided in the 2013 ARP.
For the regulatory asset balances remaining at December 31, 2019, Georgia Power requested recovery in the Georgia Power 2019 Base Rate Case as follows: (i) the net book values of Plant Mitchell Unit 3 (approximately $8 million at June 30, 2019) and Plant McIntosh Unit 1, any unusable materials and supplies inventory, and the future generation site in Stewart County, Georgia over a three-year period ending December 31, 2022 and (ii) the net book
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
values of Plant Hammond Units 1 through 4 over a period equal to the applicable unit's remaining useful life through 2035. The ultimate outcome of these matters cannot be determined at this time.
Also in the 2019 IRP, the Georgia PSC rejected a request to certify approximately 25 MWs of capacity at Plant Scherer Unit 3 for the retail jurisdiction beginning January 1, 2020 following the expiration of a wholesale PPA. Georgia Power may offer such capacity in the wholesale market or to the retail jurisdiction in a future Integrated Resource Plan. The ultimate outcome of this matter cannot be determined at this time but is not expected to have a material impact on Georgia Power's or Southern Company's financial statements.
Additionally, the Georgia PSC approved Georgia Power's proposed environmental compliance strategy associated with ash pond and certain landfill closures and post-closure care in compliance with the CCR Rule and the related state rule. In the Georgia Power 2019 Base Rate Case, Georgia Power requested recovery of the under recovered balance of these compliance costs at December 31, 2019 (approximately $135 million at June 30, 2019) over a three-year period ending December 31, 2022 and recovery of estimated compliance costs of $277 million for 2020, $395 million for 2021, and $655 million for 2022 over three-year periods ending December 31, 2022, 2023, and 2024, respectively. The ultimate outcome of this matter cannot be determined at this time. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information regarding Georgia Power's AROs.
The Georgia PSC also approved Georgia Power to (i) issue requests for proposals (RFP) for capacity beginning in 2022 or 2023 and in 2026, 2027, or 2028; (ii) procure up to an additional 2,210 MWs of renewable resources through competitive RFPs; and (iii) invest in a portfolio of up to 80 MWs of battery energy storage technologies.
See "Rate Plans" herein for additional information regarding the Georgia Power 2019 Base Rate Case.
Nuclear Construction
See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding Georgia Power's construction of Plant Vogtle Units 3 and 4, the joint ownership agreements and related funding agreement, VCM reports, and the NCCR tariff.
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. Georgia Power holds a 45.7% ownership interest in Plant Vogtle Units 3 and 4. 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 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement. In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into several transitional arrangements to allow construction to continue. In July 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 time and materials cost basis. The Vogtle Services Agreement provides that it will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.
In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, executed the Bechtel Agreement, a cost reimbursable plus fee arrangement, whereby Bechtel is 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,
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.
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) | $ | 8.0 |
|
| Construction contingency estimate | 0.4 |
|
Total project capital cost forecast(a)(b) | 8.4 |
|
Net investment as of June 30, 2019(b) | (5.2 | ) |
Remaining estimate to complete(a) | $ | 3.2 |
|
| |
| (a) | Excludes financing costs expected to be capitalized through AFUDC of approximately $315 million. |
| |
| (b) | Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds. |
Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $2.0 billion had been incurred through June 30, 2019.
In April 2019, Southern Nuclear completed a cost and schedule validation process to verify and update quantities of commodities remaining to install, labor hours to install remaining quantities and related productivity, testing and system turnover requirements, and forecasted staffing needs and related costs. This process confirmed the estimated total project capital cost forecast for Plant Vogtle Units 3 and 4. The expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4, as previously approved by the Georgia PSC, remain unchanged.
As construction continues and testing and system turnover activities increase, challenges with management of contractors, subcontractors, and vendors; supervision of craft labor and related craft labor productivity, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, and/or installation and the initial testing and start-up, including any required engineering changes, of plant systems, structures, or components (some of which are based on new technology that only recently began initial operation in the global nuclear industry at this scale), or regional transmission upgrades, any of which may require additional labor and/or materials; or other issues could arise and change the projected schedule and estimated cost.
The April 2019 cost and schedule validation process established target values for monthly construction production and system turnover activities as part of a strategy to maintain and, where possible, build margin to the approved in-service dates. To support that strategy, monthly production and activity target values will continue to increase significantly throughout 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers (particularly electrical and pipefitter craft labor), as well as additional supervision and other field support resources, must be retained and deployed.
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. 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)
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 $12 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 entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 to provide for, among other conditions, additional Vogtle Owner approval requirements. Effective in August 2018, the 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 to continue construction (as amended, and together with the November 2017 amendment, the Vogtle Joint Ownership Agreements). The Vogtle Joint Ownership Agreements also confirm 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 the 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, 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'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 and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. On January 14, 2019, Georgia Power, MEAG, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. On February 18, 2019, Georgia Power, the other Vogtle Owners, and MEAG'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.
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 Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. At June 30, 2019, Georgia Power had recovered approximately $2.0 billion of financing costs. Financing costs related to capital costs above $4.418 billion will be recovered through AFUDC; however, Georgia Power will not record AFUDC related to any 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 2018, the Georgia PSC approved Georgia Power's request to increase the NCCR tariff by $88 million annually, effective January 1, 2019.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 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.
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 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 should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (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 impact of payments received under the Guarantee 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 revised cost forecast 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 ROE used to calculate the NCCR tariff (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, (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 in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 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 base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective Unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $100 million in 2018 and are estimated to have negative earnings impacts of approximately $70 million in 2019 and an aggregate of approximately $630 million from 2020 to 2022.
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 two appeals. On January 9, 2019, GIPL, PSE, and Georgia Watch filed an appeal of this decision with the Georgia Court of Appeals. Georgia Power believes the appeal has no merit; however, an adverse outcome in the appeal 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.
In August 2018, Georgia Power filed its nineteenth VCM report with the Georgia PSC, which requested approval of $578 million of construction capital costs incurred from January 1, 2018 through June 30, 2018. On February 19, 2019, the Georgia PSC approved the nineteenth VCM, but deferred approval of $51.6 million of expenditures
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
related to Georgia Power's portion of an administrative claim filed in the Westinghouse bankruptcy proceedings. Through the nineteenth VCM, the Georgia PSC has approved total construction capital costs incurred through June 30, 2018 of $5.4 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds).
On April 30, 2019, as requested by the staff of the Georgia PSC, Georgia Power reported the results of the cost and schedule validation process to the Georgia PSC. On August 30, 2019, Georgia Power will file its twentieth VCM report concurrently with its twenty-first VCM report with the Georgia PSC, which will reflect the capital cost forecast discussed previously and request approval of $1.2 billion of construction capital costs incurred from June 30, 2018 through June 30, 2019. In addition, on June 20, 2019, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a settlement agreement related to the administrative claim filed in the Westinghouse bankruptcy proceedings. Accordingly, in the twentieth/twenty-first VCM report, Georgia Power will also request approval of the $51.6 million of associated expenditures previously deferred by the Georgia PSC.
The ultimate outcome of these matters cannot be determined at this time.
DOE Financing
At June 30, 2019, Georgia Power had borrowed $3.46 billion related to Plant Vogtle Units 3 and 4 costs as provided through the Amended and Restated Loan Guarantee Agreement and related multi-advance credit facilities among Georgia Power, the DOE, and the FFB, which provide for borrowings of up to approximately $5.130 billion, subject to the satisfaction of certain conditions. See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (F) under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
The ultimate outcome of these matters cannot be determined at this time.
Mississippi Power
Municipal and Rural Association Tariff
On May 7, 2019, the FERC accepted Mississippi Power's March 28, 2019 request for a decrease in wholesale base revenues under the MRA tariff as agreed upon in a settlement agreement reached with its wholesale customers resolving all matters related to the Kemper County energy facility similar to the retail rate settlement agreement approved by the Mississippi PSC in February 2018 and reflecting the impacts of the Tax Reform Legislation. Pursuant to the MRA settlement agreement, base rates decreased $3.7 million annually, effective January 1, 2019.
Environmental Compliance Overview Plan
On July 9, 2019, Mississippi Power filed a request with the Mississippi PSC for a Certificate of Public Convenience and Necessity to complete certain environmental compliance projects, primarily associated with the Plant Daniel coal units co-owned 50% with Gulf Power. The total estimated cost is approximately $125 million, with Mississippi Power's share of approximately $66 million being proposed for recovery through its ECO Plan. Approximately $17 million of Mississippi Power's share is associated with ash pond closure and is reflected in Mississippi Power's ARO liabilities. See Note 2 to the financial statements under "Mississippi Power – Environmental Compliance Overview Plan" in Item 8 of the Form 10-K for additional information on Mississippi Power's ECO Plan. See Note (A) under "Asset Retirement Obligations" for additional information on AROs and Note (C) under "Other Matters – Mississippi Power" herein for additional information on Gulf Power's ownership in Plant Daniel.
Kemper County Energy Facility
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. 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,
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
with monitoring expected to continue through 2027. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.
During the second quarter and year-to-date 2019, Mississippi Power recorded pre-tax charges to income of $4 million ($3 million after tax) and $6 million ($5 million after tax), respectively, primarily resulting from the abandonment and related closure activities and ongoing period costs, net of sales proceeds, for the mine and gasifier-related assets at the Kemper County energy facility. Additional closure costs for the mine and gasifier-related assets, currently estimated at up to $10 million pre-tax (excluding dismantlement costs, net of salvage), may be incurred through the first half of 2020. In addition, period costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the mine and gasifier-related assets, are estimated at $7 million for the remainder of 2019 and $2 million to $6 million annually in 2020 through 2023.
In addition, Mississippi Power constructed the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery and is currently evaluating its options regarding the final disposition of the CO2 pipeline, including removal of the pipeline. This evaluation is expected to be complete later in 2019. If Mississippi Power ultimately decides to remove the CO2 pipeline, the cost of removal would have a material impact on Mississippi Power's financial statements and could have a material impact on Southern Company's financial statements.
In December 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the $387 million of grants received. Mississippi Power and the DOE are currently in discussions regarding the requested closeout and property disposition, which may require payment to the DOE for a portion of certain property that is to be retained by Mississippi Power. In connection with the DOE closeout discussions, on April 29, 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 these matters cannot be determined at this time; however, they could have a material impact on Mississippi Power's and Southern Company's financial statements.
Southern Company Gas
Rate Proceedings
Nicor Gas
In November 2018, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $230 million increase in annual base rate revenues. The requested increase is based on a projected test year for the 12-month period ending September 30, 2020, a ROE of 10.6%, and an increase in the equity ratio from 52% to 54% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation.
On April 16, 2019, Nicor Gas entered into a stipulation agreement to resolve all related issues with the Staff of the Illinois Commission, including a ROE of 9.86% and an equity ratio of 54%. Also on April 16, 2019, Nicor Gas filed its rebuttal testimony with the Illinois Commission incorporating the stipulation agreement and addressing the remaining items outstanding with the other two intervenors. As a result of the stipulation agreement and rebuttal testimony, the revised requested annual revenue increase is $180 million.
The Illinois Commission is expected to rule on the requested increase by early October 2019, after which rate adjustments will be effective. The ultimate outcome of this matter cannot be determined at this time.
Atlanta Gas Light
On June 3, 2019, Atlanta Gas Light filed a general base rate case with the Georgia PSC requesting a $96 million increase in annual base rate revenues. The requested increase is based on a forward-looking test year for the 12-month period ending July 31, 2020, a ROE of 10.75% with an earnings band based on a ROE between 10.55% and 10.95%, and a continued equity ratio of 55%. The filing also requests the continuation of the Georgia rate adjustment mechanism, as previously authorized. Atlanta Gas Light expects the Georgia PSC to issue a final order on this matter on December 19, 2019 with the new rates becoming effective January 1, 2020. The ultimate outcome of this matter cannot be determined at this time.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Virginia Natural Gas
In December 2018, the Virginia Commission approved Virginia Natural Gas' annual information form filing, which reduced annual base rates by $14 million effective January 1, 2019 due to lower tax expense as a result of the Tax Reform Legislation. This approval also required Virginia Natural Gas to issue customer refunds, via bill credits, for $14 million related to 2018 tax benefits deferred as a regulatory liability, current, on the balance sheet at December 31, 2018. These customer refunds were completed in the first quarter 2019.
Regulatory Infrastructure Programs
Southern Company Gas is engaged in various infrastructure programs that update or expand its gas distribution systems to improve reliability and help ensure the safety of its utility infrastructure, and recovers in rates its investment and a return associated with these infrastructure programs. In addition to capital expenditures recovered through base rates by each of the natural gas distribution utilities, Nicor Gas and Virginia Natural Gas have separate rate riders that provide for timely recovery of capital expenditures for specific infrastructure replacement programs.
Virginia Natural Gas
On April 8, 2019, Virginia Natural Gas filed an application with the Virginia Commission to amend and extend its Steps to Advance Virginia's Energy program. The proposal would allow Virginia Natural Gas to continue replacing aging pipeline infrastructure and increase its authorized investment under the currently-approved plan. Virginia Natural Gas seeks to amend its currently-approved plan by increasing the authorized investment in 2019 from $35 million to $40 million and to extend the plan for an additional five years until 2024, with proposed annual investments of $50 million in 2020, $60 million in 2021, and $70 million in each year from 2022 through 2024, for a maximum total investment over the six-year term (2019 through 2024) of $370 million. The proposed investment schedule would also allow for variances of up to $6 million in 2019, $8 million in 2020, $9 million in 2021, and $10 million in each year from 2022 through 2024, with a total potential net variance of up to $10 million allowed for the program. The Virginia Commission is expected to rule on the request in the fourth quarter 2019. The ultimate outcome of this matter cannot be determined at this time.
Affiliate Asset Management Agreements
On March 15, 2019, the Virginia Commission approved an extension of Virginia Natural Gas' asset management agreement with Sequent to March 31, 2021.
FERC Matters
See Note 2 to the financial statements under "FERC Matters – Open Access Transmission Tariff" in Item 8 of the Form 10-K for additional information.
On June 28, 2019, the FERC approved a settlement agreement between Alabama Municipal Electric Authority and Cooperative Energy and SCS and the traditional electric operating companies agreeing to an OATT rate reduction based on a 10.6% ROE, with a retroactive effective date of May 10, 2018, and a five-year moratorium on these parties seeking changes to the OATT formula rate. The terms of the OATT settlement agreement will not have a material impact on the financial statements of any of the traditional electric operating companies or Southern Company.
(C) CONTINGENCIES
See Note 3 to the financial statements of the registrants in Item 8 of the Form 10-K for information relating to various lawsuits and other contingencies, and regulatory matters.contingencies.
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 regulationlaws and regulations governing air, water, land, and protection of air emissions and water discharges.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
natural resources. 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 qualitylaws and water standards,regulations, 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 predicteddetermined 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
OnIn January 20, 2017, a purportedputative 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 IGCCCounty 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. On June 12,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. On July 27,Also in 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.opposition. In March 2018, the court issued an order granting, in part, the defendants' motion to dismiss. The court dismissed certain claims against certain officers of Southern Company and Mississippi Power and dismissed the allegations related to a number of the statements that plaintiffs challenged as being false or misleading. In April 2018, the defendants filed a motion for reconsideration of the court's order, seeking dismissal of the remaining claims in the lawsuit. In August 2018, the court denied the motion for reconsideration and denied a motion to certify the issue for interlocutory appeal.
OnIn 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 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 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 April 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 putative 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 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. EachCounty energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper IGCCCounty energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. EachThe 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. EachThe 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 andIn May 2018, the court deferred the consolidated caseentered an
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
order staying this lawsuit until 30 days after certain further actionthe resolution of any dispositive motions or any settlement, whichever is earlier, in the purportedputative securities class action complaint discussed above.action.
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, theThe ultimate outcome of whichthese matters 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 amounts for municipal franchise fees (all of which(which fees are remittedpaid 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.court. Georgia Power filed a petition for writ of certiorari with the Georgia Supreme Court, which was granted on August 28,in 2017. A decision fromIn June 2018, the Georgia Supreme Court is not expected until 2018.affirmed the judgment of the Georgia Court of Appeals and remanded the case to the trial court for further proceedings. Following a motion by Georgia Power, on February 13, 2019, the Superior Court of Fulton County ordered the parties to submit petitions to the Georgia PSC for a declaratory ruling to address certain terms the court previously held were ambiguous as used in the Georgia PSC's orders. The order entered by the Superior Court of Fulton County 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. Georgia Power also filed a notice of appeal with the Georgia Court of Appeals regarding the Superior Court of Fulton County's February 2019 order. Georgia Power believes the plaintiffs' claims have no meritmerit. The amount of any possible losses cannot be calculated at this time because, among other factors, it is unknown whether conditional class certification will be upheld and intendsthe ultimate composition of any class and whether any losses would be subject to vigorously defend itself in this matter.recovery from any municipalities. The ultimate outcome of this matter cannot be determined at this time.
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 approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest. In the first quarter 2019, Mississippi Power and Southern Company filed motions to dismiss, which were denied by the arbitration panel on May 10, 2019. Southern Company and Mississippi Power believe this legal challenge has no merit; however, an adverse outcome in this proceeding could have a material impact on Southern Company's and Mississippi Power's results of operations, financial condition, and liquidity. The ultimate outcome of this matter cannot be determined at this time.
In November 2018, Ray C. Turnage and 10 other individual plaintiffs filed a putative class action complaint against Mississippi Power and the three current 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 on March 14, 2019. The amended complaint included four additional plaintiffs and additional claims for
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
gross negligence, reckless conduct, and intentional wrongdoing. Mississippi Power and the Mississippi PSC have each filed a motion to dismiss the amended complaint. Mississippi Power believes this legal challenge has no merit; however, an adverse outcome in this proceeding could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity. The ultimate outcome of this matter cannot be determined at this time.
Southern Power
During 2015, Southern Power indirectly acquiredowns 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 subsequentlyTexas. Prior to the facility being placed in service in November 2016. Prior to placing the facility in service,2016, certain solar panels were damaged during installation. Whileinstallation by the facility currently is generating energy consistent with operational expectationsconstruction contractor, McCarthy Building Companies, Inc. (McCarthy), and PPA obligations, Southern Power is pursuing remedies under its insurance policies and other contracts to repair or replace thesecertain solar panels.panels were damaged by a hail event that also occurred during construction. In connection therewith, Southern Power is withholding paymentswithheld payment of approximately $26 million fromto the construction contractor, who haswhich 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,In 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas against X.L.XL Insurance America, Inc. (XL) and North American Elite Insurance Company (North American Elite) seeking recovery from an insurance policy for damages resulting from athe hail stormevent and certainMcCarthy's installation practices bypractices. In June 2018, the construction contractor, McCarthy Building Companies, Inc. (McCarthy). On May 19, 2017, Roserock filed a separate lawsuit against McCarthycourt granted Roserock's motion for partial summary judgment, finding that the insurers were in the state district court in Travis County, Texas alleging breach of contract and breachin violation of warrantythe Texas Insurance Code for failing to pay any monies owed for the damages sustained at thehail claim. Separate lawsuits were filed between Roserock facility, which has since been moved toand McCarthy, as well as other parties, and that litigation was consolidated in the U.S. District Court for the Western District of Texas. On May 22, 2017, McCarthy filedApril 18, 2019, Roserock and the parties to the state and federal lawsuits executed a counter lawsuit against Roserock, Array Technologies, Inc., Canadian Solar (USA), Inc., XL,settlement agreement and North American Elite inmutual release that resolved both lawsuits. Following execution of the U.S. District Court foragreement, 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.lawsuits were dismissed, Southern Power intends to vigorously pursuepaid McCarthy the amounts previously withheld, and defend these matters, the ultimate outcome of which cannot be determined at this time.
Southern Company Gas
Nicor Gas and Nicor Energy Services Company, wholly-owned subsidiaries of Southern Company Gas, and Nicor Inc. were defendants in a putative class action initially filed in 2011 in the state court in Cook County, Illinois. The plaintiffs purported to represent a classMcCarthy released its lien. As part of the customers who purchasedsettlement, Roserock received funds that covered all related legal costs, damages, and the Gas Line Comfort Guard product from Nicor Energy Services Company and variously alleged that the marketing, sale, and billingreplacement costs of certain solar panels. Funds received by Southern Power in excess of the Gas Line Comfort Guard product violated the Illinois Consumer Fraudinitial replacement costs were recognized as a gain and Deceptive Business Practices Act, constituting common law fraud and resultingincluded in unjust enrichment of these entities. The plaintiffs sought, on behalfother income (expense), net in 2019. A portion of the classes they
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
purportedpre-tax gain was allocated 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 certificationnoncontrolling interests and Southern Company Gas' motion for summary judgment. On March 7, 2017, the parties reachedPower recognized a settlement, which was finalized and effective on April 3, 2017. The settlement did not have a material impact on Southern Company's or Southern Company Gas' financial statements.$12 million after-tax gain.
Environmental Remediation
The Southern Company system must comply with environmental laws and regulations that covergoverning 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 New Jersey,and 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$18 million and $17$23 million as of SeptemberJune 30, 20172019 and December 31, 2016,2018, 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$283 million and $426$294 million as of SeptemberJune 30, 20172019 and December 31, 2016,2018, 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 agencies of the natural gas distribution utilities, with the exception of one site representing $5$2 million of the total accrued remediation costs.
The finalultimate outcome of these matters cannot be determined at this time. However,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 Southern Company, Georgia Power, Gulf Power, or Southern Company Gas.
Natural Gas Storage
A wholly-owned subsidiary177
Table 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 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 storageContents
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 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-K for additional information regarding legal remedies pursued by Alabama Power and Georgia Power against the U.S. government for its partial breach of contract relating to the disposal of spent nuclear fuel and high level radioactive waste generated at each company's nuclear plants.
On October 10, 2017,In 2014, 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 PlantPlants Farley, Plant Hatch, and Plant Vogtle Units 1 and 2 for the period from January 1, 20152011 through December 31, 2017. Damages2013. The damage period was subsequently extended to December 31, 2014. On June 12, 2019, the Court of Federal Claims granted Alabama Power's and Georgia Power's motion for summary judgment on damages not disputed by the U.S. government, awarding those undisputed damages to Alabama Power and Georgia Power. However, those undisputed damages are not collectible and no amounts will continue to accumulate until the issue is resolved or storage is provided. No amounts have beenbe recognized in the financial statements as of September 30, 2017 for any potential recoveries fromuntil the additional lawsuits.court enters final judgment on the remaining damages. The final outcome of these matters cannot be determined at this time; however,time. However, Alabama Power and Georgia Power expect to credit any recoveries for the benefit of customers in accordance with direction from their respective PSC; therefore, no material impact on Southern Company's, Alabama Power's, or Georgia Power's net income is expected.
Other Matters
MunicipalAlabama Power
On May 17, 2019, the Alabama Department of Environmental Management (ADEM) issued a proposed administrative order assessing a penalty of $250,000 to Alabama Power for unpermitted discharge of fluids and/or pollutants to groundwater and/or soils at Plant Gadsden. The proposed order also requires the submission to the ADEM of a plan with a schedule for implementation of a comprehensive groundwater investigation, an assessment of corrective measures, a report evaluating any deficiencies at the facility that may have led to the unpermitted discharge, and Rural Associations Tariffquarterly progress reports. Alabama Power is awaiting finalization of the order and the ultimate outcome of this matter cannot be determined at this time; however, it is not expected to have a material impact on Alabama Power's net income.
Mississippi Power
In conjunction with Southern Company's sale of Gulf Power, Mississippi Power and Gulf Power have committed to seek a restructuring of their 50% undivided ownership interests in Plant Daniel such that each of them would, after the restructuring, own 100% of a generating unit. On January 15, 2019, Gulf Power provided notice to Mississippi Power that Gulf Power will retire its share of the generating capacity of Plant Daniel on January 15, 2024. Mississippi Power has the option to purchase Gulf Power's ownership interest for $1 on January 15, 2024, provided that Mississippi Power exercises the option no later than 120 days prior to that date. Mississippi Power is assessing the potential operational and economic effects of Gulf Power's notice. The ultimate outcome of these matters remains subject to completion of Mississippi Power's evaluations and applicable regulatory approvals, including by the FERC and the Mississippi PSC, and cannot be determined at this time. See Note 3 to the financial statements of Mississippi Power(K) 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 CycleSouthern Company" herein for information regarding the Kemper IGCC.sale of Gulf Power.
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. Southern Company Gas
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 statementsfuture performance of Southern Company Gas' natural gas storage facility consisting of two salt dome caverns in Louisiana, as well as Southern Company Gas' two other natural gas storage facilities located in California and Mississippi Power under "FERC Matters – Market-Based Rate Authority"Texas, could be impacted by ongoing changes in the U.S. natural gas storage market. Recent sales of natural gas storage facilities have resulted in losses for the sellers and Note 3may imply an impact on future rates and/or asset values. Southern Company Gas is evaluating these recent market transactions for impacts on its plans to the financial statements of Alabama Power, Georgia Power, Gulf Power, and Southern Power under "FERC Matters" in Item 8return one of the Form 10-K for additional information regarding the traditional electric operating companies' and Southern Power's market power proceeding and amendmentsalt dome caverns in Louisiana back 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 termsservice in 2021. Sustained diminished natural gas storage values could trigger impairment 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 remainsone or all of these natural gas storage facilities, which have a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' and Southern Power'scombined net book value of $438 million at 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.
2019. The ultimate outcome of these matters cannot be determined at this time.time, but could have a material impact on Southern Company's and Southern Company Gas' financial statements.
Regulatory Matters
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
(D) REVENUE FROM CONTRACTS WITH CUSTOMERS
The registrants generate revenues from a variety of sources, some of which are excluded from the scope of ASC 606, Revenue from Contracts with Customers (ASC 606), such as leases, derivatives, and certain cost recovery mechanisms. See Note 31 to the financial statements of Southern Company and Alabama Power under "Regulatory Matters "Recently Adopted Accounting Standards – Alabama Power" and "Retail Regulatory Matters," respectively,Revenue" 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 Complianceadoption of ASC 606 for revenue from contracts with customers 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 31 to the financial statements of Southern Companyunder "Revenues" and Georgia Power under "Regulatory Matters – Georgia Power – Rate Plans" and "Retail Regulatory Matters – Rate Plans," respectively,"Other Taxes" in Item 8 of the Form 10-K for additional information.information on the revenue policies of the registrants. For additional information on revenues accounted for under other accounting guidance, see Notes (J) and (L) for energy-related derivative contracts and lessor revenues, respectively, Note 1 to the financial statements under "Revenues – Southern Company Gas" in Item 8 of the Form 10-K for alternative revenue programs at the natural gas distribution utilities, and Note 2 to the financial statements in Item 8 of the Form 10-K for cost recovery mechanisms.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
The following tables disaggregate revenue sources for the three and six months ended June 30, 2019 and 2018:
|
| | | | | | | | | | | | |
| | For the Three Months Ended June 30, 2019 | For the Three Months Ended June 30, 2018 | For the Six Months Ended June 30, 2019 | For the Six Months Ended June 30, 2018 |
| | (in millions) |
| Southern Company | | | | |
| Operating revenues | | | | |
Retail electric revenues(a) | | | | |
| Residential | $ | 1,488 |
| $ | 1,579 |
| $ | 2,776 |
| $ | 3,118 |
|
| Commercial | 1,258 |
| 1,315 |
| 2,350 |
| 2,557 |
|
| Industrial | 763 |
| 814 |
| 1,440 |
| 1,569 |
|
| Other | 31 |
| 32 |
| 57 |
| 64 |
|
Natural gas distribution revenues(b) | 562 |
| 642 |
| 1,724 |
| 1,865 |
|
Alternative revenue programs(c) | 1 |
| (4 | ) | — |
| (27 | ) |
| Total retail electric and gas distribution revenues | $ | 4,103 |
| $ | 4,378 |
| $ | 8,347 |
| $ | 9,146 |
|
Wholesale energy revenues(d)(e) | 410 |
| 464 |
| 777 |
| 937 |
|
Wholesale capacity revenues(e) | 132 |
| 152 |
| 264 |
| 302 |
|
Other natural gas revenues(f)(g) | 126 |
| 68 |
| 439 |
| 476 |
|
Other revenues(h) | 327 |
| 565 |
| 683 |
| 1,138 |
|
| Total operating revenues | $ | 5,098 |
| $ | 5,627 |
| $ | 10,510 |
| $ | 11,999 |
|
| |
| (a) | Retail electric revenues include $8 million, $18 million, $16 million, and $36 million of revenues accounted for as leases for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, and a (net reduction) or net increase of $(14) million, $68 million, $(117) million and $101 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, from certain cost recovery mechanisms that are not accounted for as revenue under ASC 606. |
| |
| (b) | Natural gas distribution revenues include $5 million for each of the three months ended June 30, 2019 and 2018 and $8 million for each of the six months ended June 30, 2019 and 2018 of revenues not accounted for under ASC 606. |
| |
| (c) | Alternative revenue program revenues are presented net of any previously recognized program amounts billed to customers during the same accounting period. |
| |
| (d) | Wholesale energy revenues include $30 million, $61 million, $82 million, and $155 million of revenues accounted for as derivatives for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, primarily related to physical energy sales in the wholesale electricity market. |
| |
| (e) | Wholesale energy revenues include $115 million, $118 million, $182 million, and $187 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, and wholesale capacity revenues include $22 million, $31 million, $47 million, and $61 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, related to PPAs accounted for as leases. |
| |
| (f) | Other natural gas revenues related to Southern Company Gas' energy and risk management activities are presented net of the related costs of those activities and include gross third-party revenues of $1.2 billion, $1.3 billion, $3.1 billion, and $3.3 billion for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, of which $0.8 billion, $0.7 billion, $2.0 billion, and $1.8 billion, respectively, relates to contracts that are accounted for as derivatives. See Note (M) under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues. |
| |
| (g) | Other natural gas revenues include $10 million and $27 million for the three and six months ended June 30, 2019, respectively, of revenues not accounted for under ASC 606, including $8 million and $16 million, respectively, of revenues accounted for as leases. |
| |
| (h) | Other revenues include $89 million, $89 million, $180 million, and $183 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, of revenues not accounted for under ASC 606, including $28 million, $33 million, $59 million, and $66 million, respectively, accounted for as leases. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | |
| | Alabama Power | Georgia Power | Mississippi Power |
| | (in millions) |
| For the Three Months Ended June 30, 2019 | | | |
| Operating revenues | | | |
Retail revenues(a)(b) | | | |
| Residential | $ | 588 |
| $ | 831 |
| $ | 69 |
|
| Commercial | 418 |
| 767 |
| 73 |
|
| Industrial | 366 |
| 327 |
| 70 |
|
| Other | 6 |
| 21 |
| 3 |
|
| Total retail electric revenues | $ | 1,378 |
| $ | 1,946 |
| $ | 215 |
|
Wholesale energy revenues(c) | 41 |
| 14 |
| 93 |
|
| Wholesale capacity revenues | 25 |
| 22 |
| 1 |
|
Other revenues(b)(d) | 69 |
| 135 |
| 4 |
|
| Total operating revenues | $ | 1,513 |
| $ | 2,117 |
| $ | 313 |
|
| | | | |
| For the Three Months Ended June 30, 2018 | | | |
| Operating revenues | | | |
Retail revenues(a)(b) | | | |
| Residential | $ | 557 |
| $ | 785 |
| $ | 65 |
|
| Commercial | 402 |
| 749 |
| 68 |
|
| Industrial | 372 |
| 335 |
| 76 |
|
| Other | 7 |
| 20 |
| 3 |
|
| Total retail electric revenues | $ | 1,338 |
| $ | 1,889 |
| $ | 212 |
|
Wholesale energy revenues(c) | 71 |
| 26 |
| 77 |
|
| Wholesale capacity revenues | 25 |
| 13 |
| 1 |
|
Other revenues(b)(d) | 69 |
| 120 |
| 7 |
|
| Total operating revenues | $ | 1,503 |
| $ | 2,048 |
| $ | 297 |
|
| |
| (a) | Retail revenues at Alabama Power, Georgia Power, and Mississippi Power include a net increase or (net reduction) of $(11) million, $(5) million, and $2 million, respectively, for the three months ended June 30, 2019 and $78 million, $3 million, and $(1) million, respectively, for the three months ended June 30, 2018 related to certain cost recovery mechanisms that are not accounted for as revenue under ASC 606. |
| |
| (b) | Retail revenues and other revenues at Georgia Power include $8 million and $11 million, respectively, for the three months ended June 30, 2019 and $18 million and $33 million, respectively, for the three months ended June 30, 2018 of revenues accounted for as leases. |
| |
| (c) | Wholesale energy revenues at Alabama Power, Georgia Power, and Mississippi Power include $3 million, $4 million, and $1 million, respectively, for the three months ended June 30, 2019 and $4 million, $5 million, and $1 million, respectively, for the three months ended June 30, 2018 accounted for as derivatives primarily related to physical energy sales in the wholesale electricity market. |
| |
| (d) | Other revenues at Alabama Power and Georgia Power include $31 million and $30 million, respectively, for the three months ended June 30, 2019 and $26 million and $26 million, respectively, for the three months ended June 30, 2018 of revenues not accounted for under ASC 606. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | |
| | Alabama Power | Georgia Power | Mississippi Power |
| | (in millions) |
| For the Six Months Ended June 30, 2019 | | | |
| Operating revenues | | | |
Retail revenues(a)(b) | | | |
| Residential | $ | 1,128 |
| $ | 1,519 |
| $ | 129 |
|
| Commercial | 772 |
| 1,440 |
| 138 |
|
| Industrial | 679 |
| 616 |
| 145 |
|
| Other | 13 |
| 39 |
| 6 |
|
| Total retail electric revenues | $ | 2,592 |
| $ | 3,614 |
| $ | 418 |
|
Wholesale energy revenues(c) | 135 |
| 27 |
| 170 |
|
| Wholesale capacity revenues | 51 |
| 40 |
| 2 |
|
Other revenues(b)(d) | 143 |
| 270 |
| 10 |
|
| Total operating revenues | $ | 2,921 |
| $ | 3,951 |
| $ | 600 |
|
| | | | |
| For the Six Months Ended June 30, 2018 | | | |
| Operating revenues | | | |
Retail revenues(a)(b) | | | |
| Residential | $ | 1,127 |
| $ | 1,529 |
| $ | 125 |
|
| Commercial | 774 |
| 1,466 |
| 130 |
|
| Industrial | 710 |
| 650 |
| 146 |
|
| Other | 13 |
| 43 |
| 5 |
|
| Total retail electric revenues | $ | 2,624 |
| $ | 3,688 |
| $ | 406 |
|
Wholesale energy revenues(c) | 172 |
| 66 |
| 176 |
|
| Wholesale capacity revenues | 49 |
| 27 |
| 5 |
|
Other revenues(b)(d) | 131 |
| 227 |
| 11 |
|
| Total operating revenues | $ | 2,976 |
| $ | 4,008 |
| $ | 598 |
|
| |
| (a) | Retail revenues at Alabama Power, Georgia Power, and Mississippi Power include a net increase or (net reduction) of $(68) million, $(52) million, and $3 million, respectively, for the six months ended June 30, 2019 and $125 million, $12 million, and $(8) million, respectively, for the six months ended June 30, 2018 related to certain cost recovery mechanisms that are not accounted for as revenue under ASC 606. |
| |
| (b) | Retail revenues and other revenues at Georgia Power include $16 million and $23 million, respectively, for the six months ended June 30, 2019 and $36 million and $66 million, respectively, for the six months ended June 30, 2018 of revenues accounted for as leases. |
| |
| (c) | Wholesale energy revenues at Alabama Power, Georgia Power, and Mississippi Power include $6 million, $8 million, and $1 million, respectively, for the six months ended June 30, 2019 and $9 million, $13 million, and $2 million, respectively, for the six months ended June 30, 2018 accounted for as derivatives primarily related to physical energy sales in the wholesale electricity market. |
| |
| (d) | Other revenues at Alabama Power and Georgia Power include $59 million and $61 million, respectively, for the six months ended June 30, 2019 and $52 million and $53 million, respectively, for the six months ended June 30, 2018 of revenues not accounted for under ASC 606. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | |
| | For the Three Months Ended June 30, 2019 | For the Three Months Ended June 30, 2018 | For the Six Months Ended June 30, 2019 | For the Six Months Ended June 30, 2018 |
| | (in millions) |
| Southern Power | | | | |
PPA capacity revenues(a) | $ | 125 |
| $ | 144 |
| $ | 252 |
| $ | 282 |
|
PPA energy revenues(a) | 291 |
| 302 |
| 518 |
| 556 |
|
Non-PPA revenues(b) | 91 |
| 106 |
| 177 |
| 221 |
|
| Other revenues | 3 |
| 3 |
| 6 |
| 5 |
|
| Total operating revenues | $ | 510 |
| $ | 555 |
| $ | 953 |
| $ | 1,064 |
|
| |
| (a) | PPA capacity revenues include $39 million, $47 million, $80 million, and $94 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, and PPA energy revenues include $125 million, $127 million, $198 million, and $203 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, related to PPAs accounted for as leases. |
| |
| (b) | Non-PPA revenues include $22 million, $50 million, $67 million, and $129 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, of revenues from short-term sales related to physical energy sales from uncovered capacity in the wholesale electricity market. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | |
| | For the Three Months Ended June 30, 2019 | For the Three Months Ended June 30, 2018 | For the Six Months Ended June 30, 2019 | For the Six Months Ended June 30, 2018 |
| | (in millions) |
| Southern Company Gas | | | | |
| Operating revenues | | | | |
Natural gas distribution revenues(a) | | | | |
| Residential | $ | 229 |
| $ | 273 |
| $ | 830 |
| $ | 933 |
|
| Commercial | 65 |
| 76 |
| 235 |
| 268 |
|
| Transportation | 213 |
| 228 |
| 469 |
| 505 |
|
| Industrial | 5 |
| 7 |
| 22 |
| 24 |
|
| Other | 50 |
| 58 |
| 168 |
| 135 |
|
Alternative revenue programs(b) | 1 |
| (4 | ) | — |
| (27 | ) |
| Total natural gas distribution revenues | $ | 563 |
| $ | 638 |
| $ | 1,724 |
| $ | 1,838 |
|
Gas pipeline investments(c) | 8 |
| 8 |
| 16 |
| 16 |
|
Wholesale gas services(d) | 48 |
| (15 | ) | 114 |
| 131 |
|
Gas marketing services(e) | 58 |
| 89 |
| 287 |
| 359 |
|
| Other revenues | 12 |
| 10 |
| 22 |
| 25 |
|
| Total operating revenues | $ | 689 |
| $ | 730 |
| $ | 2,163 |
| $ | 2,369 |
|
| |
| (a) | Natural gas distribution revenues include $5 million for each of the three months ended June 30, 2019 and 2018 and $8 million for each of the six months ended June 30, 2019 and 2018 of revenues not accounted for under ASC 606. |
| |
| (b) | Alternative revenue program revenues are presented net of any previously recognized program amounts billed to customers during the same accounting period. |
| |
| (c) | Revenues from gas pipeline investments include $8 million and $16 million for the three and six months ended June 30, 2019, respectively, accounted for as leases. |
| |
| (d) | Wholesale gas services revenues are presented net of the related costs associated with its energy trading and risk management activities. Operating revenues, as presented, include gross third-party revenues of $1.2 billion, $1.3 billion, $3.1 billion, and $3.3 billion for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, of which $0.8 billion, $0.7 billion, $2.0 billion, and $1.8 billion, respectively, relates to contracts accounted for as derivatives. See Note (M) under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues. |
| |
| (e) | Gas marketing services include $2 million for the three months ended June 30, 2019 and $11 million and $4 million for the six months ended June 30, 2019 and 2018, respectively, of revenues not accounted for under ASC 606. |
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 as of June 30, 2019 and December 31, 2018:
|
| | | | | | | | | | | | | | | | | | | | |
| | Receivables | | Contract Assets | | Contract Liabilities |
| | June 30, 2019 | December 31, 2018 | | June 30, 2019 | December 31, 2018 | | June 30, 2019 | December 31, 2018 |
| | (in millions) |
Southern Company(*) | $ | 2,343 |
| $ | 2,630 |
| | $ | 70 |
| $ | 102 |
| | $ | 58 |
| $ | 32 |
|
| Alabama Power | 629 |
| 520 |
| | — |
| — |
| | 10 |
| 12 |
|
| Georgia Power | 807 |
| 721 |
| | 30 |
| 58 |
| | 26 |
| 7 |
|
| Mississippi Power | 93 |
| 100 |
| | — |
| — |
| | 7 |
| — |
|
| Southern Power | 119 |
| 118 |
| | — |
| — |
| | 1 |
| 11 |
|
| Southern Company Gas | 550 |
| 952 |
| | — |
| — |
| | 1 |
| 2 |
|
| |
| (*) | Includes amounts related to held for sale investments. |
As of June 30, 2019 and December 31, 2018, 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 the one-year contract term. Alabama Power had contract liabilities for outstanding performance obligations primarily related to extended service agreements. Contract liabilities for Georgia Power and Southern Power relate to cash collections recognized in advance of revenue for certain unregulated service agreements and certain levelized PPAs, respectively. Mississippi Power had contract liabilities for cash collections recognized in advance of revenue for operating agreements associated with a tolling arrangement accounted for as a sales-type lease. Southern Company's unregulated distributed generation business had $32 million and $39 million of contract assets and $14 million and $11 million of contract liabilities at June 30, 2019 and December 31, 2018, respectively, remaining for outstanding performance obligations.
The following table reflects revenue from contracts with customers recognized in the three and six months ended June 30, 2019 included in the contract liability at December 31, 2018:
|
| | | | | | |
| | Three Months Ended
June 30, 2019 | Six Months Ended
June 30, 2019 |
| | (in millions) | |
| Southern Company | $ | 11 |
| $ | 27 |
|
| Southern Power | 1 |
| 11 |
|
Revenues recognized in the three and six months ended June 30, 2019, which were included in contract liabilities at December 31, 2018, were immaterial for Alabama Power, Georgia Power, and Southern Company Gas.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Remaining Performance Obligations
The traditional electric operating companies and Southern Power have long-term contracts with customers in which revenues are recognized when the performance obligations are satisfied during 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. Registrants with 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 costscontracts with customers related to these performance obligations remaining at June 30, 2019 expect the constructionrevenues to be recognized as follows:
|
| | | | | | | | | | | | | | | | | | |
| | 2019 (remaining) | 2020 | 2021 | 2022 | 2023 | Thereafter |
| | (in millions) |
| Southern Company | $ | 282 |
| $ | 490 |
| $ | 320 |
| $ | 311 |
| $ | 302 |
| $ | 2,230 |
|
| Alabama Power | 11 |
| 23 |
| 27 |
| 23 |
| 22 |
| 140 |
|
| Georgia Power | 27 |
| 51 |
| 44 |
| 31 |
| 31 |
| 83 |
|
| Southern Power | 169 |
| 295 |
| 270 |
| 276 |
| 269 |
| 2,154 |
|
Revenues expected to be recognized for performance obligations remaining at June 30, 2019 were immaterial for Mississippi Power.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
(E) CONSOLIDATED ENTITIES AND EQUITY METHOD INVESTMENTS
Southern Power
Consolidated Variable Interest Entities
See "Nuclear Construction" herein and Note 37 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 regardingon Southern Power's consolidated VIEs.
Southern Power has certain subsidiaries that are determined to be VIEs. Southern Power is considered the NCCR tariff. Also see "Fuel Cost Recovery" hereinprimary beneficiary of these VIEs because it controls the most significant activities of the VIEs, 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. In 2018, Southern Power sold noncontrolling interests in SP Solar and SP Wind. Southern Power continues to consolidate each entity, as the primary beneficiary of each VIE, since it controls the most significant activities of each entity, including operating and maintaining their assets. Transfers and sales of the assets in the VIEs are subject to limited partner consent and the liabilities are non-recourse to the general credit of Southern Power. Liabilities consist of customary working capital items and do not include any long-term debt.
SP Solar
At June 30, 2019, SP Solar had total assets of $6.5 billion, total liabilities of $374 million, and noncontrolling interests of $1.1 billion. 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 distribute all such available cash to its partners each quarter. Available cash includes all cash generated in the quarter subject to the maintenance of appropriate operating reserves.
SP Wind
At June 30, 2019, SP Wind had total assets of $2.5 billion, total liabilities of $136 million, and noncontrolling interests of $46 million. Under the terms of the limited liability agreement, distributions without Class A member consent are limited to available 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 quarter subject to the maintenance of appropriate operating reserves. Cash distributions from SP Wind are generally allocated 60% to Southern Power and 40% to the three financial investors in accordance with the limited liability agreement.
Equity Method Investments
In June 2019, Southern Power made investments in certain legal entities that are considered VIEs but for which Southern Power is not the primary beneficiary because it does not control the most significant activities of the VIEs. These investments are accounted for as equity method investments. The total carrying amount of these investments is $144 million as of June 30, 2019, of which $116 million relates to membership interests in DSGP, an affiliate of Bloom Energy, that owns and operates fuel cell generation facilities in Delaware. Southern Power expects to consolidate DSGP, and record a noncontrolling interest, pending FERC approval of the transfer of the facilities. FERC approval is expected to occur in the third quarter 2019; however, the ultimate outcome of this matter cannot be determined at this time.
Southern Company Gas
See Note 37 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.on Southern Company Gas' equity method investments.
Integrated Resource Plan
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Equity Method Investments
The carrying amounts of Southern Company Gas' equity method investments as of June 30, 2019 and December 31, 2018 and related income from those investments for the three- and six-month periods ended June 30, 2019 and 2018 were as follows:
|
| | | | | | |
| Investment Balance | June 30, 2019 | December 31, 2018 |
| | (in millions) |
| SNG | $ | 1,243 |
| $ | 1,261 |
|
| Atlantic Coast Pipeline | 101 |
| 83 |
|
| PennEast Pipeline | 77 |
| 71 |
|
Other(*) | 88 |
| 123 |
|
| Total | $ | 1,509 |
| $ | 1,538 |
|
| |
| (*) | Decrease primarily relates to the sale of Triton. |
|
| | | | | | | | | | | | |
| Earnings from Equity Method Investments | Three Months Ended June 30, 2019 | Three Months Ended June 30, 2018 | Six Months Ended June 30, 2019 | Six Months Ended June 30, 2018 |
| | (in millions) |
| SNG | $ | 32 |
| $ | 27 |
| $ | 74 |
| $ | 66 |
|
| Atlantic Coast Pipeline | 3 |
| 1 |
| 6 |
| 3 |
|
| PennEast Pipeline | 1 |
| 1 |
| 3 |
| 2 |
|
Other(*) | (5 | ) | 2 |
| (3 | ) | 3 |
|
| Total | $ | 31 |
| $ | 31 |
| $ | 80 |
| $ | 74 |
|
| |
| (*) | Decrease primarily relates to the sale of Triton. |
Triton
On May 29, 2019, Southern Company Gas sold its investment in Triton, a cargo container leasing company that was aggregated into Southern Company Gas' all other segment. This disposition resulted in a pre-tax loss of $6 million and a net after-tax gain of $7 million as a result of reversing a $13 million federal income tax valuation allowance.
SNG
Selected financial information of SNG for the three and six months ended June 30, 2019 and 2018 is as follows:
|
| | | | | | | | | | | | |
| Income Statement Information | Three Months Ended June 30, 2019 | Three Months Ended June 30, 2018 | Six Months Ended June 30, 2019 | Six Months Ended June 30, 2018 |
| | (in millions) |
| Revenues | $ | 155 |
| $ | 146 |
| $ | 321 |
| $ | 306 |
|
| Operating income | 86 |
| 60 |
| 192 |
| 159 |
|
| Net income | 64 |
| 54 |
| 148 |
| 132 |
|
(F) FINANCING
Bank Credit Arrangements
Bank credit arrangements provide liquidity support to the registrants' commercial paper borrowings and the traditional electric operating companies' revenue bonds. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of June 30, 2019 was approximately $1.4 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Power, and $40 million at Mississippi Power). In addition, at June 30, 2019, the traditional electric operating companies had approximately $272 million (comprised of approximately $87 million at Alabama Power and $185 million at Georgia Power) of revenue bonds outstanding that were required to be remarketed within the next 12 months. See Note 38 to the financial statements under "Bank Credit Arrangements" in Item 8 of the Form 10-K and "Financing Activities" herein for additional information.
The following table outlines the committed credit arrangements by company as of June 30, 2019:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Expires | | | |
| Company | 2019 | 2020 | 2022 | 2024 | | Total | | Unused | Due within One Year |
| | (in millions) |
Southern Company(a) | $ | — |
| $ | — |
| $ | — |
| $ | 2,000 |
| | $ | 2,000 |
| | $ | 1,999 |
| $ | — |
|
| Alabama Power | 3 |
| 500 |
| — |
| 800 |
| | 1,303 |
| | 1,303 |
| 3 |
|
| Georgia Power | — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,736 |
| — |
|
| Mississippi Power | — |
| — |
| 150 |
| — |
| | 150 |
| | 150 |
| — |
|
Southern Power(b) | — |
| — |
| — |
| 600 |
| | 600 |
| | 561 |
| — |
|
Southern Company Gas(c) | — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,745 |
| — |
|
| Other | — |
| 30 |
| — |
| — |
| | 30 |
| | 30 |
| 30 |
|
| Southern Company Consolidated | $ | 3 |
| $ | 530 |
| $ | 150 |
| $ | 6,900 |
| | $ | 7,583 |
| | $ | 7,524 |
| $ | 33 |
|
| |
| (a) | Represents the Southern Company parent entity. |
| |
| (b) | Does not include Southern Power Company's $120 million continuing letter of credit facility for standby letters of credit expiring in 2021, of which $30 million was unused at June 30, 2019. Southern Power's subsidiaries are not parties to its bank credit arrangement. |
| |
| (c) | 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 May 2019, Southern Company, Alabama Power, Georgia Power, and Southern Power each amended and restated certain of their multi-year credit arrangements, which, among other things, extended the maturity dates to 2024. Southern Power also decreased its borrowing capacity from $750 million to $600 million. In addition, Southern Company Gas Capital, along with Nicor Gas, amended and restated its multi-year credit arrangement to extend the maturity date to 2024 and decrease the aggregate borrowing capacity from $1.9 billion to $1.75 billion. In June 2019, Mississippi Power entered into a new $50 million credit arrangement that matures in 2022 and amended its existing credit arrangements, which, among other things, extended the maturity dates from 2019 to 2022.
Subject to applicable market conditions, Southern Company and Georgia Powerits 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.
DOE Loan Guarantee Borrowings
See Note 8 to the financial statements under "Regulatory Matters"Long-term Debt – Georgia Power – Integrated Resource Plan" and "Retail Regulatory Matters – Integrated Resource Plan," respectively,DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for additional information regarding Georgia Power's triennial Integrated Resource Plan.2014 loan guarantee agreement.
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 3Pursuant to the financial statementsloan guarantee program established under Title XVII of Southern Company andthe Energy Policy Act of 2005 (Title XVII Loan Guarantee Program), Georgia Power under "Regulatory Matters – Georgia Power – Fuel Cost Recovery" and "Retail Regulatory Matters – Fuel Cost Recovery," respectively,the DOE entered into a loan guarantee agreement in Item 8 of2014 and the Form 10-K for additional information.
As of September 30, 2017, Georgia Power's under recovered fuel balance totaled $100 millionAmended and is includedRestated Loan Guarantee Agreement in current assetsMarch 2019. Under the Amended 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 inRestated Loan Guarantee Agreement, 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 inDOE has agreed to guarantee 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 statementsobligations of Georgia Power under "Storm Damage Recovery"note purchase agreements among the DOE, Georgia Power, and the FFB and related promissory notes which provide for two multi-advance term loan facilities (FFB Credit Facilities). Under the FFB Credit Facilities, Georgia Power may make term loan borrowings through the FFB in Item 8an amount up to approximately $5.130 billion, provided that total
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Nuclear Constructionaggregate borrowings under the FFB Credit Facilities may not exceed 70% of (i) Eligible Project Costs minus (ii) approximately $1.492 billion (reflecting the amounts received by Georgia Power under the Guarantee Settlement Agreement less the Customer Refunds).
See Note 3In March 2019, Georgia Power made borrowings under the FFB Credit Facilities in an aggregate principal amount of $835 million at an interest rate of 3.213% through the final maturity date of February 20, 2044. At June 30, 2019, Georgia Power had a total of $3.46 billion of borrowings outstanding under the FFB Credit Facilities.
All borrowings under the FFB Credit Facilities are full recourse to the financial statements of Southern CompanyGeorgia Power, and Georgia Power is obligated to reimburse the DOE for any payments the DOE is required to make to the FFB under "Regulatory Matters –its guarantee. Georgia Power's reimbursement obligations to the DOE are full recourse and secured by a first priority lien on (i) Georgia Power's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. There are no restrictions on Georgia Power's ability to grant liens on other property.
In addition to the conditions described above, future advances are subject to satisfaction of customary conditions, as well as certification of compliance with the requirements of the Title XVII Loan Guarantee Program, including accuracy of project-related representations and warranties, delivery of updated project-related information, and 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.
Upon satisfaction of all conditions described above, advances may be requested on a quarterly basis through 2023. The final maturity date for each advance under the FFB Credit Facilities is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20, 2020. Borrowings under the FFB Credit Facilities will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375%.
Under the Amended and Restated Loan Guarantee Agreement, Georgia Power – Nuclear Construction"is subject to customary borrower affirmative and "Retail Regulatory Matters – Nuclear Construction," respectively, in Item 8negative 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 Facilities will terminate and Georgia Power will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facilities over a period of five years (with level principal amortization). Among other things, these mandatory prepayment events include (i) the termination of the Form 10-K for additional information regardingVogtle Services Agreement or rejection of the Vogtle Services Agreement in any Westinghouse bankruptcy if Georgia Power's constructionPower does not maintain access to intellectual property rights under the related intellectual property licenses; (ii) termination of the Bechtel Agreement, unless the Vogtle Owners enter into a replacement agreement; (iii) cancellation of Plant Vogtle Units 3 and 4 Vogtle Construction Monitoring (VCM) reports,by 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 termsPSC or by Georgia Power; (iv) failure 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 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.
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, 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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 mustto vote to continue construction iffollowing certain adverse events occur, including (i)schedule extensions; (v) cost disallowances by the bankruptcy of Toshiba orGeorgia PSC that could have a material breachadverse effect on completion of Plant Vogtle Units 3 and 4 or Georgia Power's ability to repay the outstanding borrowings under the FFB Credit Facilities; or (vi) loss of or failure to receive necessary regulatory approvals. 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 Facilities. In addition, if Georgia Power discontinues construction of Plant Vogtle Units 3 and 4, Georgia Power would be obligated to immediately repay a portion of the outstanding borrowings under the FFB Credit Facilities to the extent such outstanding borrowings exceed 70% of Eligible Project Costs, net of the proceeds received by Toshiba ofGeorgia Power under the Guarantee Settlement Agreement; (ii) terminationAgreement less the Customer Refunds. Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facilities. Under the FFB Credit Facilities, any prepayment (whether mandatory or rejection in bankruptcyoptional) will be made with a make-whole premium or discount, as applicable.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
In connection with any cancellation of Plant Vogtle Units 3 and 4, the DOE may elect to continue construction of Plant Vogtle Units 3 and 4. In such an event, the DOE will have the right to assume Georgia Power's rights and obligations under the principal agreements including the Services Agreementrelating to Plant Vogtle Units 3 and 4 and to acquire all or the Bechtel Agreement; (iii) the Georgia PSC determines that anya portion of Georgia Power's costs relatingownership interest in Plant Vogtle Units 3 and 4.
Financing Activities
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first six months of 2019:
|
| | | | | | | | | | | | | | | | | | | |
| Company | Senior Note Maturities, Redemptions, and Repurchases | | Revenue Bond Issuances and Reofferings of Purchased Bonds | | Revenue Bond
Maturities, Redemptions, and
Repurchases | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(a) |
| | (in millions) |
Southern Company(b) | $ | 2,100 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Alabama Power | 200 |
| | — |
| | — |
| | — |
| | — |
|
| Georgia Power | — |
| | 513 |
| | 223 |
| | 835 |
| | 3 |
|
| Mississippi Power | — |
| | 43 |
| | — |
| | — |
| | — |
|
| Other | — |
| | — |
| | 25 |
| | — |
| | 9 |
|
| Southern Company Consolidated | $ | 2,300 |
| | $ | 556 |
| | $ | 248 |
| | $ | 835 |
| | $ | 12 |
|
| |
| (a) | Includes reductions in finance lease obligations resulting from cash payments under finance leases. |
| |
| (b) | Represents the Southern Company parent entity. |
Except as otherwise described herein, Southern Company and its subsidiaries used the proceeds of debt issuances for their redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including working capital. The subsidiaries also used the proceeds for their construction programs.
Southern Company
In January 2019, Southern Company repaid a $250 million short-term uncommitted bank credit arrangement and a $1.5 billion short-term floating rate bank loan.
Also in January 2019, through cash tender offers, Southern Company repurchased and retired approximately $522 million of the $1.0 billion aggregate principal amount outstanding of its 1.85% Senior Notes due July 1, 2019 (1.85% Notes), approximately $180 million of the $350 million aggregate principal amount outstanding of its Series 2014B 2.15% Senior Notes due September 1, 2019 (Series 2014B Notes), and approximately $504 million of the $750 million aggregate principal amount outstanding of its Series 2018A Floating Rate Notes due February 14, 2020 (Series 2018A Notes), for an aggregate purchase price, excluding accrued and unpaid interest, of approximately $1.2 billion. In addition, following the completion of the cash tender offers, in February 2019, Southern Company completed the redemption of all of the Series 2018A Notes, 1.85% Notes, and Series 2014B Notes remaining outstanding.
Georgia Power
In January 2019, Georgia Power redeemed approximately $13 million, $20 million, and $75 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 1992, Eighth Series 1994, and Second Series 1995, respectively.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
In March 2019, Georgia Power reoffered to the public the following pollution control revenue bonds that previously had been purchased and held by Georgia Power:
$173 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2009;
approximately $105 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2013; and
$65 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2008.
In April 2019, Georgia Power purchased and held the following pollution control revenue bonds. In May 2019, Georgia Power reoffered these pollution control revenue bonds to the public.
$55 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fourth Series 1994;
$30 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fourth Series 1995;
$20 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Ninth Series 1994; and
$10 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 1994.
In June 2019, Georgia Power reoffered to the public $55 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1994, which had been previously purchased and held by Georgia Power.
Also in June 2019, Georgia Power entered into two short-term floating rate bank loans in aggregate principal amounts of $125 million each, both of which bear interest based on one-month LIBOR.
Mississippi Power
In March 2019, Mississippi Power reoffered to the public $43 million of Mississippi Business Finance Corporation Pollution Control Revenue Refunding Bonds, Series 2002, which previously had been purchased and held by Mississippi Power.
Southern Power
In May 2019, Southern Power repaid at maturity a $100 million aggregate principal amount short-term bank loan.
Earnings per Share
For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under stock-based compensation plans. See Note 12 to the financial statements in Item 8 of the Form 10-K for information on stock-based compensation plans. The effect of stock-based compensation plans was determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:
|
| | | | | | | | |
| | Three Months Ended June 30, 2019 | Three Months Ended June 30, 2018 | Six Months Ended June 30, 2019 | Six Months Ended June 30, 2018 |
| | (in millions) |
| As reported shares | 1,044 |
| 1,014 |
| 1,041 |
| 1,012 |
|
| Effect of stock-based compensation | 8 |
| — |
| 8 |
| 5 |
|
| Diluted shares | 1,052 |
| 1,014 |
| 1,049 |
| 1,017 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
There were no stock-based compensation awards that were not included in the diluted earnings per share calculation because they were anti-dilutive for the three and six months ended June 30, 2019 and an immaterial amount of such awards was not included for the six months ended June 30, 2018. For the three months ended June 30, 2018, approximately 5.3 million shares of stock-based compensation awards were not included in the diluted earnings per share calculation because they were anti-dilutive.
(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 Carryforwards
Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) totaling $2.0 billion as of June 30, 2019 compared to $2.4 billion as of December 31, 2018.
The federal ITC and PTC carryforwards begin expiring in 2034 and 2032, respectively, but are expected to be fully utilized by 2023. The estimated tax credit utilization reflects the projected taxable gains on the various sale transactions describe in Note (K) and could be further delayed 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, 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 regarding 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 and 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 33.5% for the six months ended June 30, 2019 compared to an effective tax benefit rate of (3.2)% for the corresponding period in 2018. The effective tax rate increase was primarily due to the tax impact from the sale of Gulf Power in 2019 and the 2018 charge to earnings related to the construction of Plant Vogtle Units 3 and 4. See Note (K) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.
Georgia Power
Georgia Power's effective tax rate was 21.7% for the six months ended June 30, 2019 compared to a benefit rate of (53.5)% for the corresponding period in 2018. The effective tax rate increase was primarily due to the 2018 charge to earnings related to the construction of Plant Vogtle Units 3 and 4, will not be recoveredpartially offset by an increase in retail rates because such costs are deemed unreasonable or imprudent; or (iv)state ITCs. See Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.
Mississippi Power
Mississippi Power's effective tax rate was 14.0% for the six months ended June 30, 2019 compared to 18.7% for the corresponding period in 2018. The effective tax rate decrease was primarily due to an increase in the construction budget contained in the seventeenth VCM report by more than $1 billion or extensionflowback of the project schedule contained in the seventeenth VCM report by more than one year. In addition, under the term sheet, the required approvalexcess deferred income taxes as a result 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) resolvingreached with wholesale customers under the following prudence matters: (i) noneMRA tariff. See Note (B) under "Mississippi Power" for additional information.
Table of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report will be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement is reasonable and prudent and none of the amounts paid or to be paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) financing costs on verified and approved capital costs will be deemed prudent provided they are incurred prior to December 31, 2019 and December 31, 2020 for Plant Vogtle Units 3 and 4, respectively; and (iv) (a) the in-service capital cost forecast will be adjusted to $5.680 billion (Revised Forecast), which includes a contingency of $240 million above Georgia Power's then current forecast of $5.440 billion, (b) capital costs incurred up to the Revised Forecast will be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, and (c) Georgia Power would have the burden to show that any capital costs above the Revised Forecast are reasonable and prudent. Under the terms of the Vogtle Cost Settlement Agreement, the certified in-service capital cost for purposes of calculating the NCCR tariff will remain at $4.418 billion. Construction capital costs above $4.418 billion will accrue AFUDC through the date each unit is placed in service. The ROE used to calculate the NCCR tariff was reduced from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016. For purposes of the AFUDC calculation, the ROE on costs between $4.418 billion and $5.440 billion will also be 10.00% and the ROE on any amounts above $5.440 billion would be Georgia Power's average cost of long-term debt. If the Georgia PSC adjusts GeorgiaContents
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Southern Power
Southern Power's ROEeffective tax benefit 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 usedwas (35.5)% 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 throughsix months ended June 30, 2017, requesting approval2019 compared to (1,386.5)% for the corresponding period in 2018. The effective tax benefit rate decrease was primarily due to reductions of $542 milliontax benefits from wind PTCs primarily as a result of construction capital costs incurred duringthe 2018 sale of the noncontrolling tax equity interest in SPC Wind and from changes in state apportionment rates following the reorganization of Southern Power's legal entities that own and operate certain solar facilities, partially offset by the net tax benefits from the sale of Plant Nacogdoches in 2019. See Note (K) and Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power" for additional information.
Southern Company Gas
Southern Company Gas' effective tax rate was 18.0% for the six months ended June 30, 2019 compared to 39.1% for the corresponding period within 2018. This decrease was primarily related to an increase in the flowback of excess deferred income taxes in 2019, primarily at Atlanta Gas Light as previously authorized by the Georgia PSC, on August 31, 2017.
Inand the seventeenth VCM report, Georgia Power recommended that constructionreversal of Plant Vogtle Units 3 and 4 be continued,a federal tax valuation allowance in connection with Southern Nuclear servingCompany Gas' sale of its investment in Triton in 2019, as project manager. Georgia Power believes thatwell as 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 parttax impacts of the proposed costSouthern Company Gas Dispositions in 2018. See Note (E) under "Southern Company Gas" and schedule revisions, Georgia Power may cancel Plant Vogtle Units 3Notes 2 and 4 and recover its actual investment15 to the financial statements under "Southern Company Gas" in Plant Vogtle Units 3 and 4; (ii) thatItem 8 of the Vogtle Cost Settlement Agreement remains in full force and effect, including Georgia Power retaining the burden of provingForm 10-K for additional information.
(H) RETIREMENT BENEFITS
The Southern Company system has a qualified defined benefit, trusteed, pension plan covering substantially 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 consistentemployees, with the Vogtle Cost Settlement Agreement, the Georgia PSC recognizes that the certified amountexception of employees at PowerSecure. The qualified pension plan 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 guarantorfunded in accordance with requirements of the Toshiba Guarantee,Employee Retirement Income Security Act of 1974, as amended (ERISA). No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2019. 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 failureSouthern 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 Toshibadiscontinued businesses.
See Note 11 to pay the Toshiba Guarantee, the failurefinancial statements in Item 8 of the U.S. Congress to extend the PTCsForm 10-K for Plant Vogtle Units 3 and 4, or the failureadditional information.
The ultimate outcome of these matters cannot be determined at this time.
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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Georgia Power's cancellationOn each registrant's condensed statements of income, the service cost estimate results indicate that its proportionate sharecomponent 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 other income (expense), net. Components of the estimatednet periodic benefit costs to cancel both units is approximately $350 million. As a result, as of Septemberfor the three and six months ended June 30, 2017, total estimated costs subject to evaluation by Georgia Power2019 and the Georgia PSC2018 are presented in the event of a cancellation decision are as follows:following tables.
|
| | | |
| | 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 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
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 |
|
| |
(*) | 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
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 and Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (E) under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
The IRS has allocated PTCs to Plant Vogtle Units 3 and 4 which require that the 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 |
| | | | | | | | | | | | | | | | | | | | | | | |
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 |
|
Table 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.Contents The ultimate outcome of these matters cannot be determined at this time.
Gulf Power
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information regarding Gulf Power's rates and charges for service to retail customers.
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 8 of the Form 10-K 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 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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Cost Recovery Clauses
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K for additional information regarding Gulf Power's recovery of retail costs through various regulatory clauses and accounting orders. Gulf Power has four regulatory clauses which are approved by the Florida PSC. The balance of each regulatory clause recovery on the balance sheet follows:
|
| | | | | | | | | | | | | | | | | | | | | | | |
Three Months Ended June 30, 2018 | Southern Company | | Alabama Power | | Georgia Power | | Mississippi Power | | Southern Power | | Southern Company Gas |
| | (in millions) |
| Pension Plans |
| Service cost | $ | 89 |
|
| $ | 20 |
|
| $ | 21 |
|
| $ | 4 |
|
| $ | 2 |
|
| $ | 8 |
|
| Interest cost | 116 |
|
| 25 |
|
| 35 |
|
| 5 |
|
| 2 |
|
| 9 |
|
| Expected return on plan assets | (235 | ) |
| (53 | ) |
| (74 | ) |
| (10 | ) |
| (2 | ) |
| (17 | ) |
| Amortization: | | | | | | | | | | | |
| Prior service costs | 1 |
|
| 1 |
|
| 1 |
|
| — |
|
| — |
|
| — |
|
| Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 4 |
|
| Net (gain)/loss | 54 |
|
| 13 |
|
| 17 |
|
| 2 |
|
| — |
|
| 3 |
|
| Net periodic pension cost (income) | $ | 25 |
|
| $ | 6 |
|
| $ | — |
|
| $ | 1 |
|
| $ | 2 |
|
| $ | 7 |
|
| Postretirement Benefits |
| Service cost | $ | 6 |
| | $ | 2 |
| | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | — |
|
| Interest cost | 18 |
| | 4 |
| | 7 |
| | 1 |
| | — |
| | 3 |
|
| Expected return on plan assets | (17 | ) | | (7 | ) | | (7 | ) | | (1 | ) | | — |
| | (2 | ) |
| Amortization: | | | | | | | | | | | |
| Prior service costs | 1 |
| | 1 |
| | 1 |
| | — |
| | — |
| | — |
|
| Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 2 |
|
| Net (gain)/loss | 4 |
| | 1 |
| | 2 |
| | — |
| | — |
| | — |
|
| Net periodic postretirement benefit cost | $ | 12 |
| | $ | 1 |
| | $ | 4 |
| | $ | 1 |
| | $ | — |
| | $ | 3 |
|
|
| | | | | | | |
| 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. The ultimate outcome of this matter cannot be determined at this time.
Energy Efficiency
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Energy Efficiency" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's energy efficiency programs.
On July 6, 2017, the Mississippi PSC issued an order approving Mississippi Power's Energy Efficiency Cost Rider compliance filing, which increased annual retail revenues by approximately $2 million effective with the first billing cycle for August 2017.
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 Units 1
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
and 2 scrubbers placed in service in 2015. The rates became effective with the first billing cycle for June 2017. Approximately $26 million |
| | | | | | | | | | | | | | | | | | | | | | | |
Six Months Ended June 30, 2018 | Southern Company | | Alabama Power | | Georgia Power | | Mississippi Power | | Southern Power | | Southern Company Gas |
| | (in millions) |
| Pension Plans |
| Service cost | $ | 179 |
| | $ | 39 |
| | $ | 43 |
| | $ | 8 |
| | $ | 4 |
| | $ | 16 |
|
| Interest cost | 232 |
| | 50 |
| | 70 |
| | 10 |
| | 3 |
| | 19 |
|
| Expected return on plan assets | (471 | ) | | (104 | ) | | (148 | ) | | (20 | ) | | (5 | ) | | (35 | ) |
| Amortization: | | | | | | | | | | | |
| Prior service costs | 2 |
| | 1 |
| | 1 |
| | — |
| | — |
| | (1 | ) |
| Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 7 |
|
| Net (gain)/loss | 107 |
| | 27 |
| | 34 |
| | 5 |
| | 1 |
| | 6 |
|
| Net periodic pension cost (income) | $ | 49 |
| | $ | 13 |
| | $ | — |
| | $ | 3 |
| | $ | 3 |
| | $ | 12 |
|
| Postretirement Benefits |
| Service cost | $ | 12 |
| | $ | 3 |
| | $ | 3 |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
|
| Interest cost | 37 |
| | 8 |
| | 14 |
| | 2 |
| | — |
| | 5 |
|
| Expected return on plan assets | (34 | ) | | (13 | ) | | (13 | ) | | (1 | ) | | — |
| | (4 | ) |
| Amortization: | | | | | | | | | | | |
| Prior service costs | 3 |
| | 2 |
| | 1 |
| | — |
| | — |
| | — |
|
| Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 3 |
|
| Net (gain)/loss | 7 |
| | 1 |
| | 4 |
| | — |
| | — |
| | — |
|
| Net periodic postretirement benefit cost | $ | 25 |
| | $ | 1 |
| | $ | 9 |
| | $ | 2 |
| | $ | — |
| | $ | 5 |
|
Fuel Cost Recovery
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's retail fuel cost recovery.
At September 30, 2017, the amount of over-recovered retail fuel costs included on Mississippi Power's condensed balance sheet was $2 million compared to $37 million at December 31, 2016.
Ad Valorem Tax Adjustment
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Ad Valorem Tax Adjustment" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's ad valorem tax adjustments.
On 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" in Item 8 of the Form 10-K for additional information.
Settled Base Rate Cases
On February 21, 2017, the Georgia PSC approved the Georgia Rate Adjustment Mechanism (GRAM) and a $20 million increase in annual base rate revenues for Atlanta Gas Light, effective March 1, 2017. GRAM adjusts base rates annually, up or down, based on the previously approved ROE of 10.75% and does not collect revenue through special riders and surcharges. Various infrastructure programs previously authorized by the Georgia PSC under Atlanta Gas Light's STRIDE program, which include the Integrated Vintage Plastic Replacement Program 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.
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
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.(I) FAIR VALUE MEASUREMENTS
Beginning with the next rate adjustment in June 2018, Atlanta Gas Light's recovery of the previously unrecovered Pipeline Replacement Program revenue through 2014, as well as the mitigation costs associated with the Pipeline Replacement Program that were not previously included in its rates, will also be included in GRAM. In connection with the GRAM approval, the last monthly Pipeline Replacement Program surcharge increase became effective March 1, 2017.
In September 2016, Elizabethtown Gas filed a general base rate case with the New Jersey BPU requesting a $19 million increase in annual base rate revenues. The requested increase was based on a projected 12-month test year ending March 31, 2017 and a ROE of 10.25%. On June 30, 2017, the New Jersey BPU approved a settlement that provides for a $13 million increase in annual base rate revenues, effective July 1, 2017, based on a ROE of 9.6%. Also included in the settlement was a new composite depreciation rate that is expected to result in a $3 million annual reduction of depreciation. 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 3 to the financial statements of Southern Company and Southern Company Gas under "Regulatory Matters – Southern Company Gas – Regulatory Infrastructure Programs" and "Regulatory Matters – Regulatory Infrastructure Programs," respectively, in Item 8 of the Form 10-K for additional information.
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 dateAs 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 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.
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; however, an adverse outcome in these proceedings could have a material impact on Southern Company's and Mississippi Power's results of operations, financial condition, and liquidity. Southern Company and Mississippi Power will vigorously defend themselves in these matters, and the ultimate outcome of these matters cannot be determined at this time.
Baseload Act
In 2008, the Baseload Act was signed by the Governor of Mississippi. The Baseload Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism that includes in retail base rates, prior to and during construction, all or a portion of the prudently-incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passage of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews by the Mississippi PSC and prohibits the cancellation of any such generating plant without the approval of the Mississippi PSC. In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery 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.
Section 174 Research and Experimental Deduction
Southern Company, on behalf of Mississippi Power, has reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation, resolving a methodology for these deductions. See Note (G) for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| |
(C) | FAIR VALUE MEASUREMENTS |
As of September 30, 2017,2019, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
| | | | Fair Value Measurements Using: | | | 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 | |
| As of June 30, 2019: | | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Net Asset Value as a Practical Expedient (NAV) | | Total |
| | (in millions) | (in millions) |
| Southern Company | | | | | | | | | | | | | | | | | | |
| Assets: | | | | | | | | | | | | | | | | | | |
Energy-related derivatives(a)(b) | $ | 231 |
| | $ | 184 |
| | $ | — |
| | $ | — |
| | $ | 415 |
| |
| Interest rate derivatives | — |
| | 5 |
| | — |
| | — |
| | 5 |
| |
Energy-related derivatives(a) | | $ | 270 |
| | $ | 177 |
| | $ | 12 |
| | $ | — |
| | $ | 459 |
|
| Foreign currency derivatives | — |
| | 103 |
| | — |
| | — |
| | 103 |
| — |
| | 60 |
| | — |
| | — |
| | 60 |
|
Nuclear decommissioning trusts(c) | 752 |
| | 1,004 |
| | — |
| | 26 |
| | 1,782 |
| |
Investments in trusts:(b)(c) | | | | | | | | | | |
| Domestic equity | | 703 |
| | 124 |
| | — |
| | — |
| | 827 |
|
| Foreign equity | | 62 |
| | 206 |
| | — |
| | — |
| | 268 |
|
| U.S. Treasury and government agency securities | | — |
| | 307 |
| | — |
| | — |
| | 307 |
|
| Municipal bonds | | — |
| | 72 |
| | — |
| | — |
| | 72 |
|
| Pooled funds – fixed income | | — |
| | 16 |
| | — |
| | — |
| | 16 |
|
| Corporate bonds | | 23 |
| | 299 |
| | — |
| | — |
| | 322 |
|
| Mortgage and asset backed securities | | — |
| | 74 |
| | — |
| | — |
| | 74 |
|
| Private equity | | — |
| | — |
| | — |
| | 54 |
| | 54 |
|
| Cash and cash equivalents | | 1 |
| | — |
| | — |
| | — |
| | 1 |
|
| Other | | 27 |
| | 2 |
| | — |
| | — |
| | 29 |
|
| Cash equivalents | 1,271 |
| | — |
| | — |
| | — |
| | 1,271 |
| 841 |
| | 5 |
| | — |
| | — |
| | 846 |
|
| Other investments | 9 |
| | — |
| | 1 |
| | — |
| | 10 |
| 9 |
| | 17 |
| | — |
| | — |
| | 26 |
|
| Total | $ | 2,263 |
| | $ | 1,296 |
| | $ | 1 |
| | $ | 26 |
| | $ | 3,586 |
| $ | 1,936 |
| | $ | 1,359 |
| | $ | 12 |
| | $ | 54 |
| | $ | 3,361 |
|
| Liabilities: | | | | | | | | | | | | | | | | | | |
Energy-related derivatives(a)(b) | $ | 265 |
| | $ | 146 |
| | $ | — |
| | $ | — |
| | $ | 411 |
| |
Energy-related derivatives(a) | | $ | 405 |
| | $ | 189 |
| | $ | 22 |
| | $ | — |
| | $ | 616 |
|
| Interest rate derivatives | — |
| | 24 |
| | — |
| | — |
| | 24 |
| — |
| | 52 |
| | — |
| | — |
| | 52 |
|
| Foreign currency derivatives | — |
| | 23 |
| | — |
| | — |
| | 23 |
| — |
| | 23 |
| | — |
| | — |
| | 23 |
|
| Contingent consideration | — |
| | — |
| | 20 |
| | — |
| | 20 |
| — |
| | — |
| | 21 |
| | — |
| | 21 |
|
| Total | $ | 265 |
| | $ | 193 |
| | $ | 20 |
| | $ | — |
| | $ | 478 |
| $ | 405 |
| | $ | 264 |
| | $ | 43 |
| | $ | — |
| | $ | 712 |
|
| | | | | | | | | | | | | | | | | | | |
| 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 |
| |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| | | | Fair Value Measurements Using: | | | 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 | |
| As of June 30, 2019: | | 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 | | $ | — |
| | $ | 6 |
| | $ | — |
| | $ | — |
| | $ | 6 |
|
Nuclear decommissioning trusts:(b) | | | | | | | | | |
|
|
| Domestic equity | | 456 |
| | 113 |
| | — |
| | — |
| | 569 |
|
| Foreign equity | | 62 |
| | 60 |
| | — |
| | — |
| | 122 |
|
| U.S. Treasury and government agency securities | | — |
| | 21 |
| | — |
| | — |
| | 21 |
|
| Municipal bonds | | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
| Corporate bonds | | 23 |
| | 141 |
| | — |
| | — |
| | 164 |
|
| Mortgage and asset backed securities | | — |
| | 25 |
| | — |
| | — |
| | 25 |
|
| Private equity | | — |
| | — |
| | — |
| | 54 |
| | 54 |
|
| Other | | 7 |
| | — |
| | — |
| | — |
| | 7 |
|
| Cash equivalents | | 430 |
| | 5 |
| | — |
| | — |
| | 435 |
|
| Other investments | | — |
| | 17 |
| | — |
| | — |
| | 17 |
|
| Total | | $ | 978 |
| | $ | 389 |
| | $ | — |
| | $ | 54 |
| | $ | 1,421 |
|
| Liabilities: | | | | | | | | | | |
| Energy-related derivatives | | $ | — |
| | $ | 18 |
| | $ | — |
| | $ | — |
| | $ | 18 |
|
| | (in millions) | | | | | | | | | |
| Georgia Power | | | | | | | | | | | | | | | | | | |
| Assets: | | | | | | | | | | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 18 |
| | $ | — |
| | $ | — |
| | $ | 18 |
| $ | — |
| | $ | 6 |
| | $ | — |
| | $ | — |
| | $ | 6 |
|
| Interest rate derivatives | — |
| | 1 |
| | — |
| | — |
| | 1 |
| |
Nuclear decommissioning trusts:(d) (e) | | | | | | | | | | |
Nuclear decommissioning trusts:(b)(c) | | | | | | | | | | |
| Domestic equity | 235 |
| | 1 |
| | — |
| | — |
| | 236 |
| 247 |
| | 1 |
| | — |
| | — |
| | 248 |
|
| Foreign equity | — |
| | 156 |
| | — |
| | — |
| | 156 |
| — |
| | 143 |
| | — |
| | — |
| | 143 |
|
| U.S. Treasury and government agency securities | — |
| | 225 |
| | — |
| | — |
| | 225 |
| — |
| | 286 |
| | — |
| | — |
| | 286 |
|
| Municipal bonds | — |
| | 64 |
| | — |
| | — |
| | 64 |
| — |
| | 71 |
| | — |
| | — |
| | 71 |
|
| Corporate bonds | — |
| | 160 |
| | — |
| | — |
| | 160 |
| — |
| | 158 |
| | — |
| | — |
| | 158 |
|
| Mortgage and asset backed securities | — |
| | 38 |
| | — |
| | — |
| | 38 |
| — |
| | 50 |
| | — |
| | — |
| | 50 |
|
| Other | 16 |
| | 19 |
| | — |
| | — |
| | 35 |
| 20 |
| | 2 |
| | — |
| | — |
| | 22 |
|
| Cash equivalents | 112 |
| | — |
| | — |
| | — |
| | 112 |
| |
| Total | $ | 363 |
| | $ | 682 |
| | $ | — |
| | $ | — |
| | $ | 1,045 |
| $ | 267 |
| | $ | 717 |
| | $ | — |
| | $ | — |
| | $ | 984 |
|
| Liabilities: | | | | | | | | | | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 11 |
| | $ | — |
| | $ | — |
| | $ | 11 |
| $ | — |
| | $ | 43 |
| | $ | — |
| | $ | — |
| | $ | 43 |
|
| Interest rate derivatives | — |
| | 3 |
| | — |
| | — |
| | 3 |
| — |
| | 37 |
| | — |
| | — |
| | 37 |
|
| Total | $ | — |
| | $ | 14 |
| | $ | — |
| | $ | — |
| | $ | 14 |
| $ | — |
| | $ | 80 |
| | $ | — |
| | $ | — |
| | $ | 80 |
|
| | | | | | | | | | | | | | | | | | | |
| 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: | | | 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 | |
| As of June 30, 2019: | | 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 | | $ | — |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 3 |
|
| Cash equivalents | | 170 |
| | — |
| | — |
| | — |
| | 170 |
|
| Total | | $ | 170 |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 173 |
|
| Liabilities: | | | | | | | | | | |
| Energy-related derivatives | | $ | — |
| | $ | 19 |
| | $ | — |
| | $ | — |
| | $ | 19 |
|
| | (in millions) | | | | | | | | | |
| Southern Power | | | | | | | | | | | | | | | | | | |
| Assets: | | | | | | | | | | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 9 |
| | $ | — |
| | $ | — |
| | $ | 9 |
| $ | — |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 2 |
|
| Foreign currency derivatives | — |
| | 103 |
| | — |
| | — |
| | 103 |
| — |
| | 60 |
| | — |
| | — |
|
| 60 |
|
| Cash equivalents | 90 |
| | — |
| | — |
| | — |
| | 90 |
| 177 |
| | — |
| | — |
| | — |
| | 177 |
|
| Total | $ | 90 |
| | $ | 112 |
| | $ | — |
| | $ | — |
| | $ | 202 |
| $ | 177 |
| | $ | 62 |
| | $ | — |
| | $ | — |
| | $ | 239 |
|
| Liabilities: | | | | | | | | | | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | 4 |
| $ | — |
| | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | 4 |
|
| Foreign currency derivatives | — |
| | 23 |
| | — |
| | — |
| | 23 |
| — |
| | 23 |
| | — |
| | — |
| | 23 |
|
| Contingent consideration | — |
| | — |
| | 20 |
| | — |
| | 20 |
| — |
| | — |
| | 21 |
| | — |
| | 21 |
|
| Total | $ | — |
|
| $ | 27 |
|
| $ | 20 |
|
| $ | — |
|
| $ | 47 |
| $ | — |
|
| $ | 27 |
|
| $ | 21 |
|
| $ | — |
|
| $ | 48 |
|
| | | | | | | | | | | | | | | | | | | |
| Southern Company Gas | | | | | | | | | | | | | | | | | | |
| Assets: | | | | | | | | | | | | | | | | | | |
Energy-related derivatives(a)(b) | $ | 231 |
| | $ | 145 |
| | $ | — |
| | $ | — |
| | $ | 376 |
| |
Energy-related derivatives(a) | | $ | 270 |
| | $ | 160 |
| | $ | 12 |
| | $ | — |
| | $ | 442 |
|
| Non-qualified deferred compensation trusts: | | | | | | | | | | |
| Domestic equity | | — |
| | 10 |
| | — |
| | — |
| | 10 |
|
| Foreign equity | | — |
| | 4 |
| | — |
| | — |
| | 4 |
|
| Pooled funds – fixed income | | — |
| | 16 |
| | — |
| | — |
| | 16 |
|
| Cash equivalents | | 1 |
| | — |
| | — |
| | — |
| | 1 |
|
| Total | | $ | 271 |
|
| $ | 190 |
|
| $ | 12 |
|
| $ | — |
|
| $ | 473 |
|
| Liabilities: | | | | | | | | | | | | | | | | | | |
Energy-related derivatives(a)(b) | $ | 265 |
| | $ | 95 |
| | $ | — |
| | $ | — |
| | $ | 360 |
| |
Energy-related derivatives(a) | | $ | 405 |
| | $ | 105 |
| | $ | 22 |
| | $ | — |
| | $ | 532 |
|
| |
| (a) | Excludes $13 million associated with certain weatherEnergy-related derivatives accounted for based on intrinsic value rather than fair value.exclude cash collateral of $178 million. |
| |
| (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. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information. |
| |
(e)(c) | Includes the investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of SeptemberJune 30, 2017,2019, approximately $66$30 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. |
Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. The fair value of the funds, at Southern Company, including reinvested interest
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
and dividends and excluding the funds' expenses, increased (decreased) by $50 million and $168 million, respectively,the amounts shown in the table below for the three and ninesix months ended SeptemberJune 30, 2017,2019 and by $49 million and $116 million, respectively, for the three and nine months ended September 30, 2016. Alabama Power2018. The changes were 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 into the regulatory assets and liabilities related to its AROs.AROs for 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.Alabama Power, respectively.
|
| | | | | | | | | | | | |
| | Three Months Ended June 30, 2019 | Three Months Ended June 30, 2018 | Six Months Ended June 30, 2019 | Six Months Ended June 30, 2018 |
| | (in millions) |
| Southern Company | $ | 75 |
| $ | 14 |
| $ | 227 |
| $ | 4 |
|
| Alabama Power | 38 |
| 15 |
| 125 |
| 10 |
|
| Georgia Power | 37 |
| (1 | ) | 102 |
| (6 | ) |
Valuation MethodologiesDOE Loan Guarantee Borrowings
The energy-related derivatives primarily consistSee Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of exchange-tradedthe Form 10-K for additional information regarding Georgia Power's 2014 loan guarantee agreement.
Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 (Title XVII Loan Guarantee Program), Georgia Power and over-the-counter financial productsthe DOE entered into a loan guarantee agreement in 2014 and the Amended and Restated Loan Guarantee Agreement in March 2019. Under the Amended and Restated Loan Guarantee Agreement, the DOE has agreed to guarantee the obligations of Georgia Power under note purchase agreements among the DOE, Georgia Power, and the FFB and related promissory notes which provide for natural gas and physical power products, including, from timetwo multi-advance term loan facilities (FFB Credit Facilities). Under the FFB Credit Facilities, Georgia Power may make term loan borrowings through the FFB in an amount up 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 fromapproximately $5.130 billion, provided that total
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 usedaggregate borrowings under the FFB Credit Facilities may not exceed 70% of (i) Eligible Project Costs minus (ii) approximately $1.492 billion (reflecting the amounts received by market participants. The fair valueGeorgia Power under the Guarantee Settlement Agreement less the Customer Refunds).
In March 2019, Georgia Power made borrowings under the FFB Credit Facilities in an aggregate principal amount of $835 million at an interest rate derivatives reflectsof 3.213% through the net present valuefinal maturity date of expected payments and receiptsFebruary 20, 2044. At June 30, 2019, Georgia Power had a total of $3.46 billion of borrowings outstanding 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 receiptsFFB Credit Facilities.
All borrowings under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputsFFB Credit Facilities are full recourse 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 (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, AlabamaGeorgia Power, and Georgia Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.
Southern Power has contingent payment obligations related to certain acquisitions whereby Southern Power is obligated to reimburse the DOE for any payments the DOE is required to make generation-based payments to the sellerFFB under its guarantee. Georgia Power's reimbursement obligations to the DOE are full recourse and secured by a first priority lien on (i) Georgia Power's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. There are no restrictions on Georgia Power's ability to grant liens on other property.
In addition to the conditions described above, future advances are subject to satisfaction of customary conditions, as well as certification of compliance with the requirements of the Title XVII Loan Guarantee Program, including accuracy of project-related representations and warranties, delivery of updated project-related information, and 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.
Upon satisfaction of all conditions described above, advances may be requested on a quarterly basis through 2023. The final maturity date for each advance under the FFB Credit Facilities is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20, 2020. Borrowings under the FFB Credit Facilities will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375%.
Under the Amended and Restated 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 Facilities will terminate and Georgia Power will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facilities over a period ranging from 10of five years (with level principal amortization). Among other things, these mandatory prepayment events include (i) the termination of the Vogtle Services Agreement or rejection of the Vogtle Services Agreement in any Westinghouse bankruptcy if Georgia Power does not maintain access to 30 years, beginning atintellectual property rights under the commercial operation date. The obligation is categorized as Levelrelated intellectual property licenses; (ii) termination of the Bechtel Agreement, unless the Vogtle Owners enter into a replacement agreement; (iii) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC or by Georgia Power; (iv) failure of the holders of 90% of the ownership interests in Plant Vogtle Units 3 and 4 to vote to continue construction following certain schedule extensions; (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 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, and is evaluated periodically. The fair valueFFB Credit Facilities; or (vi) loss of contingent consideration reflects the net present value of expected paymentsor failure to receive necessary regulatory approvals. Under certain circumstances, insurance proceeds and any periodic change arisingproceeds from forecasted generation is expectedan event of taking must be applied to immediately prepay outstanding borrowings under the FFB Credit Facilities. In addition, if Georgia Power discontinues construction of Plant Vogtle Units 3 and 4, Georgia Power would be immaterial.
"Other investments" include investments that are not traded inobligated to immediately repay a portion of the open market. The fair valueoutstanding borrowings under the FFB Credit Facilities to the extent such outstanding borrowings exceed 70% of these investments has been determined based on market factors including comparable multiples andEligible Project Costs, net of the expectations regarding cash flows and business plan executions.
As of September 30, 2017,proceeds received by Georgia Power under the fair value measurements of private equity investments held inGuarantee Settlement Agreement less the nuclear decommissioning trust that are calculated at net asset value per share (or its equivalent) as a practical expedient, as well asCustomer Refunds. Georgia Power also may voluntarily prepay outstanding borrowings under 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 fundsFFB Credit Facilities. Under the FFB Credit Facilities, any prepayment (whether mandatory or optional) will be receivedmade with a make-whole premium or discount, as the underlying investments in the funds are liquidated. Liquidations are expected to occur at various times over the next 10 years.applicable.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
AsIn connection with any cancellation of September 30, 2017, other financial instrumentsPlant Vogtle Units 3 and 4, the DOE may elect to continue construction of Plant Vogtle Units 3 and 4. In such an event, the DOE will have the right to assume Georgia Power's rights and obligations under the principal agreements relating to Plant Vogtle Units 3 and 4 and to acquire all or a portion of Georgia Power's ownership interest in Plant Vogtle Units 3 and 4.
Financing Activities
The following table outlines the long-term debt financing activities for whichSouthern Company and its subsidiaries for the carrying amount did not equal fair value were as follows:first six months of 2019:
|
| | | | | | | |
| | 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 prices for the same or similar issues or on the current rates available to Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas.
|
| | | | | | | | | | | | | | | | | | | |
| Company | Senior Note Maturities, Redemptions, and Repurchases | | Revenue Bond Issuances and Reofferings of Purchased Bonds | | Revenue Bond
Maturities, Redemptions, and
Repurchases | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(a) |
| | (in millions) |
Southern Company(b) | $ | 2,100 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Alabama Power | 200 |
| | — |
| | — |
| | — |
| | — |
|
| Georgia Power | — |
| | 513 |
| | 223 |
| | 835 |
| | 3 |
|
| Mississippi Power | — |
| | 43 |
| | — |
| | — |
| | — |
|
| Other | — |
| | — |
| | 25 |
| | — |
| | 9 |
|
| Southern Company Consolidated | $ | 2,300 |
| | $ | 556 |
| | $ | 248 |
| | $ | 835 |
| | $ | 12 |
|
| |
(D)(a) | STOCKHOLDERS' EQUITYIncludes reductions in finance lease obligations resulting from cash payments under finance leases. |
| |
| (b) | Represents the Southern Company parent entity. |
Except as otherwise described herein, Southern Company and its subsidiaries used the proceeds of debt issuances for their redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including working capital. The subsidiaries also used the proceeds for their construction programs.
Southern Company
In January 2019, Southern Company repaid a $250 million short-term uncommitted bank credit arrangement and a $1.5 billion short-term floating rate bank loan.
Also in January 2019, through cash tender offers, Southern Company repurchased and retired approximately $522 million of the $1.0 billion aggregate principal amount outstanding of its 1.85% Senior Notes due July 1, 2019 (1.85% Notes), approximately $180 million of the $350 million aggregate principal amount outstanding of its Series 2014B 2.15% Senior Notes due September 1, 2019 (Series 2014B Notes), and approximately $504 million of the $750 million aggregate principal amount outstanding of its Series 2018A Floating Rate Notes due February 14, 2020 (Series 2018A Notes), for an aggregate purchase price, excluding accrued and unpaid interest, of approximately $1.2 billion. In addition, following the completion of the cash tender offers, in February 2019, Southern Company completed the redemption of all of the Series 2018A Notes, 1.85% Notes, and Series 2014B Notes remaining outstanding.
Georgia Power
In January 2019, Georgia Power redeemed approximately $13 million, $20 million, and $75 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 1992, Eighth Series 1994, and Second Series 1995, respectively.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
In March 2019, Georgia Power reoffered to the public the following pollution control revenue bonds that previously had been purchased and held by Georgia Power:
$173 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2009;
approximately $105 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2013; and
$65 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2008.
In April 2019, Georgia Power purchased and held the following pollution control revenue bonds. In May 2019, Georgia Power reoffered these pollution control revenue bonds to the public.
$55 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fourth Series 1994;
$30 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fourth Series 1995;
$20 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Ninth Series 1994; and
$10 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 1994.
In June 2019, Georgia Power reoffered to the public $55 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1994, which had been previously purchased and held by Georgia Power.
Also in June 2019, Georgia Power entered into two short-term floating rate bank loans in aggregate principal amounts of $125 million each, both of which bear interest based on one-month LIBOR.
Mississippi Power
In March 2019, Mississippi Power reoffered to the public $43 million of Mississippi Business Finance Corporation Pollution Control Revenue Refunding Bonds, Series 2002, which previously had been purchased and held by Mississippi Power.
Southern Power
In May 2019, Southern Power repaid at maturity a $100 million aggregate principal amount short-term bank loan.
Earnings per Share
For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under the stock option and performance sharestock-based compensation plans. See Note 812 to the financial statements of Southern Company in Item 8 of the Form 10-K for information on the stock option and performance sharestock-based compensation plans. The effect of both stock options and performance share award unitsstock-based compensation plans was determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:
|
| | | | | | | | |
| | Three Months Ended June 30, 2019 | Three Months Ended June 30, 2018 | Six Months Ended June 30, 2019 | Six Months Ended June 30, 2018 |
| | (in millions) |
| As reported shares | 1,044 |
| 1,014 |
| 1,041 |
| 1,012 |
|
| Effect of stock-based compensation | 8 |
| — |
| 8 |
| 5 |
|
| Diluted shares | 1,052 |
| 1,014 |
| 1,049 |
| 1,017 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | |
| | 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 unitsThere were no stock-based compensation awards that were not included in the diluted earnings per share calculation because they were anti-dilutive were immaterial for the three and ninesix months ended SeptemberJune 30, 20172019 and 2016.an immaterial amount of such awards was not included for the six months ended June 30, 2018. For the three months ended June 30, 2018, approximately 5.3 million shares of stock-based compensation awards were not included in the diluted earnings per share calculation because they were anti-dilutive.
(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 Carryforwards
Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) totaling $2.0 billion as of June 30, 2019 compared to $2.4 billion as of December 31, 2018.
The federal ITC and PTC carryforwards begin expiring in 2034 and 2032, respectively, but are expected to be fully utilized by 2023. The estimated tax credit utilization reflects the projected taxable gains on the various sale transactions describe in Note (K) and could be further delayed 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, 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 regarding 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 and 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 33.5% for the six months ended June 30, 2019 compared to an effective tax benefit rate of (3.2)% for the corresponding period in 2018. The effective tax rate increase was primarily due to the tax impact from the sale of Gulf Power in 2019 and the 2018 charge to earnings related to the construction of Plant Vogtle Units 3 and 4. See Note (K) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.
Georgia Power
Georgia Power's effective tax rate was 21.7% for the six months ended June 30, 2019 compared to a benefit rate of (53.5)% for the corresponding period in 2018. The effective tax rate increase was primarily due to the 2018 charge to earnings related to the construction of Plant Vogtle Units 3 and 4, partially offset by an increase in state ITCs. See Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.
Mississippi Power
Mississippi Power's effective tax rate was 14.0% for the six months ended June 30, 2019 compared to 18.7% for the corresponding period in 2018. The effective tax rate decrease was primarily due to an increase in the flowback of excess deferred income taxes as a result of a settlement agreement reached with wholesale customers under the MRA tariff. See Note (B) under "Mississippi Power" for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
ChangesSouthern Power
Southern Power's effective tax benefit rate was (35.5)% for the six months ended June 30, 2019 compared to (1,386.5)% for the corresponding period in Stockholders' Equity2018. The effective tax benefit rate decrease was primarily due to reductions of tax benefits from wind PTCs primarily as a result of the 2018 sale of the noncontrolling tax equity interest in SPC Wind and from changes in state apportionment rates following the reorganization of Southern Power's legal entities that own and operate certain solar facilities, partially offset by the net tax benefits from the sale of Plant Nacogdoches in 2019. See Note (K) and Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power" for additional information.
Southern Company Gas
Southern Company Gas' effective tax rate was 18.0% for the six months ended June 30, 2019 compared to 39.1% for the corresponding period in 2018. This decrease was primarily related to an increase in the 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, as well as the tax impacts of the Southern Company Gas Dispositions in 2018. See Note (E) under "Southern Company Gas" and 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). No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2019. 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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 other income (expense), net. Components of the net periodic benefit costs for the three and six months ended June 30, 2019 and 2018 are presented in the following table presents year-to-date changes in stockholders' equity of Southern Company:tables.
|
| | | | | | | | | | | | | | | | | |
| | 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 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
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)
|
| | | | | | | | | | | | | | | | | | | | | | | |
Three Months Ended June 30, 2018 | Southern Company | | Alabama Power | | Georgia Power | | Mississippi Power | | Southern Power | | Southern Company Gas |
| | (in millions) |
| Pension Plans |
| Service cost | $ | 89 |
|
| $ | 20 |
|
| $ | 21 |
|
| $ | 4 |
|
| $ | 2 |
|
| $ | 8 |
|
| Interest cost | 116 |
|
| 25 |
|
| 35 |
|
| 5 |
|
| 2 |
|
| 9 |
|
| Expected return on plan assets | (235 | ) |
| (53 | ) |
| (74 | ) |
| (10 | ) |
| (2 | ) |
| (17 | ) |
| Amortization: | | | | | | | | | | | |
| Prior service costs | 1 |
|
| 1 |
|
| 1 |
|
| — |
|
| — |
|
| — |
|
| Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 4 |
|
| Net (gain)/loss | 54 |
|
| 13 |
|
| 17 |
|
| 2 |
|
| — |
|
| 3 |
|
| Net periodic pension cost (income) | $ | 25 |
|
| $ | 6 |
|
| $ | — |
|
| $ | 1 |
|
| $ | 2 |
|
| $ | 7 |
|
| Postretirement Benefits |
| Service cost | $ | 6 |
| | $ | 2 |
| | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | — |
|
| Interest cost | 18 |
| | 4 |
| | 7 |
| | 1 |
| | — |
| | 3 |
|
| Expected return on plan assets | (17 | ) | | (7 | ) | | (7 | ) | | (1 | ) | | — |
| | (2 | ) |
| Amortization: | | | | | | | | | | | |
| Prior service costs | 1 |
| | 1 |
| | 1 |
| | — |
| | — |
| | — |
|
| Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 2 |
|
| Net (gain)/loss | 4 |
| | 1 |
| | 2 |
| | — |
| | — |
| | — |
|
| Net periodic postretirement benefit cost | $ | 12 |
| | $ | 1 |
| | $ | 4 |
| | $ | 1 |
| | $ | — |
| | $ | 3 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | | | | | |
Six Months Ended June 30, 2018 | Southern Company | | Alabama Power | | Georgia Power | | Mississippi Power | | Southern Power | | Southern Company Gas |
| | (in millions) |
| Pension Plans |
| Service cost | $ | 179 |
| | $ | 39 |
| | $ | 43 |
| | $ | 8 |
| | $ | 4 |
| | $ | 16 |
|
| Interest cost | 232 |
| | 50 |
| | 70 |
| | 10 |
| | 3 |
| | 19 |
|
| Expected return on plan assets | (471 | ) | | (104 | ) | | (148 | ) | | (20 | ) | | (5 | ) | | (35 | ) |
| Amortization: | | | | | | | | | | | |
| Prior service costs | 2 |
| | 1 |
| | 1 |
| | — |
| | — |
| | (1 | ) |
| Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 7 |
|
| Net (gain)/loss | 107 |
| | 27 |
| | 34 |
| | 5 |
| | 1 |
| | 6 |
|
| Net periodic pension cost (income) | $ | 49 |
| | $ | 13 |
| | $ | — |
| | $ | 3 |
| | $ | 3 |
| | $ | 12 |
|
| Postretirement Benefits |
| Service cost | $ | 12 |
| | $ | 3 |
| | $ | 3 |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
|
| Interest cost | 37 |
| | 8 |
| | 14 |
| | 2 |
| | — |
| | 5 |
|
| Expected return on plan assets | (34 | ) | | (13 | ) | | (13 | ) | | (1 | ) | | — |
| | (4 | ) |
| Amortization: | | | | | | | | | | | |
| Prior service costs | 3 |
| | 2 |
| | 1 |
| | — |
| | — |
| | — |
|
| Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 3 |
|
| Net (gain)/loss | 7 |
| | 1 |
| | 4 |
| | — |
| | — |
| | — |
|
| Net periodic postretirement benefit cost | $ | 25 |
| | $ | 1 |
| | $ | 9 |
| | $ | 2 |
| | $ | — |
| | $ | 5 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
(I) FAIR VALUE MEASUREMENTS
As of June 30, 2019, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
|
| | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using: | | |
| As of June 30, 2019: | 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) | $ | 270 |
| | $ | 177 |
| | $ | 12 |
| | $ | — |
| | $ | 459 |
|
| Foreign currency derivatives | — |
| | 60 |
| | — |
| | — |
| | 60 |
|
Investments in trusts:(b)(c) | | | | | | | | | |
| Domestic equity | 703 |
| | 124 |
| | — |
| | — |
| | 827 |
|
| Foreign equity | 62 |
| | 206 |
| | — |
| | — |
| | 268 |
|
| U.S. Treasury and government agency securities | — |
| | 307 |
| | — |
| | — |
| | 307 |
|
| Municipal bonds | — |
| | 72 |
| | — |
| | — |
| | 72 |
|
| Pooled funds – fixed income | — |
| | 16 |
| | — |
| | — |
| | 16 |
|
| Corporate bonds | 23 |
| | 299 |
| | — |
| | — |
| | 322 |
|
| Mortgage and asset backed securities | — |
| | 74 |
| | — |
| | — |
| | 74 |
|
| Private equity | — |
| | — |
| | — |
| | 54 |
| | 54 |
|
| Cash and cash equivalents | 1 |
| | — |
| | — |
| | — |
| | 1 |
|
| Other | 27 |
| | 2 |
| | — |
| | — |
| | 29 |
|
| Cash equivalents | 841 |
| | 5 |
| | — |
| | — |
| | 846 |
|
| Other investments | 9 |
| | 17 |
| | — |
| | — |
| | 26 |
|
| Total | $ | 1,936 |
| | $ | 1,359 |
| | $ | 12 |
| | $ | 54 |
| | $ | 3,361 |
|
| Liabilities: | | | | | | | | | |
Energy-related derivatives(a) | $ | 405 |
| | $ | 189 |
| | $ | 22 |
| | $ | — |
| | $ | 616 |
|
| Interest rate derivatives | — |
| | 52 |
| | — |
| | — |
| | 52 |
|
| Foreign currency derivatives | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
| Contingent consideration | — |
| | — |
| | 21 |
| | — |
| | 21 |
|
| Total | $ | 405 |
| | $ | 264 |
| | $ | 43 |
| | $ | — |
| | $ | 712 |
|
| | | | | | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using: | | |
| As of June 30, 2019: | 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 | $ | — |
| | $ | 6 |
| | $ | — |
| | $ | — |
| | $ | 6 |
|
Nuclear decommissioning trusts:(b) | | | | | | | | |
|
|
| Domestic equity | 456 |
| | 113 |
| | — |
| | — |
| | 569 |
|
| Foreign equity | 62 |
| | 60 |
| | — |
| | — |
| | 122 |
|
| U.S. Treasury and government agency securities | — |
| | 21 |
| | — |
| | — |
| | 21 |
|
| Municipal bonds | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
| Corporate bonds | 23 |
| | 141 |
| | — |
| | — |
| | 164 |
|
| Mortgage and asset backed securities | — |
| | 25 |
| | — |
| | — |
| | 25 |
|
| Private equity | — |
| | — |
| | — |
| | 54 |
| | 54 |
|
| Other | 7 |
| | — |
| | — |
| | — |
| | 7 |
|
| Cash equivalents | 430 |
| | 5 |
| | — |
| | — |
| | 435 |
|
| Other investments | — |
| | 17 |
| | — |
| | — |
| | 17 |
|
| Total | $ | 978 |
| | $ | 389 |
| | $ | — |
| | $ | 54 |
| | $ | 1,421 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 18 |
| | $ | — |
| | $ | — |
| | $ | 18 |
|
| | | | | | | | | | |
| Georgia Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 6 |
| | $ | — |
| | $ | — |
| | $ | 6 |
|
Nuclear decommissioning trusts:(b)(c) | | | | | | | | | |
| Domestic equity | 247 |
| | 1 |
| | — |
| | — |
| | 248 |
|
| Foreign equity | — |
| | 143 |
| | — |
| | — |
| | 143 |
|
| U.S. Treasury and government agency securities | — |
| | 286 |
| | — |
| | — |
| | 286 |
|
| Municipal bonds | — |
| | 71 |
| | — |
| | — |
| | 71 |
|
| Corporate bonds | — |
| | 158 |
| | — |
| | — |
| | 158 |
|
| Mortgage and asset backed securities | — |
| | 50 |
| | — |
| | — |
| | 50 |
|
| Other | 20 |
| | 2 |
| | — |
| | — |
| | 22 |
|
| Total | $ | 267 |
| | $ | 717 |
| | $ | — |
| | $ | — |
| | $ | 984 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 43 |
| | $ | — |
| | $ | — |
| | $ | 43 |
|
| Interest rate derivatives | — |
| | 37 |
| | — |
| | — |
| | 37 |
|
| Total | $ | — |
| | $ | 80 |
| | $ | — |
| | $ | — |
| | $ | 80 |
|
| | | | | | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using: | | |
| As of June 30, 2019: | 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 | $ | — |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 3 |
|
| Cash equivalents | 170 |
| | — |
| | — |
| | — |
| | 170 |
|
| Total | $ | 170 |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 173 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 19 |
| | $ | — |
| | $ | — |
| | $ | 19 |
|
| | | | | | | | | | |
| Southern Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 2 |
|
| Foreign currency derivatives | — |
| | 60 |
| | — |
| | — |
|
| 60 |
|
| Cash equivalents | 177 |
| | — |
| | — |
| | — |
| | 177 |
|
| Total | $ | 177 |
| | $ | 62 |
| | $ | — |
| | $ | — |
| | $ | 239 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | 4 |
|
| Foreign currency derivatives | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
| Contingent consideration | — |
| | — |
| | 21 |
| | — |
| | 21 |
|
| Total | $ | — |
|
| $ | 27 |
|
| $ | 21 |
|
| $ | — |
|
| $ | 48 |
|
| | | | | | | | | | |
| Southern Company Gas | | | | | | | | | |
| Assets: | | | | | | | | | |
Energy-related derivatives(a) | $ | 270 |
| | $ | 160 |
| | $ | 12 |
| | $ | — |
| | $ | 442 |
|
| Non-qualified deferred compensation trusts: | | | | | | | | | |
| Domestic equity | — |
| | 10 |
| | — |
| | — |
| | 10 |
|
| Foreign equity | — |
| | 4 |
| | — |
| | — |
| | 4 |
|
| Pooled funds – fixed income | — |
| | 16 |
| | — |
| | — |
| | 16 |
|
| Cash equivalents | 1 |
| | — |
| | — |
| | — |
| | 1 |
|
| Total | $ | 271 |
|
| $ | 190 |
|
| $ | 12 |
|
| $ | — |
|
| $ | 473 |
|
| Liabilities: | | | | | | | | | |
Energy-related derivatives(a) | $ | 405 |
| | $ | 105 |
| | $ | 22 |
| | $ | — |
| | $ | 532 |
|
| |
(*)(a) | RelatedEnergy-related derivatives exclude cash collateral of $178 million. |
| |
| (b) | Excludes receivables related to Southern Power Companyinvestment income, pending investment sales, payables related to pending investment purchases, 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.currencies. See Note 106 to the financial statements of Southern Power 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, 2019, approximately $30 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. |
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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Going Concern
As of September 30, 2017, Mississippi Power's current liabilities exceeded current assetsand dividends and excluding the funds' expenses, increased (decreased) by approximately $769 million primarily due to approximately $935 million that will be required through September 30, 2018 to fund maturities of long-term debt and $4 million that will be required to fund maturities of short-term debt. In addition, Mississippi Power has $40 million of tax-exempt variable rate demand obligations that are supported by short-term credit facilities and $50 million of fixed rate pollution control revenue bonds that are required to be remarketed over the next 12 months. Mississippi Power intends to utilize operating cash flows, lines of credit, and bank term loans, as market conditions permit, as well as, under certain circumstances, commercial paper and/or equity contributions and/or loans from Southern Company to fund Mississippi Power's short-term capital needs. Specifically, Mississippi Power has been informed by Southern Company thatamounts shown 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 fundtable below for the remaining indebtedness scheduled to maturethree and other cash needs over the next 12 months. Therefore, Mississippi Power's financial statement presentation contemplates continuation of Mississippi Powersix months ended June 30, 2019 and 2018. The changes were recorded 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 6change to the financial statements of Mississippiregulatory assets and liabilities related to AROs for Georgia Power under "Recently Issued Accounting Standards" and "Going Concern," respectively, in Item 8 of the Form 10-K and Note (B) under "Integrated Coal Gasification Combined Cycle."Alabama Power, respectively.
|
| | | | | | | | | | | | |
| | Three Months Ended June 30, 2019 | Three Months Ended June 30, 2018 | Six Months Ended June 30, 2019 | Six Months Ended June 30, 2018 |
| | (in millions) |
| Southern Company | $ | 75 |
| $ | 14 |
| $ | 227 |
| $ | 4 |
|
| Alabama Power | 38 |
| 15 |
| 125 |
| 10 |
|
| Georgia Power | 37 |
| (1 | ) | 102 |
| (6 | ) |
DOE Loan Guarantee Borrowings
See Note 68 to the financial statements of Southern Company and Georgia Powerunder "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for additional information regarding Georgia Power's 2014 loan guarantee agreement.
Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 (Title XVII Loan Guarantee Program), Georgia Power and the DOE entered into a loan guarantee agreement in 2014 and the Amended and Restated Loan Guarantee Agreement within March 2019. Under the Amended and Restated Loan Guarantee Agreement, the DOE has agreed to guarantee the obligations of Georgia Power under note purchase agreements among the DOE, Georgia Power, and the FFB and related promissory notes which provide for two multi-advance term loan facilityfacilities (FFB Credit Facility) withFacilities). Under the FFB.
On July 27, 2017,FFB Credit Facilities, Georgia Power entered intomay make term loan borrowings through the FFB in an amendmentamount up to approximately $5.130 billion, provided that total
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
aggregate borrowings under the FFB Credit Facilities may not exceed 70% of (i) Eligible Project Costs minus (ii) approximately $1.492 billion (reflecting the amounts received by Georgia Power under the Guarantee Settlement Agreement less the Customer Refunds).
In March 2019, Georgia Power made borrowings under the FFB Credit Facilities in an aggregate principal amount of $835 million at an interest rate of 3.213% through the final maturity date of February 20, 2044. At June 30, 2019, Georgia Power had a total of $3.46 billion of borrowings outstanding under the FFB Credit Facilities.
All borrowings under the FFB Credit Facilities are full recourse to Georgia Power, and Georgia Power is obligated to reimburse the DOE for any payments the DOE is required to make to the Loan Guarantee Agreement (LGA Amendment) in connection with the DOE's consent toFFB under its guarantee. Georgia Power's entry intoreimbursement obligations to the Services AgreementDOE are full recourse 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 intosecured by a first priority lien on (i) Georgia Power's 45.7% undivided ownership interest 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 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) deliveredGeorgia Power's rights and obligations under the principal contracts relating to the DOE an updated project schedule, construction budget, and other information, (iii) entered into one or more agreements with a construction contractor or contractors that will be primarily responsible for construction of Plant Vogtle Units 3 and 4 and such agreements have been approved by the DOE (together with the Services Agreement and the IP Licenses, the Replacement EPC Arrangements), and (iv) entered into a further amendment4. There are no restrictions on Georgia Power's ability 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 Facilitygrant liens on a quarterly basis through 2020. The final maturity date for each advance under the FFB Credit Facility is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20, 2020. Borrowings under the FFB Credit Facility will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375%.other property.
In addition to the conditions described above, future advances are subject to satisfaction of customary conditions, as well as certification of compliance with the requirements of the Title XVII Loan Guarantee Program, including accuracy of project-related representations and warranties, delivery of updated project-related information, absence of liens on Georgia Power's ownership interest in Plant Vogtle Units 3 and 4 other than permitted liens, evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act of 1931, as amended, and certification from the DOE's consulting engineer that proceeds of the advances are used to reimburse Eligible Project Costs.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Upon satisfaction of all conditions described above, advances may be requested on a quarterly basis through 2023. The final maturity date for each advance under the FFB Credit Facilities is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20, 2020. Borrowings under the FFB Credit Facilities will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375%.
Under the Amended and Restated 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 FacilityFacilities will terminate and Georgia Power will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit FacilityFacilities over a period of five years (with level principal amortization). Among other things, these mandatory prepayment events include (i) the termination of the Vogtle Services Agreement or rejection of the Vogtle Services Agreement in any Westinghouse bankruptcy if Georgia Power does not maintain access to intellectual property rights under the IP Licenses;related intellectual property licenses; (ii) a decision by Georgia Power not to continue constructiontermination of Plantthe Bechtel Agreement, unless the Vogtle Units 3 and 4; (iii) a failure by Georgia Power to complete the Cost Assessments orOwners enter into Replacement EPC Arrangements by December 31, 2017; (iv)a replacement agreement; (iii) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC or by Georgia Power if authorized byPower; (iv) failure of the Georgia PSC;holders of 90% of the ownership interests in Plant Vogtle Units 3 and 4 to vote to continue construction following certain schedule extensions; (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.Facilities; or (vi) loss of or failure to receive necessary regulatory approvals. 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.Facilities. In addition, under certain circumstancesif Georgia Power maydiscontinues construction of Plant Vogtle Units 3 and 4, Georgia Power would be requiredobligated to make additional prepayments in connection with its receiptimmediately repay a portion of paymentsthe outstanding borrowings under the FFB Credit Facilities to the extent such outstanding borrowings exceed 70% of Eligible Project Costs, net of the proceeds received by Georgia Power under the Guarantee Settlement Agreement or fromless the EPC Contractor under the Vogtle 3 and 4 Agreement.Customer Refunds. Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facility.Facilities. Under the FFB Credit Facility,Facilities, 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
See Note (B) under "Regulatory Matters – Georgia Power – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.
Bank Credit Arrangements
Bank credit arrangements provide liquidity support to the registrants' commercial paper borrowings and the traditional electric operating companies' pollution control revenue bonds. The amount of variable rate pollution control revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of September 30, 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" in Item 8 of the Form 10-K and "Financing Activities" herein for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
The following table outlinesIn connection with any cancellation of Plant Vogtle Units 3 and 4, the committed credit arrangements by company asDOE may elect to continue construction of September 30, 2017:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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.
|
As reflected inPlant Vogtle Units 3 and 4. In such an event, the table above, in May 2017, Southern Company, Alabama Power,DOE will have the right to assume Georgia Power,Power's rights and Southern Power Company each amended certain of their multi-year credit arrangements, which, among other things, extendedobligations under the maturity dates from 2020principal agreements relating to 2022. Southern CompanyPlant Vogtle Units 3 and Southern Power Company increased their borrowing ability under these arrangements to $2.0 billion from $1.25 billion4 and to $750 million from $600 million, respectively. Southern Company also terminated its $1.0 billion facility maturingacquire all or a portion of Georgia Power's ownership interest in 2018. Also in May 2017, Southern Company Gas CapitalPlant Vogtle Units 3 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 2020.4.
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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Financing Activities
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first ninesix months of 2017:2019:
| | | Company | Senior Note Issuances | | Senior Note Maturities and Redemptions | | Revenue Bond
Maturities, Redemptions, and
Repurchases | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(a) | Senior Note Maturities, Redemptions, and Repurchases | | Revenue Bond Issuances and Reofferings of Purchased Bonds | | Revenue Bond
Maturities, Redemptions, and
Repurchases | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(a) |
| | (in millions) | (in millions) |
Southern Company(b) | $ | 300 |
| | $ | 400 |
| | $ | — |
| | $ | 500 |
| | $ | 400 |
| $ | 2,100 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Alabama Power | 550 |
| | 200 |
| | 36 |
| | — |
| | — |
| 200 |
| | — |
| | — |
| | — |
| | — |
|
| Georgia Power | 1,350 |
| | 450 |
| | 65 |
| | 370 |
| | 13 |
| — |
| | 513 |
| | 223 |
| | 835 |
| | 3 |
|
| Gulf Power | 300 |
| | 85 |
| | — |
| | 6 |
| | — |
| |
| Mississippi Power | — |
| | — |
| | — |
| | 40 |
| | 893 |
| — |
| | 43 |
| | — |
| | — |
| | — |
|
| Southern Power | — |
| | — |
| | — |
| | 43 |
| | 4 |
| |
Southern Company Gas(c) | 450 |
| | — |
| | — |
| | 200 |
| | 22 |
| |
| Other | — |
| | — |
| | — |
| | — |
| | 12 |
| — |
| | — |
| | 25 |
| | — |
| | 9 |
|
Elimination(d) | — |
| | — |
| | — |
| | (40 | ) | | (599 | ) | |
| Southern Company Consolidated | $ | 2,950 |
| | $ | 1,135 |
| | $ | 101 |
| | $ | 1,119 |
| | $ | 745 |
| $ | 2,300 |
| | $ | 556 |
| | $ | 248 |
| | $ | 835 |
| | $ | 12 |
|
| |
| (a) | Includes reductions in capitalfinance lease obligations resulting from cash payments under capitalfinance 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. |
Southern Company
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 byExcept as otherwise described herein, Southern Company and its subsidiaries used the bank from time to timeproceeds of debt issuances for their redemptions and is payable on no less than 30 days' demand bymaturities shown in the bank. The proceeds were used for working capital and other general corporate purposes.
Alabama Power
In March 2017, Alabama Power issued $550 million aggregate principal amount of Series 2017A 2.45% Senior Notes due March 30, 2022. The proceeds were usedtable above, to repay Alabama Power's short-term indebtedness, and for general corporate purposes, including Alabama Power's continuousworking capital. The subsidiaries also used the proceeds for their construction program.programs.
Southern Company
In September 2017, Alabama Power issued 10January 2019, Southern Company repaid a $250 million shares ($250short-term uncommitted bank credit arrangement and a $1.5 billion short-term floating rate bank loan.
Also in January 2019, through cash tender offers, Southern Company repurchased and retired approximately $522 million of the $1.0 billion aggregate principal amount outstanding of its 1.85% Senior Notes due July 1, 2019 (1.85% Notes), approximately $180 million of the $350 million aggregate stated capital)principal amount outstanding of 5.00% Class A Preferred Stock, Cumulative, Par Value $1 Per Share (Stated Capital $25 Per Share). The proceeds were usedits Series 2014B 2.15% Senior Notes due September 1, 2019 (Series 2014B Notes), and approximately $504 million of the $750 million aggregate principal amount outstanding of its Series 2018A Floating Rate Notes due February 14, 2020 (Series 2018A Notes), for an aggregate purchase price, excluding accrued and unpaid interest, of approximately $1.2 billion. In addition, following the completion of the cash tender offers, in February 2019, Southern Company completed the redemption of all of the Series 2018A Notes, 1.85% Notes, and Series 2014B Notes remaining outstanding.
Georgia Power
In January 2019, Georgia Power redeemed approximately $13 million, $20 million, and $75 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 1992, Eighth Series 1994, and Second Series 1995, respectively.
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 2017,2019, Georgia Power issued $450reoffered to the public the following pollution control revenue bonds that previously had been purchased and held by Georgia Power:
$173 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2017A 2.00% Senior Notes due March 30, 2020 and $4002009;
approximately $105 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2017B 3.25% Senior Notes due March 30, 2027. The proceeds were used to repay a portion2013; and
$65 million aggregate principal amount of Georgia Power's short-term indebtedness and for general corporate purposes, including Georgia Power's continuous construction program.Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2008.
In April 2017,2019, Georgia Power purchased and held $27the following pollution control revenue bonds. In May 2019, Georgia Power reoffered these pollution control revenue bonds to the public.
$55 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fourth Series 1994;
$30 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fourth Series 1995;
$20 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Ninth Series 1994; and
$10 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 1994.
In June 2019, Georgia Power reoffered to the public $55 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1995. Subsequent to September 30, 2017,1994, which had been previously purchased and held by Georgia Power remarketed these bonds to the public.Power.
InAlso in June 2017,2019, Georgia Power entered into threetwo short-term floating rate bank loans in aggregate principal amounts of $50$125 million $150 million, and $100 million, with maturity dateseach, both 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
Mississippi 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, GeorgiaMarch 2019, Mississippi Power reoffered to the public $43 million of Mississippi Business Finance Corporation Pollution Control Revenue Refunding Bonds, Series 2002, which previously had been purchased and held by Mississippi Power.
Southern Power
In May 2019, Southern Power repaid $250 million of the $500at maturity a $100 million aggregate principal amount short-term bank loan.
Earnings per Share
For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding pursuantunder stock-based compensation plans. See Note 12 to its uncommitted bank credit arrangement. Alsothe financial statements in August 2017, Georgia Power amended its $100 million floating rate bank loan to extendItem 8 of the maturity date from June 28, 2018 to October 26, 2018.
Also in August 2017, Georgia Power issued $500 million aggregate principal amountForm 10-K for information on stock-based compensation plans. The effect of Series 2017C 2.00% Senior Notes due September 8, 2020. The proceeds werestock-based compensation plans was determined using the treasury stock method. Shares 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.compute diluted earnings per share were as follows:
Also in August 2017, Georgia Power purchased and held $38 million aggregate principal amount |
| | | | | | | | |
| | Three Months Ended June 30, 2019 | Three Months Ended June 30, 2018 | Six Months Ended June 30, 2019 | Six Months Ended June 30, 2018 |
| | (in millions) |
| As reported shares | 1,044 |
| 1,014 |
| 1,041 |
| 1,012 |
|
| Effect of stock-based compensation | 8 |
| — |
| 8 |
| 5 |
|
| Diluted shares | 1,052 |
| 1,014 |
| 1,049 |
| 1,017 |
|
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.
Gulf Power
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 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)
There were no stock-based compensation awards that were not included in the diluted earnings per share calculation because they were anti-dilutive for the three 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 borrowedsix months ended June 30, 2019 and 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 principalimmaterial 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 obligationssuch awards was not included for the quarter ending Septembersix months ended June 30, 2017 and subsequently repaid2018. For the promissory note upon receiptthree months ended June 30, 2018, approximately 5.3 million shares of its income tax refund fromstock-based compensation awards were not included in 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 proceedsdiluted earnings per share calculation because they were used to repay existing indebtedness and for other general corporate purposes.
Southern Company Gas
In May 2017, Southern Company Gas Capital issued $450 million aggregate principal amount of Series 2017A 4.40% Senior Notes due May 30, 2047. The proceeds were used to repay Southern Company Gas' 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.anti-dilutive.
Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees at Southern Company Gas, as discussed below, and PowerSecure. The Southern Company qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (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 for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions.
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.(G) INCOME TAXES
See Note 210 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$2.0 billion as of SeptemberJune 30, 20172019 compared to $1.8$2.4 billion as of December 31, 2016.2018.
The federal ITC and PTC carryforwards begin expiring in 2034 and 2032, respectively, but are expected to be fully utilized by 2022.2023. The PTC carryforwards begin expiring in 2036 but are expected to be utilized by 2022. The expected utilization ofestimated tax credit carryforwardsutilization reflects the projected taxable gains on the various sale transactions describe in Note (K) and could be further delayed by numerous factors. These factors, includeincluding the acquisition of additional renewable projects, increased generation at existing wind facilities, carrying back the federal net operating loss,purchase of rights to additional PTCs of Plant Vogtle Units 3 and potential tax reform legislation, as well as additional deductions4 pursuant to certain joint ownership agreements, and changes in taxable income projections. See Note (B) and Note 2 to 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, netfinancial statements in Item 8 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.Form 10-K under "Georgia Power – Nuclear Construction" for additional information regarding 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 and flowback of excess deferred income taxes at the regulated utilities, and federal income tax benefits from ITCs and PTCs.PTCs, primarily at Southern Power.
Southern Company's effective tax rate was 42.6%33.5% for the ninesix months ended SeptemberJune 30, 20172019 compared to 28.3%an effective tax benefit rate of (3.2)% for the corresponding period in 2016.2018. The effective tax rate increase was primarily due to the estimated probable losses ontax impact from the Kemper IGCC, netsale of Gulf Power in 2019 and the 2018 charge to earnings related to the construction of Plant Vogtle Units 3 and 4. See Note (K) and Note 2 to the financial statements in Item 8 of the non-deductible AFUDC equity portion. Other factors includeForm 10-K under "Georgia Power – Nuclear Construction" for additional information.
Georgia Power
Georgia Power's effective tax rate was 21.7% for the six months ended June 30, 2019 compared to a decreasebenefit rate of (53.5)% for the corresponding period in 2018. The effective tax benefits from solar ITCsrate increase was primarily due to the 2018 charge to earnings related to the construction of Plant Vogtle Units 3 and an increase in state valuation allowances,4, partially offset by an increase in tax benefits from wind PTCs.state ITCs. See Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.
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 annualMississippi Power
Mississippi Power's 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 was 14.0% for the six months ended June 30, 2019 compared to 18.7% for the corresponding period depending onin 2018. The effective tax rate decrease was primarily due to an increase in the amountflowback of pretax income.excess deferred income taxes as a result of a settlement agreement reached with wholesale customers under the MRA tariff. See Note (B) under "Mississippi Power" for additional information.
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 portion and the related state valuation allowances.
Southern Power
Southern Power's effective tax (benefit)benefit rate was (66.5)(35.5)% for the ninesix months ended SeptemberJune 30, 20172019 compared to (88.9)(1,386.5)% for the corresponding period in 2016.2018. The effective tax benefit rate increasedecrease was primarily due to a decrease inreductions of tax benefits from solar ITCs, partially offset by additional wind PTCs primarily as a result of the 2018 sale of the noncontrolling tax equity interest in SPC Wind 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 computed on a quarterly basis using an overall estimated annual effective income tax rate. Southern Power uses this method of recognition since the amount of PTCs can be significantly impacted by wind generation. This method can significantly affect the effective income tax rate for the period depending on the amount of pretax income.
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 following the reorganization of Southern Power's legal entities that own and operate certain solar facilities, partially offset by the net operating loss carryforward utilization. The ultimate outcometax benefits from the sale of this matter cannot be determined at this time.Plant Nacogdoches in 2019. See Note (K) and Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power" for additional information.
Southern Company Gas
Southern Company Gas' effective tax rate was 43.4%18.0% for the successor ninesix months ended SeptemberJune 30, 20172019 compared to 60.3%39.1% for the successorcorresponding period in 2018. This decrease was primarily related to an increase in the flowback of July 1, 2016 through September 30, 2016excess deferred income taxes in 2019, primarily at Atlanta Gas Light as previously authorized by the Georgia PSC, and 37.6% for the predecessor periodreversal of January 1, 2016 through June 30, 2016. The effectivea federal tax rate forvaluation allowance in connection with Southern Company Gas' sale of its investment in Triton in 2019, as well as the successor year-to-date 2017 was impacted by Statetax impacts 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 periodsDispositions 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
2018. See Note 5(E) under "Southern Company Gas" and Notes 2 and 15 to the financial statements of each registrant under "Unrecognized Tax Benefits""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 nine months ended September 30, 2017exception 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). No mandatory contributions to the qualified pension plan are anticipated for unrecognized taxthe year ending December 31, 2019. The Southern Company system also provides certain non-qualified defined benefits were as follows: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.
|
| | | | | | | | | | | |
| | 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 currentOn each registrant's condensed statements of income, the service cost component of net periodic benefit costs is included in other operations and prior periods primarily relate to state tax benefits, deductions for R&E expenditures,maintenance expenses and charitable contribution carryforwards that were impacted as a resultall other components of net periodic benefit costs are included in other income (expense), net. Components of the settlement of R&E expenditures associated withnet periodic benefit costs for the Kemper IGCC, as well as federal income tax benefits from deferred ITCs. See "Section 174 Researchthree and Experimental Deduction" herein for additional information. These amountssix months ended June 30, 2019 and 2018 are presented in the following tables.
|
| | | | | | | | | | | | | | | | | | | | | | | |
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)
|
| | | | | | | | | | | | | | | | | | | | | | | |
Three Months Ended June 30, 2018 | Southern Company | | Alabama Power | | Georgia Power | | Mississippi Power | | Southern Power | | Southern Company Gas |
| | (in millions) |
| Pension Plans |
| Service cost | $ | 89 |
|
| $ | 20 |
|
| $ | 21 |
|
| $ | 4 |
|
| $ | 2 |
|
| $ | 8 |
|
| Interest cost | 116 |
|
| 25 |
|
| 35 |
|
| 5 |
|
| 2 |
|
| 9 |
|
| Expected return on plan assets | (235 | ) |
| (53 | ) |
| (74 | ) |
| (10 | ) |
| (2 | ) |
| (17 | ) |
| Amortization: | | | | | | | | | | | |
| Prior service costs | 1 |
|
| 1 |
|
| 1 |
|
| — |
|
| — |
|
| — |
|
| Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 4 |
|
| Net (gain)/loss | 54 |
|
| 13 |
|
| 17 |
|
| 2 |
|
| — |
|
| 3 |
|
| Net periodic pension cost (income) | $ | 25 |
|
| $ | 6 |
|
| $ | — |
|
| $ | 1 |
|
| $ | 2 |
|
| $ | 7 |
|
| Postretirement Benefits |
| Service cost | $ | 6 |
| | $ | 2 |
| | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | — |
|
| Interest cost | 18 |
| | 4 |
| | 7 |
| | 1 |
| | — |
| | 3 |
|
| Expected return on plan assets | (17 | ) | | (7 | ) | | (7 | ) | | (1 | ) | | — |
| | (2 | ) |
| Amortization: | | | | | | | | | | | |
| Prior service costs | 1 |
| | 1 |
| | 1 |
| | — |
| | — |
| | — |
|
| Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 2 |
|
| Net (gain)/loss | 4 |
| | 1 |
| | 2 |
| | — |
| | — |
| | — |
|
| Net periodic postretirement benefit cost | $ | 12 |
| | $ | 1 |
| | $ | 4 |
| | $ | 1 |
| | $ | — |
| | $ | 3 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | | | | | |
Six Months Ended June 30, 2018 | Southern Company | | Alabama Power | | Georgia Power | | Mississippi Power | | Southern Power | | Southern Company Gas |
| | (in millions) |
| Pension Plans |
| Service cost | $ | 179 |
| | $ | 39 |
| | $ | 43 |
| | $ | 8 |
| | $ | 4 |
| | $ | 16 |
|
| Interest cost | 232 |
| | 50 |
| | 70 |
| | 10 |
| | 3 |
| | 19 |
|
| Expected return on plan assets | (471 | ) | | (104 | ) | | (148 | ) | | (20 | ) | | (5 | ) | | (35 | ) |
| Amortization: | | | | | | | | | | | |
| Prior service costs | 2 |
| | 1 |
| | 1 |
| | — |
| | — |
| | (1 | ) |
| Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 7 |
|
| Net (gain)/loss | 107 |
| | 27 |
| | 34 |
| | 5 |
| | 1 |
| | 6 |
|
| Net periodic pension cost (income) | $ | 49 |
| | $ | 13 |
| | $ | — |
| | $ | 3 |
| | $ | 3 |
| | $ | 12 |
|
| Postretirement Benefits |
| Service cost | $ | 12 |
| | $ | 3 |
| | $ | 3 |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
|
| Interest cost | 37 |
| | 8 |
| | 14 |
| | 2 |
| | — |
| | 5 |
|
| Expected return on plan assets | (34 | ) | | (13 | ) | | (13 | ) | | (1 | ) | | — |
| | (4 | ) |
| Amortization: | | | | | | | | | | | |
| Prior service costs | 3 |
| | 2 |
| | 1 |
| | — |
| | — |
| | — |
|
| Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 3 |
|
| Net (gain)/loss | 7 |
| | 1 |
| | 4 |
| | — |
| | — |
| | — |
|
| Net periodic postretirement benefit cost | $ | 25 |
| | $ | 1 |
| | $ | 9 |
| | $ | 2 |
| | $ | — |
| | $ | 5 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
(I) FAIR VALUE MEASUREMENTS
As of June 30, 2019, assets and liabilities measured at fair value on a grossrecurring basis without consideringduring the related federal or state income tax impact.
The impact onperiod, together with their associated level of the effective tax rate, if recognized, isfair value hierarchy, were 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 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using: | | |
| As of June 30, 2019: | 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) | $ | 270 |
| | $ | 177 |
| | $ | 12 |
| | $ | — |
| | $ | 459 |
|
| Foreign currency derivatives | — |
| | 60 |
| | — |
| | — |
| | 60 |
|
Investments in trusts:(b)(c) | | | | | | | | | |
| Domestic equity | 703 |
| | 124 |
| | — |
| | — |
| | 827 |
|
| Foreign equity | 62 |
| | 206 |
| | — |
| | — |
| | 268 |
|
| U.S. Treasury and government agency securities | — |
| | 307 |
| | — |
| | — |
| | 307 |
|
| Municipal bonds | — |
| | 72 |
| | — |
| | — |
| | 72 |
|
| Pooled funds – fixed income | — |
| | 16 |
| | — |
| | — |
| | 16 |
|
| Corporate bonds | 23 |
| | 299 |
| | — |
| | — |
| | 322 |
|
| Mortgage and asset backed securities | — |
| | 74 |
| | — |
| | — |
| | 74 |
|
| Private equity | — |
| | — |
| | — |
| | 54 |
| | 54 |
|
| Cash and cash equivalents | 1 |
| | — |
| | — |
| | — |
| | 1 |
|
| Other | 27 |
| | 2 |
| | — |
| | — |
| | 29 |
|
| Cash equivalents | 841 |
| | 5 |
| | — |
| | — |
| | 846 |
|
| Other investments | 9 |
| | 17 |
| | — |
| | — |
| | 26 |
|
| Total | $ | 1,936 |
| | $ | 1,359 |
| | $ | 12 |
| | $ | 54 |
| | $ | 3,361 |
|
| Liabilities: | | | | | | | | | |
Energy-related derivatives(a) | $ | 405 |
| | $ | 189 |
| | $ | 22 |
| | $ | — |
| | $ | 616 |
|
| Interest rate derivatives | — |
| | 52 |
| | — |
| | — |
| | 52 |
|
| Foreign currency derivatives | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
| Contingent consideration | — |
| | — |
| | 21 |
| | — |
| | 21 |
|
| Total | $ | 405 |
| | $ | 264 |
| | $ | 43 |
| | $ | — |
| | $ | 712 |
|
| | | | | | | | | | |
The tax positions impacting the effective tax rate primarily relate to state tax benefits and charitable contribution carryforwards that were impacted as a result
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using: | | |
| As of June 30, 2019: | 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 | $ | — |
| | $ | 6 |
| | $ | — |
| | $ | — |
| | $ | 6 |
|
Nuclear decommissioning trusts:(b) | | | | | | | | |
|
|
| Domestic equity | 456 |
| | 113 |
| | — |
| | — |
| | 569 |
|
| Foreign equity | 62 |
| | 60 |
| | — |
| | — |
| | 122 |
|
| U.S. Treasury and government agency securities | — |
| | 21 |
| | — |
| | — |
| | 21 |
|
| Municipal bonds | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
| Corporate bonds | 23 |
| | 141 |
| | — |
| | — |
| | 164 |
|
| Mortgage and asset backed securities | — |
| | 25 |
| | — |
| | — |
| | 25 |
|
| Private equity | — |
| | — |
| | — |
| | 54 |
| | 54 |
|
| Other | 7 |
| | — |
| | — |
| | — |
| | 7 |
|
| Cash equivalents | 430 |
| | 5 |
| | — |
| | — |
| | 435 |
|
| Other investments | — |
| | 17 |
| | — |
| | — |
| | 17 |
|
| Total | $ | 978 |
| | $ | 389 |
| | $ | — |
| | $ | 54 |
| | $ | 1,421 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 18 |
| | $ | — |
| | $ | — |
| | $ | 18 |
|
| | | | | | | | | | |
| Georgia Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 6 |
| | $ | — |
| | $ | — |
| | $ | 6 |
|
Nuclear decommissioning trusts:(b)(c) | | | | | | | | | |
| Domestic equity | 247 |
| | 1 |
| | — |
| | — |
| | 248 |
|
| Foreign equity | — |
| | 143 |
| | — |
| | — |
| | 143 |
|
| U.S. Treasury and government agency securities | — |
| | 286 |
| | — |
| | — |
| | 286 |
|
| Municipal bonds | — |
| | 71 |
| | — |
| | — |
| | 71 |
|
| Corporate bonds | — |
| | 158 |
| | — |
| | — |
| | 158 |
|
| Mortgage and asset backed securities | — |
| | 50 |
| | — |
| | — |
| | 50 |
|
| Other | 20 |
| | 2 |
| | — |
| | — |
| | 22 |
|
| Total | $ | 267 |
| | $ | 717 |
| | $ | — |
| | $ | — |
| | $ | 984 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 43 |
| | $ | — |
| | $ | — |
| | $ | 43 |
|
| Interest rate derivatives | — |
| | 37 |
| | — |
| | — |
| | 37 |
|
| Total | $ | — |
| | $ | 80 |
| | $ | — |
| | $ | — |
| | $ | 80 |
|
| | | | | | | | | | |
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.NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
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.(UNAUDITED)
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 DeductionSouthern 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.
|
| | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using: | | |
| As of June 30, 2019: | 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 | $ | — |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 3 |
|
| Cash equivalents | 170 |
| | — |
| | — |
| | — |
| | 170 |
|
| Total | $ | 170 |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 173 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 19 |
| | $ | — |
| | $ | — |
| | $ | 19 |
|
| | | | | | | | | | |
| Southern Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 2 |
|
| Foreign currency derivatives | — |
| | 60 |
| | — |
| | — |
|
| 60 |
|
| Cash equivalents | 177 |
| | — |
| | — |
| | — |
| | 177 |
|
| Total | $ | 177 |
| | $ | 62 |
| | $ | — |
| | $ | — |
| | $ | 239 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | 4 |
|
| Foreign currency derivatives | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
| Contingent consideration | — |
| | — |
| | 21 |
| | — |
| | 21 |
|
| Total | $ | — |
|
| $ | 27 |
|
| $ | 21 |
|
| $ | — |
|
| $ | 48 |
|
| | | | | | | | | | |
| Southern Company Gas | | | | | | | | | |
| Assets: | | | | | | | | | |
Energy-related derivatives(a) | $ | 270 |
| | $ | 160 |
| | $ | 12 |
| | $ | — |
| | $ | 442 |
|
| Non-qualified deferred compensation trusts: | | | | | | | | | |
| Domestic equity | — |
| | 10 |
| | — |
| | — |
| | 10 |
|
| Foreign equity | — |
| | 4 |
| | — |
| | — |
| | 4 |
|
| Pooled funds – fixed income | — |
| | 16 |
| | — |
| | — |
| | 16 |
|
| Cash equivalents | 1 |
| | — |
| | — |
| | — |
| | 1 |
|
| Total | $ | 271 |
|
| $ | 190 |
|
| $ | 12 |
|
| $ | — |
|
| $ | 473 |
|
| Liabilities: | | | | | | | | | |
Energy-related derivatives(a) | $ | 405 |
| | $ | 105 |
| | $ | 22 |
| | $ | — |
| | $ | 532 |
|
| |
(H)(a) | DERIVATIVESEnergy-related derivatives exclude cash collateral of $178 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, 2019, approximately $30 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. |
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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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, 2019 and 2018. The changes were recorded as a change to the regulatory assets and liabilities related to AROs for Georgia Power and Alabama Power, respectively.
|
| | | | | | | | | | | | |
| | Three Months Ended June 30, 2019 | Three Months Ended June 30, 2018 | Six Months Ended June 30, 2019 | Six Months Ended June 30, 2018 |
| | (in millions) |
| Southern Company | $ | 75 |
| $ | 14 |
| $ | 227 |
| $ | 4 |
|
| Alabama Power | 38 |
| 15 |
| 125 |
| 10 |
|
| Georgia Power | 37 |
| (1 | ) | 102 |
| (6 | ) |
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. 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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
As of June 30, 2019, 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 $54 million and unfunded commitments related to the private equity investments totaled $45 million. Private equity funds include funds-of-funds that invest 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.
As of June 30, 2019, 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 | $ | 42,596 |
| $ | 7,922 |
| $ | 10,969 |
| $ | 1,618 |
| $ | 5,011 |
| $ | 5,916 |
|
| Fair value | 45,394 |
| 8,717 |
| 11,749 |
| 1,657 |
| 5,261 |
| 6,420 |
|
| |
| (*) | The long-term debt of Southern Company Gas is recorded at amortized cost, including the 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 Southern Company, Alabama Power, Georgia Power, Mississippi Power, Southern Power, and Southern Company Gas.
Commodity Contracts with Level 3 Valuation Inputs
As of June 30, 2019, the fair value of Southern Company Gas' Level 3 physical natural gas forward contracts was $10 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.
|
| | | | | | |
| | Three Months Ended June 30, 2019 | Six Months Ended June 30, 2019 |
| | (in millions) |
| Beginning balance | $ | (19 | ) | $ | — |
|
| Transfers to Level 3 | (3 | ) | (33 | ) |
| Changes in fair value | 12 |
| 23 |
|
| Ending balance | $ | (10 | ) | $ | (10 | ) |
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.
The 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 $0.09
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
to $1.39 per mmBtu). Forward price increases (decreases) as of June 30, 2019 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
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)(I) for additional fair value information. In the statements of cash flows, theany cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. TheAny 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
Southern Company, theThe 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 isare 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-tradedNon-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 statementsoperating 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 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.
| |
| • | 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
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.
At SeptemberJune 30, 2017,2019, the net volume of energy-related derivative contracts for natural gas positions, for the Southern Company system, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows:
| | | | Net Purchased mmBtu | | Longest Hedge Date | | Longest Non-Hedge Date | Net Purchased mmBtu | | Longest Hedge Date | | Longest Non-Hedge Date |
| | (in millions) | | (in millions) | |
Southern Company(*) | 463 | | 2021 | | 2024 | 536 | | 2023 | | 2029 |
| Alabama Power | 66 | | 2020 | | — | 88 | | 2022 | | — |
| Georgia Power | 159 | | 2021 | | — | 200 | | 2022 | | — |
| Gulf Power | 28 | | 2020 | | — | |
| Mississippi Power | 44 | | 2021 | | — | 101 | | 2023 | | — |
| Southern Power | 13 | | 2018 | | — | 8 | | 2020 | | — |
Southern Company Gas(*) | 153 | | 2020 | | 2024 | 139 | | 2021 | | 2029 |
| |
| (*) | 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 3.34.0 billion mmBtu and short natural gas positions of 3.13.9 billion mmBtu as of SeptemberJune 30, 2017,2019, 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 natural gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 3425 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, andwhich includes 4 million mmBtu for Alabama Power, 8 million mmBtu for Georgia Power, 4 million mmBtu for Mississippi Power, and 9 million mmBtu for Southern Power.
For cash flow hedges of energy-related derivatives, the amountsestimated pre-tax gains (losses) expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending SeptemberJune 30, 20182020 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 isare recorded in OCI and isare reclassified into earnings at the
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
same time and presented on the same income statement line item as the earnings effect of the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings.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 providing an offset, with any difference representing ineffectiveness.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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
At SeptemberJune 30, 2017,2019, 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 | Notional Amount | | Interest Rate Received | Weighted Average Interest Rate Paid | Hedge Maturity Date | | Fair Value Gain (Loss) at June 30, 2019 |
| | (in millions) | | | | (in millions) | (in millions) | | | | (in millions) |
| Cash Flow Hedges of Existing Debt | | | |
| Mississippi Power | $ | 900 |
| | 1-month
LIBOR | 0.79% | March 2018 | | $ | 2 |
| |
| Cash Flow Hedges of Forecasted Debt | | Cash Flow Hedges of Forecasted Debt | | |
| Georgia Power | | $ | 250 |
| | 3-month LIBOR | 2.23% | March 2025 | | $ | (6 | ) |
| Georgia Power | | 250 |
| | 3-month LIBOR | 2.39% | September 2029 | | (10 | ) |
| Georgia Power | | 250 |
| | 3-month LIBOR | 2.40% | March 2030 | | (9 | ) |
| Georgia Power | | 250 |
| | 3-month LIBOR | 2.48% | February 2044 | | (12 | ) |
| Fair Value Hedges of Existing Debt | Fair Value Hedges of Existing Debt | | | Fair Value Hedges of Existing Debt | | |
Southern Company(*) | 300 |
| | 2.75% | 3-month
LIBOR + 0.92% | June 2020 | | — |
| 300 |
| | 2.75% | 3-month LIBOR+0.92% | June 2020 | | (1 | ) |
Southern Company(*) | 1,500 |
| | 2.35% | 1-month
LIBOR + 0.87% | July 2021 | | (19 | ) | 1,500 |
| | 2.35% | 1-month LIBOR+0.87% | July 2021 | | (14 | ) |
| Georgia Power | 250 |
| | 5.40% | 3-month
LIBOR + 4.02% | June 2018 | | — |
| 200 |
| | 4.25% | 3-month LIBOR+2.46% | December 2019 | | (1 | ) |
| 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 | ) | $ | 3,000 |
| | $ | (53 | ) |
| |
| (*) | 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 SeptemberJune 30, 20182020 are $(19)$(18) million for Southern Company and immaterial for all other registrants. Southern Company and certain subsidiaries have deferredDeferred gains and losses related to interest rate derivatives are expected to be amortized into earnings through 2046.2046 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 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 isare recorded in OCI and isare reclassified into earnings at the same time thatand on the same income statement line as the earnings effect of the hedged transactions, affect earnings, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Any ineffectiveness is recorded directly to earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
At SeptemberJune 30, 2017,2019, 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, 2019 |
| | (in millions) | | (in millions) | | | (in millions) |
| Cash Flow Hedges of Existing Debt | | | | | |
| Southern Power | $ | 677 |
| 2.95% | € | 600 |
| 1.00% | June 2022 | $ | 14 |
|
| Southern Power | 564 |
| 3.78% | 500 |
| 1.85% | June 2026 | 23 |
|
| Total | $ | 1,241 |
| | € | 1,100 |
| | | $ | 37 |
|
|
| | | | | | | | | | | | |
| 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 Southern Power's foreign currency derivatives that willexpected to be reclassified from accumulated OCI to earnings for the next 12-month period ending SeptemberJune 30, 20182020 are $(23) million for Southern Company and Southern Power.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 September 30, 2017 | As of December 31, 2016 | As of June 30, 2019 | As of December 31, 2018 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities | 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 |
| $ | 7 |
| $ | 57 |
| $ | 8 |
| $ | 23 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 13 |
| 23 |
| 25 |
| 33 |
| 9 |
| 34 |
| 9 |
| 26 |
|
| Assets held for sale, current/Liabilities held for sale, current | | — |
| — |
| — |
| 6 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 34 |
| $ | 48 |
| $ | 98 |
| $ | 60 |
| $ | 16 |
| $ | 91 |
| $ | 17 |
| $ | 55 |
|
| 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 |
| $ | 1 |
| $ | 7 |
| $ | 3 |
| $ | 7 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | | — |
| 1 |
| 1 |
| 2 |
|
| Interest rate derivatives: | | |
| Other current assets/Other current liabilities | 5 |
| 1 |
| 12 |
| 1 |
| — |
| 50 |
| — |
| 19 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 23 |
| 1 |
| 28 |
| — |
| 2 |
| — |
| 30 |
|
| Foreign currency derivatives: | | |
| Other current assets/Other current liabilities | — |
| 23 |
| — |
| 25 |
| — |
| 23 |
| — |
| 23 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 103 |
| — |
| — |
| 33 |
| 60 |
| — |
| 75 |
| — |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 116 |
| $ | 53 |
| $ | 36 |
| $ | 94 |
| $ | 61 |
| $ | 83 |
| $ | 79 |
| $ | 81 |
|
| Derivatives not designated as hedging instruments | | |
| Energy-related derivatives: | | |
| Other current assets/Other current liabilities | $ | 271 |
| $ | 254 |
| $ | 489 |
| $ | 483 |
| $ | 286 |
| $ | 298 |
| $ | 561 |
| $ | 575 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 115 |
| 103 |
| 66 |
| 81 |
| 156 |
| 219 |
| 180 |
| 325 |
|
| Interest rate derivatives: | | |
| Other current assets/Other current liabilities | — |
| — |
| 1 |
| — |
| |
| Total derivatives not designated as hedging instruments | $ | 386 |
| $ | 357 |
| $ | 556 |
| $ | 564 |
| $ | 442 |
| $ | 517 |
| $ | 741 |
| $ | 900 |
|
| Gross amounts recognized | $ | 536 |
| $ | 458 |
| $ | 690 |
| $ | 718 |
| $ | 519 |
| $ | 691 |
| $ | 837 |
| $ | 1,036 |
|
Gross amounts offset(*) | $ | (275 | ) | $ | (351 | ) | $ | (462 | ) | $ | (524 | ) | |
Gross amounts offset(a) | | $ | (328 | ) | $ | (506 | ) | $ | (524 | ) | $ | (801 | ) |
Net amounts recognized in the Balance Sheets | $ | 261 |
| $ | 107 |
| $ | 228 |
| $ | 194 |
| $ | 191 |
| $ | 185 |
| $ | 313 |
| $ | 235 |
|
| | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| | | | As of September 30, 2017 | As of December 31, 2016 | As of June 30, 2019 | As of December 31, 2018 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities | 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 |
| $ | 4 |
| $ | 11 |
| $ | 3 |
| $ | 4 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 3 |
| 3 |
| 7 |
| 4 |
| 2 |
| 7 |
| 3 |
| 6 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 9 |
| $ | 7 |
| $ | 20 |
| $ | 9 |
| $ | 6 |
| $ | 18 |
| $ | 6 |
| $ | 10 |
|
| Gross amounts recognized | $ | 9 |
| $ | 7 |
| $ | 20 |
| $ | 9 |
| $ | 6 |
| $ | 18 |
| $ | 6 |
| $ | 10 |
|
| Gross amounts offset | $ | (5 | ) | $ | (5 | ) | $ | (8 | ) | $ | (8 | ) | $ | (3 | ) | $ | (3 | ) | $ | (4 | ) | $ | (4 | ) |
| Net amounts recognized in the Balance Sheets | $ | 4 |
| $ | 2 |
| $ | 12 |
| $ | 1 |
| $ | 3 |
| $ | 15 |
| $ | 2 |
| $ | 6 |
|
| | | |
| Georgia Power | | |
| Derivatives designated as hedging instruments for regulatory purposes | | |
| Energy-related derivatives: | | |
| Other current assets/Other current liabilities | $ | 10 |
| $ | 3 |
| $ | 30 |
| $ | 1 |
| $ | 1 |
| $ | 26 |
| $ | 2 |
| $ | 8 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 8 |
| 8 |
| 14 |
| 7 |
| 5 |
| 17 |
| 4 |
| 13 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 18 |
| $ | 11 |
| $ | 44 |
| $ | 8 |
| $ | 6 |
| $ | 43 |
| $ | 6 |
| $ | 21 |
|
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | |
| Interest rate derivatives: | | |
| Other current assets/Other current liabilities | $ | 1 |
| $ | 1 |
| $ | 2 |
| $ | — |
| $ | — |
| $ | 37 |
| $ | — |
| $ | 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 |
| $ | — |
| $ | 37 |
| $ | — |
| $ | 2 |
|
| Gross amounts recognized | $ | 19 |
| $ | 14 |
| $ | 46 |
| $ | 11 |
| $ | 6 |
| $ | 80 |
| $ | 6 |
| $ | 23 |
|
| Gross amounts offset | $ | (10 | ) | $ | (10 | ) | $ | (8 | ) | $ | (8 | ) | $ | (6 | ) | $ | (6 | ) | $ | (6 | ) | $ | (6 | ) |
| Net amounts recognized in the Balance Sheets | $ | 9 |
| $ | 4 |
| $ | 38 |
| $ | 3 |
| $ | — |
| $ | 74 |
| $ | — |
| $ | 17 |
|
| | | |
| 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 | As of June 30, 2019 | As of December 31, 2018 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities | 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 |
| $ | 1 |
| $ | 10 |
| $ | 1 |
| $ | 3 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 2 |
| 3 |
| 2 |
| 5 |
| 2 |
| 9 |
| 2 |
| 6 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 3 |
| $ | 7 |
| $ | 4 |
| $ | 11 |
| $ | 3 |
| $ | 19 |
| $ | 3 |
| $ | 9 |
|
| 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 |
| $ | 3 |
| $ | 19 |
| $ | 3 |
| $ | 9 |
|
| Gross amounts offset | $ | (3 | ) | $ | (3 | ) | $ | (3 | ) | $ | (3 | ) | $ | (3 | ) | $ | (3 | ) | $ | (2 | ) | $ | (2 | ) |
| Net amounts recognized in the Balance Sheets | $ | 2 |
| $ | 4 |
| $ | 4 |
| $ | 8 |
| $ | — |
| $ | 16 |
| $ | 1 |
| $ | 7 |
|
| | | |
| 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 |
| $ | 1 |
| $ | 3 |
| $ | 3 |
| $ | 6 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | | — |
| 1 |
| 1 |
| 2 |
|
| Foreign currency derivatives: | | |
| Other current assets/Other current liabilities | — |
| 23 |
| — |
| 25 |
| — |
| 23 |
| — |
| 23 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 103 |
| — |
| — |
| 33 |
| 60 |
| — |
| 75 |
| — |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 111 |
| $ | 27 |
| $ | 18 |
| $ | 62 |
| $ | 61 |
| $ | 27 |
| $ | 79 |
| $ | 31 |
|
| Derivatives not designated as hedging instruments | | |
| Energy-related derivatives: | | |
| Other current assets/Other current liabilities | $ | 1 |
| $ | — |
| $ | 3 |
| $ | 1 |
| $ | 1 |
| $ | — |
| $ | — |
| $ | — |
|
| Interest rate derivatives: | | |
| Other current assets/Other current liabilities | — |
| — |
| 1 |
| — |
| |
| Total derivatives not designated as hedging instruments | $ | 1 |
| $ | — |
| $ | 4 |
| $ | 1 |
| $ | 1 |
| $ | — |
| $ | — |
| $ | — |
|
| Gross amounts recognized | $ | 112 |
| $ | 27 |
| $ | 22 |
| $ | 63 |
| $ | 62 |
| $ | 27 |
| $ | 79 |
| $ | 31 |
|
| Gross amounts offset | $ | (1 | ) | $ | (1 | ) | $ | (5 | ) | $ | (5 | ) | $ | (1 | ) | $ | (1 | ) | $ | (3 | ) | $ | (3 | ) |
| Net amounts recognized in the Balance Sheets | $ | 111 |
| $ | 26 |
| $ | 17 |
| $ | 58 |
| $ | 61 |
| $ | 26 |
| $ | 76 |
| $ | 28 |
|
| | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| | | | As of September 30, 2017 | As of December 31, 2016 | As of June 30, 2019 | As of December 31, 2018 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities | 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 |
| $ | 1 |
| $ | 10 |
| $ | 2 |
| $ | 8 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| — |
| 1 |
| — |
| — |
| 1 |
| — |
| 1 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 4 |
| $ | 1 |
| $ | 25 |
| $ | 3 |
| $ | 1 |
| $ | 11 |
| $ | 2 |
| $ | 9 |
|
| 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 |
| $ | — |
| $ | 4 |
| $ | — |
| $ | 1 |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | | $ | — |
| $ | 4 |
| $ | — |
| $ | 1 |
|
| Derivatives not designated as hedging instruments | | |
| Energy-related derivatives: | | |
| Assets from risk management activities/Liabilities from risk management activities-current | $ | 270 |
| $ | 254 |
| $ | 486 |
| $ | 482 |
| $ | 285 |
| $ | 298 |
| $ | 559 |
| $ | 574 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 115 |
| 103 |
| 66 |
| 81 |
| 156 |
| 219 |
| 180 |
| 325 |
|
| Total derivatives not designated as hedging instruments | $ | 385 |
| $ | 357 |
| $ | 552 |
| $ | 563 |
| $ | 441 |
| $ | 517 |
| $ | 739 |
| $ | 899 |
|
| Gross amounts of recognized | $ | 389 |
| $ | 360 |
| $ | 581 |
| $ | 569 |
| $ | 442 |
| $ | 532 |
| $ | 741 |
| $ | 909 |
|
Gross amounts offset(*) | $ | (251 | ) | $ | (327 | ) | $ | (435 | ) | $ | (497 | ) | |
Gross amounts offset(a) | | $ | (315 | ) | $ | (493 | ) | $ | (508 | ) | $ | (785 | ) |
Net amounts recognized in the Balance Sheets | $ | 138 |
| $ | 33 |
| $ | 146 |
| $ | 72 |
| $ | 127 |
| $ | 39 |
| $ | 233 |
| $ | 124 |
|
| |
(*)(a) | Gross amounts offset include cash collateral held on deposit in broker margin accounts of $76$178 million and $62$277 million as of SeptemberJune 30, 20172019 and December 31, 2016,2018, respectively. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| |
| (b) | Net amounts of derivative instruments outstanding exclude premium and intrinsic value associated with weather derivatives of $8 million as of December 31, 2018. |
At SeptemberJune 30, 20172019 and December 31, 2016,2018, 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 June 30, 2019 |
Derivative Category and Balance Sheet Location | Southern Company(*) | Alabama Power | Georgia Power | Mississippi Power | Southern Company Gas(*) |
| | (in millions) |
| Energy-related derivatives: | | | | | |
| Other regulatory assets, current | $ | (48 | ) | $ | (11 | ) | $ | (25 | ) | $ | (10 | ) | $ | (2 | ) |
| Other regulatory assets, deferred | (23 | ) | (5 | ) | (12 | ) | (6 | ) | — |
|
| Other regulatory liabilities, current | 6 |
| 3 |
| — |
| — |
| 3 |
|
| Total energy-related derivative gains (losses) | $ | (65 | ) | $ | (13 | ) | $ | (37 | ) | $ | (16 | ) | $ | 1 |
|
|
| | | | | | | | | | | | | | | | | | |
| 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$12 million at SeptemberJune 30, 2017.2019. |
|
| | | | | | | | | | | | | | | | | | |
| 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)
|
| | | | | | | | | | | | | | | |
| Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2018 |
Derivative Category and Balance Sheet Location | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Company Gas |
| | (in millions) |
| Energy-related derivatives: | | | | | |
| Other regulatory assets, current | $ | (19 | ) | $ | (3 | ) | $ | (6 | ) | $ | (2 | ) | $ | (8 | ) |
| Other regulatory assets, deferred | (16 | ) | (3 | ) | (9 | ) | (4 | ) | — |
|
| Assets held for sale, current | (6 | ) | — |
| — |
| — |
| — |
|
| Other regulatory liabilities, current | 1 |
| — |
| — |
| — |
| 1 |
|
| Total energy-related derivative gains (losses) | $ | (40 | ) | $ | (6 | ) | $ | (15 | ) | $ | (6 | ) | $ | (7 | ) |
For the three and six months ended SeptemberJune 30, 20172019 and 2016,2018, 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, |
| 2019 | 2018 | 2019 | 2018 |
| | (in millions) | (in millions) |
| Southern Company | | | | |
| Energy-related derivatives | $ | (6 | ) | $ | — |
| $ | (6 | ) | $ | 12 |
|
| Interest rate derivatives | (37 | ) | — |
| (37 | ) | (2 | ) |
| Foreign currency derivatives | (1 | ) | (73 | ) | (39 | ) | (21 | ) |
| Total | $ | (44 | ) | $ | (73 | ) | $ | (82 | ) | $ | (11 | ) |
| Georgia Power | | | | |
| Interest rate derivatives | $ | (37 | ) | $ | — |
| $ | (37 | ) | $ | — |
|
| Total | $ | (37 | ) | $ | — |
| $ | (37 | ) | $ | — |
|
| Southern Power | | | | |
| Energy-related derivatives | $ | (2 | ) | $ | (1 | ) | $ | (2 | ) | $ | 10 |
|
| Foreign currency derivatives | (1 | ) | (73 | ) | (39 | ) | (21 | ) |
| Total | $ | (3 | ) | $ | (74 | ) | $ | (41 | ) | $ | (11 | ) |
For the three and six months ended June 30, 2019 and 2018, the pre-tax effects of energy-related derivatives and interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instruments on accumulated OCI were as follows:immaterial for the other registrants.
|
| | | | | | | | | | | | | | | | |
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 ninethree and six months ended SeptemberJune 30, 20172019 and 2016,2018, the pre-tax effects of energy-related derivatives, interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instrumentsand fair value hedge accounting on income were as follows:
|
| | | | | | | | | | | | | | | | |
Derivatives in Cash Flow
Hedging Relationships | Gain (Loss)
Recognized in OCI
on Derivative
(Effective Portion) | | Gain (Loss) Reclassified from Accumulated OCI into
Income (Effective Portion) |
| | Statements of Income Location | Amount |
| | 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 | ) |
|
| | | | | | | | | | | | | |
| | 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, |
| |
| | 2019 | 2018 | 2019 | 2018 |
| | | (in millions) | (in millions) |
| | Southern Company | | | | |
| | Total depreciation and amortization | $ | 755 |
| $ | 783 |
| $ | 1,506 |
| $ | 1,552 |
|
| | Gain (loss) on energy-related cash flow hedges(a) | (1 | ) | 1 |
| (4 | ) | 2 |
|
| | Total interest expense, net of amounts capitalized | (429 | ) | (470 | ) | (859 | ) | (928 | ) |
| | Gain (loss) on interest rate cash flow hedges(a) | (5 | ) | (6 | ) | (9 | ) | (11 | ) |
| | Gain (loss) on foreign currency cash flow hedges(a) | (6 | ) | (7 | ) | (12 | ) | (12 | ) |
| | Gain (loss) on interest rate fair value hedges(b) | 19 |
| (7 | ) | 33 |
| (31 | ) |
| | Total other income (expense), net | 99 |
| 78 |
| 176 |
| 138 |
|
| | Gain (loss) on foreign currency cash flow hedges(a)(c) | 16 |
| (73 | ) | (8 | ) | (37 | ) |
| | Southern Power | | | | |
| | Total depreciation and amortization | $ | 119 |
| $ | 125 |
| $ | 237 |
| $ | 240 |
|
| | Gain (loss) on energy-related cash flow hedges(a) | (1 | ) | 1 |
| (4 | ) | 2 |
|
| | Total interest expense, net of amounts capitalized | (41 | ) | (46 | ) | (84 | ) | (93 | ) |
| | Gain (loss) on foreign currency cash flow hedges(a) | (6 | ) | (7 | ) | (12 | ) | (12 | ) |
| | Total other income (expense), net | 40 |
| 2 |
| 41 |
| 5 |
|
| | Gain (loss) on foreign currency cash flow hedges(a)(c) | 16 |
| (73 | ) | (8 | ) | (37 | ) |
| |
(*)(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 Southern Company Gas,the three and six months ended June 30, 2019 and 2018, the pre-tax effecteffects of energy relatedcash flow and fair value hedge accounting on income for energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earningswere immaterial for the successor nine months ended September 30, 2017, the successor periodtraditional electric operating companies and Southern Company Gas.
As of July 1, 2016 through September 30, 2016, and the predecessor period of January 1, 2016 through June 30, 20162019 and December 31, 2018, the following amounts were as follows: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, 2019 | As of December 31, 2018 |
| As of June 30, 2019 | As of December 31, 2018 |
| (in millions) | | (in millions) |
| Southern Company | | | | | |
| Securities due within one year | $ | (499 | ) | $ | (498 | ) | | $ | 1 |
| $ | 2 |
|
| Long-term debt | (2,087 | ) | (2,052 | ) | | 7 |
| 41 |
|
| | | | | | |
| Georgia Power | | | | | |
| Securities due within one year | $ | (499 | ) | $ | (498 | ) | | $ | 1 |
| $ | 2 |
|
|
| | | | | | | | |
| | 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 | ) |
For the three and ninesix months ended SeptemberJune 30, 20172019 and 2016,2018, 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 of Southern Company and Southern Company Gas were as follows:
| | | | | Gain (Loss) | | Gain (Loss) |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended June 30, | | Six Months Ended June 30, |
| Derivatives in Non-Designated Hedging Relationships | Statements of Income Location | 2017 | 2016 | | 2017 | 2016 | Statements of Income Location | 2019 | 2018 | | 2019 | 2018 |
| | | (in millions) | | (in millions) | | (in millions) | | (in millions) |
| Southern Company | | | | | | | | |
| Energy Related derivatives: | Natural gas revenues(*) | $ | (17 | ) | $ | — |
| | $ | 48 |
| $ | — |
| |
| Energy-related derivatives: | | Natural gas revenues(*) | $ | 50 |
| $ | (28 | ) | | $ | 83 |
| $ | (43 | ) |
| | Cost of natural gas | 2 |
| 6 |
| | (2 | ) | 6 |
| Cost of natural gas | (5 | ) | 2 |
| | 3 |
| 4 |
|
| Total derivatives in non-designated hedging relationships | Total derivatives in non-designated hedging relationships | $ | (15 | ) | $ | 6 |
| | $ | 46 |
| $ | 6 |
| Total derivatives in non-designated hedging relationships | $ | 45 |
| $ | (26 | ) | | $ | 86 |
| $ | (39 | ) |
| Southern Company Gas | | | | | |
| Energy-related derivatives: | | Natural gas revenues(*) | $ | 50 |
| $ | (28 | ) | | $ | 83 |
| $ | (43 | ) |
| | | Cost of natural gas | (5 | ) | 2 |
| | 3 |
| 4 |
|
| Total derivatives in non-designated hedging relationships | | Total derivatives in non-designated hedging relationships | $ | 45 |
| $ | (26 | ) | | $ | 86 |
| $ | (39 | ) |
| |
| (*) | Excludes immaterial gains (losses) recorded in cost of natural gas revenues 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 ninesix months ended SeptemberJune 30, 20172019 and 2016,2018, 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 do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At SeptemberJune 30, 2017,2019, the registrants had no collateral posted with derivative counterparties to satisfy these arrangements.
At SeptemberFor the registrants with interest rate derivatives at June 30, 2017,2019, the fair value of interest rate 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, was immaterial for all registrants. Theimmaterial. At June 30, 2019, 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 one or more 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.
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.
Alabama Power and Southern Power maintain accounts with certain regional transmission organizations to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Alabama Power and Southern Power may be required to post collateral. At SeptemberJune 30, 2017,2019, cash
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 SeptemberJune 30, 2017,2019, cash collateral held on deposit in broker margin accounts was $76$178 million.
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company GasThe registrants 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 GasThe 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. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company GasThe registrants 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'their exposure to counterparty credit risk. Prior to entering into a physical transaction, Southern Company Gas assigns physical wholesale counterparties an internal credit rating and credit limit based on the counterparties' Moody's, S&P, and Fitch Ratings Inc. 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 credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody's and BBB- from S&P. Generally, Southern Company Gas requires credit enhancements by way of a guaranty, cash deposit, or letter of credit for transaction counterparties that do not have investment grade ratings.
Southern Company Gas also utilizes master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When Southern Company Gas is engaged in more than one outstanding derivative transaction with the same counterparty and it also has a legally enforceable netting agreement with that counterparty, the "net" mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of Southern Company Gas' credit risk. Southern Company Gas also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Master netting agreements enable Southern Company Gas to net certain assets and liabilities by counterparty. Southern Company Gas also nets across product lines and against cash collateral provided the master netting and cash collateral agreements include such provisions. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company GasThe registrants do not anticipate a material adverse effect on thetheir respective financial statements as a result of counterparty nonperformance.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| |
(I) | (K) ACQUISITIONS AND DISPOSITIONS |
Southern Company
Merger with Southern Company Gas
Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through the natural gas distribution utilities. On July 1, 2016, Southern Company completed the Merger for a total purchase price of approximately $8.0 billion and Southern Company Gas became a wholly-owned, direct subsidiary of Southern Company.
The Merger was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value as of the acquisition date. The following table presents the 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 acquired and liabilities assumed of $6.0 billion is recognized as goodwill, which is primarily attributable to positioning the Southern Company system to provide natural gas infrastructure to meet customers' growing energy needs and to compete for growth across the energy value chain. Southern Company anticipates that much of the value assigned to goodwill will not be deductible for tax purposes.
The valuation of identifiable intangible assets included customer relationships, trade names, and storage and transportation contracts with estimated lives of one to 28 years. The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3).
The results of operations for Southern Company Gas have been included in Southern Company's consolidated financial statements from the date of acquisition and consist of operating revenues of $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 January 1, 2015. The summarized unaudited pro forma consolidated statement of earnings information includes adjustments for (i) intercompany sales, (ii) amortization of intangible assets, (iii) adjustments to interest expense to reflect current interest rates on Southern Company Gas debt and additional interest expense associated with borrowings by Southern Company to fund the Merger, and (iv) the elimination of nonrecurring expenses associated with the Merger.
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 215 to the financial statements of Southern Power and Note 12 to the financial statements of Southern Company under "Southern Power" in Item 8 of the Form 10-K for additional information.
Southern Company
On January 1, 2019, Southern Company completed the Nine Months Ended Septembersale of all of the capital stock of Gulf Power to 700 Universe, LLC, a wholly-owned subsidiary of NextEra Energy, for an aggregate cash purchase price of approximately $5.8 billion (less $1.3 billion of indebtedness assumed), subject to customary working capital adjustments. The preliminary gain associated with the sale of Gulf Power totaled $2.5 billion pre-tax ($1.3 billion after tax). The assets and liabilities of Gulf Power were classified as assets held for sale and liabilities held for sale on Southern Company's balance sheet as of December 31, 2018.
On July 22, 2019, PowerSecure completed the sale of its utility infrastructure services business unit for approximately $71 million, subject to customary working capital adjustments. The related assets and liabilities were classified as held for sale on Southern Company's balance sheet as of June 30, 20172019. In contemplation of this sale, a goodwill impairment charge of $32 million was recorded in the second quarter 2019.
See "Assets Held for Sale" herein for additional information.
Southern Power
Construction Projects
During the ninesix months ended SeptemberJune 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.
|
| | | | | | | | | |
| 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 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,2019, Southern Power completed construction of and placed in service orthe 385-MW Plant Mankato expansion and continued construction of thetwo other projects set forthas described in the following table. Through Septembertable below. Total aggregate construction costs, excluding acquisition costs, are expected to be between $405 million and $450 million for the Wildhorse Mountain and Reading facilities. At June 30, 2017,2019, 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$186 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.
|
| | | | | |
| Project Facility | Resource | Approximate Nameplate Capacity (MW) | Location | Actual/Expected COD | PPA Contract Period |
Projects Completed During the NineSix Months Ended SeptemberJune 30, 20172019 |
East PecosMankato expansion(a) | SolarNatural Gas | 120385 | Pecos County, TXMankato, MN | March 2017May 2019 | 1520 years |
Lamesa | Solar | 102 | Dawson County, TX | April 2017 | 15 years |
| | | | | |
Projects Under Construction as of SeptemberJune 30, 20172019 |
Cactus FlatsWildhorse Mountain(*)(b)
| Wind | 148100 | ConchoPushmataha County, TXOK | Third quarter 2018 | 12-15 years |
Mankato | Natural Gas | 345 | Mankato, MN | SecondFourth quarter 2019 | 20 years |
Reading(c) | Wind | 200 | Osage and Lyon Counties, KS | Second quarter 2020 | 12 years |
| |
(*)(a) | On July 31, 2017,In November 2018, Southern Power acquiredentered into an agreement to sell all of its equity interests in Plant Mankato, including this expansion that was completed during May 2019. This transaction is subject to state commission approvals and is expected to close in fall 2019. The expansion unit started providing energy under a PPA with Northern States Power on June 1, 2019. See "Sales of Natural Gas and Biomass Plants" below. |
| |
| (b) | In May 2018, Southern Power purchased 100% ownership interest of the Wildhorse Mountain facility. Southern Power entered into a tax equity partnership in June 2019 with funding of tax equity amounts expected to occur upon commercial operation. |
| |
| (c) | In August 2018, Southern Power purchased 100% of the Cactus Flatsmembership interests of the Reading facility from the joint development arrangement with Renewable Energy Systems Americas, Inc. Southern Power may enter into a tax equity partnership, in which is incase it would then own 100% of the early stages of construction, from RES America Developments, Inc.class B membership interests. |
Development Projects
Southern Power continues to evaluate and refine the deployment of wind turbine equipment purchased in 2016 and 2017 to potential joint development and construction projects as well as the amount of MW capacity to be
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 ofconstructed. During the facilities. All of thesix months ended June 30, 2019, certain wind turbine equipment was deliveredsold, resulting in a gain on the sale of approximately $14 million.
On June 14, 2019, Southern Power entered into an agreement with Bloom Energy to acquire a majority interest in its affiliate DSGP, which owns and operates fuel cell generation facilities in Delaware, for a total amount not to exceed $173 million. In June 2019, Southern Power, through an affiliate, contributed a total of $116 million in exchange for Class B membership interests in DSGP, with the remainder expected to be contributed by April 2017, which allows the projectsend of 2019. FERC approval of the transfer of the facilities is expected to qualify for 100% PTCs for 10 years following their expected commercial operation dates between 2018 and 2020. Theoccur in the third quarter 2019; however, the ultimate outcome of these mattersthis matter cannot be determined at this time.
Southern CompanySales of Natural Gas and Biomass Plants
On October 15, 2017,June 13, 2019, Southern Company Gas subsidiary, Pivotal Utility Holdings, entered into agreements forPower completed the sale of its equity interests in Nacogdoches Power, LLC, the assetsowner of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas,an approximately 115-MW biomass facility located in Nacogdoches County, Texas, to South Jersey Industries, Inc.Austin Energy, for a totalan aggregate cash purchase price of $1.7 billion.approximately $461 million, including working capital adjustments. This sale resulted in an $88 million after-tax gain.
On May 4, 2019, Southern Power achieved commercial operation of the 385-MW natural gas expansion unit at Plant Mankato and started providing energy under a PPA with Northern States Power on June 1, 2019. The completionsale of each sale isPlant Mankato to Northern States Power remains subject to Minnesota and North Dakota state commission approvals and is expected to close in fall 2019. If these state commission approvals are not obtained by October 1, 2019, either party has 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 respectoption to terminate the sale, which, if elected, would result in the payment of Elkton Gas, the Maryland PSC; and (iii) other customary closing conditions. The sales are expecteda $15 million termination fee by Northern States Power to be completed by the end of the third quarter 2018.
Southern Power. The ultimate outcome of these mattersthis matter cannot be determined at this time. The assets and liabilities of Plant Mankato are classified as assets held for sale and liabilities held for sale on Southern Company's and Southern Power's balance sheets as of June 30, 2019 and December 31, 2018. See "Assets Held for Sale" herein for additional information.
Assets Subject to Lien
Under the terms of the PPAs for Plant Mankato, approximately $545 million of assets, primarily related to property, plant, and equipment, are subject to lien at June 30, 2019.
| |
(J) | JOINT OWNERSHIP AGREEMENTS |
Assets Held for Sale
As discussed above, Southern Company Gasand Southern Power each have assets and liabilities held for sale on their balance sheets at June 30, 2019 and December 31, 2018. Assets and liabilities held for sale have been classified separately on each company's balance sheet at the lower of carrying value or fair value less costs to sell at the time the criteria for held-for-sale classification were met. For assets and liabilities held for sale recorded at fair value on a nonrecurring basis, the fair value of assets held for sale is based primarily on unobservable inputs (Level 3), which includes the agreed upon sales prices in executed sales agreements.
See Note 4Upon classification as held for sale in November 2018 and April 2019 for Plant Mankato and Plant Nacogdoches, respectively, Southern Power ceased recognizing depreciation and amortization on the long-lived assets to the financial statementsbe sold.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Equity Method Investments
The carrying amountsfollowing table provides Southern Company's and Southern Power's major classes of Southern Company Gas' equity method investmentsassets and liabilities classified as of Septemberheld for sale at June 30, 20172019 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:2018:
|
| | | | | | |
| | Southern Company | Southern Power |
| | (in millions) |
| At June 30, 2019 | | |
| Assets Held for Sale: | | |
| Current assets | $ | 58 |
| $ | 10 |
|
| Total property, plant, and equipment | 588 |
| 559 |
|
| Goodwill and other intangible assets | 51 |
| 40 |
|
| Other non-current assets | 46 |
| — |
|
| Total Assets Held for Sale | $ | 743 |
| $ | 609 |
|
| | | |
| Liabilities Held for Sale: | | |
| Current liabilities | $ | 36 |
| $ | 10 |
|
| Other non-current liabilities | 39 |
| — |
|
| Total Liabilities Held for Sale | $ | 75 |
| $ | 10 |
|
| | | |
| At December 31, 2018 | | |
| Assets Held for Sale: | | |
| Current assets | $ | 393 |
| $ | 8 |
|
| Total property, plant, and equipment | 4,583 |
| 536 |
|
| Other intangible assets | 40 |
| 40 |
|
| Other non-current assets | 727 |
| — |
|
| Total Assets Held for Sale | $ | 5,743 |
| $ | 584 |
|
| | | |
| Liabilities Held for Sale: | | |
| Current liabilities | $ | 425 |
| $ | 15 |
|
| Long-term debt | 1,286 |
| — |
|
| Accumulated deferred income taxes | 618 |
| — |
|
| Other non-current liabilities | 932 |
| — |
|
| Total Liabilities Held for Sale | $ | 3,261 |
| $ | 15 |
|
|
| | | | | | |
| 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,Company and Southern Company Gas, throughPower each concluded that the sale of their assets, both individually and combined, did not represent a wholly-owned, indirect subsidiary, acquiredstrategic shift in operations that has, or is expected to have, 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 maintainmajor effect on its 50% equity interest in SNG. See Note 11operations and financial results; therefore, none of the assets related to the financial statements of Southern Company Gas under "Investment in SNG" in Item 8sales have been classified as discontinued operations for any of the Form 10-K for additional information on this investment. Selected financial informationperiods presented.
|
| | | | | | | | | |
| 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)Gulf Power and Southern Power's equity interests in Plant Oleander and Plant Stanton Unit A (together, the Florida Plants) and Plant Nacogdoches represented individually significant components of Southern Company and Southern Power, respectively; therefore, pre-tax profit for these components for the three and six months ended June 30, 2019 and 2018 is presented below:
|
| | | | | | | | | | | | |
| | For the Three Months Ended June 30, | For the Six Months Ended June 30, |
| | 2019 | 2018 | 2019 | 2018 |
| | (in millions) |
| Earnings before income taxes: | | | | |
| Gulf Power | $ | — |
| $ | 31 |
| $ | — |
| $ | 87 |
|
| Southern Power's Florida Plants | $ | — |
| $ | 14 |
| $ | — |
| $ | 24 |
|
Southern Power's Plant Nacogdoches(*) | $ | 9 |
| $ | 7 |
| $ | 16 |
| $ | 13 |
|
| |
| (*) | Earnings before income taxes for Plant Nacogdoches for the three and six months ended June 30, 2019 represents the beginning of the corresponding period through June 13, 2019 (the divestiture date). |
(L) LEASES
On January 1, 2019, the registrants adopted the provisions of FASB ASC Topic 842 (as amended), Leases (ASC 842), which require lessees to recognize leases with a term of greater than 12 months on the balance sheet as lease obligations, representing the discounted future fixed payments due, along with right-of-use (ROU) assets that will be amortized over the term of each lease.
The registrants elected the transition methodology provided by ASC 842, whereby the applicable requirements are applied on a prospective basis as of the adoption date of January 1, 2019, without restating prior periods. The registrants also elected the package of practical expedients provided by ASC 842 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, the registrants applied the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and elected the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed.
Lessee
As lessee, the registrants lease certain electric generating units (including renewable energy facilities), real estate/land, communication towers, railcars, and other equipment and vehicles. The major categories of lease obligations are as follows:
|
| | | | | | | | | | | | | | | | | | |
| | As of June 30, 2019 |
| | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| | (in millions) |
| Electric generating units | $ | 1,072 |
| $ | 150 |
| $ | 1,580 |
| $ | — |
| $ | — |
| $ | — |
|
| Real estate/land | 800 |
| 4 |
| 62 |
| 2 |
| 395 |
| 81 |
|
| Communication towers | 147 |
| 1 |
| 3 |
| — |
| — |
| 13 |
|
| Railcars | 54 |
| 25 |
| 27 |
| 3 |
| — |
| — |
|
| Other | 145 |
| 10 |
| 14 |
| 2 |
| — |
| — |
|
| Total | $ | 2,218 |
| $ | 190 |
| $ | 1,686 |
| $ | 7 |
| $ | 395 |
| $ | 94 |
|
Real estate/land leases primarily consist of commercial real estate leases at Southern Company, Georgia Power, and Southern Company Gas and various land leases primarily associated with renewable energy facilities at Southern
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Power. The commercial real estate leases have remaining terms of up to 25 years while the land leases have remaining terms of up to 48 years, including renewal periods.
Communication towers are leased for the installation of equipment to provide cellular phone service to customers and to support the automated meter infrastructure programs at the traditional electric operating companies. Communication tower leases have terms of up to 10 years with options to renew for periods up to 20 years.
While renewal options exist in many of the leases, other than for land leases associated with renewable energy facilities, the expected term used in calculating the lease obligation generally reflects only the noncancelable period of the lease as it is not considered reasonably certain that the lease will be extended. The expected term of land leases associated with renewable energy facilities includes renewal periods reasonably certain of exercise resulting in an expected lease term at least equal to the expected life of the renewable energy facilities.
Contracts that Contain a Lease
While not specifically structured as a lease, some of the PPAs at Alabama Power and Georgia Power are deemed to represent a lease of the underlying electric generating units when the terms of the PPA convey the right to control the use of the underlying assets. Amounts recorded for leases of electric generating units are generally based on the amount of scheduled capacity payments due over the remaining term of the affiliate PPA, which varies between four and 18 years. Georgia Power has several PPAs with Southern Power that Georgia Power accounts for as leases with a lease obligation of approximately $660 million at June 30, 2019. The amount paid for energy under these affiliate PPAs reflects a price that would be paid in an arm's-length transaction as those amounts have been reviewed and approved by the Georgia PSC.
Short-term Leases
Leases with an initial term of 12 months or less are not recorded on the balance sheet; the registrants generally recognize lease expense for these leases on a straight-line basis over the lease term.
Residual Value Guarantees
Residual value guarantees exist primarily in railcar leases at Alabama Power and Georgia Power and the amounts probable of being paid under those guarantees are included in the lease payments. All such amounts are immaterial as of June 30, 2019.
Lease and Nonlease Components
For all asset categories, with the exception of electric generating units, gas pipelines, and real estate leases, the registrants combine lease payments and any nonlease components, such as asset maintenance, for purposes of calculating the lease obligation and the right-of-use asset.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Balance sheet amounts recorded for operating and finance leases are as follows:
|
| | | | | | | | | | | | | | | | | | |
| | As of June 30, 2019 |
| | Southern Company(*) | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| | (in millions) |
| Operating Leases | | | | | | |
| Operating lease ROU assets, net | $ | 1,907 |
| $ | 152 |
| $ | 1,492 |
| $ | 7 |
| $ | 370 |
| $ | 95 |
|
| | | | | | | |
| Operating lease obligations - current | $ | 241 |
| $ | 48 |
| $ | 140 |
| $ | 2 |
| $ | 22 |
| $ | 15 |
|
| Operating lease obligations - non current | 1,733 |
| 137 |
| 1,377 |
| 5 |
| 373 |
| 79 |
|
| Total operating lease obligations | $ | 1,974 |
| $ | 185 |
| $ | 1,517 |
| $ | 7 |
| $ | 395 |
| $ | 94 |
|
| | | | | | | |
| Finance Leases | | | | | | |
| Finance lease ROU assets, net | $ | 237 |
| $ | 5 |
| $ | 142 |
| $ | — |
| $ | — |
| $ | — |
|
| | | | | | | |
| Finance lease obligations - current | $ | 24 |
| $ | 1 |
| $ | 10 |
| $ | — |
| $ | — |
| $ | — |
|
| Finance lease obligations - noncurrent | 220 |
| 4 |
| 159 |
| — |
| — |
| — |
|
| Total finance lease obligations | $ | 244 |
| $ | 5 |
| $ | 169 |
| $ | — |
| $ | — |
| $ | — |
|
| |
| (*) | Includes operating lease ROU assets, net and operating lease obligations classified as held for sale. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Lease costs for the three and six months ended June 30, 2019, which includes both amounts recognized as operations and maintenance expense and amounts capitalized as part of the cost of another asset, are as follows:
|
| | | | | | | | | | | | | | | | | | |
| | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| | (in millions) |
| For the Three Months Ended June 30, 2019 | | | | | |
| Lease cost | | | | | | |
| Operating lease cost | $ | 77 |
| $ | 13 |
| $ | 50 |
| $ | 1 |
| $ | 7 |
| $ | 5 |
|
| Finance lease cost: | | | | | | |
| Amortization of ROU assets | 7 |
| — |
| 4 |
| — |
| — |
| — |
|
| Interest on lease obligations | 3 |
| — |
| 4 |
| — |
| — |
| — |
|
| Total finance lease cost | 10 |
| — |
| 8 |
| — |
| — |
| — |
|
| Short-term lease costs | 13 |
| 6 |
| 6 |
| — |
| — |
| — |
|
| Variable lease cost | 29 |
| 1 |
| 25 |
| — |
| 1 |
| — |
|
| Sublease income | — |
| — |
| — |
| — |
| — |
| — |
|
| Total lease cost | $ | 129 |
| $ | 20 |
| $ | 89 |
| $ | 1 |
| $ | 8 |
| $ | 5 |
|
| | | | | | | |
| For the Six Months Ended June 30, 2019 | | | | | |
| Lease cost | | | | | | |
| Operating lease cost | $ | 147 |
| $ | 20 |
| $ | 99 |
| $ | 1 |
| $ | 14 |
| $ | 9 |
|
| Finance lease cost: | | | | | | |
| Amortization of ROU assets | 14 |
| — |
| 7 |
| — |
| — |
| — |
|
| Interest on lease obligations | 6 |
| — |
| 9 |
| — |
| — |
| — |
|
| Total finance lease cost | 20 |
| — |
| 16 |
| — |
| — |
| — |
|
| Short-term lease costs | 30 |
| 11 |
| 12 |
| — |
| — |
| — |
|
| Variable lease cost | 48 |
| 1 |
| 41 |
| — |
| 3 |
| — |
|
| Sublease income | — |
| — |
| — |
| — |
| — |
| — |
|
| Total lease cost | $ | 245 |
| $ | 32 |
| $ | 168 |
| $ | 1 |
| $ | 17 |
| $ | 9 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Georgia Power has variable lease payments that are based on the amount of energy produced by certain renewable generating facilities subject to PPAs.
Other information with respect to cash and noncash activities related to leases, as well as weighted-average lease terms and discount rates, is as follows:
|
| | | | | | | | | | | | | | | | | | |
| | For the Six Months Ended June 30, 2019 |
| | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| | (in millions) |
| Other information | | | | | | |
| Cash paid for amounts included in the measurements of lease obligations: | | | | | | |
| Operating cash flows from operating leases | $ | 129 |
| $ | 20 |
| $ | 75 |
| $ | 1 |
| $ | 12 |
| $ | 9 |
|
| Operating cash flows from finance leases | 2 |
| — |
| 10 |
| — |
| — |
| — |
|
| Financing cash flows from finance leases | 16 |
| — |
| 3 |
| — |
| — |
| — |
|
| ROU assets obtained in exchange for new operating lease obligations | 55 |
| 5 |
| 13 |
| — |
| — |
| 13 |
|
| ROU assets obtained in exchange for new finance lease obligations | 33 |
| 1 |
| 28 |
| — |
| — |
| — |
|
|
| | | | | | | | | | | | |
| | As of June 30, 2019 |
| | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| Weighted-average remaining lease term in years: | | | | | | |
| Operating leases | 14.0 |
| 3.6 |
| 10.5 |
| 7.0 |
| 33.5 |
| 9.7 |
|
| Finance leases | 18.3 |
| 12.8 |
| 11.0 |
| N/A |
| N/A |
| N/A |
|
| Weighted-average discount rate: | | | | | | |
| Operating leases | 4.53 | % | 3.33 | % | 4.46 | % | 4.06 | % | 5.68 | % | 3.73 | % |
| Finance leases | 5.05 | % | 3.67 | % | 10.69 | % | N/A |
| N/A |
| N/A |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Maturities of lease liabilities are as follows:
|
| | | | | | | | | | | | | | | | | | |
| | As of June 30, 2019 |
| | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| | (in millions) |
| Maturity Analysis | | | | | | |
| Operating leases: | | | | | | |
| 2019 (remaining) | $ | 178 |
| $ | 33 |
| $ | 129 |
| $ | 1 |
| $ | 13 |
| $ | 9 |
|
| 2020 | 295 |
| 53 |
| 203 |
| 2 |
| 22 |
| 17 |
|
| 2021 | 279 |
| 52 |
| 198 |
| 1 |
| 23 |
| 16 |
|
| 2022 | 268 |
| 52 |
| 196 |
| 1 |
| 23 |
| 13 |
|
| 2023 | 204 |
| 4 |
| 197 |
| 1 |
| 24 |
| 11 |
|
| Thereafter | 1,661 |
| 2 |
| 990 |
| 2 |
| 849 |
| 49 |
|
| Total | 2,885 |
| 196 |
| 1,913 |
| 8 |
| 954 |
| 115 |
|
| Less: Present value discount | 911 |
| 11 |
| 396 |
| 1 |
| 559 |
| 21 |
|
| Operating lease obligations | $ | 1,974 |
| $ | 185 |
| $ | 1,517 |
| $ | 7 |
| $ | 395 |
| $ | 94 |
|
| Finance leases: | | | | | | |
| 2019 (remaining) | $ | 16 |
| $ | — |
| $ | 16 |
| $ | — |
| $ | — |
| $ | — |
|
| 2020 | 33 |
| 1 |
| 28 |
| — |
| — |
| — |
|
| 2021 | 27 |
| 1 |
| 25 |
| — |
| — |
| — |
|
| 2022 | 23 |
| 1 |
| 25 |
| — |
| — |
| — |
|
| 2023 | 18 |
| 1 |
| 25 |
| — |
| — |
| — |
|
| Thereafter | 266 |
| 1 |
| 165 |
| — |
| — |
| — |
|
| Total | 383 |
| 5 |
| 284 |
| — |
| — |
| — |
|
| Less: Present value discount | 139 |
| — |
| 115 |
| — |
| — |
| — |
|
| Finance lease obligations | $ | 244 |
| $ | 5 |
| $ | 169 |
| $ | — |
| $ | — |
| $ | — |
|
Payments made under PPAs at Georgia Power for energy generated from certain renewable energy facilities accounted for as operating and finance leases are considered variable lease costs and are therefore not reflected in the above maturity analysis. As of June 30, 2019, Southern Company and Southern Power have additional operating leases, primarily for land, that have not yet commenced. These operating leases are expected to commence during the remainder of 2019 through 2022, with lease terms of up to 31 years, and have estimated total obligations of $81 million.
For additional information on each registrant's operating lease obligations at December 31, 2018, see Note 9 to the financial statements in Item 8 of the Form 10-K.
Lessor
With the exception of Southern Company Gas, the registrants are each considered lessors in various arrangements that have been determined to contain a lease due to the customer's ability to control the use of the underlying asset owned by the applicable registrant. For the traditional electric operating companies, these arrangements consist of outdoor lighting contracts accounted for as operating leases with initial terms of up to five years, after which the contracts renew on a month-to-month basis at the customer's option. For Mississippi Power, these arrangements also include tolling arrangements related to electric generating units accounted for as sales-type leases with terms of up to 20 years. For Southern Power, these arrangements consist of PPAs related to electric generating units, including renewable energy facilities, accounted for as operating leases with terms of up to 28 years. For Southern Company, these arrangements also include PPAs related to fuel cells accounted for as operating leases with terms of up to 15
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
years. Southern Company Gas is the lessor in operating leases related to gas pipelines with remaining terms of up to 24 years.
Lease income for the three and six months ended June 30, 2019 is as follows:
|
| | | | | | | | | | | | | | | |
| | Southern Company | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| | (in millions) |
| For the Three Months Ended June 30, 2019 | | | | | |
| Lease income - interest income on sales-type leases | $ | 2 |
| $ | — |
| $ | 2 |
| $ | — |
| $ | — |
|
| Lease income - operating leases | 67 |
| 19 |
| — |
| 39 |
| 9 |
|
| Variable lease income | 115 |
| — |
| — |
| 125 |
| — |
|
| Total lease income | $ | 184 |
| $ | 19 |
| $ | 2 |
| $ | 164 |
| $ | 9 |
|
| | | | | | |
| For the Six Months Ended June 30, 2019 | | | | | |
| Lease income - interest income on sales-type leases | $ | 5 |
| $ | — |
| $ | 5 |
| $ | — |
| $ | — |
|
| Lease income - operating leases | 139 |
| 39 |
| — |
| 80 |
| 17 |
|
| Variable lease income | 182 |
| — |
| — |
| 198 |
| — |
|
| Total lease income | $ | 326 |
| $ | 39 |
| $ | 5 |
| $ | 278 |
| $ | 17 |
|
No profit or loss was recognized by Mississippi Power upon commencement of a sales-type lease during the first quarter 2019.
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. Scheduled payments to be received under outdoor lighting contracts, tolling arrangements, and PPAs accounted for as leases are presented in the following maturity analyses.
The undiscounted cash flows to be received under tolling arrangements accounted for as sales-type leases are as follows:
|
| | | | | | |
| | As of June 30, 2019 |
| | Southern Company | Mississippi Power |
| | (in millions) |
| 2019 (remaining) | $ | 7 |
| $ | 7 |
|
| 2020 | 14 |
| 14 |
|
| 2021 | 14 |
| 14 |
|
| 2022 | 13 |
| 13 |
|
| 2023 | 12 |
| 12 |
|
| Thereafter | 135 |
| 135 |
|
| Total undiscounted cash flows | $ | 195 |
| $ | 195 |
|
| Lease receivable | 106 |
| 106 |
|
| Difference between undiscounted cash flows and discounted cash flows | $ | 89 |
| $ | 89 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
The undiscounted cash flows to be received under operating leases and contracts accounted for as operating leases (adjusted for intercompany eliminations) are as follows:
|
| | | | | | | | | | | | |
| | As of June 30, 2019 |
| | Southern Company | Georgia Power | Southern Power | Southern Company Gas |
| | (in millions) |
| 2019 (remaining) | $ | 75 |
| $ | 13 |
| $ | 52 |
| $ | 17 |
|
| 2020 | 125 |
| 26 |
| 65 |
| 35 |
|
| 2021 | 118 |
| 18 |
| 66 |
| 35 |
|
| 2022 | 109 |
| 8 |
| 68 |
| 34 |
|
| 2023 | 103 |
| 2 |
| 69 |
| 34 |
|
| Thereafter | 1,142 |
| — |
| 350 |
| 497 |
|
| Total | $ | 1,672 |
| $ | 67 |
| $ | 670 |
| $ | 652 |
|
Southern Power receives payments for renewable energy under PPAs accounted for as operating leases that are considered contingent rents and are therefore not reflected in the table above. Southern Power allocates revenue to the nonlease components of PPAs based on the stand-alone selling price of capacity and energy. The undiscounted cash flows to be received under outdoor lighting contracts accounted for as operating leases at Alabama Power and Mississippi Power are immaterial.
(M) 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 fourthree 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 wholesale market. Southern Company Gas distributes natural gas through the sevenits natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services,pipeline investments, wholesale gas services, and gas midstream operations.marketing services.
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$117 million and $295$204 million for the three and ninesix months ended SeptemberJune 30, 2017,2019, respectively, and $110$109 million and $313$192 million for the three and ninesix months ended SeptemberJune 30, 2016,2018, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies were immaterial for both the three and six months ended June 30, 2019 and 2018. Revenues from sales of natural gas from Southern Company Gas to Southern Power were $16 million and $33 million for the three and six months ended June 30, 2019, respectively, and $22 million and $58 million for the three and six months ended June 30, 2018, 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 technologiessolutions, such as distributed energy infrastructure and energy efficiency products and services, to electric utilities and large industrial, commercial, institutional, and municipal customers;customers, as well as investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Financial data for business segments and products and services for the three and ninesix months ended SeptemberJune 30, 20172019 and 20162018 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 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Electric Utilities | | | | |
| | Traditional Electric Operating Companies | Southern Power | Eliminations | Total | Southern Company Gas | All Other | Eliminations | Consolidated |
| | (in millions) |
| Three Months Ended June 30, 2019 | | | | | | | |
| Operating revenues | $ | 3,899 |
| $ | 510 |
| $ | (119 | ) | $ | 4,290 |
| $ | 689 |
| $ | 186 |
| $ | (67 | ) | $ | 5,098 |
|
Segment net income (loss)(a)(b)(c)(d) | 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)(b)(c)(d) | 1,346 |
| 230 |
| — |
| 1,576 |
| 376 |
| 1,041 |
| (11 | ) | 2,982 |
|
| At June 30, 2019 | | | | | | | | |
| Goodwill | $ | — |
| $ | 2 |
| $ | — |
| $ | 2 |
| $ | 5,015 |
| $ | 265 |
| $ | — |
| $ | 5,282 |
|
| Total assets | 78,314 |
| 14,518 |
| (783 | ) | 92,049 |
| 20,761 |
| 3,343 |
| (1,286 | ) | 114,867 |
|
| Three Months Ended June 30, 2018 | | | | | | | |
| Operating revenues | $ | 4,124 |
| $ | 555 |
| $ | (114 | ) | $ | 4,565 |
| $ | 730 |
| $ | 381 |
| $ | (49 | ) | $ | 5,627 |
|
Segment net income (loss)(a)(b)(d) | (48 | ) | 22 |
| — |
| (26 | ) | (31 | ) | (100 | ) | 3 |
| (154 | ) |
| Six Months Ended June 30, 2018 | | | | | | | |
| Operating revenues | $ | 8,104 |
| $ | 1,064 |
| $ | (220 | ) | $ | 8,948 |
| $ | 2,369 |
| $ | 782 |
| $ | (100 | ) | $ | 11,999 |
|
Segment net income (loss)(a)(b)(d)(e) | 563 |
| 143 |
| — |
| 706 |
| 248 |
| (174 | ) | 4 |
| 784 |
|
| At December 31, 2018 | | | | | | | | |
| Goodwill | $ | — |
| $ | 2 |
| $ | — |
| $ | 2 |
| $ | 5,015 |
| $ | 298 |
| $ | — |
| $ | 5,315 |
|
| Total assets | 79,382 |
| 14,883 |
| (306 | ) | 93,959 |
| 21,448 |
| 3,285 |
| (1,778 | ) | 116,914 |
|
| |
| (a) | Attributable to Southern Company. |
| |
| (b) | Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated probable losses on the Kemper IGCCplants under construction of $34$4 million ($213 million after tax) and $88 million$1.1 billion ($54 million0.8 billion after tax) for the three months ended SeptemberJune 30, 20172019 and 2016,2018, respectively, and $3.2 billion$6 million ($2.2 billion5 million after tax) and $222 million$1.1 billion ($137 million0.8 billion after tax) for the ninesix months ended SeptemberJune 30, 20172019 and 2016,2018, respectively. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) under "Integrated Coal Gasification Combined Cycle"Georgia Power – Nuclear Construction" and "Mississippi Power – Kemper IGCC Schedule and Cost EstimateCounty Energy Facility" for additional information. |
| |
| (c) | Segment net income (loss) for the traditional electric operating companies also"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 one of PowerSecure's business units. See Note (K) under "Southern Company" for additional information. |
| |
| (d) | Segment net income (loss) for Southern Power includes a $23 million pre-tax chargegain ($88 million gain after tax) on the sale of Plant Nacogdoches for the write-downthree and six months ended June 30, 2019 and a pre-tax impairment charge of Gulf Power's ownership of Plant Scherer Unit 3 of $33$119 million ($2089 million after tax) for the ninethree and six months ended SeptemberJune 30, 2017.2018 related to the sale of Southern Power's Florida Plants. See Note (B)(K) under "Regulatory MattersSouthern Power" and Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power – Gulf Power – Retail Base Rate Cases"Sale of Natural Gas Plants" for additional information. |
| |
| (e) | Segment net income (loss) for Southern Company Gas includes a goodwill impairment charge of $42 million for the six months ended June 30, 2018 related to the sale of Pivotal Home Solutions. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Products and Services
|
| | | | | | | | | | | | | | | | |
| | | Electric Utilities' Revenues |
| Period | | Retail | | Wholesale | | Other | | Total |
| | | (in millions) |
| Three Months Ended September 30, 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)
|
| | | | | | | | | | | | |
| | Electric Utilities' Revenues |
| | Retail | Wholesale | Other | Total |
| | (in millions) |
| Three Months Ended June 30, 2019 | $ | 3,540 |
| $ | 542 |
| $ | 208 |
| $ | 4,290 |
|
| Three Months Ended June 30, 2018 | 3,740 |
| 616 |
| 209 |
| 4,565 |
|
| Six Months Ended June 30, 2019 | $ | 6,623 |
| $ | 1,041 |
| $ | 421 |
| $ | 8,085 |
|
| Six Months Ended June 30, 2018 | 7,308 |
| 1,239 |
| 401 |
| 8,948 |
|
|
| | | | | | | | | | | | |
| | 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' Revenues |
| | Gas
Distribution
Operations(a) | Gas
Marketing
Services(b) | Other | Total |
| | (in millions) |
| Three Months Ended June 30, 2019 | $ | 563 |
| $ | 58 |
| $ | 68 |
| $ | 689 |
|
| Three Months Ended June 30, 2018 | 638 |
| 89 |
| 3 |
| 730 |
|
| Six Months Ended June 30, 2019 | $ | 1,724 |
| $ | 287 |
| $ | 152 |
| $ | 2,163 |
|
| Six Months Ended June 30, 2018 | 1,838 |
| 359 |
| 172 |
| 2,369 |
|
| |
| (a) | Operating revenues for the three gas distribution operations dispositions were $70 million and $237 million for the three and six months ended June 30, 2018, respectively. |
| |
| (b) | Operating revenues for Pivotal Home Solutions were $24 million and $55 million for the three and six months ended June 30, 2018, respectively. |
Southern Company Gas
Southern Company Gas manages its business through four reportable segments – gas distribution operations, gas marketing services,pipeline investments, wholesale gas services, and gas midstream operations.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 sevenfour states.
Gas marketing services includespipeline investments consists of joint ventures in natural gas marketingpipeline investments including a 50% interest in SNG, two significant pipeline construction projects, and a 50% joint ownership interest in the Dalton Pipeline. These natural gas pipelines enable the provision of diverse sources of natural gas supplies to end-usethe customers primarily in Georgia and Illinois. Additionally, gas marketing services provides home equipment protection products and services. of Southern Company Gas.
Wholesale gas services provides natural gas asset management and/or related logistics services for each of Southern Company Gas' utilities except Nicor Gas as well as for non-affiliated companies. Additionally, wholesale gas services engages in natural gas storage and gas pipeline arbitrage and related activities.
Gas midstream operationsmarketing services provides natural gas marketing to end-use customers primarily consists of Southern Company Gas' pipeline investments, with storagein Georgia and fuel operations also aggregated into this segment. Illinois through SouthStar Energy Services, LLC.
The all other column includes segments below the quantitative threshold for separate disclosure, includingdisclosure. This includes Southern Company Gas' storage and fuels operations, its investment in Triton through the completion of its sale on May 29, 2019, and other subsidiaries that fall below the quantitative threshold for separate disclosure.
After the Merger, See Note (E) under "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." for additional information and related disclosures.
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)
Business segment financial data for the three and six months ended June 30, 2019 and 2018 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, 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 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Gas Distribution Operations(a) | Gas Pipeline Investments | Wholesale Gas Services(b) | Gas Marketing Services(c)(d) | Total | All Other | Eliminations | Consolidated |
| | (in millions) |
| 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 June 30, 2019 | 17,397 |
| 1,768 |
| 668 |
| 1,527 |
| 21,360 |
| 10,934 |
| (11,533 | ) | 20,761 |
|
| Three Months Ended June 30, 2018 | | | | | | |
| Operating revenues | $ | 643 |
| $ | 8 |
| $ | (16 | ) | $ | 89 |
| $ | 724 |
| $ | 11 |
| $ | (5 | ) | $ | 730 |
|
| Segment net income (loss) | 68 |
| 21 |
| (21 | ) | (76 | ) | (8 | ) | (23 | ) | — |
| (31 | ) |
| Six Months Ended June 30, 2018 | | | | | | | |
| Operating revenues | $ | 1,856 |
| $ | 16 |
| $ | 150 |
| $ | 359 |
| $ | 2,381 |
| $ | 26 |
| $ | (38 | ) | $ | 2,369 |
|
| Segment net income (loss) | 216 |
| 48 |
| 83 |
| (63 | ) | 284 |
| (36 | ) | — |
| 248 |
|
| Total assets at December 31, 2018 | 17,266 |
| 1,763 |
| 1,302 |
| 1,587 |
| 21,918 |
| 11,112 |
| (11,582 | ) | 21,448 |
|
| |
(*)(a) | Operating revenues for the three gas distribution operations dispositions were $70 million and $237 million for the three and six months ended June 30, 2018, respectively. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information. |
| |
| (b) | 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 | ) |
|
| | | | | | | | | | | | | | | |
| | Third Party Gross Revenues | Intercompany Revenues | Total Gross Revenues | Less Gross Gas Costs | Operating Revenues |
| | (in millions) |
| Three Months Ended June 30, 2019 | $ | 1,223 |
| $ | 63 |
| $ | 1,286 |
| $ | 1,238 |
| $ | 48 |
|
| Three Months Ended June 30, 2018 | 1,336 |
| 102 |
| 1,438 |
| 1,454 |
| (16 | ) |
| Six Months Ended June 30, 2019 | $ | 3,148 |
| $ | 151 |
| $ | 3,299 |
| $ | 3,165 |
| $ | 134 |
|
| Six Months Ended June 30, 2018 | 3,274 |
| 269 |
| 3,543 |
| 3,393 |
| 150 |
|
| |
| (c) | Operating revenues for Pivotal Home Solutions were $24 million and $55 million for the three and six months ended June 30, 2018, respectively. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information on the sale of Pivotal Home Solutions. |
| |
| (d) | Segment net income (loss) for gas marketing services includes a loss on disposition of $36 million for the three and six months ended June 30, 2018 and a goodwill impairment charge of $42 million for the six months ended June 30, 2018 related to the sale of Pivotal Home Solutions. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information. |
PART II — OTHER INFORMATION
Item 1. Legal Proceedings.
See the Notes to the Condensed Financial Statements herein for information regarding certain legal and administrative proceedings in which the registrants are involved.
Item 1A. Risk Factors.
See RISK FACTORS in Item 1A of the Form 10-K for a discussion of the risk factors of the registrants. Except as described below, thereThere 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 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 June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion (Guarantee Obligations), of which Georgia Power's proportionate share is approximately $1.7 billion, and that the Guarantee Obligations exist regardless of whether Plant Vogtle Units 3 and 4 are completed. The Guarantee Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations, 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, 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 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 Vogtle Construction Monitoring (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.
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.
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(2) Plan of Incorporation and By-Lawsacquisition, reorganization, arrangement, liquidation or succession |
| | | | | |
| | | AlabamaSouthern Power |
| | | | | |
| | | (b)(e)1 | - | ArticlesMembership Interest Purchase Agreement, dated as of Amendment to the ArticlesApril 17, 2019, by and between Southern Power and The City of Incorporation of Alabama Power dated September 7, 2017.Austin d/b/a Austin Energy. (Designated in Form 8-K dated September 5, 2017,June 13, 2019, File No. 1-3164,001-37803, as Exhibit 4.5.2.1.) |
| | | | |
|
| | | | |
| | (4) Instruments Describing Rights of Security Holders, Including Indentures |
| | | | |
| | Georgia Power |
| | | | |
| | (c)1 | - | |
| | | | | |
| | | (c)(e)2 | - | Subordinated Note Indenture,Letter Agreement, dated as of September 1, 2017,May 24, 2019, by and between GeorgiaSouthern Power and Wells Fargo Bank, National Association, as Trustee, and First Supplemental Indenture thereto dated asThe City of September 21, 2017. (Designated 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 | - | Amendment No. 3, dated July 27, 2017 to Loan Guarantee Agreement dated February 20, 2014, between Georgia Power and the DOE.Austin d/b/a Austin Energy. (Designated in Form 8-K dated July 27, 2017,June 13, 2019, File No. 1-6468,001-37803, as Exhibit 4.1.2.2.) |
| | | | | |
| | | (10) Material Contracts(3) Articles of Incorporation and By-Laws |
| | | | |
| | | Mississippi Power |
| | | | | |
| | * | (e)1(d) | - | |
| | | | | |
| | | Southern Company Gas |
| | | | | |
| | * | (g)1(e) | - | Asset Purchase Agreement, datedBy-laws of Southern Company Gas 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.)amended. |
| | | | | |
| | | (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 | - | |
| | | | | |
| | | Southern Company Gas |
| | | | | |
| | | (g)(f)1 | - | |
| | | | |
| | (f)2 | - | |
| | | | | |
| | | (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 |
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 30, 2019
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 30, 2019
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 30, 2019
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 |
| | | 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 30, 2019
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. MillerMark S. Lantrip |
| | | 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 30, 2019
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 30, 2019