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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, 20182019
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 every Interactive Data File required to be submitted 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 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.
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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, 20182019 |
|
| The Southern Company | | Par Value $5 Per Share | 1,045,231,646 | 1,028,888,684 |
|
| 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, 20182019
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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, 20182019
|
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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. | | |
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|
| |
| Term | Meaning |
| |
| 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 |
| Bechtel | Bechtel Power Corporation, the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4 |
| Bechtel Agreement | The October 23, 2017 construction completion agreement between the Vogtle Owners and Bechtel |
| CCR | Coal combustion residuals |
| CCR Rule | Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in 2015 |
| Chattanooga Gas | Chattanooga Gas Company, a wholly-owned subsidiary of Southern Company Gas |
Clean Power Plan | Final action published by the EPA in 2015 that established guidelines for states to develop
plans to meet EPA-mandated CO2 emission rates or emission reduction goals for existing
electric generating units
|
CO2
| Carbon dioxide |
| COD | Commercial operation date |
| Contractor Settlement Agreement | The December 31, 2015 agreement between Westinghouse and 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 |
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 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 of the Energy Policy Act of 2005 |
| EPA | U.S. Environmental Protection Agency |
| EPC Contractor | Westinghouse and its affiliate, WECTEC Global Project Services Inc.; 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, 2017,2018, as applicable |
| GAAP | U.S. generally accepted accounting principles |
| Georgia Power | Georgia Power Company |
| GHG | Greenhouse gas |
DEFINITIONS
(continued)
|
| |
Term | Meaning |
| 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 LLCGas' natural gas usage and operating revenues are generally higher |
| HLBV | 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 |
Interim Assessment AgreementITAAC | Agreement entered intoInspections, Tests, Analyses, and Acceptance Criteria, standards established by the Vogtle Owners and the EPC Contractor to allow construction to continue after the EPC Contractor's bankruptcy filing |
IRS | Internal Revenue ServiceNRC |
| ITC | Investment tax credit |
| JEA | Jacksonville 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 |
| MEAG | Municipal Electric Authority of Georgia |
Merger | The merger, effective July 1, 2016, of a wholly-owned, direct subsidiary of Southern Company with and into Southern Company Gas, with Southern Company Gas continuing as the surviving corporation |
| 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' natural gas distribution utilities (Nicor Gas, Atlanta Gas Light, Virginia Natural Gas, Elizabethtown Gas, Florida City Gas, Chattanooga Gas, and Elkton 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 |
| NextEra Energy | NextEra Energy, Inc. |
| Nicor Gas | Northern Illinois Gas Company, a wholly-owned subsidiary of Southern Company Gas |
| NRC | U.S. Nuclear Regulatory Commission |
| NYMEX | New York Mercantile Exchange, Inc. |
| 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 |
|
| |
| Term | Meaning |
| Pivotal Home Solutions | Nicor Energy Services Company, until June 4, 2018 a wholly-owned subsidiary of Southern Company Gas, 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 |
| 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 |
| 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. |
| 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, Southern Electric Generating Company, Southern Nuclear, SCS, Southern Communications Services, Inc., PowerSecure, and other subsidiaries |
| Southern Nuclear | Southern Nuclear Operating Company, Inc. |
| Southern Power | Southern Power Company and its subsidiaries |
SPSHSP Solar | SP Solar Holdings I, LP |
| SP Wind | SP Wind Holdings II, LLC |
| Tax Reform Legislation | The Tax Cuts and Jobs Act, which was signed into law on December 22, 2017 and became effective on January 1, 2018 |
| Toshiba | Toshiba Corporation, the parent company of Westinghouse |
| 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 |
| Virginia Natural Gas | Virginia Natural Gas, Inc., a wholly-owned subsidiary of Southern Company Gas |
DEFINITIONS
(continued)
|
| |
Term | Meaning |
| Vogtle 3 and 4 Agreement | Agreement entered into with the EPC Contractor in 2008 by Georgia Power, acting for itself and as agent for the Vogtle Owners, and rejected in bankruptcy in July 2017, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4 |
| Vogtle Owners | Georgia Power, Oglethorpe Power Corporation, MEAG, and the City of Dalton Georgia, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light, and Sinking Fund Commissioners |
| Vogtle Services Agreement | The June 9, 2017 services agreement between the Vogtle Owners and the EPC Contractor, as 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 |
| WACOG | Weighted average cost of gas |
| Westinghouse | Westinghouse Electric Company LLC |
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This Quarterly Report on Form 10-Q contains forward-looking statements. Forward-looking statements include, among other things, statements concerning regulated rates, the strategic goals for the wholesale business, customer and sales growth, economic conditions, fuel and environmental cost recovery and other rate actions, projected equity ratios, costs of modernization efforts, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, financing activities, completion dates of construction projects, completion of announced dispositions, filings with state and federal regulatory authorities, impacts of the Tax Reform Legislation, federal and state 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," "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 environmental laws and regulations governing air, water, land, and protection of other natural resources, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;
the uncertainty surrounding the Tax Reform Legislation, including implementing regulations and IRS interpretations, actions that may be taken in response by regulatory authorities, and its impact, if any, on the credit ratings of Southern Company and its subsidiaries;
current and future litigation or 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, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies;
variations in demand for electricity and natural gas, including those relating to weather, the general economy, population and business growth (and declines), the effects of energy conservation and efficiency measures, and any potential economic impacts resulting from federal fiscal decisions;
available sources and costs of natural gas and other fuels;
limits on pipeline capacity;
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 scale, including changes in labor costs, availability, and productivity, challenges with management of contractors, subcontractors, or vendors, adverse weather conditions, shortages, increased costs or inconsistent quality of equipment, materials, and labor, including any changes related to imposition of import tariffs, 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;
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 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;
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)
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 Georgia 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;
litigation or other disputes related to the Kemper County energy facility;
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 dispositionsdisposition of Gulf Power, Southern Power's plants located in Florida, and thePlant Mankato, natural gas facility and the proposed sale of a noncontrolling interest in Southern Power's wind facilities, 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 and the possibility that costs related to the integration of Southern Company and Southern Company Gas will be greater than expected;
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 physical attack and the threat of 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, |
| | 2018 | | 2017 | | 2018 | | 2017 |
| | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | |
| Retail electric revenues | $ | 4,605 |
| | $ | 4,615 |
| | $ | 11,913 |
| | $ | 11,786 |
|
| Wholesale electric revenues | 693 |
| | 718 |
| | 1,923 |
| | 1,867 |
|
| Other electric revenues | 170 |
| | 168 |
| | 509 |
| | 510 |
|
Natural gas revenues (includes alternative revenue programs of
$5, $-, $(23), and $9, respectively) | 492 |
| | 532 |
| | 2,806 |
| | 2,746 |
|
| Other revenues | 199 |
| | 168 |
| | 1,007 |
| | 494 |
|
| Total operating revenues | 6,159 |
| | 6,201 |
| | 18,158 |
| | 17,403 |
|
| Operating Expenses: | | | | | | | |
| Fuel | 1,310 |
| | 1,285 |
| | 3,514 |
| | 3,372 |
|
| Purchased power | 257 |
| | 256 |
| | 760 |
| | 646 |
|
| Cost of natural gas | 104 |
| | 134 |
| | 1,053 |
| | 1,085 |
|
| Cost of other sales | 120 |
| | 90 |
| | 688 |
| | 293 |
|
| Other operations and maintenance | 1,404 |
| | 1,341 |
| | 4,217 |
| | 4,100 |
|
| Depreciation and amortization | 787 |
| | 767 |
| | 2,338 |
| | 2,236 |
|
| Taxes other than income taxes | 319 |
| | 303 |
| | 990 |
| | 941 |
|
| Estimated loss on plants under construction | 1 |
| | 34 |
| | 1,105 |
| | 3,155 |
|
| Gain on dispositions, net | (353 | ) | | — |
| | (317 | ) | | (19 | ) |
| Impairment charges | 36 |
| | — |
| | 197 |
| | — |
|
| Total operating expenses | 3,985 |
| | 4,210 |
| | 14,545 |
| | 15,809 |
|
| Operating Income | 2,174 |
| | 1,991 |
| | 3,613 |
| | 1,594 |
|
| Other Income and (Expense): | | | | | | | |
| Allowance for equity funds used during construction | 36 |
| | 18 |
| | 99 |
| | 133 |
|
| Earnings from equity method investments | 36 |
| | 32 |
| | 108 |
| | 100 |
|
| Interest expense, net of amounts capitalized | (458 | ) | | (407 | ) | | (1,386 | ) | | (1,248 | ) |
| Other income (expense), net | 57 |
| | 65 |
| �� | 195 |
| | 165 |
|
| Total other income and (expense) | (329 | ) | | (292 | ) | | (984 | ) | | (850 | ) |
| Earnings Before Income Taxes | 1,845 |
| | 1,699 |
| | 2,629 |
| | 744 |
|
| Income taxes | 623 |
| | 590 |
| | 598 |
| | 317 |
|
| Consolidated Net Income | 1,222 |
| | 1,109 |
| | 2,031 |
| | 427 |
|
| Dividends on preferred and preference stock of subsidiaries | 4 |
| | 10 |
| | 12 |
| | 32 |
|
| Net income attributable to noncontrolling interests | 54 |
| | 30 |
| | 71 |
| | 48 |
|
Consolidated Net Income Attributable to
Southern Company | $ | 1,164 |
| | $ | 1,069 |
| | $ | 1,948 |
| | $ | 347 |
|
| Common Stock Data: | | | | | | | |
| Earnings per share - | | | | | | | |
| Basic | $ | 1.14 |
| | $ | 1.07 |
| | $ | 1.92 |
| | $ | 0.35 |
|
| Diluted | $ | 1.13 |
| | $ | 1.06 |
| | $ | 1.91 |
| | $ | 0.35 |
|
| Average number of shares of common stock outstanding (in millions) | | | | | | | |
| Basic | 1,023 |
| | 1,003 |
| | 1,016 |
| | 998 |
|
| Diluted | 1,029 |
| | 1,010 |
| | 1,021 |
| | 1,005 |
|
| Cash dividends paid per share of common stock | $ | 0.60 |
| | $ | 0.58 |
| | $ | 1.78 |
| | $ | 1.72 |
|
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, |
| | 2018 | | 2017 | | 2018 | | 2017 |
| | (in millions) | | (in millions) |
| Consolidated Net Income | $ | 1,222 |
| | $ | 1,109 |
| | $ | 2,031 |
| | $ | 427 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
Changes in fair value, net of tax of
$(4), $15, $(6), and $32, respectively | (11 | ) | | 25 |
| | (19 | ) | | 54 |
|
Reclassification adjustment for amounts included in net income,
net of tax of $5, $(10), $21, and $(36), respectively | 14 |
| | (17 | ) | | 60 |
| | (59 | ) |
| Pension and other postretirement benefit plans: | | | | | | | |
Reclassification adjustment for amounts included in net income,
net of tax of $3, $1, $4, and $2, respectively | 8 |
| | 1 |
| | 11 |
| | 3 |
|
| Total other comprehensive income (loss) | 11 |
| | 9 |
| | 52 |
| | (2 | ) |
| Comprehensive Income | 1,233 |
| | 1,118 |
| | 2,083 |
| | 425 |
|
| Dividends on preferred and preference stock of subsidiaries | 4 |
| | 10 |
| | 12 |
| | 32 |
|
| Comprehensive income attributable to noncontrolling interests | 54 |
| | 30 |
| | 71 |
| | 48 |
|
Consolidated Comprehensive Income Attributable to
Southern Company | $ | 1,175 |
| | $ | 1,078 |
| | $ | 2,000 |
| | $ | 345 |
|
|
| | | | | | | | | | | | | | | |
| | 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 electric revenues | $ | 3,540 |
| | $ | 3,740 |
| | $ | 6,623 |
| | $ | 7,308 |
|
| Wholesale electric revenues | 542 |
| | 616 |
| | 1,041 |
| | 1,239 |
|
| Other electric revenues | 161 |
| | 170 |
| | 331 |
| | 330 |
|
Natural gas revenues (includes alternative revenue programs of
$1, $(4), $-, and $(27), respectively) | 689 |
| | 706 |
| | 2,163 |
| | 2,314 |
|
| Other revenues | 166 |
| | 395 |
| | 352 |
| | 808 |
|
| Total operating revenues | 5,098 |
| | 5,627 |
| | 10,510 |
| | 11,999 |
|
| Operating Expenses: | | | | | | | |
| Fuel | 914 |
| | 1,103 |
| | 1,764 |
| | 2,204 |
|
| Purchased power | 201 |
| | 236 |
| | 371 |
| | 503 |
|
| Cost of natural gas | 191 |
| | 228 |
| | 877 |
| | 949 |
|
| Cost of other sales | 84 |
| | 279 |
| | 203 |
| | 568 |
|
| Other operations and maintenance | 1,316 |
| | 1,523 |
| | 2,628 |
| | 2,972 |
|
| Depreciation and amortization | 755 |
| | 783 |
| | 1,506 |
| | 1,552 |
|
| Taxes other than income taxes | 299 |
| | 316 |
| | 628 |
| | 671 |
|
| 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 | 3,756 |
| | 5,564 |
| | 5,477 |
| | 10,560 |
|
| Operating Income | 1,342 |
| | 63 |
| | 5,033 |
| | 1,439 |
|
| Other Income and (Expense): | | | | | | | |
| Allowance for equity funds used during construction | 31 |
| | 32 |
| | 63 |
| | 63 |
|
| Earnings from equity method investments | 33 |
| | 31 |
| | 81 |
| | 72 |
|
| Interest expense, net of amounts capitalized | (429 | ) | | (470 | ) | | (859 | ) | | (928 | ) |
| Other income (expense), net | 99 |
| | 78 |
| | 176 |
| | 138 |
|
| Total other income and (expense) | (266 | ) | | (329 | ) | | (539 | ) | | (655 | ) |
| 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 | 29 |
| | 23 |
| | — |
| | 17 |
|
Consolidated Net Income (Loss) Attributable to
Southern Company | $ | 899 |
| | $ | (154 | ) | | $ | 2,982 |
| | $ | 784 |
|
| Common Stock Data: | | | | | | | |
| Earnings (loss) per share - | | | | | | | |
| Basic | $ | 0.86 |
| | $ | (0.15 | ) | | $ | 2.86 |
| | $ | 0.77 |
|
| Diluted | $ | 0.85 |
| | $ | (0.15 | ) | | $ | 2.84 |
| | $ | 0.77 |
|
| Average number of shares of common stock outstanding (in millions) | | | | | | | |
| Basic | 1,044 |
| | 1,014 |
| | 1,041 |
| | 1,012 |
|
| Diluted | 1,052 |
| | 1,014 |
| | 1,049 |
| | 1,017 |
|
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, |
| | 2018 | | 2017 |
| | (in millions) |
| Operating Activities: | | | |
| Consolidated net income | $ | 2,031 |
| | $ | 427 |
|
| Adjustments to reconcile consolidated net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 2,647 |
| | 2,564 |
|
| Deferred income taxes | (286 | ) | | 15 |
|
| Allowance for equity funds used during construction | (99 | ) | | (133 | ) |
| Pension, postretirement, and other employee benefits | (60 | ) | | (64 | ) |
| Settlement of asset retirement obligations | (160 | ) | | (137 | ) |
| Stock based compensation expense | 108 |
| | 95 |
|
| Estimated loss on plants under construction | 1,081 |
| | 3,148 |
|
| Gain on dispositions, net | (324 | ) | | (22 | ) |
| Impairment charges | 197 |
| | — |
|
| Other, net | (21 | ) | | (80 | ) |
| Changes in certain current assets and liabilities — | | | |
| -Receivables | 37 |
| | 423 |
|
| -Prepayments | 14 |
| | (39 | ) |
| -Natural gas for sale | 87 |
| | — |
|
| -Other current assets | (90 | ) | | (66 | ) |
| -Accounts payable | (248 | ) | | (467 | ) |
| -Accrued taxes | 839 |
| | 157 |
|
| -Accrued compensation | (138 | ) | | (230 | ) |
| -Retail fuel cost over recovery | 36 |
| | (211 | ) |
| -Other current liabilities | (67 | ) | | (129 | ) |
| Net cash provided from operating activities | 5,584 |
| | 5,251 |
|
| Investing Activities: | | | |
| Business acquisitions, net of cash acquired | (64 | ) | | (1,016 | ) |
| Property additions | (5,793 | ) | | (5,242 | ) |
| Nuclear decommissioning trust fund purchases | (846 | ) | | (585 | ) |
| Nuclear decommissioning trust fund sales | 840 |
| | 580 |
|
| Dispositions | 2,773 |
| | 66 |
|
| Cost of removal, net of salvage | (252 | ) | | (208 | ) |
| Change in construction payables, net | 91 |
| | 120 |
|
| Investment in unconsolidated subsidiaries | (93 | ) | | (134 | ) |
| Payments pursuant to LTSAs | (157 | ) | | (189 | ) |
| Other investing activities | 1 |
| | (77 | ) |
| Net cash used for investing activities | (3,500 | ) | | (6,685 | ) |
| Financing Activities: | | | |
| Decrease in notes payable, net | (1,225 | ) | | (515 | ) |
| Proceeds — | | | |
| Long-term debt | 1,950 |
| | 4,068 |
|
| Common stock | 878 |
| | 613 |
|
| Preferred stock | — |
| | 250 |
|
| Short-term borrowings | 3,150 |
| | 1,263 |
|
| Redemptions and repurchases — | | | |
| Long-term debt | (4,498 | ) | | (1,981 | ) |
| Preferred and preference stock | — |
| | (150 | ) |
| Short-term borrowings | (1,800 | ) | | (409 | ) |
| Distributions to noncontrolling interests | (86 | ) | | (89 | ) |
| Capital contributions from noncontrolling interests | 1,333 |
| | 79 |
|
| Payment of common stock dividends | (1,805 | ) | | (1,716 | ) |
| Other financing activities | (237 | ) | | (113 | ) |
| Net cash provided from (used for) financing activities | (2,340 | ) | | 1,300 |
|
| Net Change in Cash, Cash Equivalents, and Restricted Cash | (256 | ) | | (134 | ) |
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 2,147 |
| | 1,992 |
|
| Cash, Cash Equivalents, and Restricted Cash at End of Period | $ | 1,891 |
| | $ | 1,858 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
| Interest (net of $53 and $72 capitalized for 2018 and 2017, respectively) | $ | 1,402 |
| | $ | 1,286 |
|
| Income taxes, net | 137 |
| | (187 | ) |
| Noncash transactions — Accrued property additions at end of period | 1,125 |
| | 805 |
|
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 SHEETSCOMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | |
| Assets | | At September 30, 2018 | | At December 31, 2017 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 1,847 |
| | $ | 2,130 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 1,730 |
| | 1,806 |
|
| Energy marketing receivables | | 498 |
| | 607 |
|
| Unbilled revenues | | 738 |
| | 810 |
|
| Under recovered fuel clause revenues | | 105 |
| | 171 |
|
| Other accounts and notes receivable | | 690 |
| | 698 |
|
| Accumulated provision for uncollectible accounts | | (33 | ) | | (44 | ) |
| Materials and supplies | | 1,418 |
| | 1,438 |
|
| Fossil fuel for generation | | 390 |
| | 594 |
|
| Natural gas for sale | | 486 |
| | 595 |
|
| Prepaid expenses | | 354 |
| | 452 |
|
| Other regulatory assets, current | | 522 |
| | 604 |
|
| Assets held for sale, current | | 407 |
| | 12 |
|
| Other current assets | | 232 |
| | 199 |
|
| Total current assets | | 9,384 |
| | 10,072 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 100,672 |
| | 103,542 |
|
| Less: Accumulated depreciation | | 30,739 |
| | 31,457 |
|
| Plant in service, net of depreciation | | 69,933 |
| | 72,085 |
|
| Nuclear fuel, at amortized cost | | 844 |
| | 883 |
|
| Construction work in progress | | 7,655 |
| | 6,904 |
|
| Total property, plant, and equipment | | 78,432 |
| | 79,872 |
|
| Other Property and Investments: | | | | |
| Goodwill | | 5,315 |
| | 6,268 |
|
| Equity investments in unconsolidated subsidiaries | | 1,569 |
| | 1,513 |
|
Other intangible assets, net of amortization of $225 and $186
at September 30, 2018 and December 31, 2017, respectively | | 674 |
| | 873 |
|
| Nuclear decommissioning trusts, at fair value | | 1,872 |
| | 1,832 |
|
| Leveraged leases | | 794 |
| | 775 |
|
| Miscellaneous property and investments | | 258 |
| | 249 |
|
| Total other property and investments | | 10,482 |
| | 11,510 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 792 |
| | 825 |
|
| Unamortized loss on reacquired debt | | 328 |
| | 206 |
|
| Other regulatory assets, deferred | | 6,196 |
| | 6,943 |
|
| Assets held for sale | | 4,667 |
| | — |
|
| Other deferred charges and assets | | 1,436 |
| | 1,577 |
|
| Total deferred charges and other assets | | 13,419 |
| | 9,551 |
|
| Total Assets | | $ | 111,717 |
| | $ | 111,005 |
|
|
| | | | | | | | | | | | | | | |
| | 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 BALANCE SHEETSSTATEMENTS OF CASH FLOWS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholders' Equity | | At September 30, 2018 | | At December 31, 2017 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 3,013 |
| | $ | 3,892 |
|
| Notes payable | | 2,564 |
| | 2,439 |
|
| Energy marketing trade payables | | 521 |
| | 546 |
|
| Accounts payable | | 2,246 |
| | 2,530 |
|
| Customer deposits | | 524 |
| | 542 |
|
| Accrued taxes | | 1,060 |
| | 636 |
|
| Accrued interest | | 422 |
| | 488 |
|
| Accrued compensation | | 800 |
| | 959 |
|
| Asset retirement obligations, current | | 348 |
| | 351 |
|
| Other regulatory liabilities, current | | 349 |
| | 337 |
|
| Liabilities held for sale, current | | 355 |
| | — |
|
| Other current liabilities | | 763 |
| | 874 |
|
| Total current liabilities | | 12,965 |
| | 13,594 |
|
| Long-term Debt | | 41,425 |
| | 44,462 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 6,035 |
| | 6,842 |
|
| Deferred credits related to income taxes | | 6,651 |
| | 7,256 |
|
| Accumulated deferred ITCs | | 2,377 |
| | 2,267 |
|
| Employee benefit obligations | | 2,017 |
| | 2,256 |
|
| Asset retirement obligations, deferred | | 5,817 |
| | 4,473 |
|
| Accrued environmental remediation | | 269 |
| | 389 |
|
| Other cost of removal obligations | | 2,330 |
| | 2,684 |
|
| Other regulatory liabilities, deferred | | 153 |
| | 239 |
|
| Liabilities held for sale | | 2,835 |
| | — |
|
| Other deferred credits and liabilities | | 454 |
| | 691 |
|
| Total deferred credits and other liabilities | | 28,938 |
| | 27,097 |
|
| Total Liabilities | | 83,328 |
| | 85,153 |
|
| Redeemable Preferred Stock of Subsidiaries | | 324 |
| | 324 |
|
| Stockholders' Equity: | | | | |
| Common Stockholders' Equity: | | | | |
| Common stock, par value $5 per share — | | | | |
| Authorized — 1.5 billion shares | | | | |
| Issued — 1.0 billion shares | | | | |
| Treasury — September 30, 2018: 1.0 million shares | | | | |
| — December 31, 2017: 0.9 million shares | | | | |
| Par value | | 5,140 |
| | 5,038 |
|
| Paid-in capital | | 10,905 |
| | 10,469 |
|
| Treasury, at cost | | (39 | ) | | (36 | ) |
| Retained earnings | | 9,048 |
| | 8,885 |
|
| Accumulated other comprehensive loss | | (177 | ) | | (189 | ) |
| Total Common Stockholders' Equity | | 24,877 |
| | 24,167 |
|
| Noncontrolling Interests | | 3,188 |
| | 1,361 |
|
| Total Stockholders' Equity | | 28,065 |
| | 25,528 |
|
| Total Liabilities and Stockholders' Equity | | $ | 111,717 |
| | $ | 111,005 |
|
|
| | | | | | | |
| | For the Six Months
Ended June 30, |
| | 2019 | | 2018 |
| | (in millions) |
| Operating Activities: | | | |
| Consolidated net income | $ | 2,989 |
| | $ | 809 |
|
| Adjustments to reconcile consolidated net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 1,623 |
| | 1,750 |
|
| Deferred income taxes | 274 |
| | (338 | ) |
| Allowance for equity funds used during construction | (63 | ) | | (63 | ) |
| Mark-to-market adjustments | 31 |
| | 3 |
|
| Pension, postretirement, and other employee benefits | (65 | ) | | (74 | ) |
| Settlement of asset retirement obligations | (143 | ) | | (97 | ) |
| 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 | (22 | ) | | (34 | ) |
| Changes in certain current assets and liabilities — | | | |
| -Receivables | 653 |
| | 94 |
|
| -Prepayments | (53 | ) | | (73 | ) |
| -Natural gas for sale | 255 |
| | 295 |
|
| -Other current assets | (18 | ) | | (40 | ) |
| -Accounts payable | (1,045 | ) | | (406 | ) |
| -Accrued taxes | 938 |
| | 213 |
|
| -Accrued compensation | (312 | ) | | (284 | ) |
| -Other current liabilities | (135 | ) | | 136 |
|
| Net cash provided from operating activities | 2,513 |
| | 3,258 |
|
| Investing Activities: | | | |
| Property additions | (3,484 | ) | | (3,828 | ) |
| Nuclear decommissioning trust fund purchases | (405 | ) | | (571 | ) |
| Nuclear decommissioning trust fund sales | 400 |
| | 566 |
|
| Proceeds from dispositions and asset sales | 5,000 |
| | 500 |
|
| Cost of removal, net of salvage | (197 | ) | | (128 | ) |
| Change in construction payables, net | (107 | ) | | 49 |
|
| Investment in unconsolidated subsidiaries | (134 | ) | | (63 | ) |
| Payments pursuant to LTSAs | (64 | ) | | (103 | ) |
| Other investing activities | (7 | ) | | (46 | ) |
| Net cash provided from (used for) investing activities | 1,002 |
| | (3,624 | ) |
| Financing Activities: | | | |
| Increase in notes payable, net | 83 |
| | 1,442 |
|
| Proceeds — | | | |
| Long-term debt | 1,390 |
| | 1,100 |
|
| Common stock | 452 |
| | 222 |
|
| Short-term borrowings | 250 |
| | 1,650 |
|
| Redemptions and repurchases — | | | |
| Long-term debt | (2,560 | ) | | (3,379 | ) |
| Short-term borrowings | (1,850 | ) | | (550 | ) |
| Distributions to noncontrolling interests | (82 | ) | | (42 | ) |
| Capital contributions from noncontrolling interests | 5 |
| | 1,210 |
|
| Payment of common stock dividends | (1,269 | ) | | (1,194 | ) |
| Other financing activities | (67 | ) | | (223 | ) |
| 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 during the period for — | | | |
| Interest (net of $36 and $35 capitalized for 2019 and 2018, respectively) | $ | 844 |
| | $ | 927 |
|
| Income taxes, net | 210 |
| | 4 |
|
| Noncash transactions — Accrued property additions at end of period | 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 June 30, 2019 | | At December 31, 2018 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 1,383 |
| | $ | 1,396 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 1,654 |
| | 1,726 |
|
| Energy marketing receivables | | 361 |
| | 801 |
|
| Unbilled revenues | | 583 |
| | 654 |
|
| Under recovered fuel clause revenues | | 69 |
| | 115 |
|
| Other accounts and notes receivable | | 756 |
| | 813 |
|
| Accumulated provision for uncollectible accounts | | (50 | ) | | (50 | ) |
| Materials and supplies | | 1,440 |
| | 1,465 |
|
| Fossil fuel for generation | | 435 |
| | 405 |
|
| Natural gas for sale | | 268 |
| | 524 |
|
| Prepaid expenses | | 543 |
| | 432 |
|
| Assets from risk management activities, net of collateral | | 107 |
| | 222 |
|
| Other regulatory assets | | 607 |
| | 525 |
|
| Assets held for sale | | 58 |
| | 393 |
|
| Other current assets | | 138 |
| | 162 |
|
| Total current assets | | 8,352 |
| | 9,583 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 103,428 |
| | 103,706 |
|
| Less: Accumulated depreciation | | 30,693 |
| | 31,038 |
|
| Plant in service, net of depreciation | | 72,735 |
| | 72,668 |
|
| Nuclear fuel, at amortized cost | | 871 |
| | 875 |
|
| Construction work in progress | | 7,568 |
| | 7,254 |
|
| Total property, plant, and equipment | | 81,174 |
| | 80,797 |
|
| Other Property and Investments: | | | | |
| Goodwill | | 5,282 |
| | 5,315 |
|
| Equity investments in unconsolidated subsidiaries | | 1,557 |
| | 1,580 |
|
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 | | 1,942 |
| | 1,721 |
|
| Leveraged leases | | 813 |
| | 798 |
|
| Miscellaneous property and investments | | 505 |
| | 269 |
|
| Total other property and investments | | 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 | | 794 |
| | 794 |
|
| Unamortized loss on reacquired debt | | 313 |
| | 323 |
|
| Regulatory assets – asset retirement obligations | | 4,062 |
| | 2,933 |
|
| Other regulatory assets, deferred | | 5,835 |
| | 5,375 |
|
| Assets held for sale, deferred | | 685 |
| | 5,350 |
|
| Other deferred charges and assets | | 1,141 |
| | 1,463 |
|
| Total deferred charges and other assets | | 14,692 |
| | 16,238 |
|
| Total Assets | | $ | 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 June 30, 2019 | | At December 31, 2018 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 3,148 |
| | $ | 3,198 |
|
| Notes payable | | 1,398 |
| | 2,915 |
|
| Energy marketing trade payables | | 393 |
| | 856 |
|
| Accounts payable | | 1,978 |
| | 2,580 |
|
| Customer deposits | | 489 |
| | 522 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 171 |
| | 21 |
|
| Other accrued taxes | | 501 |
| | 635 |
|
| Accrued interest | | 455 |
| | 472 |
|
| Accrued compensation | | 676 |
| | 1,030 |
|
| Asset retirement obligations | | 429 |
| | 404 |
|
| Other regulatory liabilities | | 304 |
| | 376 |
|
| Liabilities held for sale | | 36 |
| | 425 |
|
| Operating lease obligations | | 228 |
| | — |
|
| Other current liabilities | | 793 |
| | 852 |
|
| Total current liabilities | | 10,999 |
| | 14,286 |
|
| Long-term Debt | | 39,682 |
| | 40,736 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 7,728 |
| | 6,558 |
|
| Deferred credits related to income taxes | | 6,386 |
| | 6,460 |
|
| Accumulated deferred ITCs | | 2,283 |
| | 2,372 |
|
| Employee benefit obligations | | 2,058 |
| | 2,147 |
|
| Operating lease obligations, deferred | | 1,702 |
| | — |
|
| Asset retirement obligations, deferred | | 9,478 |
| | 8,990 |
|
| Accrued environmental remediation | | 247 |
| | 268 |
|
| Other cost of removal obligations | | 2,283 |
| | 2,297 |
|
| Other regulatory liabilities, deferred | | 176 |
| | 169 |
|
| Liabilities held for sale, deferred | | 39 |
| | 2,836 |
|
| Other deferred credits and liabilities | | 384 |
| | 465 |
|
| Total deferred credits and other liabilities | | 32,764 |
| | 32,562 |
|
| Total Liabilities | | 83,445 |
| | 87,584 |
|
| Redeemable Preferred Stock of Subsidiaries | | 291 |
| | 291 |
|
Total Stockholders' Equity (See accompanying statements) | | 31,131 |
| | 29,039 |
|
| Total Liabilities and Stockholders' Equity | | $ | 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 2019 vs. SECOND QUARTER 2018 vs. THIRD QUARTER 2017
AND
YEAR-TO-DATE 20182019 vs. YEAR-TO-DATE 20172018
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. During the second quarter 2018, Southern Power completed the sale of a 33% equity interest in a limited partnership indirectly owning substantially all of its solar facilities. On October 31, 2018, Southern Power entered into agreements with three financial investors for the sale of a noncontrolling interest for approximately $1.2 billion in tax equity in SP Wind, which owns a portfolio of eight operating wind facilities. On November 5, 2018, Southern Power entered into an agreement to sell all of its equity interests in Plant Mankato (including the 385-MW expansion currently under construction) for an aggregate purchase price of $650 million. Southern Company Gas distributes natural gas through its natural gas distribution utilities and is involved in several other complementary businesses including gas marketing services,pipeline investments, wholesale gas services, and gas midstream operations. In July 2018, Southern Company Gas completed sales of three of its natural gas distribution utilities. During the second quarter 2018, Southern Company Gas also completed the sale of Pivotal Home Solutions.marketing services. The Southern Company 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. See FUTURE EARNINGS POTENTIAL and Note (J) to the Condensed Financial Statements herein for additional information regarding disposition activity.
On May 20, 2018,January 1, 2019, Southern Company entered into a stock purchase agreement withcompleted the sale of Gulf Power to NextEra Energy to sell Gulf Power for an aggregate cash purchase price of $5.75approximately $5.8 billion (less the amount$1.3 billion of indebtedness assumed at closing, which is currently estimated at approximately $1.3 billion)assumed), subject to certaincustomary working capital adjustments. The completion ofpreliminary gain associated with the sale isof 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 occurconclude in 2019. In addition, Mississippi Power is scheduled to file a base rate case with the Mississippi PSC in the firstfourth quarter 2019 and is subject to the satisfaction or waiver of certain closing conditions.2019. The ultimate outcome of this matterthese matters cannot be determined at this time. See Note (J) to the Condensed Financial Statements under "Southern Company's Sale of Gulf Power" herein for additional information.
In 2018, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Atlanta Gas Light, and Nicor Gas reached agreements with their respective state PSCs or other applicable state regulatory agencies relating to the regulatory impacts of the Tax Reform Legislation, which, for some companies, included capital structure adjustments expected to help mitigate the potential adverse impacts to certain of their credit metrics. See Note (B) to the Condensed Financial Statements under "Regulatory Matters" herein for additional information regarding state PSC or other regulatory agency actions related to the Tax Reform Legislation. Also see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax"Regulatory Matters" of Southern Companyherein and Note 2 to the financial statements in Item 78 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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). Although, with respect to Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC has stated the $7.3 billion estimate included in the seventeenth VCM proceeding does not represent a cost cap, Georgia Power did not seek rate recovery for the $0.7 billion increase in costs included in the revised base capital cost forecast (or any related financing costs) in the nineteenth VCM report filed with the Georgia PSC on August 31, 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs included in the revised construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018.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. OnIn September 26, 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, is working withMEAG, 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 clarify any interpretive issues relatedtheir joint ownership agreements to implement the operation of certain provisions of the Vogtle Owner Term Sheet.
In September 2017,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, issued a conditional commitmentunder 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 $1.67$5.130 billion. At June 30, 2019, Georgia Power had a total of $3.46 billion in additional guaranteed loansof borrowings outstanding under the Loan Guarantee Agreement. In September 2018, the DOE extended the conditional commitment to March 31, 2019. Any further extension must be approved by the DOE. 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.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 ACCOUNTING POLICIES –Note (F) to the Condensed Financial Statements under "Application of Critical Accounting Policies and EstimatesDOE Loan Guarantee Borrowings" herein for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIESMANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
Net Income (Loss)
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $95 | | 8.9 | | $1,601 | | 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) |
| $1,053 | | N/M | | $2,198 | | N/M |
N/M - Not meaningful
Consolidated net income attributable to Southern Company was $1.2 billion$899 million ($1.140.86 per share) for the thirdsecond quarter 20182019 compared to $1.1 billiona net loss of $154 million ($1.07(0.15) per share) for the corresponding period in 2017.2018. The increasechange was primarily due to lower federal income tax expense as a result of the Tax Reform Legislation and higher retail electric revenues due to warmer weather in the third quarter 2018 compared to the corresponding period in 2017. These increases were partially offset by reductions in retail revenues related to Tax Reform Legislation impacts and an increase in operations and maintenance expenses.
Consolidated net income attributable to Southern Company was $1.9 billion ($1.92 per share) for year-to-date 2018 compared to $347 million ($0.35 per share) for the corresponding period in 2017. The increase was primarily due to charges of $3.2 billion ($2.2 billion after tax) in 2017 related to the Kemper IGCC at Mississippi Power, partially offset by a $1.1 billion ($0.8 billion after tax) charge in the second quarter 2018 for an estimated probable loss onrelated to Georgia Power's construction of Plant Vogtle Units 3 and 4. Also contributing4 and a decrease in operations and maintenance expenses.
Consolidated net income attributable to the increase were lower federal income tax expense as a result of the Tax Reform Legislation and higher retail electric revenues due to colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018Southern Company was $3.0 billion ($2.86 per share) for year-to-date 2019 compared to the corresponding periods in 2017, partially offset by reductions in retail revenues related to Tax Reform Legislation impacts and impairment charges at Southern Power and Southern Company Gas, primarily related to the dispositions described in Note (J) to the Condensed Financial Statements herein.
Retail Electric Revenues
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(10) | | (0.2) | | $127 | | 1.1 |
In the third quarter 2018, retail electric revenues were $4.61 billion compared to $4.62 billion$784 million ($0.77 per share) for the corresponding period in 2017. For year-to-date 2018, retail electric revenues were $11.9 billion compared to $11.8 billion for the corresponding period in 2017.
Details of the changes in retail electric revenues were as follows:
|
| | | | | | | | | | | | | | |
| | | Third Quarter 2018 | | Year-to-Date 2018 |
| | | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail electric – prior year | | $ | 4,615 |
| | | | $ | 11,786 |
| | |
| Estimated change resulting from – | | | | | | | | |
| Rates and pricing | | (198 | ) | | (4.2 | ) | | (444 | ) | | (3.8 | ) |
| Sales growth | | 43 |
| | 0.9 |
| | 65 |
| | 0.6 |
|
| Weather | | 80 |
| | 1.7 |
| | 297 |
| | 2.5 |
|
| Fuel and other cost recovery | | 65 |
| | 1.4 |
| | 209 |
| | 1.8 |
|
| Retail electric – current year | | $ | 4,605 |
| | (0.2 | )% | | $ | 11,913 |
| | 1.1 | % |
Revenues associated with changes in rates and pricing decreased in the third quarter and year-to-date 2018 when compared to the corresponding periods in 20172018. The increase was primarily due to revenues deferred as regulatory liabilitiesthe $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 futurean 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 decreasesincreases to CNP Compliance revenue, increases in revenues recognized under 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 2018 decrease was2019 increase also reflects the rate pricing effect of decreased customer usage, partially offset by higherlower contributions from variable demand-driven pricing from commercial and industrial customers with variable demand-driven pricing at Georgia 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 increaseddecreased in the thirdsecond quarter and year-to-date 20182019 when compared to the corresponding periods in 2017. In2018. Weather-adjusted residential KWH sales decreased 1.0% and 0.3% in the thirdsecond quarter and year-to-date 2018, weather-adjusted residential KWH sales increased 1.2% and 0.8%, respectively, and weather-adjusted commercial KWH sales increased 0.8% and 0.6%, respectively, primarily due to customer growth. Industrial KWH sales increased 2.4% and 1.9% in the third quarter and year-to-date 2018, respectively, primarily in the primary metals sector, largely due to strong domestic demand for steel and aluminum, partially offset by decreased sales in the chemicals and paper sectors, primarily due to customer maintenance outages and on-site cogeneration.
Fuel and other cost recovery revenues increased $65 million and $209 million in the third quarter and year-to-date 2018,2019, respectively, when compared to the corresponding periods in 20172018 primarily due to higher energy salesdecreased customer usage primarily resulting from colder weatheran increase in the first quarter 2018energy efficient residential appliances, partially offset by customer growth. Weather-adjusted commercial KWH sales decreased 1.3% and warmer weather1.6% in the second quarter and third quarters 2018year-to-date 2019, respectively, when compared to the corresponding periods in 2017. 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
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(25) | | (3.5) | | $56 | | 3.0 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(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, 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 thirdsecond quarter 2018,2019, wholesale electric revenues were $693$542 million compared to $718$616 million for the corresponding period in 2017. This2018. 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 $20$54 million decrease in energy revenues and a $5$20 million decrease in capacity revenues. The year-to-date 2019 decrease was related to a $160 million decrease in energy revenues isand 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 fromdue to a decrease in the volume of KWHs sold through short-term sales at Southern Power and a decrease in revenuerevenues 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 Shared Services AgreementForm 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
(SSA) between Mississippi Power and Cooperative Energy. These decreases were partially offset by an increase in revenues at Southern Power from new natural gas PPAs from existing facilities, an increase in sales from renewable facilities, and an increase in fuel costs that are contractually recovered through PPAs.
For year-to-date 2018, wholesale electric revenues were $1.92 billion compared to $1.87 billion for the corresponding period in 2017. This increase was related to a $70 million increase in energy revenues, partially offset by a $14 million decrease in capacity revenues. The increase in energy revenues primarily related to Southern Power included revenues from new natural gas PPAs from existing facilities, an increase in fuel costs that are contractually recovered through PPAs, and an increase in sales from renewable facilities. These increases were partially offset by a decrease in non-PPA revenues from short-term sales at Southern Power and a decrease in revenue under the SSA between Mississippi Power and Cooperative Energy.
Natural Gas Revenues
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(40) | | (7.5) | | $60 | | 2.2 |
In the third quarter 2018, natural gas revenues were $492 million compared to $532 million for the corresponding period in 2017. For year-to-date 2018, natural gas revenues were $2.8 billion compared to $2.7 billion for the corresponding period in 2017.
Details of the changes in natural gas revenues were as follows:
| | | | Third Quarter 2018 | | Year-to-Date 2018 | Second Quarter 2019 | | Year-to-Date 2019 |
| | (in millions) | | (% change) | | (in millions) | | (% change) | (in millions) | | (% change) | | (in millions) | | (% change) |
| Natural gas revenues – prior year | $ | 532 |
| | | | $ | 2,746 |
| | | $ | 706 |
| | | | $ | 2,314 |
| | |
| Estimated change resulting from – | | | | | | | | | | | | | | |
| Infrastructure replacement programs and base rate changes | — |
| | — |
| | 53 |
| | 1.9 |
| 10 |
| | 1.4 | % | | 42 |
| | 1.8 | % |
| Gas costs and other cost recovery | (16 | ) | | (3.0 | ) | | (24 | ) | | (0.9 | ) | (13 | ) | | (1.8 | ) | | 49 |
| | 2.1 |
|
| Weather | 1 |
| | 0.2 |
| | 17 |
| | 0.6 |
| (7 | ) | | (1.1 | ) | | — |
| | — |
|
| Wholesale gas services | 17 |
| | 3.2 |
| | 46 |
| | 1.7 |
| 64 |
| | 9.1 |
| | (16 | ) | | (0.7 | ) |
Dispositions(*) | (43 | ) | | (8.1 | ) | | (30 | ) | | (1.1 | ) | |
| Southern Company Gas Dispositions | | (70 | ) | | (9.9 | ) | | (237 | ) | | (10.2 | ) |
| Other | 1 |
| | 0.2 |
| | (2 | ) | | — |
| (1 | ) | | (0.1 | ) | | 11 |
| | 0.5 |
|
| Natural gas revenues – current year | $ | 492 |
| | (7.5 | )% | | $ | 2,806 |
| | 2.2 | % | $ | 689 |
| | (2.4 | )% | | $ | 2,163 |
| | (6.5 | )% |
| |
(*) | Includes Pivotal Utility Holdings' disposition of Elizabethtown Gas and Elkton Gas as well as NUI Corporation's disposition of Pivotal Utility Holdings, which primarily consisted of Florida City Gas. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
|
Revenues attributable to infrastructure replacement programs and base rate changes at the natural gas distribution utilities increased forin 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 a result of rate cases, partially offset by revenue reductions forwell as increases due to the impacts of the Tax Reform Legislation.
Revenues attributable to gas costs and other cost recovery decreased in the thirdsecond quarter 2018 decreased primarily due to reduced natural gas prices during the third quarter 20182019 and increased year-to-date 2019 compared to the corresponding periodperiods in 20172018. The decrease in the second quarter 2019 is primarily due to lower natural gas prices and decreased volumes of natural gas sold in the third quarter 2018 as a result of fewer customers served following the dispositions. Revenues attributable to gas costs and other cost recoverysold. The increase for year-to-date 2018 decreased2019 is primarily due to reducedincreased natural gas prices during 2018 compared toin the corresponding period in 2017,first quarter 2019, partially offset by increaseddecreased volumes of natural gas sold in 2018 as a result of colder weather, as determined by Heating Degree Days.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Revenues increased due to colder weather, as determined by Heating Degree Days, in 2018 compared to the corresponding periods in 2017 that affected the utility customers in Illinois and Southern Company Gas' gas marketing services customers in Georgia and Illinois.
Revenues attributable to Southern Company Gas' wholesale gas services business increased primarily due to increased commercial activity, partially offset by derivative losses.
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 operations.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 "Regulatory Matters – Southern Company Gas" for additional information.
Other Revenues
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $31 | | 18.5 | | $513 | | 103.8 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(229) | | (58.0) | | $(456) | | (56.4) |
In the thirdsecond quarter 2018,2019, other revenues were $199$166 million compared to $168$395 million for the corresponding period in 2017.2018. For year-to-date 2018,2019, other revenues were $1.0 billion$352 million compared to $494$808 million for the corresponding period in 2017.2018. These increasesdecreases were primarily related to an increase in sales of products and services from additional customer contracts in distributed generation and utility infrastructure at PowerSecure, partially offset by a decrease in revenues resulting from the sale of Pivotal Home Solutions on June 4,PowerSecure's 2018 at Southern Company Gas. The year-to-date 2018 increase was primarily related to storm restoration services in Puerto Rico. Additionally, these increases reflect $21 million and $40 million
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | |
| | Third Quarter 2018
vs.
Third Quarter 2017 | | Year-to-Date 2018
vs.
Year-to-Date 2017 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | 25 |
| | 1.9 | | $ | 142 |
| | 4.2 |
| Purchased power | 1 |
| | 0.4 | | 114 |
| | 17.6 |
| Total fuel and purchased power expenses | $ | 26 |
| | | | $ | 256 |
| | |
In the third quarter 2018, total fuel and purchased power expenses were $1.6 billion compared to $1.5 billion for the corresponding period in 2017. The increase was primarily the result of a $68 million increase in the volume of KWHs generated and purchased, partially offset by a $42 million decrease in the average cost of fuel and purchased power.
For year-to-date 2018, total fuel and purchased power expenses were $4.3 billion compared to $4.0 billion for the corresponding period in 2017. The increase was primarily the result of a $300 million increase in the volume of KWHs generated and purchased, partially offset by a $74 million net decrease in the average cost of fuel and purchased power. In addition, fuel expense increased $30 million for 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.Contents
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" and Recovery" – Alabama Power – Accounting Order" 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:
| | | | Third Quarter 2018 | | Third Quarter 2017 | | Year-to-Date 2018 | | Year-to-Date 2017 | Second Quarter 2019 | | Second Quarter 2018(a) | | Year-to-Date 2019 | | Year-to-Date 2018(a) |
Total generation (in billions of KWHs) | 56 | | 55 | | 153 | | 147 | 46 | | 47 | | 90 | | 93 |
Total purchased power (in billions of KWHs) | 6 | | 6 | | 16 | | 14 | 4 | | 4 | | 8 | | 7 |
Sources of generation (percent) — | | | | | | |
| Gas | 47 | | 47 | | 46 | | 46 | 52 | | 45 | | 50 | | 45 |
| Coal | 32 | | 31 | | 30 | | 30 | 22 | | 29 | | 22 | | 29 |
| Nuclear | 14 | | 15 | | 15 | | 16 | 16 | | 15 | | 16 | | 16 |
| Hydro | 2 | | 2 | | 3 | | 2 | 3 | | 3 | | 5 | | 3 |
| Other | 5 | | 5 | | 6 | | 6 | 7 | | 8 | | 7 | | 7 |
Cost of fuel, generated (in cents per net KWH)(a) — | | | | |
Cost of fuel, generated (in cents per net KWH)— | | | | |
| Gas | 2.78 | | 2.92 | | 2.79 | | 2.93 | 2.39 | | 2.71 | | 2.47 | | 2.78 |
| Coal | 2.75 | | 2.75 | | 2.79 | | 2.82 | 3.04 | | 2.71 | | 2.98 | | 2.80 |
| Nuclear | 0.81 | | 0.80 | | 0.80 | | 0.80 | 0.80 | | 0.82 | | 0.80 | | 0.80 |
Average cost of fuel, generated (in cents per net KWH)(a) | 2.47 | | 2.52 | | 2.47 | | 2.51 | 2.26 | | 2.39 | | 2.29 | | 2.43 |
Average cost of purchased power (in cents per net KWH)(b) | 5.32 | | 5.36 | | 5.52 | | 5.32 | 4.89 | | 5.18 | | 5.04 | | 6.11 |
| |
| (a) | For year-to-date 2018, cost of fuel, generated and average cost of fuel, generated excludes a $30 million adjustment associated with the Alabama PSC accounting order related to excess deferred income taxes.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 2018,2019, fuel expense was $1.31$0.9 billion compared to $1.29$1.1 billion for the corresponding period in 2017. The increase2018. Excluding approximately $74 million related to Gulf Power in 2018, the decrease was primarily due to a 7.5%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 1.3%6.4% increase in the volume of KWHs generated by coal, partially offset by a 4.8% decrease in the average cost of natural gas per KWH generated.
For year-to-date 2018, fuel expense was $3.5 billion compared to $3.4 billion for the corresponding period in 2017. The increase was primarily due to a 9.3% increase in the volume of KWHs generated by natural gas and a 4.1% increase in the volume of KWHs generated by coal, partially offset by a 4.8% decrease in the average cost of natural gas per KWH generated and a 1.1% decrease in the average cost of coal per KWH generated.
Purchased Power
For year-to-date 2018,In the second quarter 2019, purchased power expense was $760$201 million compared to $646$236 million for the corresponding period in 2017. 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 10.5% increase in the volume of KWHs purchased and a 3.8% increase17.5% 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.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Cost of Natural Gas
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(30) | | (22.4) | | $(32) | | (2.9) |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(37) | | (16.2) | | $(72) | | (7.6) |
NaturalExcluding 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 75%80% and 83%85% of total cost of natural gas for the thirdsecond quarter and year-to-date 2018,2019, respectively.
In the thirdsecond quarter 2018,2019, cost of natural gas was $104$191 million compared to $134$228 million for the corresponding period in 2017. The2018. Excluding a $25 million decrease reflects $14 million related to the Southern Company Gas Dispositions, which resultedcost 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 in the third quarter 2018 as a result of fewer gas distribution customers, and a 3.2% decrease in natural gas prices during the third quarter 2018year-to-date 2019 compared to the corresponding period in 2017.2018.
For year-to-date 2018, cost
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Cost of Other Sales
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $30 | | 33.3 | | $395 | | 134.8 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(195) | | (69.9) | | $(365) | | (64.3) |
In the thirdsecond quarter 2018,2019, cost of other sales was $120$84 million compared to $90$279 million for the corresponding period in 2017.2018. For year-to-date 2018,2019, cost of other sales was $688$203 million compared to $293$568 million for the corresponding period in 2017.2018. These increasesdecreases were primarily related to an increase in sales of products and services from additional customer contracts in distributed generation and utility infrastructure at PowerSecure. The year-to-datePowerSecure's 2018 increase was primarily related to storm restoration services in Puerto Rico.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $63 | | 4.7 | | $117 | | 2.9 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(207) | | (13.6) | | $(344) | | (11.6) |
In the thirdsecond quarter 2018,2019, other operations and maintenance expenses were $1.4$1.3 billion compared to $1.3$1.5 billion for the corresponding period in 2017. The increase was primarily due to a $22 million increase in electric transmission and distribution costs, primarily due to additional line maintenance, and $21 million of disposition-related costs at Southern Company Gas. The increase also reflects $21 million of expenses from unregulated sales of products and services that were reclassified to other operations and maintenance expenses as a result of the adoption of ASC 606. In prior periods, these expenses were included in other income (expense), net.
2018. For year-to-date 2018,2019, other operations and maintenance expenses were $4.2$2.6 billion compared to $4.1$3.0 billion for the corresponding period in 2017.2018. 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 a $60decreases of $48 million increase in electric transmission and distribution costs, primarily due$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 line maintenance, and $29plant 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 disposition-related costs atGulf Power.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Company Gas. The increase also reflects $51 million of expenses from unregulated sales of products and services that were reclassified to other operations and maintenance expenses as a result of the adoption of ASC 606. In prior periods, these expenses were included in other income (expense), net. These increases were partially offset by a $32.5 million charge in the first quarter 2017 related to the write-down of Gulf Power's ownership of Plant Scherer Unit 3 in accordance with the settlement of Gulf Power's 2017 rate case. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information.
See Note (A) to the Condensed Financial Statements herein for additional information regarding the adoption of ASC 606.
Depreciation and Amortization
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $20 | | 2.6 | | $102 | | 4.6 |
In the third quarter 2018, depreciation and amortization was $787 million compared to $767 million for the corresponding period in 2017. For year-to-date 2018, depreciation and amortization was $2.3 billion compared to $2.2 billion for the corresponding period in 2017. These increases primarily reflect increases of $18 million and $76 million for the third quarter and year-to-date 2018, respectively, related to additional plant in service. Additionally, the year-to-date 2018 increase was due to $34 million in depreciation credits recognized in 2017, as authorized in Gulf Power's 2013 rate case settlement. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information.
Taxes Other Than Income Taxes
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $16 | | 5.3 | | $49 | | 5.2 |
In the third quarter 2018, taxes other than income taxes were $319 million compared to $303 million for the corresponding period in 2017. For year-to-date 2018, taxes other than income taxes were $990 million compared to $941 million for the corresponding period in 2017. These increases were primarily due to increased property taxes at the traditional electric operating companies and investment capital taxes at Southern Company Gas. Also contributing to the year-to-date 2018 increase was an increase in municipal franchise fees primarily related to higher retail revenues at Georgia Power and an increase in revenue tax expenses as a result of higher revenues at Southern Company Gas.
Estimated Loss on Plants Under Construction
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(33) | | (97.1) | | $(2,050) | | (65.0) |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(1,056) | | (99.6) | | $(1,099) | | (99.5) |
In the thirdsecond quarter 2018,2019, estimated loss on plants under construction was $1$4 million compared to $34 million$1.06 billion for the corresponding period in 2017.2018. For year-to-date 2018,2019, estimated loss on plants under construction was $1.1 billion$6 million compared to $3.2$1.11 billion for the corresponding period in 2017. The third quarter 2018 decrease was2018. These decreases were primarily due to lower costs associated with abandonment and related closure activities for the mine and gasifier-related assets$1.1 billion charge recorded in the second quarter 2018 as a result of the Kemper IGCC at Mississippi Power. The year-to-date 2018 decrease was primarily due to revisions to the estimated construction costs for, and subsequent suspension in June 2017 of, the Kemper IGCC at Mississippi
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Power, partially offset by charges in 2018 related to 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 32 to the financial statements of Southern Company under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Kemper County Energy FacilityGeorgia Power – Nuclear Construction" and "Nuclear Construction" herein for additional information.
Gain(Gain) Loss on Dispositions, Net
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $353 | | N/M | | $298 | | 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) |
| $44 | | N/M | | $2,542 | | N/M |
N/M - Not meaningful
In the thirdsecond quarter and year-to-date 2018, a net gain on dispositions of $353 million ($40 million gain after tax) and $317 million ($35 million loss after tax), respectively, were recorded related to the Southern Company Gas Dispositions. The year-to-date 2018 increase in2019, 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 $19$15 million decreaseadjustment 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 gains from salesthe corresponding period in 2018. This change was primarily due to a preliminary gain of integrated transmission system assets at Georgia$2.5 billion ($1.3 billion after tax) on the sale of Gulf Power.
See Note (J)(K) to the Condensed Financial Statements under "Southern"Southern Company Gas"" herein for additional information regarding related income taxes which substantially offset the gains for the Southern Company Gas Dispositions.
Impairment Charges
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $36 | | N/M | | $197 | | N/M |
N/M - Not meaningful
Southern Power recorded a $36 million asset impairment charge in the third quarter 2018 on wind turbine equipment held for development projects and a $119 million asset impairment charge in the second quarter 2018 in contemplation of the sale of its Florida plants. Additionally, Southern Company Gas recorded a goodwill impairment charge of $42 million during the first quarter 2018 in contemplation of the sale of Pivotal Home Solutions.
See Notes (A) and (J) to the Condensed Financial Statements herein under "Goodwill and Other Intangible Assets" and under "Southern Power – Sale of Florida Plants" and "Southern Company Gas," respectively, for additional information.
Allowance for Equity Funds Used During Construction
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $18 | | 100.0 | | $(34) | | (25.6) |
In the third quarter 2018, AFUDC equity was $36 million compared to $18 million in the corresponding period in 2017. The increase was primarily due to a higher AFUDC rate resulting from a higher equity ratio and lower short-term borrowings at Georgia Power and a higher AFUDC base related to environmental and transmission projects at Alabama Power.
For year-to-date 2018, AFUDC equity was $99 million compared to $133 million in the corresponding period in 2017. The decrease primarily resulted from Mississippi Power's suspension of the Kemper IGCC construction in June 2017, partially offset by a higher AFUDC rate resulting from a higher equity ratio and lower short-term borrowings at Georgia Power and a higher AFUDC base related to environmental and transmission projects at Alabama Power.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
See Note 3 to the financial statements of Southern Company under "Kemper County Energy Facility" in Item 8 of the Form 10-K.
Interest Expense, Net of Amounts Capitalized
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $51 | | 12.5 | | $138 | | 11.1 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(41) | | (8.7) | | $(69) | | (7.4) |
In the thirdsecond quarter 2018,2019, interest expense, net of amounts capitalized was $458$429 million compared to $407$470 million in the corresponding period in 2017.2018. For year-to-date 2018,2019, interest expense, net of amounts capitalized was $1.4 billion$859 million compared to $1.2 billion$928 million in the corresponding period in 2017. These increases2018. 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 an increase in variable interest rates and average outstanding debt at the parent company and a $33 million net reduction in the third quarter 2017 following a settlement with the IRS related to research and experimental deductions at Mississippi Power, partially offset by a decrease in average outstanding long-term debt, primarily at Georgia Power. The year-to-date 2018 increase was also due to new debt issuances and short-term debt at Southern Company Gas and a reduction in AFUDC debt of $24 million related to the Kemper IGCC project suspension in June 2017 at Mississippi Power.parent company.
See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein, Note 68 to the financial statements of Southern Company in Item 8 of the Form 10-K, and Note (F) to the Condensed Financial Statements herein for additional information.
Other Income (Expense), Net
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(8) | | (12.3) | | $30 | | 18.2 |
For year-to-date 2018, other income (expense), net was $195 million compared to $165 million for the corresponding period in 2017. The increase was primarily due to the settlement of Mississippi Power's Deepwater Horizon claim in May 2018 and a gain from a joint-development wind project at Southern Power, which is attributable to Southern Power's partner in the project and fully offset within noncontrolling interests, partially offset by a reduction of gains from the settlement of contractor litigation claims at Southern Company Gas.
See Note (B) to the Condensed Financial Statements herein under "General Litigation Matters – Mississippi Power" and "Regulatory Matters – Southern Company Gas – Atlanta Gas Light's Pipeline Replacement Program" and Note (J) to the Condensed Financial Statements herein under "Southern Power – Development Projects" for additional information.Contents
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Income Taxes(Expense), Net
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $33 | | 5.6 | | $281 | | 88.6 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $21 | | 26.9 | | $38 | | 27.5 |
In the thirdsecond quarter 20182019, other income (expense), income taxes were $623net was $99 million compared to $590$78 million for the corresponding period in 2017. The increase was primarily due to tax expense related to the sales of Elizabethtown Gas, Elkton Gas, and Florida City Gas and the recognition of a valuation allowance on certain state tax credit carryforwards at Georgia Power, partially offset by lower federal income tax expense as well as the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation and a decrease in pre-tax earnings (excluding the gains on the sales of Elizabethtown Gas, Elkton Gas, and Florida City Gas).
2018. For year-to-date 2018,2019, other income taxes were $598(expense), net was $176 million compared to $317$138 million for the corresponding period in 2017.2018. 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 increasechange was primarily due to an increasethe reduction in pre-tax earnings primarilyin the second quarter 2018 resulting from charges recorded in 2017 related to the Kemper IGCC at Mississippi Power partially offset by the estimated probable loss oncharge associated with Plant Vogtle Units 3 and 4 at Georgiaconstruction.
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 recognizedand the reduction in pre-tax earnings in the second quarter 2018 and tax expense related to the Southern Company Gas Dispositions. This increase was partially offset by lower federal income tax expense as well as the benefitresulting from the flowback of excess deferred income taxes as a result of the Tax Reform Legislationcharge associated with Plant Vogtle Units 3 and the net state income tax benefits arising from the reorganizations of certain of Southern Power's legal entities.4 construction.
See Note (H)Notes (G) and (K) to the Condensed Financial Statements herein for additional information.
Dividends on Preferred and Preference Stock of Subsidiaries
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(6) | | (60.0) | | $(20) | | (62.5) |
In the third quarter 2018, dividends on preferred and preference stock of subsidiaries was $4 million compared to $10 million for the corresponding period in 2017. For year-to-date 2018, dividends on preferred and preference stock of subsidiaries was $12 million compared to $32 million for the corresponding period in 2017. These decreases were primarily due to the 2017 redemptions of all outstanding shares of preferred and preference stock at Georgia Power.
See Note 6 the financial statements of Southern Company under "Redeemable Preferred Stock of Subsidiaries" in Item 8 of the Form 10-K for additional information. Also see FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein for information on Mississippi Power's redemption of all of its outstanding preferred stock subsequent to September 30, 2018.
Net Income Attributable to Noncontrolling Interests
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $24 | | 80.0 | | $23 | | 47.9 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $6 | | 26.1 | | $(17) | | N/M |
N/M - Not meaningful
Substantially all noncontrolling interests relate to renewable projects at Southern Power. See Note (J)Notes 1 and 7 to the Condensed Financial Statementsfinancial statements in Item 8 of the Form 10-K under "General" and "Southern Power" hereinPower," respectively, for additional information.
In the thirdsecond quarter 2018,2019, net income attributable to noncontrolling interests was $54$29 million compared to $30$23 million for the corresponding period in 2017.2018. The increase was due to $14 million of other income allocations attributable to a joint-development wind project and $10 million of net income allocations primarily due to an allocation of approximately $26 million of income to the salenoncontrolling interest partner related to the Roserock solar facility litigation settlement, partially offset by $25 million of a 33%losses attributable to noncontrolling interests related to the tax equity interestpartnerships entered into in SPSH in 2018, the company holding substantially all2018.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2018,2019, net income attributable to noncontrolling interests was $71 millionimmaterial compared to $48$17 million for the corresponding period in 2017.2018. The increasedecrease was primarily due to $21$48 million of net income allocations due to the sale of a 33% equity interest in SPSH in 2018 and $14 million of other income allocationslosses attributable to a joint-development wind project, partially offset by a reduction of $10 million of net income allocations to other partnershipnoncontrolling interests primarily duerelated to the tax equity partnership for Gaskell West 1.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, limited projected demandfor the traditional electric operating companies, the weak pace of growth over the next several years.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 and successful additional investments in renewable and other energy projects are also major factors.
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 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, 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 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 May 20, 2018,June 13, 2019, Southern Company entered into a stock purchase agreement with NextEraPower 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, to sell all of the capital stock of Gulf Power for an aggregate cash purchase price of $5.75 billion (lessapproximately $461 million, including working capital adjustments.
On May 4, 2019, Southern Power achieved commercial operation of the amount385-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 indebtedness assumed at closing, which is currently estimated at approximately $1.3 billion),Plant Mankato to Northern States Power remains subject to (i) customary adjustments for indebtednessstate commission approvals and working capital and (ii) reduction by the amount (if any) by which Gulf Power fails to meet a specified capital expenditure target. The completion of the sale is expected to occurclose in fall 2019. If these state commission approvals are not obtained by October 1, 2019, either party has the first quarter 2019 and is subjectoption to the satisfaction or waiver
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their affiliates, and (iii) other customary closing conditions. See Note (J)terminate the sale, which, if elected, would result in the payment of a $15 million termination fee by Northern States Power to the Condensed Financial Statements under "Southern Company's Sale of Gulf Power" herein for additional information.Power. The ultimate outcome of this matter cannot be determined at this time.
On June 4, 2018, Southern Company Gas completed the stock sale of Pivotal Home Solutions to American Water Enterprises LLC for a total cash purchase price of $365 million, which includes the final working capital adjustment. This disposition resulted in an estimated net loss of $73 million, which includes $39 million of income tax expense, the calculation of which is expected to be finalized in the fourth quarter 2018. In contemplation of the transaction, a goodwill impairment charge of $42 million was recorded during the first quarter 2018.
On July 1, 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. for a total cash purchase price of $1.7 billion and an additional $40 million for working capital, subject to a final working capital adjustment expected in the fourth quarter 2018. This disposition resulted in an estimated pre-tax gain of approximately $230 million and an after-tax gain of approximately $18 million, the calculations of which are expected to be finalized in the fourth quarter 2018.
On July 29, 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI Corporation, completed the stock sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energy for a total cash purchase price of $530 million (less $3 million of indebtedness assumed at closing for customer deposits) and an additional $60 million for cash and other working capital, which includes the final working capital adjustment. This disposition resulted in an estimated pre-tax gain of approximately $121 million and an after-tax gain of approximately $20 million, the calculations of which are expected to be finalized in the fourth quarter 2018.
The after-tax impacts of the Southern Company Gas Dispositions included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
In May 2018, Southern Power completed the sale of a 33% equity interest in SPSH, a limited partnership indirectly owning substantially all of Southern Power's solar facilities, for an aggregate purchase price of approximately $1.2 billion. On October 31, 2018, Southern Power entered into agreements with three financial investors for the sale of a noncontrolling interest for approximately $1.2 billion in tax equity in SP Wind, which owns a portfolio of eight operating wind facilities. The transaction is subject to Public Utility Commission of Texas approval and is expected to close by the end of 2018. On November 5, 2018, Southern Power entered into an agreement to sell all of its equity interests in Plant Mankato (including the 385-MW expansion currently under construction) for an aggregate purchase price of $650 million. The transaction is subject to the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act and FERC and state commission approvals and is expected to close mid-2019. See Note (J) to the Condensed Financial Statements under "Southern Power" herein for additional information. 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.
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. The costs, including capital expenditures, operations and maintenance costs, and costs reflected in ARO liabilities, required to comply with environmental laws and regulations and to achieve stated goals may impact future unit retirement and replacement decisions, results of operations, cash flows, and financial condition.goals. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to the Southern Company system's transmission system.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
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major portion of these costs areis expected to be recovered through existing ratemaking provisions.retail and wholesale rates. The ultimate impact of environmental laws and regulations and the GHG goals discussed below 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. 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, 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
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Water Quality" of Southern Company in Item 7 of the Form 10-K for additional information regarding the effluent limitations guidelines (ELG) rule.
On May 2, 2018, the EPA updated its anticipated final rulemaking schedule for ELG from September 2020 to December 2019. The impact of any changes to the ELG rule will depend on the content of the final rule and the outcome of any legal challenges and cannot be determined at this time.
Coal Combustion Residuals
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" of Southern Company in Item 7 of the Form 10-K for additional information regarding the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule).
The EPA published certain amendments to the CCR Rule, which became effective August 29, 2018. These amendments extend the date from April 2019 to October 31, 2020 to cease sending CCR and other waste streams to impoundments that demonstrate compliance with all except two specified criteria. These amendments also establish groundwater protection standards for four constituents that do not have established EPA maximum contaminant levels and allow a participating state director or the EPA (where the EPA is the permitting authority) to suspend groundwater monitoring requirements under certain circumstances. Specific site impacts are being evaluated by the traditional electric operating companies.
On October 15, 2018, the U.S. Court of Appeals for the District of Columbia Circuit issued a mandate that broadens the CCR Rule to regulate previously-excluded inactive surface impoundments (legacy units) located at retired generation facilities and challenges both the ability of unlined impoundments to continue operating and the classification of clay lined units. It is anticipated that the EPA will issue a series of rulemakings to address this court action. The Southern Company system is evaluating the extent of potential impacts on legacy units but anticipates no significant impacts to its ongoing CCR strategies due to this mandate. The ultimate impact of these changes will not be known until the EPA rulemaking and any legal challenges are finalized.
In June 2018,2019, Alabama Power recorded an increase of approximately $1.2 billion$308 million to its AROs primarily related to the CCR Rule. The revised cost estimates wereRule and the related state rule based on information from feasibility studies performed on ash ponds in use
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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at plants operated by Alabama Power, including a plant jointly-owned by Mississippi Power. Duringmanagement's completion of closure designs during the second quarter 2018, Alabama Power's management completed2019 for all but two of its analysis of these studies which indicated thatash pond facilities, including one jointly owned with Mississippi Power. The additional closureestimated costs primarily related to increases in estimated ash volume, water management requirements, and design revisions, will be required to close these ash ponds under the planned closure-in-place methodology. Asmethodology primarily relate to cost inputs from contractor bids, internal drainage and dewatering system designs, and increases in the level of work becomes more defined inestimated ash volumes. The cost estimate for the remaining ash pond facilities will be updated within the next 12 months it is likely that these cost estimates will change and the change could be material.
Georgia Power continuesAs further analysis is performed and additional details are developed with respect to perform engineering studies related to its plans to close the ash ponds at all of its generating plants, including one jointly owned with Gulf Power, in compliance with federal and state CCR rules. Georgia Power also continues to refine its closure strategy and cost estimates for each ash pond and is preparing permit applications as required by the State of Georgia CCR rule. While Georgia Power and Gulf Power believe their recorded liabilities for ash pond closures, appropriately reflect their obligations under the current closure strategies they have elected, changes to such strategies and cost estimates would likely result in additional closure costs which would increase their ARO liabilities. It is not currently possible to quantify the impacts of any increase related to a change in closure strategies and/or ongoing engineering studies for the current closure strategies, and the timing of future cash outflows is indeterminable at this time; however, the impact on Georgia Power's and Gulf Power's ARO liabilities is expected to be material. As permit applications advance, engineering studies continue, and the timing of individual ash pond closures develops further during the fourth quarter 2018, Georgia Power and Gulf Power will record any necessary changes to their ARO liabilities.
The traditional electric operating companies expect to continue to periodically update their ARO cost estimates, which could increase further, as additional information becomes available.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. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
The ultimate outcome of these matters cannot be determined at this time.
Nuclear Decommissioning
See Note 16 to the financial statements of Southern Company under "Nuclear Decommissioning" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" and "Nuclear Decommissioning" herein for additional information.
In June 2018, Alabama Power completed an updated decommissioning cost site study for Plant Farley. The estimated cost
Georgia Power expects to complete updated decommissioning cost site studies for Plant Hatch and Plant Vogtle Units 1 and 2 in the fourth quarter 2018, which could result in additional changes to Southern Company's ARO liability. The ultimate outcome of these studies 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 regarding the Clean Power Plan and domestic GHG policies.
On August 31, 2018, the EPA published a proposed Clean Power Plan replacement rule known as the Affordable Clean Energy rule (ACE Rule), which would require states to develop unit-specific emission rate standards based on heat-rate efficiency improvements for existing fossil fuel-fired steam units. As proposed, combustion turbines, including natural gas combined cycles, are not affected sources. As of September 30, 2018, the Southern Company system has ownership interests in 44 fossil fuel-fired steam units to which the proposed ACE Rule is applicable. The ultimate impact of this rule to the Southern Company system is currently unknown and will depend on changesContents
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
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betweenGlobal Climate Issues
On July 8, 2019, the proposal andEPA published the final Affordable Clean Energy rule subsequent state plan developments(ACE Rule) to repeal and requirements,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 any associated legal proceedings.
Through 2017,replacement of the CPP, to the Southern Company system has achieved an estimated GHG emission reduction of 36% since 2007. In April 2018, Southern Company established an intermediate goal of a 50% reduction in carbon emissions from 2007 levels by 2030 and a long-term goal of low- to no-carbon operations by 2050. To achieve these goals, the Southern Company system expects to continue growing its renewable energy portfolio, optimize technology advancements to modernize its transmission and distribution systems, increase the use of natural gas for generation, complete construction of Plant Vogtle Units 3 and 4, invest in energy efficiency, and continue research and development efforts focusedwill depend on technologies to lower GHG emissions. The Southern Company system's ability to achieve these goals also will be dependent on many external factors, including supportive national energy policies, low natural gas prices,state implementation plan requirements and the development, deployment, and advancement of relevant energy technologies. The ultimate outcome of this matterany associated legal challenges and cannot be determined at this time.
FERCRegulatory Matters
Market-Based Rate Authority
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters – Market-Based Rate Authority" of Southern CompanyNote 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 regarding proceedings related to the traditional electric operating companies' and Southern Power's 2014 and 2017 triennial market power analyses.information.
On May 4, 2018, the FERC issued an order terminating both proceedings, finding that the traditional electric operating companies and Southern Power satisfy the FERC's standards for market-based rates. On May 9, 2018, the traditional electric operating companies and Southern Power made the compliance filing required by the order. These proceedings are concluded.
Open Access Transmission Tariff
On May 10, 2018, the Alabama Municipal Electric Authority and Cooperative Energy filed with the FERC a complaint against SCS and the traditional electric operating companies claiming that the current 11.25% base ROE used in calculating the annual transmission revenue requirements of the traditional electric operating companies' open access transmission tariff is unjust and unreasonable as measured by the applicable FERC standards. The complaint requests that the base ROE be set no higher than 8.65% and that the FERC order refunds for the difference in revenue requirements that results from applying a just and reasonable ROE established in this proceeding upon determining the current ROE is unjust and unreasonable. On June 18, 2018, SCS and the traditional electric operating companies filed their response challenging the adequacy of the showing presented by the complainants and offering support for the current ROE. On September 6, 2018, the FERC issued an order establishing a refund effective date of May 10, 2018 in the event a refund is due and initiating an investigation and settlement procedures regarding the current base ROE. Through September 30, 2018, the estimated maximum potential refund is not expected to be material to Southern Company's results of operations. The ultimate outcome of this matter 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 of the Form 10-K for additional information regarding Southern Company Gas' gas pipeline construction projects.
The Atlantic Coast Pipeline has experienced challenges to its permits since construction began earlier in 2018 and continues to work with the appropriate agencies to obtain the necessary permits. The PennEast Pipeline continues to work with state and federal agencies to obtain the required permits to begin construction. Any material permitting delays may impact forecasted capital expenditures and in-service dates. The ultimate outcome of these matters cannot be determined at this time.
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Regulatory Matters
Fuel Cost Recovery
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Fuel Cost Recovery" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Regulatory Matters – Alabama Power – Rate ECR" and "Regulatory Matters – Georgia Power – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding fuel cost recovery for the traditional electric operating companies.
The traditional electric operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect 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 32 to the financial statements of Southern Company under "Regulatory Matters"Alabama Power – Alabama Power" in Item 8 of the Form 10-KEnvironmental Accounting Order" 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.
On May 1, 2018, the Alabama PSC approved modifications to Rate RSE and other commitments designed to position Alabama Power to address the growing pressure on its credit quality resulting from the Tax Reform Legislation, without increasing retail rates under Rate RSE in the near term. Alabama Power plans to reduce growth in total debt by increasing equity, with corresponding reductions in debt issuances, thereby de-leveraging its capital structure. Alabama Power's goal is to achieve an equity ratio of approximately 55% by the end of 2025. At September 30, 2018, Alabama Power's equity ratio was approximately 47%. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" of Southern Company in Item 7 of the Form 10-K for additional information.
Rate RSE
The approved modifications to Rate RSE became effective June 2018 and are applicable for January 2019 billings and thereafter. The modifications include reducing the top of the allowed weighted common equity return (WCER) range from 6.21% to 6.15% and modifications to the refund mechanism applicable to prior year actual results. The modifications to the refund mechanism allow Alabama Power to retain a portion of the revenue that causes the actual WCER for a given year to exceed the allowed range.
In conjunction with these modifications to Rate RSE, on May 8, 2018, Alabama Power consented to a moratorium on any upward adjustments under Rate RSE for 2019 and 2020. Additionally, Alabama Power will return $50 million to customers through bill credits in 2019.
In accordance with an established retail tariff that provides for an interim adjustment to customer billings to recognize the impact of a change in the statutory income tax rate, Alabama Power has returned $151 million through September 30, 2018 and anticipates returning a total of approximately $257 million to retail customers through bill credits by December 31, 2018 as a result of the change in the federal income tax rate under the Tax Reform Legislation.
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Rate ECR
On May 1, 2018, the Alabama PSC approved an increase to Rate ECR from 2.015 cents per KWH to 2.353 cents per KWH effective July 2018 which is expected to result in additional collections of approximately $100 million through December 31, 2018. The approved increase in the Rate ECR factor will have no significant effect on Southern Company's net income, but will increase operating cash flows related to fuel cost recovery in 2018. Absent any further order from the Alabama PSC, in January 2019, the rate will return to the originally authorized 5.910 cents per KWH.
Accounting Order
On May 1, 2018, the Alabama PSC approved an accounting order that authorizes Alabama Power to defer the benefits of federal excess deferred income taxes associated with the Tax Reform Legislation for the year ending December 31, 2018 as a regulatory liability and to use up to $30 million of such deferrals to offset under recovered amounts under Rate ECR. Any remaining amounts will be used for the benefit of customers as determined by the Alabama PSC. As of September 30, 2018, Alabama Power had applied the full $30 million to offset the under recovered balance under Rate ECR and expects the total deferrals for the year ending December 31, 2018 to be approximately $50 million. See Note 5 to the financial statements of Southern Company under "Federal Tax Reform Legislation"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. See Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein and Note 3 to the financial statements of Southern Company under "Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding Georgia Power's NCCR tariff. Also see Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Fuel Cost Recovery" herein for additional information regarding Georgia Power's fuel cost recovery.
Rate Plans
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters –On June 28, 2019, Georgia Power – Rate Plans" of Southern Company in Item 7 of the Form 10-K for additional information regarding Georgia Power's 2013 ARP and the Georgia PSC's 2018 order related to the Tax Reform Legislation.
On April 3, 2018, the Georgia PSC approved a settlement agreement between Georgia Power and the staff of the Georgia PSC regarding the retail rate impact of the Tax Reform Legislation (Georgia Power Tax Reform Settlement Agreement). Pursuant to the Georgia Power Tax Reform Settlement Agreement, to reflect the federal income tax rate reduction impact of the Tax Reform Legislation, Georgia Power will refund to customers a total of $330 million through bill credits. Georgia Power issued bill credits of approximately $130 million in October 2018 and will issue bill credits of approximately $95 million in June 2019 and $105 million in February 2020. In addition, Georgia Power is deferring as a regulatory liability (i) the revenue equivalent of the tax expense reduction resulting from legislation lowering the Georgia state income tax rate from 6.00% to 5.75% in 2019 and (ii) the entire benefit of approximately $700 million in federal and state excess accumulated deferred income taxes. At September 30, 2018, Georgia Power's related regulatory liability balance totaled $655 million. The amortization of these regulatory liabilities is expected to be addressed in Georgia Power's next base rate case, which is scheduled to be filed by July 1, 2019. If there is not a base rate case in(Georgia Power 2019 customers will receive $185Base Rate Case) with the Georgia PSC. The filing includes a three-year Alternate Rate Plan with requested rate increases totaling $563 million, in annual bill credits beginning in$145 million, and $234 million effective January 1, 2020, with any additional federalJanuary 1, 2021, and state income tax savings deferred as a regulatory liability, until Georgia Power's next base rate case.January 1, 2022, respectively. These
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Toincreases 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 negative cash flow and credit metric 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 also approved an increaseto issue a final order in Georgia Power's retail equity ratio to the lower of (i) Georgia Power's actual common equity weight in its capital structure or (ii) 55%, until Georgia Power's next base rate case. At September 30, 2018, Georgia Power's actual retail common equity ratio (on a 13-month average basis) was approximately 53%. Benefits from reduced federal income tax rates in excess of the amounts refunded to customers will be retained by Georgia Power to cover the carrying costs of the incremental equity in 2018 and 2019.
Storm Damage Recovery
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.
Georgia Power is accruing $30 million annually throughthis matter on December 31, 2019, as provided in the 2013 ARP, for incremental operations and maintenance costs of damage from major storms to its transmission and distribution facilities. As of September 30, 2018, the total balance in Georgia Power's regulatory asset related to storm damage was $311 million. During October 2018, Hurricane Michael caused significant damage to Georgia Power's transmission and distribution facilities. Georgia Power currently estimates the costs of repairing the damage will total approximately $125 million to $150 million, which will be charged to Georgia Power's storm damage reserve or capitalized. The rate of storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case, which is scheduled to be filed by July 1,17, 2019. The ultimate outcome of this matter cannot be determined at this time.
Gulf PowerIntegrated Resource Plan
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Gulf Power"In 2016, the Georgia PSC approved Georgia Power's triennial Integrated Resource Plan, including recovery of Southern Companycosts up to $99 million through June 30, 2019 to preserve nuclear generation as an option at a future generation site in Item 7 ofStewart County, Georgia. In 2017, the Form 10-K for additional information.
Storm Damage Cost Recovery
On October 10, 2018, Hurricane Michael made landfall onGeorgia PSC approved Georgia Power's decision to suspend work at the Gulf Coast of Florida causing substantial damage in Gulf Power's service territory. Gulf Power currently estimates the costs of repairing the damagessite due to its transmissionchanging economics, including lower load forecasts and distribution lines and uninsured facilities will total approximately $350 million to $400 million, which primarily will be charged to Gulf Power's property damage reserve or capitalized. Gulf Power maintains a reserve for property damage to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generating facilities and other property. At September 30, 2018, Gulf Power had a balance of approximately $48 million in its property damage reserve.fuel costs. In accordance with the settlementGeorgia 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 approvedamong Georgia Power, the staff of the Georgia PSC, and certain intervenors and further modified by the FloridaGeorgia 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 April 2017 (2017 Gulfthe 2013 ARP.
For the regulatory asset balances remaining at December 31, 2019, Georgia Power requested recovery in the Georgia Power 2019 Base Rate Case Settlement Agreement), Gulf Power can petitionas follows: (i) the Florida PSC to seek recoverynet book values of the costs associated with Hurricane Michael, along with replenishing the property damage reserve to approximately $40 million. Any recovery from customers would begin, on an interim basis, 60 days following the filingPlant Mitchell Unit 3 (approximately $8
Retail Base Rate Case
As a continuation of the 2017 Gulf Power Rate Case Settlement Agreement, on March 26, 2018, the Florida PSC approved a stipulation and settlement agreement among Gulf Power and three intervenors addressing the retail revenue requirement effects of the Tax Reform Legislation (Gulf Power Tax Reform Settlement Agreement).
The Gulf Power Tax Reform Settlement Agreement results in annual reductions to Gulf Power's revenues of $18.2 million from base rates and $15.6 million from environmental cost recovery rates implemented April 1, 2018 and also provided for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to normalization) deferred tax liabilities through a reduced fuel cost recovery rate over the remainder of 2018. Through September 30, 2018, approximately $53 million of this refund has been reflected in customer bills. As a result of theContents
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Gulf Power Tax Reform Settlement Agreement,million at June 30, 2019) and Plant McIntosh Unit 1, any unusable materials and supplies inventory, and the Florida PSC also approved an increasefuture generation site in Gulf Power's maximum equity ratio from 52.5% to 53.5% for all retail regulatory purposes.
As partStewart County, Georgia over a three-year period ending December 31, 2022 and (ii) the net book values of the Gulf Power Tax Reform Settlement Agreement,Plant Hammond Units 1 through 4 over a limited scope proceeding to address protected deferred tax liabilities consistent with IRS normalization principles was initiated on April 30, 2018. On October 30, 2018, the Florida PSC approved a $9.6 million annual reduction in base rate revenues effective January 2019, which concluded this proceeding. Through September 30, 2018, Gulf Power has deferred $7 million of related 2018 tax benefits as a regulatory liability to be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rate.
Mississippi Power
On February 7, 2018, Mississippi Power submitted its revised 2018 projected PEP filingperiod equal to the Mississippiapplicable 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 which reflectedrejected a request to certify approximately 25 MWs of capacity at Plant Scherer Unit 3 for the impactsretail jurisdiction beginning January 1, 2020 following the expiration of a wholesale PPA. Georgia Power may offer such capacity in the Tax Reform Legislation, requesting an increase in annual retail revenues of $26 million based on a performance-adjusted ROE of 9.33% and an increased equity ratio of 55%.
On July 27, 2018, Mississippi Power and the Mississippi Public Utilities Staff (MPUS) entered into a settlement agreement with respectwholesale market or to the 2018 PEP filing and all unresolved PEP filings for prior years (PEP Settlement Agreement), which was approved by the Mississippi PSC on August 7, 2018. Rates under the PEP Settlement Agreement became effective with the first billing cycle of September 2018. The PEP Settlement Agreement provides for an increase of approximately $21.6 millionretail jurisdiction in annual base retail revenues, which excludes certain compensation costs contested by the MPUS, as well as approximately $2 million which was subsequently approved for recovery through a separate Mississippi Power cost rider. Under the PEP Settlement Agreement, Mississippi Power is deferring the contested compensation costs for 2018 and 2019 as a regulatory asset. The Mississippi PSC is currently expected to rule on the appropriate treatment for such costs in connection with Mississippi Power's next base rate case, which is scheduled to be filed in the fourth quarter 2019 (2019 Base Rate Case).future Integrated Resource Plan. The ultimate outcome of this matter cannot be determined at this time.time but is not expected to have a material impact on Southern Company's financial statements.
Pursuant toAdditionally, the PEP Settlement Agreement, MississippiGeorgia PSC approved Georgia Power's performance-adjusted allowed ROE is 9.31%proposed environmental compliance strategy associated with ash pond and its allowed equity ratio remains at 50%, pending further review bycertain landfill closures and post-closure care in compliance with the Mississippi PSC. In lieu ofCCR Rule and the requested equity ratio increase, Mississippi Power retained $44 million of excess accumulated deferred income taxes resulting from the Tax Reform Legislation, which had been proposed to be amortized beginning in 2018, until the conclusion of the 2019 Base Rate Case. Further, Mississippi Power will seek equity contributions sufficient to restore its equity ratio (which was 45% at September 30, 2018) to 50% by December 31, 2018.related state rule. In the event Mississippi Power's actual average equity ratio for 2018 is more than 1% higher or lower than the 50% target, MississippiGeorgia Power will defer the corresponding difference in its revenue requirement as a regulatory asset or liability for resolution in the 2019 Base Rate Case.
Pursuant to the PEP Settlement Agreement, PEP proceedings are suspended until after the conclusion of the 2019 Base Rate Case, and MississippiGeorgia Power is not required to make any PEP filings for regulatory years 2018, 2019, and 2020. The PEP Settlement Agreement also resolved all open PEP filings with no change to customer rates. As a result, in the third quarter 2018, Mississippi Power recognized revenues of $5 million previously reserved in connection with the 2012 PEP lookback filing.
Southern Company Gas
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Southern Company Gas" of Southern Company in Item 7requested recovery of the Form 10-Kunder 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 (B) to the Condensed Financial Statements under "Regulatory Matters – Southern Company Gas" herein for additional information.
On February 23, 2018, Atlanta Gas Light revised its annual base rate filing to reflect the impacts of the Tax Reform Legislation and requested a $16 million rate reduction in 2018. On May 15, 2018, the Georgia PSC approved a stipulation for Atlanta Gas Light's annual base rates to remain at the 2017 level for 2018 and 2019, with customer credits of $8 million in each of July 2018 and October 2018 to reflect the impacts of the Tax Reform Legislation.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
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The Georgia PSC maintained Atlanta Gas Light's previously authorized earnings band based on a ROE between 10.55% and 10.95% and increased the allowed equity ratio by 4% to an equity ratio of 55% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation. Additionally, Atlanta Gas Light is required to file a traditional base rate case on or before June 1, 2019 for rates effective January 1, 2020.
On May 2, 2018, the Illinois Commission approved Nicor Gas' rehearing request for revised base rates to incorporate the reduction in the federal income tax rate as a result of the Tax Reform Legislation. The resulting decrease of approximately $44 million in annual base rate revenues became effective May 5, 2018. Nicor Gas' previously-authorized capital structure and ROE of 9.8% were not addressed in the rehearing and remain unchanged.
Kemper County Energy Facility
For additional information on the Kemper County energy facility, see Note 36 to the financial statements of Southern Company under "Kemper County Energy Facility" in Item 8 of the Form 10-K.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, for the Kemper County energy facility, Liberty Fuels Company, LLC has a legal obligation to perform mine reclamation, and Mississippi Power has a contractual obligation to fund all reclamation activities. MineAs 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 firstfinancial statements in Item 8 of the Form 10-K for additional information.
During the second quarter 2018.
As of September 30, 2018,and year-to-date 2019, Mississippi Power recorded pre-tax charges to income of an immaterial amount for the third quarter 2018 and $45$4 million ($343 million after tax) for year-to-date 2018,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 to costat up to $20$10 million pre-tax (excluding salvage,dismantlement costs, net of dismantlement costs)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 $2$7 million for the remainder of 2018, $8 million in 2019 and $4$2 million to $6 million annually beginning in 2020. The ultimate outcome2020 through 2023.
In addition, Mississippi Power constructed the CO2 pipeline for the planned transport of this matter cannot be determined at this time.
The combined cyclecaptured CO2 for use in enhanced oil recovery and associated common facilities portionsis currently evaluating its options regarding the final disposition of the Kemper County energy facility were dedicated as Plant RatcliffeCO2 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 April 27, 2018.Southern Company's financial statements.
Reserve Margin Plan
On August 6,In December 2018, Mississippi Power filed with the DOE its proposed Reserve Margin Plan (RMP), as requiredrequest 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 Mississippi PSC's order inDOE closeout discussions, on April 29, 2019, the docket established for the purposes of pursuing a global settlementCivil Division of the costsDepartment 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. Under the RMP, Mississippi Power proposes alternatives that would reduce its reserve margin, with the most economic of the alternatives being the two-year and seven-year acceleration of the retirement of Plant Watson Units 4 and 5, respectively, to the first quarter 2022 and the four-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively, in order to lower or avoid operating costs. The Plant Greene County unit retirements would require the completion by Alabama Power of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. The RMP filing also states that, in the event the Mississippi PSC ultimately approves an alternative that includes an accelerated retirement, Mississippi Power would require authorization to defer in a regulatory asset for future recovery the remaining net book value of the units at the time of retirement. Mississippi Power expects the MPUS and other interested parties to review the proposal prior to resolution by the Mississippi PSC. The ultimate outcome of this matterthese matters cannot be determined at this time. However, if approvedtime; 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 Mississippi PSC,relevant regulatory agencies in the alternativesstates 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 have any adverse impactrule on customer rates.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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
its strategy of developing and constructing new electric generating facilities, 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 32 and 12
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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15 to the financial statements of Southern Company under "Regulatory Matters – Southern"Southern Company Gas – Regulatory Infrastructure Programs"Replacement Programs and Capital Projects" and "Southern Power, – Construction Projects in Progress," respectively, in Item 8 of the Form 10-K and Note (J)(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 32 to the financial statements of Southern Company under "Nuclear"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 32 to the financial statements of Southern Company under "Nuclear"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 the Interim Assessment Agreement with the EPC Contractorseveral transitional arrangements to allow construction to continue. The Interim Assessment Agreement expired inIn July 2017, when Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Vogtle Services Agreement. Under 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 between Georgia Power and the DOE, Georgia Power is required to obtain the DOE's approval
In December 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor.SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
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Cost and Schedule
In preparation for its nineteenth VCM filing, Georgia Power requested Southern Nuclear to perform a full cost reforecast for the project. 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) | (in billions) |
Base project capital cost forecast(a)(b) | $ | 8.0 |
| $ | 8.0 |
|
| Construction contingency estimate | 0.4 |
| 0.4 |
|
Total project capital cost forecast(a)(b) | 8.4 |
| 8.4 |
|
Net investment as of September 30, 2018(b) | (4.3 | ) | |
Net investment as of June 30, 2019(b) | | (5.2 | ) |
Remaining estimate to complete(a) | $ | 4.1 |
| $ | 3.2 |
|
| |
| (a) | Excludes financing costs expected to be capitalized through AFUDC of approximately $350$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 $3.2$3.1 billion, of which $1.8$2.0 billion had been incurred through SeptemberJune 30, 2018.2019.
The table above reflectsIn 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 $0.7 billion increase to the baseestimated total project capital cost forecast reported in the second quarter 2018 and is based on the cost reforecast performed prior to the nineteenth VCM filing, which primarily resulted from changed assumptions related to the finalization of contract scopes and management responsibilities for Bechtel and over 60 subcontractors, labor productivity rates, and craft labor incentives, as well as the related levels of project management, oversight, and support, including field supervision and engineering support.
Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC's order in the seventeenth VCM proceeding specifically states that the construction of Plant Vogtle Units 3 and 4. The expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4, is not subject to a cost cap, Georgia Power did not seek rate recovery for these cost increases included in the current base capital cost forecast (or any related financing costs) in the nineteenth VCM report that was filed withas previously approved by the Georgia PSC, on August 31, 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs currently included in the construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018, which includes the total increase in the base capital cost forecast and construction contingency estimate.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, availability,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, andor 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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
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issues could arise and change the projected schedule and estimated cost. Monthly
The April 2019 cost and schedule validation process established target values for monthly construction production targets requiredand system turnover activities as part of a strategy to maintain and, where possible, build margin to the current project scheduleapproved in-service dates. To support that strategy, monthly production and activity target values will continue to increase significantly through the remainder of 2018 and intothroughout 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 resolutionsubmittal by Southern Nuclear of Inspections, Tests, Analyses, and Acceptance Criteria (ITAAC)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 31, 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 as described above,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. OnIn September 26, 2018, the Vogtle Owners unanimously voted to continue construction of Plant Vogtle Units 3 and 4.
AmendmentsRegulatory Matters
See Note 2 to the Vogtle Joint Ownership Agreementsfinancial 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 connectionaddition, 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 voteAlabama PSC. The asset retirement costs are being recovered through 2055. See Note 2 to continue construction,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 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 PTCscurrently recovers its costs from the other Vogtle Owners,regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, Environmental Compliance Cost Recovery (ECCR) tariffs, and (ii) a term sheet (MEAG Term Sheet and, together with the Vogtle Owner Term Sheet, Term Sheets) with MEAG and MEAG SPVJMunicipal Franchise Fee tariffs. In addition, financing costs related to provide funding with respect to MEAG SPVJ's ownership interest incertified construction costs of Plant Vogtle Units 3 and 4 (Project J) under certain circumstances. Pursuant toare being collected through the Vogtle Owner Term Sheet,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 Vogtle Joint Ownership Agreements will be modified as follows: (i) each Vogtle Owner will pay its proportionate shareGeorgia 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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3increases are based on a proposed retail ROE of 10.90% and 4 which formsa proposed equity ratio of 56% and reflect levelized revenue requirements during the basisthree-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 forecastfiling primarily reflects requests to (i) address the impacts of $8.4 billionthe 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 nineteenth VCM plus $800 millionevent earnings are projected to fall below the bottom of additional construction costs; (ii) the ROE range during the three-year term of the plan.
Georgia Power willexpects the Georgia PSC to issue a final order in this matter on December 17, 2019. The ultimate outcome of this matter cannot be responsible for 55.7% of actual qualifying construction costs between $800 million and $1.6 billion overdetermined at this time.
Integrated Resource Plan
In 2016, the EAC in the nineteenth VCM (resulting in $80 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests; and (iii) Georgia Power will be responsible for 65.7% of qualifying construction costs between $1.6 billion and $2.1 billion over the EAC in the nineteenth VCM (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests.
If the EAC is revised and exceeds the EAC in the nineteenth VCM by more than $2.1 billion, each of the other Vogtle Owners will have a one-time option to tender a portion of its ownership interest to Georgia Power in exchange forPSC approved Georgia Power's agreementtriennial Integrated Resource Plan, including recovery of costs up to pay 100% of such Vogtle Owner's remaining share of total construction costs$99 million through June 30, 2019 to preserve nuclear generation as an option at a future generation site in excess ofStewart County, Georgia. In 2017, the EAC inGeorgia PSC approved Georgia Power's decision to suspend work at the nineteenth VCM plus $2.1 billion.site due to changing economics, including lower load forecasts and fuel costs. In this event, Georgia Power will have the option of cancelling the project in lieu of purchasing a portion of the ownership interest of any other Vogtle Owner. If Georgia Power accepts the offer to purchase a portion of another Vogtle Owner's ownership interest in Plant Vogtle Units 3 and 4, the ownership interest(s) to be conveyed from the tendering Vogtle Owner(s) to Georgia Power would be calculated based on the proportion of the cumulative amount of construction costs paid by each such tendering Vogtle Owner(s) and by Georgia Power as of the commercial operation date of Plant Vogtle Unit 4. For purposes of this calculation, payments made by Georgia Power on behalf of another Vogtle Owner in accordance with the secondGeorgia 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 third items described in the paragraph above would be treated as payments madecertain intervenors and further modified by the applicable Vogtle Owner.Georgia PSC.
In the event the actual costs at completion are less than the EAC reflected in the nineteenth VCM report and Plant Vogtle Unit 3 is placed in service by the currently scheduled date of November 2021 or Plant Vogtle Unit 4 is placed in service by the currently scheduled date of November 2022, Georgia Power would be entitled to 60.7% of the cost savings with respect to the relevant unit and the remaining Vogtle Owners would be entitled to 39.3% of such savings on a pro rata basis in accordance with their respective ownership interests.
For purposes of the foregoing provisions, qualifying construction costs would not include costs (i) resulting from force majeure events, including governmental actions or inactions (or significant delays associated with issuance of such actions) that affect the licensing, completion, startup, operations, or financing of Plant Vogtle Units 3 and 4, administrative proceedings or litigation regarding ITAAC or other regulatory challenges to commencement of operation of Plant Vogtle Units 3 and 4, and changes in laws or regulations governing Plant Vogtle Units 3 and 4, (ii) legal fees and legal expenses incurred due to litigation with contractors or subcontractors that are not subsidiaries or affiliates of Southern Company, and (iii) additional costs caused by Vogtle Owner requests other than Georgia Power, except for the exercise of a right to vote granted under the Vogtle Joint Ownership Agreements, that increase costs by $100,000 or more.
Georgia Power is working with the other Vogtle Owners to clarify any interpretive issues related to the operation of certain of the above provisions of the Vogtle Owner Term Sheet.
Under the Vogtle Owner Term Sheet, the provisions of the Vogtle Joint Ownership Agreements requiring that Vogtle Owners holding 90% of the ownership interests in Plant Vogtle Units 3 and 4 vote to continue construction following certain adverse events (Project Adverse Events) will be modified. Pursuant to the Vogtle Joint Ownership Agreements and the Vogtle Owner 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 Project Adverse Events occur, including: (i) the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power publicly announces its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 or2019 IRP, the Georgia PSC determines that any of Georgia Power's costs relating toapproved the constructiondecertification and retirement of Plant VogtleHammond Units 31 through 4 (840 MWs) and 4Plant 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 not be recoveredcontinue through December 31, 2019 as provided in retail rates, excluding any additional amounts paid bythe 2013 ARP.
For the regulatory asset balances remaining at December 31, 2019, Georgia Power on behalf of the other Vogtle Owners pursuant to the Vogtle Owner Term Sheet provisions described above and the first 6% of costs during any six-month VCM reporting period that are disallowed byrequested recovery in the Georgia PSC for recovery, or forPower 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
whichmillion at June 30, 2019) and Plant McIntosh Unit 1, any unusable materials and supplies inventory, and the future generation site in Stewart County, Georgia Power elects not to seek cost recovery,over a three-year period ending December 31, 2022 and (ii) the net book values of Plant Hammond Units 1 through retail rates; and (iv) an incremental extension of one year or more4 over the most recently approved schedule. Under the Vogtle Owner Term Sheet, Georgia Power may cancel the project at any time in its sole discretion.
In addition, pursuanta period equal to the Vogtle Joint Ownership Agreements, 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 Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement.
The Vogtle Owner Term Sheet provides that if the holders of at least 90% of the ownership interests fail to vote in favor of continuing the project following any future Project Adverse Event, work on Plant Vogtle Units 3 and 4 would continue for a period of 30 days if the holders of more than 50% of the ownership interests vote in favor of continuing construction (Majority Voting Owners). In such a case, the Vogtle Owners (i) would agree to negotiate in good faith towards the resumption of the project, (ii) if no agreement was reached during such 30-day period, the project would be cancelled, and (iii) in the event of such a cancellation, the Majority Voting Owners would be obligated to reimburse any other Vogtle Owner for the costs it incurred during such 30-day negotiation period.
Purchase of PTCs During Commercial Operation
In addition, under the terms of the Vogtle Owner Term Sheet, Georgia Power agreed to purchase additional PTCs from OPC, Dalton, MEAG SPVM, MEAG SPVP, and MEAG SPVJ (to the extent any MEAG SPVJ PTC rights remain after any purchases required under the MEAG Term Sheet as described below) at varying purchase prices dependent upon the actual cost to complete construction of Plant Vogtle Units 3 and 4 as compared to the EAC included in the nineteenth VCM report. The purchases will be at the option of the applicable Vogtle Owner and will occur during the month after such PTCs are earned.
Potential Funding to MEAG Project J
Pursuant to the MEAG Term Sheet, if MEAG SPVJ is unable to make its payments due under the Vogtle Joint Ownership Agreements solely because (i) the conduct of JEA, such as JEA's legal challenges of its obligations under a PPA with MEAG (PPA-J), materially impedes access to capital markets for MEAG for Project J, or (ii) PPA-J is declared void by a court of competent jurisdiction or rejected by JEA under the applicable provisions of the U.S. Bankruptcy Code (each of (i) and (ii), a JEA Default), Georgia Power would purchase from MEAG SPVJ the rights to PTCs attributable to MEAG SPVJ's share of Plant Vogtle Units 3 and 4 (approximately 206 MWs) at varying prices dependent upon the stage of construction of Plant Vogtle Units 3 and 4. The aggregate purchase price of the PTCs, together with any advances made as described in the next paragraph, shall not exceed $300 million.
At the option of MEAG, as an alternative or supplement to Georgia Power's purchase of PTCs as described above, Georgia Power has agreed to provide up to $250 million in funding to MEAG for Project J in the form of advances (either advances under the Vogtle Joint Ownership Agreements or the purchase of MEAG Project J bonds, at the discretion of Georgia Power), subject to any required approvals of the Georgia PSC and the DOE.
In the event MEAG SPVJ certifies to Georgia Power that it is unable to fund its obligations under the Vogtle Joint Ownership Agreements as a result of a JEA Default and Georgia Power becomes obligated to provide funding as described above, MEAG is required to (i) assign to Georgia Power its right to vote on any future Project Adverse Event and (ii) diligently pursue JEA for its breach of PPA-J. In addition, Georgia Power agreed that it will not sue MEAG for any amounts due from MEAG SPVJ under MEAG's guarantee of MEAG SPVJ's obligations so long as MEAG SPVJ complies with the terms of the MEAG Term Sheet as to its payment obligations and the other provisions of the Vogtle Joint Ownership Agreements.
Under the terms of the MEAG Term Sheet, Georgia Power may decline to provide any funding in the form of advances, including in the event of a failure to receive any required Georgia PSC or DOE approvals, and cancel the project in lieu of providing such funding.
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.
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
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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
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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
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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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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 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. As of SeptemberAt June 30, 2018,2019, Georgia Power had recovered approximately $1.8$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 Power expects to file on November 9, 2018PSC approved Georgia Power's request to increase the NCCR tariff by approximately $90$88 million annually, effective January 1, 2019, pending Georgia PSC approval.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
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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) certain recommendations made by Georgia Power in thePower's seventeenth VCM report and modifyingmodified 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 unitUnit is commercially operational. The ROE reductions negatively impacted earnings by approximately $25$100 million in 20172018 and are estimated to have negative earnings impacts of approximately $100$70 million in 20182019 and an aggregate of $680approximately $630 million from 20192020 to 2022.
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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.
OnIn February 12, 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. OnIn March 8, 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's final 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 two appeals haveappeal has no merit; however, an adverse outcome in eitherthe 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.
The Georgia PSC has approved eighteen VCM reports covering the periods through December 31, 2017, including total construction capital costs incurred through that date of $4.9 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds). OnIn August 31, 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
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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 Southern Company in Item 1A herein and in 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
As of SeptemberAt June 30, 2018,2019, 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. In September 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. In September 2018, the DOE extended the conditional commitment to March 31, 2019. Any further extension must be approved by the DOE. 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 Southern Company under "DOE"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, (including any decision not to continue construction of Plant Vogtle Units 3 and 4), and conditions to borrowing.
The ultimate outcome of these matters cannot be determined at this time.
Income TaxOther Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax "Other Matters" of Southern Company in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk," Note (B) to the Condensed Financial Statements under "Regulatory Matters," and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation and related regulatory actions.additional information.
Southern Power
In April 2018, Southern Power completed the final stage of a legal entity reorganization of various direct and indirect subsidiaries that own and operate substantially all of its solar facilities, including certain subsidiaries owned in partnership with various third parties. The reorganization resulted in net state tax benefits related to certain changes in apportionment rates totaling approximately $54 million, which were recorded in the first half of 2018.
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In September 2018, Southern Power also completed a legal reorganization of eight operating wind facilities under a new holding company, SP Wind, which resulted in net state tax benefits totaling approximately $11 million related to certain changes in apportionment rates.
Other Matters
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 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, 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 October 2, 2018, the Mississippi PSC approved executed agreements between Mississippi Power and its largest retail customer, Chevron, for Mississippi Power to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038. The new agreements are not expected to have a material impact on earnings.
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Litigation
In 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 to include, among other things, Southern Company as a defendant. The individual plaintiff alleged that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs 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 County energy facility and that these alleged breaches unjustly enriched Mississippi Power and Southern Company. The plaintiffs sought unspecified actual damages and punitive damages; asked the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper County energy facility; asked the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper County energy facility in Mississippi; and sought attorney's fees, costs, and interest. The plaintiffs also sought an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. In June 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. In July 2017, the plaintiffs filed notice of an appeal. On July 13, 2018, Mississippi Power and Southern Company reached a settlement agreement with the plaintiffs and the plaintiffs' appeal was dismissed with prejudice. The settlement had no material impact on Southern Company's financial statements.
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 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 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 June 2017, the plaintiffs filed an amended
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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. In JulyAlso in 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition in September 2017. Onopposition. In March 29, 2018, the U.S. District Court for the Northern District of Georgia, Atlanta Division,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. OnIn April 26, 2018, the defendants filed a motion for reconsideration of the court's order, seeking dismissal of the remaining claims in the lawsuit. OnIn August 10, 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 and, in May 2017, Judy Mesirov filed a shareholder derivative lawsuit, each 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 August 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. OnIn April 25, 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, State of Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper 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. OnIn May 4, 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.
OnIn May 18, 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 September 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.
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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. Southern Company will vigorously defend itself in these matters, theThe ultimate outcome of whichthese matters cannot be determined at this time.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIESMississippi Power
MANAGEMENT'S DISCUSSION AND ANALYSIS OFIn 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.
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Investments in Leveraged LeasesSouthern Company Gas
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters – Investments in Leveraged Leases" of Southern Company in Item 7 and Note 13 to the financial statements of Southern Company under "Leveraged Leases" in Item 8 of the Form 10-K for additional information regarding the leveraged lease agreements of a subsidiary ofunder "Other Matters – Southern Company Holdings Inc. (Southern Holdings)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 concerns aboutTexas, could be impacted by ongoing changes in the financialU.S. natural gas storage market. Recent sales of natural gas storage facilities have resulted in losses for the sellers and operational performance ofmay 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 lessees and the associated generation assets.
The abilitysalt dome caverns in Louisiana back to service in 2021. Sustained diminished natural gas storage values could trigger impairment of the lessees to make required payments to the Southern Holdings subsidiary is dependent on the operational performanceone or all of the assets. Asthese natural gas storage facilities, which have a result of operational improvements in the first half of 2018, the June 2018 lease payment was paid in full and the December 2018 lease payment is currently expected to be paid in full. However, operational issues and the resulting cash liquidity challenges persist and significant concerns continue regarding the lessee's ability to make the remaining semi-annual lease payments. These operational challenges may also impact the expected residualcombined net book value of the assets$438 million at the end of the lease term in 2047. If any future lease payment is not paid in full, the Southern Holdings subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. Failure to make the required payment to the debtholders would represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the generation assets from the Southern Holdings subsidiary, in effect terminating the lease and resulting in the write-off of the related lease receivable, which would result in a reduction in net income of approximately $86 million after tax based on the lease receivable balance as of SeptemberJune 30, 2018. Southern Company has evaluated the recoverability of the lease receivable and the expected residual value of the generation assets at the end of the lease under various scenarios and has concluded that its investment in the leveraged lease is not impaired as of September 30, 2018. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments.2019. The ultimate outcome of this matterthese matters cannot be determined at this time.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 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
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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.
Estimated Cost, Schedule, and Rate Recovery for the Construction of Plant Vogtle Units 3 and 4
In December 2016, the Georgia PSC approved the Vogtle Cost Settlement Agreement, which resolved certain prudency matters in connection with Georgia Power's fifteenth VCM report. In December 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor, as well as a modification of the Vogtle Cost Settlement Agreement. The Georgia PSC's related order stated that under the modified Vogtle Cost Settlement Agreement, (i) none of the $3.3 billion of costs incurred through December 31, 2015 should be disallowed as imprudent; (ii) 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; (iii) Georgia Power would have the burden of proof to show that any capital costs above $5.68 billion were prudent; (iv) Georgia Power's total project capital cost forecast of $7.3 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds) was found reasonable and did not represent a cost cap; and (v) prudence decisions would be made subsequent to achieving fuel load for Unit 4.
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In its 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 the second quarter 2018, Georgia Power revised its base 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). Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC has stated the $7.3 billion estimate included in the seventeenth VCM proceeding does not represent a cost cap, Georgia Power did not seek rate recovery for the $0.7 billion increase in costs included in the revised base capital cost forecast in the nineteenth VCM report filed with the Georgia PSC on August 31, 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs included in the revised construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018.
Georgia Power's revised cost estimate reflects an expected in-service date of November 2021 for Unit 3 and November 2022 for Unit 4.
As construction continues, challenges with management of contractors, subcontractors, and vendors; labor productivity, availability, and/or cost escalation; procurement, fabrication, delivery, assembly, and/or installation, including any required engineering changes, of plant systems, structures, and components (some of which are based on new technology that only recently began initial operation in the global nuclear industry at this scale); or other issues could arise and change the projected schedule and estimated cost. Monthly construction production targets required to maintain the current project schedule continue to increase significantly through the remainder of 2018 and into 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers 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 resolution of ITAAC and the related approvals by the NRC, 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. Any extension of the in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4 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.
Given the significant complexity involved in estimating the future costs to complete construction and start-up of Plant Vogtle Units 3 and 4 and the significant management judgment necessary to assess the related uncertainties surrounding future rate recovery of any projected cost increases, as well as the potential impact on Southern Company's results of operations and cash flows, Southern Company considers these items to be critical accounting
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estimates. See Note 3 to the financial statements of Southern Company under "Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information.
Recently Issued Accounting Standards
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Southern Company in Item 7 of the Form 10-K for additional information regarding ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). See Note (A) to the Condensed Financial Statements herein for information regarding Southern Company's recently adopted accounting standards.
In 2016, the FASB issued ASU No. 2016-02, which requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for existing leveraged leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and Southern Company will adopt the new standard effective January 1, 2019.
Southern Company has elected the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby it will apply the requirements of ASU 2016-02 on a prospective basis as of the adoption date of January 1, 2019, without restating prior periods. Southern Company expects to elect the package of practical expedients provided by ASU 2016-02 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Southern Company expects to apply the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and to elect the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed. Southern Company also expects to make accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and to combine lease and non-lease components in the computations of lease obligations and right-of-use assets for most asset classes.
The Southern Company system is continuing to complete the implementation of an information technology system to track and account for its leases and of changes to its internal controls and accounting policies to support the accounting for leases under ASU 2016-02. The Southern Company system has substantially completed its lease inventory and determined its most significant leases involve PPAs, real estate, and communication towers where certain of Southern Company's subsidiaries are the lessee and PPAs where certain of Southern Company's subsidiaries are the lessor. While Southern Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to result in recording lease liabilities and right-of-use assets on Southern Company's balance sheet each totaling approximately $2.1 billion, with no material impact on Southern Company's statement of income.
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, 2018.2019. 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 $5.6$2.5 billion for the first ninesix months of 2018, an increase2019, a decrease of $0.3$0.7 billion from the corresponding period in 2017.2018. The increasedecrease in net cash provided from operating activities was primarily due to increased fuel cost recovery and 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 $3.5$1.0 billion for the first ninesix months of 20182019 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
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generation, transmission, and distribution facilities and capital expenditures for Southern Company Gas' infrastructure replacement programs, partially offset by proceeds from the Southern Company Gas Dispositions.programs. Net cash used for financing activities totaled $2.3$3.6 billion for the first ninesix months of 20182019 primarily due to repayments of short-term bank debt, net redemptions and repurchases of long-term debt, and common stock dividend payments, and a decrease in commercial paper borrowings, partially offset by net issuances of short-term bank debt, proceeds from Southern Power's sale of a 33% equity interest in a limited partnership indirectly owning substantially all of its solar facilities, and the issuance of common stock.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 2018 include the reclassification of $5.1 billion and $3.2 billion2019 include:
decreases in total assets and liabilities held for sale of $5.0 billion and $3.2 billion, respectively, primarily associated withrelated to the sale of Gulf Power, as well as decreasesPower;
an increase of $2.8 billion and $0.4$2.1 billion in total assets and liabilities, respectively, associated with the Southern Company Gas Dispositions. See Note (J)stockholders' equity primarily related to the Condensed Financial Statements under "Assets Held for Sale" and "Southern Company Gas" herein for additional information. After adjusting for these changes, other significant balance sheet changes include gain on the sale of Gulf Power;
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| • | 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 $4.0$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, as well as an increase in AROs at Alabama Power, partially offset by the second quarter 2018 chargeAlabama Power's reclassification of $1.4 billion to regulatory assets related to the constructionretirement of Plant Vogtle Units 3Gorgas, including $0.7 billion associated with AROs;
decreases of $1.5 billion in notes payable and 4; a decrease of $2.6$1.1 billion in long-term debt (including amounts due within one year) resulting from the repaymentrelated to net repayments of short-term bank debt and long-term debt; debt, respectively; and
an increase of $1.8$1.2 billion in noncontrolling interestsaccumulated deferred income taxes primarily related to Southern Power'sthe expected utilization of tax credit carryforwards in the 2019 tax year as a result of increased taxable income from the sale of a 33% equity interest in a limited partnership indirectly owning substantially allGulf Power.
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See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Alabama Power" herein and an increase of $1.5 billion in ARO liabilities primarily related to revised estimates for ash pond closure costs at Alabama Power to comply with the CCR Rule. See Notes (A), (B), (F), (G), (K), and (J)(L) to the Condensed Financial Statements under "Asset Retirement Obligations," "Nuclear Construction," "Financing Activities," and "Southern Power – Sale of Solar Facility Interests," respectively, herein for additional information.
At the end of the thirdsecond quarter 2018,2019, the market price of Southern Company's common stock was $43.60$55.28 per share (based on the closing price as reported on the New York Stock Exchange)NYSE) and the book value was $24.18$25.73 per share, representing a market-to-book ratio of 180%215%, compared to $48.09, $23.99,$43.92, $23.91, and 201%184%, respectively, at the end of 2017.2018. Southern Company's common stock dividend for the thirdsecond quarter 20182019 was $0.60$0.62 per share compared to $0.58$0.60 per share in the thirdsecond quarter 2017.2018.
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. Subsequent to September 30, 2018, Mississippi Power completed the redemption of $30 million aggregate principal amount of its Series G 5.40% Senior Notes due July 1, 2035 and $125 million aggregate principal amount of its Series 2009A 5.55% Senior Notes due March 1, 2019, Alabama Power purchased and held $120 million of pollution control revenue bonds, and Southern Company Gas Capital repaid at maturity $155 million aggregate principal amount of 3.50% Series B Senior Notes. An additional $2.6Approximately $3.1 billion will be required through SeptemberJune 30, 20192020 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.
The Southern Company system's construction program is currently estimated to total approximately $8.8 billion for 2018, $8.2 billion for 2019, $7.2 billion for 2020, $7.0 billion for 2021, and $6.7 billion for 2022. These amounts include expenditures of approximately $1.4 billion, $1.4 billion, $0.9 billion, $1.0 billion, and $0.6 billion for the construction of Plant Vogtle Units 3 and 4 in 2018, 2019, 2020, 2021, and 2022, respectively, and an average of approximately $0.5 billion per year for 2018 through 2022 for Southern Power's planned expenditures for plant acquisitions and placeholder growth, as revised subsequent to Tax Reform Legislation. These amounts also include capital expenditures related to contractual purchase commitments for nuclear fuel, capital expenditures covered under LTSAs, and costs, which are immaterial to Southern Company, relating to assets divested during 2018 and held for sale at September 30, 2018. Estimated capital expenditures to comply with environmental laws and
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regulations included in these amounts are $1.1 billion, $0.3 billion, $0.4 billion, $0.5 billion, and $0.5 billion for 2018, 2019, 2020, 2021, and 2022, respectively. These estimated expenditures do not include any potential compliance costs associated with pending regulation of CO2 emissions from fossil fuel-fired electric generating units.
The traditional electric operating companies also anticipate costs associated with closure and monitoring of ash ponds in accordance with the CCR Rule, which are reflected in Southern Company's ARO liabilities. These costs, which are expected to change as the Southern Company system continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities, are currently estimated to be approximately $0.3 billion, $0.4 billion, $0.5 billion, $0.6 billion, and $0.5 billion for 2018, 2019, 2020, 2021, and 2022, respectively. For information regarding expected changes to these cost estimates during the fourth quarter 2018, see FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein. Also see Note 1 to the financial statements of Southern Company under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information on AROs.
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 1215 to the financial statements of Southern Company under "Southern Power" in Item 8 of the Form 10-K and Note (J)(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,productivity; challenges with management of contractors, subcontractors, or vendors,vendors; adverse weather conditions,conditions; shortages, anddelays, increased costs, or inconsistent quality of equipment, materials, and labor,labor; contractor or supplier delay, non-performancedelay; nonperformance under construction, operating, or other agreements,agreements; operational readiness, including specialized operator training and required site safety programs, unforeseenprograms; engineering or design problems,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, (includingincluding major equipment failure, and system integration),integration, or regional transmission upgrades; and/or operational performance. See Note 32 to the financial statements of Southern Company under "Nuclear"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. Southern Company also plans to utilize the proceeds from the disposition of Gulf Power when completed for future capital needs. 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 2018,2019, as well as in subsequent years, will be contingent on Southern Company's investment opportunities and the Southern Company system's capital
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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.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 Eligible Project Costs) 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, 2018,2019, Georgia Power had borrowed $2.6$3.46 billion under the FFB Credit Facility. In July 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.
In September 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. This conditional commitment expires on March 31, 2019, subject to any further extension approved by the DOE. 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 (F) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" and "DOE Loan Guarantee Borrowings," respectively, herein for additional information regarding the Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events (including any decision not to continue construction of Plant Vogtle Units 3 and 4), and additional conditions to borrowing. Also see Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.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 SeptemberJune 30, 2018,2019, Southern Company's current liabilities exceeded current assets by $3.6$2.6 billion, primarily due to long-term debt that is due within one year of $3.0and notes payable totaling $4.5 billion (including approximately $1.3$0.9 billion at the parent company, $0.3 billion at Alabama Power, $0.5$1.5 billion at Georgia Power, $0.2$0.3 billion at Mississippi Power, and $0.5 billion at Southern Company Gas) and notes payable of $2.6 billion (including approximately $2.0 billion at the parent company, $0.1 billion at Georgia Power, $0.1 billion at Gulf Power, $0.2$0.9 billion at Southern Power, and $0.1$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
At September 30, 2018, Southern Company and its subsidiaries had approximately $1.8 billion of cash and cash equivalents. Committed credit arrangements with banks at SeptemberJune 30, 20182019 were as follows:
| | | | Expires | | | | Executable Term Loans | | Expires Within One Year | Expires | | | | |
| Company | 2018 | 2019 | 2020 | 2022 | | Total | | Unused | | One Year | | 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 |
| | $ | 1,999 |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 2,000 |
| | $ | 2,000 |
| | $ | 1,999 |
| | $ | — |
|
| Alabama Power | — |
| 33 |
| 500 |
| 800 |
| | 1,333 |
| | 1,333 |
| | — |
| | — |
| | 33 |
| 3 |
| 500 |
| — |
| 800 |
| | 1,303 |
| | 1,303 |
| | 3 |
|
| Georgia Power | — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,736 |
| | — |
| | — |
| | — |
| — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,736 |
| | — |
|
| Gulf Power | 20 |
| 25 |
| 235 |
| — |
| | 280 |
| | 280 |
| | 45 |
| | 45 |
| | — |
| |
| Mississippi Power | — |
| 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 |
| | 1,895 |
| | — |
| | — |
| | — |
| — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,745 |
| | — |
|
| Other | — |
| 30 |
| — |
| — |
| | 30 |
| | 30 |
| | — |
| | — |
| | 30 |
| — |
| 30 |
| — |
| — |
| | 30 |
| | 30 |
| | 30 |
|
| Southern Company Consolidated | $ | 20 |
| $ | 188 |
| $ | 735 |
| $ | 7,200 |
| | $ | 8,143 |
| | $ | 8,101 |
| | $ | 45 |
| | $ | 45 |
| | $ | 63 |
| $ | 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 2019,2021, of which $2230 million remains was unused at SeptemberJune 30, 20182019. 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 $1.41.25 billion of these arrangements.this arrangement. Southern Company Gas' committed credit arrangementsarrangement also include 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 68 to the financial statements of Southern Company 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 Southern Company, Alabama Power, Georgia Power, and Southern Power CompanySEGCO, 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, 2018,2019, 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. All but $40 millionNone of the bank credit arrangements do not 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 Nicor Gas.SEGCO. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of SeptemberJune 30, 20182019 was approximately $1.5$1.4 billion. In addition, at SeptemberJune 30, 2018,2019, the traditional electric operating companies had approximately $573$272 million of revenue bonds outstanding that wereare required to be remarketed within the next 12 months. Subsequent to September 30, 2018, Alabama Power purchased and held approximately $120 million of its outstanding pollution control revenue bonds required to be remarketed.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Company, the traditional electric operating companies (other than Mississippi Power),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, 2018 | | 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 | | $ | 611 |
| | 2.5 | % | | $ | 1,323 |
| | 2.4 | % | | $ | 3,008 |
| | $ | 1,148 |
| | 2.6 | % | | $ | 1,173 |
| | 2.8 | % | | $ | 1,562 |
|
| Short-term bank debt | | 1,953 |
| | 2.9 | % | | 1,790 |
| | 3.0 | % | | 2,003 |
| | 250 |
| | 2.9 | % | | 127 |
| | 3.0 | % | | 250 |
|
| Total | | $ | 2,564 |
| | 2.8 | % | | $ | 3,113 |
| | 2.7 | % | | | | $ | 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, 2018.2019. |
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, 2018,2019, 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 SeptemberJune 30, 20182019 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 | $ | 578 |
| $ | 433 |
|
At BB+ and/or Ba1(*) | $ | 2,120 |
| $ | 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 February 26, 2018, Moody's revised its rating outlook for Mississippi Power from stable to positive. On August 8, 2018, Moody's upgraded Mississippi Power's senior unsecured rating to Baa3 from Ba1 and maintained the positive rating outlook.
On February 28, 2018, Fitch removed Mississippi Power from rating watch negative and revised its rating outlook from stable to positive.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Also on February 28, 2018, Fitch downgraded the senior unsecured long-term debt rating of Southern Company to BBB+ from A- with a stable outlook and of Georgia Power to A from A+ with a negative outlook. On August 9, 2018, Fitch downgraded the senior unsecured long-term debt rating of Georgia Power to A- from A.
On March 14, 2018, S&P upgraded the senior unsecured long-term debt rating of Mississippi Power to A- from BBB+. The outlook remained negative.
On May 21, 2018, S&P revised its rating outlook for Gulf Power from negative to stable.
On August 8, 2018, Moody's downgraded the senior unsecured debt rating of Georgia Power to Baa1 from A3.
On September 28, 2018, Moody's revised its rating outlooks for Southern Company, Alabama Power, and Georgia Power from negative to stable.
Also on September 28, 2018, Fitch assigned a negative rating outlook to the ratings of Southern Company and its subsidiaries (excluding Gulf Power and Mississippi Power).
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 32 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 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 including approvals of capital structure adjustments for Alabama Power, Georgia Power, Gulf Power, and Atlanta Gas Light, by their respective state PSCs,and Nicor Gas, which are expected to help mitigate the potential adverse impacts to certain of their credit metrics.
Financing Activities
During the first nine months46
In addition, during the third quarter 2018, Southern Company issued a total of approximately 12.1 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 $540 million, net of approximately $5 million in commissions. Subsequent to September 30, 2018, Southern Company issued an additional approximately 2.5 million shares of common stock through at-the-market issuances and received cash proceeds of approximately $107 million, net of approximately $1 million in commissions.Contents
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 ninesix months of 2018:2019:
| | | Company | Senior Note Issuances | | Senior Note Maturities, Redemptions, and Repurchases | | 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) | $ | 750 |
| | $ | 1,000 |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | 2,100 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Alabama Power | 500 |
| | — |
| | — |
| | — |
| | — |
| 200 |
| | — |
| | — |
| | — |
| | — |
|
| Georgia Power | — |
| | 1,000 |
| | 469 |
| | — |
| | 107 |
| — |
| | 513 |
| | 223 |
| | 835 |
| | 3 |
|
| Mississippi Power | 600 |
| | — |
| | 43 |
| | — |
| | 900 |
| — |
| | 43 |
| | — |
| | — |
| | — |
|
| Southern Power | — |
| | 350 |
| | — |
| | — |
| | 420 |
| |
| Southern Company Gas | — |
| | — |
| | 200 |
| | 100 |
| | — |
| |
| Other | — |
| | — |
| | — |
| | — |
| | 10 |
| — |
| | — |
| | 25 |
| | — |
| | 9 |
|
Elimination(c) | — |
| | — |
| | — |
| | — |
| | (1 | ) | |
| Southern Company Consolidated | $ | 1,850 |
| | $ | 2,350 |
| | $ | 712 |
| | $ | 100 |
| | $ | 1,436 |
| $ | 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) | Represents reductions in affiliate capital lease obligations at Georgia Power, which are eliminated in Southern Company's Consolidated Financial Statements. |
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 March 2018,January 2019, Southern Company entered intorepaid a $900 million short-term floating rate bank loan bearing interest based on one-month LIBOR, which was repaid in August 2018.
In April 2018, Southern Company borrowed $250 million pursuant to a short-term uncommitted bank credit arrangement bearing interest at a rate agreed upon by Southern Company and the bank from time to time and payable on no less than 30 days' demand by the bank.
In June 2018, Southern Company repaid at maturity two $100 million short-term floating rate bank term loans.
In August 2018, Southern Company issued $750 million aggregate principal amount of Series 2018A Floating Rate Senior Notes due February 14, 2020 bearing interest based on three-month LIBOR, entered into a $1.5 billion short-term floating rate bank loan bearing interest based on one-month LIBOR, and repaid $250 million borrowedloan.
Also in August 2017 pursuant to a short-term uncommitted bank credit arrangement.
In the third quarter 2018, Southern Company repaid at maturity $500 million aggregate principal amount of 1.55% Senior Notes and $500 million aggregate principal amount of Series 2013A 2.45% Senior Notes.
Subsequent to September 30, 2018, Alabama Power purchased and held $120 million aggregate principal amount of The Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Plant Barry Project), Series 2008. These bonds may be remarketed to the public in the future.
In January 2018, Georgia Power repaid its outstanding $150 million short-term floating rate bank loan due May 31, 2018.
In May 2018,2019, through cash tender offers, Georgia PowerSouthern Company repurchased and retired $89approximately $522 million of the $250$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 2007A 5.65%2014B 2.15% Senior Notes due MarchSeptember 1, 2037, $3262019 (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
the $500 million aggregate principal amount outstanding of its Series 2009A 5.95% Senior Notes due February 1, 2039, and $335 million of the $600 million aggregate principal amount outstanding of its Series 2010B 5.40% Senior Notes due June 1, 2040, for an aggregate purchase price, excluding accrued and unpaid interest, of $902 million.
In March 2018, Mississippi Power entered into a $300 million short-term floating rate bank loan bearing interest based on one-month LIBOR, of which $200 million was repaid in the second quarter 2018 and $100 million was repaid in the third quarter 2018. The proceeds of this loan, together with the proceeds of Mississippi Power's $600 million senior notes issuances, were used to repay Mississippi Power's $900 million unsecured floating rate term loan.
Subsequent to September 30, 2018, Mississippi Power completed the redemption of all 334,210 outstanding shares of its preferred stock (as well as related depositary shares), with an aggregate par value of approximately $33.4 million; all $30 million aggregate principal amount outstanding of its Series G 5.40% Senior Notes due July 1, 2035; and all $125 million aggregate principal amount outstanding of its Series 2009A 5.55% Senior Notes due March 1, 2019.
In May 2018, Southern Power entered into two short-term floating rate bank loans, each for an aggregate principal amount of $100 million, which bear interest based on one-month LIBOR.
During the nine months ended September 30, 2018, Southern Power received approximately $148 million of third-party tax equity related to certain of its renewable facilities. See Note (J) to the Condensed Financial Statements under "Southern Power" herein for additional information.
Prior to its sale, in the second quarter 2018, Pivotal Utility Holdings caused $200 million aggregate principal amount of gas facility revenue bonds to be redeemed.
In May 2018, Southern Company Gas Capital borrowed $95 million pursuant to a short-term uncommitted bank credit arrangement, guaranteed by Southern Company Gas, bearing interest at a rate agreed upon by Southern Company Gas Capital and the bank from time to time and payable on no less than 30 days' demand by the bank. The proceeds of the loan were used to repay short-term debt. In July 2018, Southern Company Gas Capital repaid this loan.
In July 2018, Nicor Gas agreed to issue $300 million aggregate principal amount of first mortgage bonds in a private placement, $100 million of which was issued in August 2018 and $200 million of which was issued in November 2018.
Subsequent to September 30, 2018, Southern Company Gas Capital repaid at maturity $155 million aggregate principal amount of 3.50% Series B Senior Notes.
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, 2018,2019, there were no material changes to Southern Company's, Alabama Power's, Georgia Power's, Gulf 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 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 (D)Notes (I) and Note (I)(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 20182019 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, |
| | 2018 | | 2017 | | 2018 | | 2017 | 2019 | | 2018 | | 2019 | | 2018 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | | | | | | | | |
| Retail revenues | $ | 1,584 |
| | $ | 1,595 |
| | $ | 4,208 |
| | $ | 4,155 |
| $ | 1,378 |
| | $ | 1,338 |
| | $ | 2,592 |
| | $ | 2,624 |
|
| Wholesale revenues, non-affiliates | 74 |
| | 77 |
| | 213 |
| | 210 |
| 62 |
| | 65 |
| | 123 |
| | 139 |
|
| Wholesale revenues, affiliates | 14 |
| | 18 |
| | 96 |
| | 83 |
| 4 |
| | 31 |
| | 63 |
| | 82 |
|
| Other revenues | 68 |
| | 50 |
| | 199 |
| | 158 |
| 69 |
| | 69 |
| | 143 |
| | 131 |
|
| Total operating revenues | 1,740 |
| | 1,740 |
| | 4,716 |
| | 4,606 |
| 1,513 |
| | 1,503 |
| | 2,921 |
| | 2,976 |
|
| Operating Expenses: | | | | | | | | | | | | | | |
| Fuel | 356 |
| | 343 |
| | 1,028 |
| | 944 |
| 252 |
| | 347 |
| | 553 |
| | 672 |
|
| Purchased power, non-affiliates | 64 |
| | 57 |
| | 176 |
| | 132 |
| 47 |
| | 48 |
| | 84 |
| | 113 |
|
| Purchased power, affiliates | 69 |
| | 55 |
| | 149 |
| | 117 |
| 69 |
| | 43 |
| | 90 |
| | 80 |
|
| Other operations and maintenance | 401 |
| | 406 |
| | 1,191 |
| | 1,177 |
| 402 |
| | 402 |
| | 812 |
| | 788 |
|
| Depreciation and amortization | 192 |
| | 185 |
| | 570 |
| | 549 |
| 200 |
| | 189 |
| | 399 |
| | 379 |
|
| Taxes other than income taxes | 97 |
| | 93 |
| | 289 |
| | 284 |
| 98 |
| | 94 |
| | 200 |
| | 192 |
|
| Total operating expenses | 1,179 |
| | 1,139 |
| | 3,403 |
| | 3,203 |
| 1,068 |
| | 1,123 |
| | 2,138 |
| | 2,224 |
|
| Operating Income | 561 |
| | 601 |
| | 1,313 |
| | 1,403 |
| 445 |
| | 380 |
| | 783 |
| | 752 |
|
| Other Income and (Expense): | | | | | | | | | | | | | | |
| Allowance for equity funds used during construction | 16 |
| | 11 |
| | 43 |
| | 27 |
| 14 |
| | 14 |
| | 28 |
| | 27 |
|
| Interest expense, net of amounts capitalized | (82 | ) | | (76 | ) | | (240 | ) | | (229 | ) | (82 | ) | | (80 | ) | | (165 | ) | | (158 | ) |
| Other income (expense), net | 9 |
| | 10 |
| | 24 |
| | 35 |
| 11 |
| | 12 |
| | 25 |
| | 15 |
|
| Total other income and (expense) | (57 | ) | | (55 | ) | | (173 | ) | | (167 | ) | (57 | ) | | (54 | ) | | (112 | ) | | (116 | ) |
| Earnings Before Income Taxes | 504 |
| | 546 |
| | 1,140 |
| | 1,236 |
| 388 |
| | 326 |
| | 671 |
| | 636 |
|
| Income taxes | 127 |
| | 216 |
| | 272 |
| | 493 |
| 89 |
| | 64 |
| | 151 |
| | 145 |
|
| Net Income | 377 |
| | 330 |
| | 868 |
| | 743 |
| 299 |
| | 262 |
| | 520 |
| | 491 |
|
| Dividends on Preferred and Preference Stock | 4 |
| | 5 |
| | 11 |
| | 14 |
| |
| Net Income After Dividends on Preferred and Preference Stock | $ | 373 |
| | $ | 325 |
| | $ | 857 |
| | $ | 729 |
| |
| 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, |
| | 2018 | | 2017 | | 2018 | | 2017 |
| | (in millions) | | (in millions) |
| Net Income | $ | 377 |
| | $ | 330 |
| | $ | 868 |
| | $ | 743 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
Reclassification adjustment for amounts included in net income,
net of tax of $-, $1, $1, and $2, respectively | 1 |
| | 1 |
| | 3 |
| | 3 |
|
| Total other comprehensive income (loss) | 1 |
| | 1 |
| | 3 |
| | 3 |
|
| Comprehensive Income | $ | 378 |
| | $ | 331 |
| | $ | 871 |
| | $ | 746 |
|
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, |
| | 2018 | | 2017 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 868 |
| | $ | 743 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 683 |
| | 666 |
|
| Deferred income taxes | 104 |
| | 260 |
|
| Allowance for equity funds used during construction | (43 | ) | | (27 | ) |
| Settlement of asset retirement obligations | (31 | ) | | (20 | ) |
| Other, net | (6 | ) | | 59 |
|
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (207 | ) | | (163 | ) |
| -Prepayments | (26 | ) | | (28 | ) |
| -Materials and supplies | (69 | ) | | (29 | ) |
| -Other current assets | 66 |
| | 33 |
|
| -Accounts payable | (194 | ) | | (125 | ) |
| -Accrued taxes | 225 |
| | 159 |
|
| -Accrued compensation | (41 | ) | | (48 | ) |
| -Retail fuel cost over recovery | — |
| | (76 | ) |
| -Other current liabilities | 60 |
| | 7 |
|
| Net cash provided from operating activities | 1,389 |
| | 1,411 |
|
| Investing Activities: | | | |
| Property additions | (1,529 | ) | | (1,211 | ) |
| Nuclear decommissioning trust fund purchases | (207 | ) | | (174 | ) |
| Nuclear decommissioning trust fund sales | 207 |
| | 174 |
|
| Cost of removal, net of salvage | (78 | ) | | (82 | ) |
| Change in construction payables | 30 |
| | 105 |
|
| Other investing activities | (23 | ) | | (29 | ) |
| Net cash used for investing activities | (1,600 | ) | | (1,217 | ) |
| Financing Activities: | | | |
| Proceeds — | | | |
| Senior notes | 500 |
| | 550 |
|
| Capital contributions from parent company | 495 |
| | 337 |
|
| Preferred stock | — |
| | 250 |
|
| Redemptions — | | | |
| Senior notes | — |
| | (200 | ) |
| Pollution control revenue bonds | — |
| | (36 | ) |
| Payment of common stock dividends | (602 | ) | | (536 | ) |
| Other financing activities | (24 | ) | | (26 | ) |
| Net cash provided from financing activities | 369 |
| | 339 |
|
| Net Change in Cash, Cash Equivalents, and Restricted Cash | 158 |
| | 533 |
|
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 544 |
| | 420 |
|
| Cash, Cash Equivalents, and Restricted Cash at End of Period | $ | 702 |
| | $ | 953 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid during the period for — | | | |
| Interest (net of $15 and $10 capitalized for 2018 and 2017, respectively) | $ | 220 |
| | $ | 217 |
|
| Income taxes, net | 30 |
| | 146 |
|
| Noncash transactions — Accrued property additions at end of period | 275 |
| | 189 |
|
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, 2018 | | At December 31, 2017 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 702 |
| | $ | 544 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 455 |
| | 355 |
|
| Unbilled revenues | | 159 |
| | 162 |
|
| Under recovered regulatory clause revenues | | 48 |
| | — |
|
| Affiliated | | 68 |
| | 43 |
|
| Other accounts and notes receivable | | 54 |
| | 55 |
|
| Accumulated provision for uncollectible accounts | | (9 | ) | | (9 | ) |
| Fossil fuel stock | | 117 |
| | 184 |
|
| Materials and supplies | | 536 |
| | 458 |
|
| Prepaid expenses | | 59 |
| | 85 |
|
| Other regulatory assets, current | | 141 |
| | 124 |
|
| Other current assets | | 8 |
| | 5 |
|
| Total current assets | | 2,338 |
| | 2,006 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 29,568 |
| | 27,326 |
|
| Less: Accumulated provision for depreciation | | 9,932 |
| | 9,563 |
|
| Plant in service, net of depreciation | | 19,636 |
| | 17,763 |
|
| Nuclear fuel, at amortized cost | | 316 |
| | 339 |
|
| Construction work in progress | | 1,457 |
| | 908 |
|
| Total property, plant, and equipment | | 21,409 |
| | 19,010 |
|
| Other Property and Investments: | | | | |
| Equity investments in unconsolidated subsidiaries | | 63 |
| | 67 |
|
| Nuclear decommissioning trusts, at fair value | | 938 |
| | 903 |
|
| Miscellaneous property and investments | | 127 |
| | 124 |
|
| Total other property and investments | | 1,128 |
| | 1,094 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 236 |
| | 239 |
|
| Deferred under recovered regulatory clause revenues | | 88 |
| | 54 |
|
| Other regulatory assets, deferred | | 1,209 |
| | 1,272 |
|
| Other deferred charges and assets | | 202 |
| | 189 |
|
| Total deferred charges and other assets | | 1,735 |
| | 1,754 |
|
| Total Assets | | $ | 26,610 |
| | $ | 23,864 |
|
|
| | | | | | | | | | | | | | | |
| | 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 BALANCE SHEETSSTATEMENTS OF CASH FLOWS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholder's Equity | | At September 30, 2018 | | At December 31, 2017 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 321 |
| | $ | — |
|
| Accounts payable — | | | | |
| Affiliated | | 341 |
| | 327 |
|
| Other | | 425 |
| | 585 |
|
| Customer deposits | | 96 |
| | 92 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 97 |
| | 9 |
|
| Other accrued taxes | | 132 |
| | 45 |
|
| Accrued interest | | 81 |
| | 77 |
|
| Accrued compensation | | 169 |
| | 205 |
|
| Asset retirement obligations, current | | 111 |
| | 7 |
|
| Other regulatory liabilities, current | | 57 |
| | 1 |
|
| Other current liabilities | | 46 |
| | 52 |
|
| Total current liabilities | | 1,876 |
| | 1,400 |
|
| Long-term Debt | | 7,803 |
| | 7,628 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 2,882 |
| | 2,760 |
|
| Deferred credits related to income taxes | | 2,051 |
| | 2,082 |
|
| Accumulated deferred ITCs | | 107 |
| | 112 |
|
| Employee benefit obligations | | 283 |
| | 304 |
|
| Asset retirement obligations | | 3,090 |
| | 1,702 |
|
| Other cost of removal obligations | | 542 |
| | 609 |
|
| Other regulatory liabilities, deferred | | 52 |
| | 84 |
|
| Other deferred credits and liabilities | | 48 |
| | 63 |
|
| Total deferred credits and other liabilities | | 9,055 |
| | 7,716 |
|
| Total Liabilities | | 18,734 |
| | 16,744 |
|
| Redeemable Preferred Stock | | 291 |
| | 291 |
|
| 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 | | 3,490 |
| | 2,986 |
|
| Retained earnings | | 2,902 |
| | 2,647 |
|
| Accumulated other comprehensive loss | | (29 | ) | | (26 | ) |
| Total common stockholder's equity | | 7,585 |
| | 6,829 |
|
| Total Liabilities and Stockholder's Equity | | $ | 26,610 |
| | $ | 23,864 |
|
|
| | | | | | | |
| | 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
THIRDSECOND QUARTER 2019 vs. SECOND QUARTER 2018 vs. THIRD QUARTER 2017
AND
YEAR-TO-DATE 20182019 vs. YEAR-TO-DATE 20172018
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. On May 1, 2018, the Alabama PSC approved modifications to Rate RSE and other commitments designed to position Alabama Power to address the retail rate impact and the growing pressure on its credit quality resulting from the Tax Reform Legislation. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein for additional information and Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate RSE" in Item 8 of the Form 10-K for additional information on Alabama Power's established retail tariff.
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
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) |
| (% change) |
| (change in millions) |
| (% change) |
| $48 | | 14.8 | | $128 | | 17.6 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) |
| (% change) |
| (change in millions) |
| (% change) |
| $37 | | 14.3 | | $29 | | 6.0 |
Alabama Power's net income after dividends on preferred and preference stock for the thirdsecond quarter 20182019 was $373$296 million compared to $325$259 million for the corresponding period in 2017. Alabama Power's net income after dividends on preferred and preference stock for year-to-date 20182018. The increase was $857 million compared to $729 million for the corresponding period in 2017. These increases were primarily related to an increase in retail revenues associated with colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 in Alabama Power's service territory compared to the corresponding periods in 2017 and a decrease in income tax expense, partially offset byimpacts of customer bill credits issued in 2018 related to the Tax Reform Legislation. 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 FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" herein and Note 32 to the financial statements of Alabamaunder "Alabama Power under "Retail Regulatory Matters – 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
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(11) | | (0.7) | | $53 | | 1.3 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $40 | | 3.0 | | $(32) | | (1.2) |
In the thirdsecond quarter 2018,2019, retail revenues were $1.58$1.38 billion compared to $1.60$1.34 billion for the corresponding period in 2017.2018. For year-to-date 2018,2019, retail revenues were $4.21$2.59 billion compared to $4.16$2.62 billion for the corresponding period in 2017.2018.
Details of the changes in retail revenues were as follows:
| | | | Third Quarter 2018 |
| Year-to-Date 2018 | Second Quarter 2019 |
| Year-to-Date 2019 |
| | (in millions) |
| (% change) |
| (in millions) |
| (% change) | (in millions) |
| (% change) |
| (in millions) |
| (% change) |
| Retail – prior year | $ | 1,595 |
| | | | $ | 4,155 |
| | | $ | 1,338 |
| | | | $ | 2,624 |
| | |
| Estimated change resulting from – | | | | | | | | | | | | | | |
| Rates and pricing | (87 | ) | | (5.5 | ) | | (195 | ) | | (4.7 | ) | 62 |
| | 4.7 | % | | 96 |
| | 3.7 | % |
| Sales decline | (2 | ) | | (0.1 | ) | | (8 | ) | | (0.1 | ) | (15 | ) | | (1.1 | ) | | (31 | ) | | (1.2 | ) |
| Weather | 37 |
| | 2.3 |
| | 130 |
| | 3.1 |
| 6 |
| | 0.4 |
| | (19 | ) | | (0.7 | ) |
| Fuel and other cost recovery | 41 |
| | 2.6 |
| | 126 |
| | 3.0 |
| (13 | ) | | (1.0 | ) | | (78 | ) | | (3.0 | ) |
| Retail – current year | $ | 1,584 |
| | (0.7 | )% | | $ | 4,208 |
| | 1.3 | % | $ | 1,378 |
| | 3.0 | % | | $ | 2,592 |
| | (1.2 | )% |
Revenues associated with changes in rates and pricing decreasedincreased in the thirdsecond quarter and year-to-date 20182019 when compared to the corresponding periods in 20172018 primarily due to the impacts of customer bill credits related to the Tax Reform Legislation.Legislation in 2018, as well as additional capital investments recovered through Rate CNP Compliance. See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Alabama Power" herein and 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 20182019 when compared to the corresponding periods in 2017.2018. 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 1.1%1.2% and 1.4% for2.3% in the thirdsecond quarter and year-to-date 2018, respectively, and weather-adjusted residential KWH sales decreased 0.3% and 0.5% for the third quarter and year-to-date 2018,2019, respectively, when compared to the corresponding periods in 20172018. These decreases primarily due to lowerresulted from customer usage related toinitiatives in energy efficiency.savings for commercial customers and more energy-efficient residential appliances. Industrial KWH sales increased 1.3%decreased 3.2% and 2.4% for3.1% in the thirdsecond quarter and year-to-date 2018,2019, respectively, when compared to the corresponding periods in 20172018 as a result of an increasea decrease in demand resulting from changes in production levels primarily in the primary metals sector, largely due to strong domestic demand for steel and aluminum, and in the pipelines sector, partially offset by a decrease in demand in the paper and chemicals sectors primarilyfor 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 customer maintenance outages and on-site cogeneration.
Revenues resulting from changes in weather increased in the third quarter and year-to-date 2018 due to coldermilder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 in Alabama Power's service territory2019 when compared to the corresponding periodsperiod in 2017. For the third quarter 2018, the resulting increases were 3.9% and 2.2% for residential and commercial sales revenues, respectively. For year-to-date 2018, the resulting increases were 5.7% and 2.3% for residential and commercial sales revenues, respectively.2018.
Fuel and other cost recovery revenues increaseddecreased in the thirdsecond quarter and year-to-date 20182019 when compared to the corresponding periods in 20172018 primarily due to increasesa decrease in KWH 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 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 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 | |
| Second Quarter 2019 vs. Second Quarter 2018 | | 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) | | (change in millions) | | (% change) |
$(4)(3) | | (22.2) | | $13 | | 15.7 | | (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.
For year-to-date 2018,In the second quarter 2019, wholesale revenues from sales to affiliates were $96$4 million compared to $83$31 million for the corresponding period in 2017.2018. The increasedecrease was primarily due to a 12% increase in the price of energy and a 3% increasean 87.4% decrease in KWH sales as a result of increased demand due to colder weatherdecreased coal generation associated with the retirement of Plant Gorgas Units 8, 9, and 10 and a 6.7% decrease in the first quarter 2018 and warmer weatherprice of energy as a result of lower natural gas prices in the second and third quarters 2018quarter 2019 compared to the corresponding periodsperiod in 2017.2018.
Other Revenues
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $18 | | 36.0 | | $41 | | 25.9 |
In the third quarter 2018, otherFor year-to-date 2019, wholesale revenues from sales to affiliates were $68$63 million compared to $50$82 million for the corresponding period in 2017. For year-to-date 2018, other revenues were $199 million compared to $158 million for the corresponding period in 2017. These increases were primarily due to revenues related to unregulated sales of products and services that were reclassified as other revenues as a result of the adoption of ASC 606, Revenue from Contracts with Customers (ASC 606). In prior periods, these revenues were included in other income (expense), net. See Note (A) to the Condensed Financial Statements herein for additional information regarding Alabama Power's adoption of ASC 606.2018. The year-to-date 2018 increase was partially offset by decreases in open access transmission tariff revenues primarily due to expected declines in customers' needs and a lower rate related to the Tax Reform Legislation.
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | |
| | Third Quarter 2018
vs.
Third Quarter 2017 | | Year-to-Date 2018
vs.
Year-to-Date 2017 |
| | (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| Fuel | $ | 13 |
| | 3.8 | | $ | 84 |
| | 8.9 |
| Purchased power – non-affiliates | 7 |
| | 12.3 | | 44 |
| | 33.3 |
| Purchased power – affiliates | 14 |
| | 25.5 | | 32 |
| | 27.4 |
| Total fuel and purchased power expenses | $ | 34 |
| | | | $ | 160 |
| | |
In the third quarter 2018, fuel and purchased power expenses were $489 million compared to $455 million for the corresponding period in 2017. The increasedecrease was primarily due to a $23 million increase related to13.1% decrease in KWH sales as a result of decreased coal generation associated with the volumeretirement of KWHs generatedPlant Gorgas Units 8, 9, and purchased10 and a $16 million increase related to the average cost of fuel, partially offset by a $5 millionan 11.0% decrease in the average costprice of purchased power.
For year-to-date 2018, fuel and purchased power expenses were $1.35 billionenergy due to increased hydro generation in 2019 as compared to $1.19 billion for the corresponding period in 2017. The increase was primarily due to a $98 million increase related to the volume2018.
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 addition,the second quarter 2019, fuel expense increased $30and purchased power expenses were $368 million compared to $438 million for the corresponding period in 2018. For year-to-date 20182019, fuel and purchased power expenses were $727 million compared to $865 million for the corresponding period in accordance with an Alabama PSC accounting order authorizing2018. These decreases were primarily related to the usevolume of excess deferred income taxes to offset under recovered fuel costs. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Accounting Order" herein for additional information.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 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.
Details of Alabama Power's generation and purchased power were as follows:
| | | | Third Quarter 2018 | | Third Quarter 2017 | | Year-to-Date 2018 |
| Year-to-Date 2017 | Second Quarter 2019 | | Second Quarter 2018 | | Year-to-Date 2019 |
| Year-to-Date 2018 |
Total generation (in billions of KWHs) | 16 | | 16 | | 47 | | 46 | 12 | | 15 | | 29 | | 31 |
Total purchased power (in billions of KWHs) | 3 | | 2 | | 6 | | 5 | 3 | | 2 | | 4 | | 3 |
Sources of generation (percent) — | | |
| Coal | 54 | | 52 | | 52 | | 49 | 43 | | 53 | | 43 | | 52 |
| Nuclear | 24 | | 24 | | 22 | | 25 | 26 | | 20 | | 24 | | 21 |
| Gas | 18 | | 19 | | 19 | | 20 | 23 | | 20 | | 21 | | 19 |
| Hydro | 4 | | 5 | | 7 | | 6 | 8 | | 7 | | 12 | | 8 |
Cost of fuel, generated (in cents per net KWH)(a) — | | |
Cost of fuel, generated (in cents per net KWH) — (a) | | |
| Coal | 2.74 | | 2.61 | | 2.74 | | 2.61 | 2.86 | | 2.79 | | 2.82 | | 2.74 |
| Nuclear | 0.78 | | 0.75 | | 0.77 | | 0.75 | 0.78 | | 0.80 | | 0.78 | | 0.77 |
| Gas | 2.80 | | 2.72 | | 2.72 | | 2.74 | 2.48 | | 2.51 | | 2.53 | | 2.69 |
Average cost of fuel, generated (in cents per net KWH)(a)(b) | 2.27 | | 2.17 | | 2.27 | | 2.15 | 2.18 | | 2.31 | | 2.19 | | 2.27 |
Average cost of purchased power (in cents per net KWH)(c) | 5.43 | | 5.65 | | 5.59 | | 5.57 | 4.01 | | 4.72 | | 4.45 | | 5.72 |
| |
| (a) | CostIn the second quarter and year-to-date 2018, cost of fuel generated and average cost of fuel, generated excludesexclude a $30 million adjustment for year-to-date 2018 associatedin accordance with thean Alabama PSC accounting order relatedorder. See Note 2 to excess deferred income taxes.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 thirdsecond quarter 2018,2019, fuel expense was $356$252 million compared to $343$347 million for the corresponding period in 2017.2018. The increasedecrease was primarily due to a 16.6%31.3% decrease in the volume of KWHs generated by hydro facilities due to lower rainfall, a 5.0% increase in the average cost of coal per KWH generated, a 4.0% increase in the average cost of nuclear fuel per KWH generated, and a 3.9% decrease in the volume of KWHs generated by nuclear facilities due to the timing of outages. In addition, the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, increased 2.9% and the volume of KWHs generated by coal increased 2.0%. These increases were partially offset by an 8.4% decrease in the volume of KWHs generated by natural gas.
For year-to-date 2018, fuel expense was $1.03 billion compared to $944 million for the corresponding period in 2017. The increase was primarily due to a 10.8% decrease in the volume of KWHs generated by nuclear facilities due to outages, a 6.9% increase in the volume of KWHs generated by coal and a 5.0% increase in the average cost of coal per KWH generated. These increases were partially offset by an 11.7%11.9% increase in the volume of KWHs generated by hydro facilities due to the timingnuclear.
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.costs (Tax Reform Accounting Order). See FUTURE EARNINGS POTENTIALNote 2 to the financial statements under "Alabama Power – "Retail Regulatory Matters – Tax Reform Accounting Order" hereinOrder" in Item 8 of the Form 10-K for additional information.
Purchased Power – Non-Affiliates
In the third quarter 2018,For year-to-date 2019, purchased power expense from non-affiliates was $64$84 million compared to $57$113 million for the corresponding period in 2017.2018. The increasedecrease was primarily related to a 14.8% increase in the amount of energy purchased due to warmer weather in the third quarter 2018 compared to the corresponding period in 2017.
For year-to-date 2018, purchased power expense from non-affiliates was $176 million compared to $132 million for the corresponding period in 2017. The increase was primarily related to a 24.3% increase in the amount of energy purchased and a 6.7% increase14.3% decrease in the average cost of purchased power per KWH due to colderlower natural gas prices and an 11.9% decrease in the amount of energy purchased due to milder weather in the first quarter 2018 and warmer weather in the second and third quarters 20182019 compared to the corresponding periodsperiod in 2017.2018.
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 thirdsecond quarter 2018,2019, purchased power expense from affiliates was $69 million compared to $55$43 million for the corresponding period in 2017. The increase was primarily related to a 28% increase in the amount of energy purchased due to warmer weather in the third quarter 2018 compared to the corresponding period in 2017.
2018. For year-to-date 2018,2019, purchased power expense from affiliates was $149$90 million compared to $117$80 million for the corresponding period in 2017. The increase was2018. These increases were primarily related to the availability of lower-cost generation compared to Alabama Power's owned generation and a 35% increasedecrease in the amount of energy purchasedcoal generation as a result of colder weather in the first quarter 2018retirement of Plant Gorgas Units 8, 9, and warmer weather in the second and third quarters 2018 compared to the corresponding periods in 2017.10.
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 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(5) | | (1.2) | | $14 | | 1.2 |
|
| | | | | | |
| 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 2018,2019, other operations and maintenance expenses were $1.19 billion$812 million compared to $1.18 billion$788 million for the corresponding period in 2017. The2018. This increase was primarily due to $33increases of $15 million ofin Rate CNP Compliance-related expenses from unregulated sales of products and services that were reclassified as other operations and maintenance expenses as a result of the adoption of ASC 606. In prior periods, these expenses were included in other income (expense), net. In addition, distribution costs increased $29$13 million primarily due to additional line maintenance. These increases were partially offset by a $23 million decrease in steam generation costs primarily due to the timing of outages, an $8outages.
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 decreasecompared to $189 million for the corresponding period in employee benefits as a result of amounts capitalized2018. For year-to-date 2019, depreciation and amortization was $399 million compared to $379 million for the corresponding period in connection with an increase in construction projects, a $7 million decrease in nuclear generation costs2018. These increases were primarily due to the timingadditional plant in service associated with steam, distribution, and transmission.
See Note (A) to the Condensed Financial Statements herein for additional information regarding Alabama Power's adoption of ASC 606.Contents
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Depreciation and AmortizationOther Income (Expense), Net
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $7 | | 3.8 | | $21 | | 3.8 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(1) | | (8.3) | | $10 | | 66.7 |
In the third quarter 2018, depreciation and amortizationFor year-to-date 2019, other income (expense), net was $192$25 million compared to $185$15 million for the corresponding period in 2017. For year-to-date 2018, depreciation2018. This increase was primarily due to increases in interest income from temporary cash investments and amortization was $570non-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 $549$64 million for the corresponding period in 2017. These increases were2018. This increase was primarily due to additional planthigher pre-tax earnings in service relatedthe second quarter 2019 compared to steam generation, transmission,the corresponding period in 2018 and distribution assets.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.
Allowance for Equity Funds Used During Construction
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $5 | | 45.5 | | $16 | | 59.3 |
In the third quarter 2018, AFUDC equity was $16 million compared to $11 million for the corresponding period in 2017. For year-to-date 2018, AFUDC equity was $43 million compared to $27 million for the corresponding period in 2017. These increases were primarily due to an increase in capital expenditures related to environmental and transmission projects.
Interest Expense, Net of Amounts Capitalized
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $6 | | 7.9 | | $11 | | 4.8 |
In the third quarter 2018, interest expense, net of amounts capitalized was $82 million compared to $76 million for the corresponding period in 2017. For year-to-date 2018, interest expense, net of amounts capitalized was $240 million compared to $229 million for the corresponding period in 2017. These increases were primarily due to an increase in the average debt outstanding and higher interest rates, partially offset by an increase in the amounts capitalized.
Other Income (Expense), Net
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(1) | | (10.0) | | $(11) | | (31.4) |
For year-to-date 2018, other income (expense), net was $24 million compared to $35 million for the corresponding period in 2017. This decrease was primarily due to the reclassification of revenues and expenses associated with unregulated sales of products and services to other revenues and operations and maintenance expense, respectively, as a result of the adoption of ASC 606. See Note (A) to the Condensed Financial Statements herein for additional information regarding Alabama Power's adoption of ASC 606.
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Income Taxes
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(89) | | (41.2) | | $(221) | | (44.8) |
In the third quarter 2018, income taxes were $127 million compared to $216 million for the corresponding period in 2017. For year-to-date 2018, income taxes were $272 million compared to $493 million for the corresponding period in 2017. These decreases were primarily due to the reduction in the federal income tax rate and the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation and lower pre-tax earnings. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Accounting Order" and Note (H) to the Condensed Financial Statements under "Effective Tax Rate" herein 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 limited projected demandthe weak pace of growth over the next several years. Future earnings will be impacted byin new customers and electricity use per customer, growth.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. The costs, including capital expenditures, operations and maintenance costs, and costs reflected in ARO liabilities, required to comply with environmental laws and regulations and to achieve stated goals may impact future unit retirement and replacement decisions, results of operations, cash flows, and financial condition.goals. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to theAlabama Power's transmission system. A major portionand distribution systems, and may impact future electric generating unit retirement and replacement decisions, results of theseoperations, cash flows, and/or financial condition. These costs are expected to be recoveredbeing collected through existing ratemaking and billing provisions. The ultimate impact of environmental laws and regulations and the GHG
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goals discussed below 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 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
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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" and "Retail Regulatory Matters – Rate CNP Compliance"Remediation" in Item 8 of the Form 10-K for additional information.
Environmental Laws and Regulations
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Water Quality" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the effluent limitations guidelines (ELG) rule.
On May 2, 2018, the EPA updated its anticipated final rulemaking schedule for ELG from September 2020 to December 2019. The impact of any changes to the ELG rule will depend on the content of the final rule and the outcome of any legal challenges and cannot be determined at this time.
Coal Combustion Residuals
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule).
The EPA published certain amendments to the CCR Rule, which became effective August 29, 2018. These amendments extend the date from April 2019 to October 31, 2020 to cease sending CCR and other waste streams to impoundments that demonstrate compliance with all except two specified criteria. These amendments also establish groundwater protection standards for four constituents that do not have established EPA maximum contaminant levels and allow a participating state director or the EPA (where the EPA is the permitting authority) to suspend groundwater monitoring requirements under certain circumstances. Specific site impacts are being evaluated by Alabama Power.
On October 15, 2018, the U.S. Court of Appeals for the District of Columbia Circuit issued a mandate that broadens the CCR Rule to regulate previously-excluded inactive surface impoundments (legacy units) located at retired generation facilities and challenges both the ability of unlined impoundments to continue operating and the classification of clay lined units. It is anticipated that the EPA will issue a series of rulemakings to address this court action. Alabama Power is evaluating the extent of potential impacts on legacy units. The ultimate impact of these changes will not be known until the EPA rulemaking and any legal challenges are finalized.
On April 20, 2018, the Alabama Environmental Management Commission approved a state CCR rule that has been provided to the EPA for a six-month review period. This state CCR rule is generally consistent with the federal CCR Rule. The ultimate outcome of this matter cannot be determined at this time.
In June 2018,2019, Alabama Power recorded an increase of approximately $1.2 billion$308 million to its AROs primarily related to the CCR Rule. The revised cost estimates wereRule and the related state rule based on information from feasibility studies performed on ash ponds in use at plants operated by Alabama Power. Duringmanagement's completion of closure designs during the second quarter 2018, Alabama Power's management completed2019 for all but two of its analysis of these studies which indicated thatash pond facilities. The additional closureestimated costs primarily related to increases in estimated ash volume, water management requirements, and design revisions, will be required to close these ash ponds under the planned closure-in-place methodology. 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 closureadditional details are developed with respect to all ash pond closures, Alabama Power expects to periodically update these cost estimates. Asestimates as necessary. Additionally, the level of work becomes more defined in the next 12 months, it is likely that these cost estimates will changeclosure designs and the change could be material. See Note (A)plans are subject to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
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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 these mattersthis matter cannot be determined at this time.
Nuclear Decommissioning
See Note 16 to the financial statements of Alabama Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" and "Nuclear Decommissioning" herein for additional information.
In June 2018, Alabama Power completed an updated decommissioning cost site study for Plant Farley. The estimated cost of decommissioning based on the study resulted in an increase in the ARO liability of approximately $300 million. Amounts previously contributed to the external trust funds are currently projected to be adequate to meet the updated decommissioning obligations.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Alabama Power in Item 7 of the Form 10-K for additional information.
On August 31, 2018,July 8, 2019, the EPA published a proposed Clean Power Plan replacement rule known as the final Affordable Clean Energy rule (ACE Rule), which would require 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 CO2emission rate standards for existing coal-fired units based on heat-rate efficiency improvements for existing fossil fuel-fired steam units. As proposed, combustionimprovements. Combustion turbines, including natural gas combined cycles, are not included as affected sources. As of September 30, 2018, sources in the ACE Rule. Alabama Power has ownership interests in 20 fossil fuel-fired steamseven coal-fired units to which the proposed ACE Rule is applicable. The ultimate impact of this rulethe ACE Rule, including the repeal and replacement of the CPP, to Alabama Power is currently unknown and will depend on changes between the proposalstate implementation plan requirements and the final rule, subsequent state plan developments and requirements, andoutcome of any associated legal proceedings.
Through 2017, the Southern Company system has achieved an estimated GHG emission reduction of 36% since 2007. In April 2018, Southern Company established an intermediate goal of a 50% reduction in carbon emissions from 2007 levels by 2030challenges and a long-term goal of low- to no-carbon operations by 2050. To achieve these goals, the Southern Company system expects to continue growing its renewable energy portfolio, optimize technology advancements to modernize its transmission and distribution systems, increase the use of natural gas for generation, invest in energy efficiency, and continue research and development efforts focused on technologies to lower GHG emissions. The Southern Company system's ability to achieve these goals also will be dependent on many external factors, including supportive national energy policies, low natural gas prices, and the development, deployment, and advancement of relevant energy technologies. The ultimate outcome of this matter cannot be determined at this time.
FERC Matters
Market-Based Rate Authority
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL –Note 2 to the financial statements under "FERC Matters" of Alabama PowerMatters – Open Access Transmission Tariff" in Item 78 of the Form 10-K for additional information regarding proceedings related to the traditional electric operating companies' (including Alabama Power's) and Southern Power's 2014 and 2017 triennial market power analyses.information.
On May 4, 2018,June 28, 2019, the FERC issued an order terminating both proceedings, finding thatapproved 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 Southern Power satisfya five-year moratorium on these parties seeking changes to the FERC's standards for market-based rates. On May 9, 2018,OATT formula rate. The terms of the traditional electric operating companies (includingOATT settlement agreement will not have a material impact on the financial statements of Alabama Power) and Southern Power made the compliance filing required by the order. These proceedings are concluded.Power.
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Open Access Transmission Tariff
On May 10, 2018, the Alabama Municipal Electric Authority and Cooperative Energy filed with the FERC a complaint against SCS and the traditional electric operating companies (including Alabama Power) claiming that the current 11.25% base ROE used in calculating the annual transmission revenue requirements of the traditional electric operating companies' (including Alabama Power's) open access transmission tariff is unjust and unreasonable as measured by the applicable FERC standards. The complaint requests that the base ROE be set no higher than 8.65% and that the FERC order refunds for the difference in revenue requirements that results from applying a just and reasonable ROE established in this proceeding upon determining the current ROE is unjust and unreasonable. On June 18, 2018, SCS and the traditional electric operating companies (including Alabama Power) filed their response challenging the adequacy of the showing presented by the complainants and offering support for the current ROE. On September 6, 2018, the FERC issued an order establishing a refund effective date of May 10, 2018 in the event a refund is due and initiating an investigation and settlement procedures regarding the current base ROE. Through September 30, 2018, the estimated maximum potential refund is not expected to be material to Alabama Power's results of operations. The ultimate outcome of this matter cannot be determined at this time.
Relicensing of Hydroelectric Developments
See BUSINESS – "Regulation – Federal Power Act" in Item 1 of the Form 10-K for a discussion of Alabama
Power's hydroelectric developments on the Coosa River.
On July 6, 2018, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision vacating the FERC's 2013 order issuing a new 30-year license to Alabama Power for seven hydroelectric developments on the Coosa River and remanding the proceeding to the FERC for further proceedings. Alabama Power continues to operate the Coosa River developments under annual licenses issued by the FERC. The ultimate outcome of this matter 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 of Alabama Power under "Nuclear Outage Accounting Order" and "Retail Regulatory Matters," respectively,"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.
On May 1, 2018, the Alabama PSC approved modifications to Rate RSE and other commitments designed to position Alabama Power to address the growing pressure on its credit quality resulting from the Tax Reform Legislation, without increasing retail rates under Rate RSE in the near term. Alabama Power plans to reduce growth in total debt by increasing equity, with corresponding reductions in debt issuances, thereby de-leveraging its capital structure. Alabama Power's goal is to achieve an equity ratio of approximately 55% by the end of 2025. At September 30, 2018, Alabama Power's equity ratio was approximately 47%. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" of Alabama Power in Item 7 of the Form 10-K for additional information.
Rate RSE
The approved modifications to Rate RSE became effective June 2018 and are applicable for January 2019 billings and thereafter. The modifications include reducing the top of the allowed weighted common equity return (WCER) range from 6.21% to 6.15% and modifications to the refund mechanism applicable to prior year actual results. The modifications to the refund mechanism allow Alabama Power to retain a portion of the revenue that causes the actual WCER for a given year to exceed the allowed range.
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In conjunction with these modifications to Rate RSE, on May 8, 2018, Alabama Power consented to a moratorium on any upward adjustments under Rate RSE for 2019 and 2020. Additionally, Alabama Power will return $50 million to customers through bill credits in 2019.
In accordance with an established retail tariff that provides for an interim adjustment to customer billings to recognize the impact of a change in the statutory income tax rate, Alabama Power has returned $151 million through September 30, 2018 and anticipates returning a total of approximately $257 million to retail customers through bill credits by December 31, 2018 as a result of the change in the federal income tax rate under the Tax Reform Legislation.
Rate ECR
On May 1, 2018, the Alabama PSC approved an increase to Rate ECR from 2.015 cents per KWH to 2.353 cents per KWH effective July 2018 which is expected to result in additional collections of approximately $100 million through December 31, 2018. The approved increase in the Rate ECR factor will have no significant effect on Alabama Power's net income, but will increase operating cash flows related to fuel cost recovery in 2018. Absent any further order from the Alabama PSC, in January 2019, the rate will return to the originally authorized 5.910 cents per KWH.
Environmental Accounting Order
On May 1, 2018, the Alabama PSC approved an accounting order that authorizesApril 15, 2019, Alabama Power retired Plant Gorgas Units 8, 9, and 10 and reclassified approximately $654 million of the unrecovered asset balances to deferregulatory assets, which are being recovered over the benefitsunits' remaining useful lives, the latest being through 2037, as established prior to the decision to retire. Additionally, approximately $700 million of federal excess deferred income taxes associated with the Tax Reform Legislation for the year ending December 31, 2018 asnet capitalized asset retirement costs were reclassified to a regulatory liability and to use up to $30 million of such deferrals to offset under recovered amounts under Rate ECR. Any remaining amounts will be used for the benefit of customers as determinedasset in accordance with accounting guidance provided by the Alabama PSC. As of September 30, 2018, Alabama Power had applied the full $30 million to offset the underThe asset retirement costs are being recovered balance under Rate ECR and expects the total deferrals for the year ending December 31, 2018 to be approximately $50 million.through 2055. See Note 52 to the financial statements of Alabamaunder "Alabama Power under "Federal Tax Reform Legislation"– Environmental Accounting Order" and "Current and Deferred Income Taxes"Note 6 in Item 8 of the Form 10-K for additional information.
Plant Greene County
Alabama Power jointly owns Plant Greene County with an affiliate, Mississippi Power. See Note 4 to the financial statements of Alabama Power in Item 8 of the Form 10-K for additional information regarding the joint ownership agreement. On August 6, 2018, Mississippi Power filed its proposed Reserve Margin Plan (RMP) with the Mississippi PSC, which proposes a four-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively. Mississippi Power's proposed Plant Greene County unit retirements would require the completion of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. Alabama Power will monitor Mississippi Power's proposed RMP and associated regulatory process as well as the proposed transmission and system reliability improvements. Alabama Power will review all the facts and circumstances and will evaluate all its alternatives prior to reaching a final determination on the ongoing operations of Plant Greene County. The ultimate outcome of this matter cannot be determined at this time.
Request for Proposals for Future Generation
On September 21, 2018, Alabama Power issued a request for proposals of between 100 MWs and 1,200 MWs of capacity beginning no later than 2023. Any purchases will depend upon the cost competitiveness of the respective offers as well as other options available to Alabama Power. The ultimate outcome of this matter cannot be determined at this time.
Income Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Alabama Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY –
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"Credit Rating Risk," Note (B) to the Condensed Financial Statements under "Regulatory Matters – Alabama Power," and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation and related regulatory actions.
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 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 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.
On March 2, 2018, the Alabama Department of Environmental Management (ADEM) issued proposed administrative orders assessing a penalty of $1.25 millionIn response to changing customer expectations, payment patterns, and ongoing efforts to increase overall operating efficiencies, Alabama Power for unpermitted dischargeinitiated a plan to close 40 of fluids and/or pollutantsits 86 payment offices by the end of 2019. Charges associated with these activities are not expected to groundwater at five electric generating plants. The orders were finalized andhave a material impact on Alabama Power paid the penalty on September 27, 2018. This matter is now concluded.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.
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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 regarding ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). See Note (A) to the Condensed Financial Statements herein for information regarding Alabama Power's recently adopted accounting standards.
In 2016, the FASB issued ASU No. 2016-02, which requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and Alabama Power will adopt the new standard effective January 1, 2019.
Alabama Power has elected the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby it will apply the requirements of ASU 2016-02 on a prospective basis as of the
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adoption date of January 1, 2019, without restating prior periods. Alabama Power expects to elect the package of practical expedients provided by ASU 2016-02 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Alabama Power expects to apply the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and to elect the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed. Alabama Power also expects to make accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and to combine lease and non-lease components in the computations of lease obligations and right-of-use assets for most asset classes.
Alabama Power is continuing to complete the implementation of an information technology system to track and account for its leases and of changes to its internal controls and accounting policies to support the accounting for leases under ASU 2016-02. Alabama Power has substantially completed its lease inventory and determined its most significant leases involve PPAs. While Alabama Power has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to result in recording lease liabilities and right-of-use assets on Alabama Power's balance sheet each totaling approximately $200 million, with no material impact on Alabama Power's statement of income.
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, 2018.2019. 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 $1.39 billion$695 million for the first ninesix months of 2018, a decrease2019, an increase of $22$43 million as compared to the first ninesix months of 2017.2018. The decreaseincrease in net cash provided from operating activities was primarily due to the timing of vendor paymentsincreased fuel cost recovery, partially offset by income tax refunds received in 2018.the prior year impacts of customer billing reductions related to the Tax Reform Legislation. Net cash used for investing activities totaled $1.60$1.0 billion for the first ninesix months of 20182019 primarily due to gross property additions related to additional capital expenditures for distribution, environmental, distribution,and transmission and steam assets. Net cash provided from financing activities totaled $369$617 million for the first ninesix months of 20182019 primarily due to an issuance of long-term debt and additional capital contributions from Southern Company, partially offset by a payment of common stock dividend payments.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 ninesix months of 20182019 include increases of $2.40 billion$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 equipmentequipment. These changes were primarily due to increases in AROs relatedthe impacts of retiring and reclassifying Plant Gorgas Units 8, 9, and 10. See Note 2 to the CCR Rulefinancial statements in Item 8 of the Form 10-K and additionsNote (B) to distribution, transmission, and steam assets, $1.39the Condensed Financial Statements herein under "Alabama Power – Environmental Accounting Order" for additional information. Other significant increases include $1.4 billion in AROs related to the CCR Rule and nuclear decommissioning, $504 million in additional paid-in capital primarily due to capital contributions from Southern Company, and $496 million in long-term debttotal common stockholder's equity, primarily due to a senior note issuance. In addition, $321$1.2 billion capital contribution from Southern Company, $342 million of long-term debt was reclassified as securitiesin asset retirement obligations, deferred due within one year.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"Asset Retirement Obligations"Obligations" herein for additional information related to changes in Alabama Power's AROs.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. Subsequent to September 30, 2018, Alabama Power purchased and held $120 million aggregate principal amount of The Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Plant Barry Project), Series 2008. An additional $201 million will be required through September 30, 2019 to fundThere are no scheduled maturities of long-term debt.
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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.
In October 2018, Alabama Power's Board of Directors approved updates to its construction program that is currently estimated to total $1.8 billion for 2019, $1.6 billion for 2020, $1.6 billion for 2021, $1.4 billion for 2022, and $1.5 billion for 2023. 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 $0.3 billion for 2019, $0.1 billion for 2020, $0.2 billion for 2021, $0.2 billion for 2022, and $0.1 billion for 2023. These estimated expenditures do not include any potential compliance costs associated with pending regulation of CO2 emissions from fossil-fuel-fired electric generating units.
Alabama Power anticipates costs associated with closure-in-place and monitoring of ash ponds in accordance with the CCR Rule, which are reflected in Alabama Power's ARO liabilities. These costs, which are expected to change, could change materially as Alabama Power continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities. These costs are expected to begin in 2019 and are currently estimated to be approximately $232 million for 2019, $238 million for 2020, $246 million for 2021, $252 million for 2022, and $258 million for 2023. See FUTURE EARNINGS POTENTIAL – "Environmental Matters– Environmental Laws and Regulations – Coal Combustion Residuals" herein, Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein, and 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.
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
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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 SeptemberJune 30, 2018,2019, Alabama Power had approximately $702$623 million of cash and cash equivalents. Committed credit arrangements with banks at SeptemberJune 30, 20182019 were as follows:
| | | Expires | Expires | | | | | | Expires Within One Year | Expires | | | | |
| 2019 | 2019 | | 2020 | | 2022 | | Total | | Unused | | Term Out | | No Term Out | 2019 | | 2020 | | 2024 | | Total | | Unused |
(in millions) | | $ | 33 |
| | $ | 500 |
| | $ | 800 |
| | $ | 1,333 |
| | $ | 1,333 |
| | $ | — |
| | $ | 33 |
| 3 |
| | $ | 500 |
| | $ | 800 |
| | $ | 1,303 |
| | $ | 1,303 |
|
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
See Note 68 to the financial statements of Alabama Power 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 SeptemberJune 30, 2018,2019, 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, 2018.2019. At SeptemberJune 30, 2018,2019, Alabama Power had $120$87 million aggregate principal amount of fixed rate The Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Plant Barry Project), Series 2008pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months. Subsequent to September 30, 2018, Alabama Power purchased and held all of these bonds.
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 at September 30, 2018 | | 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 | $ | — |
| | — | % | | $ | 11 |
| | 2.2 | % | | $ | 135 |
|
| Short-term bank loan | 3 |
| | 3.7 | % | | 3 |
| | 3.7 | % | | 3 |
|
| Total | $ | 3 |
| | 3.7 | % | | $ | 14 |
| | 2.6 | % | | |
|
| | | | | | | | | | |
| | 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, 2018.2019. 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 SeptemberJune 30, 2018,2019, 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.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or 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, 2018 were as follows:
|
| | | |
| Credit Ratings | Maximum Potential Collateral Requirements |
| | (in millions) |
| At BBB and/or Baa2 | $ | 1 |
|
| At BBB- and/or Baa3 | $ | 1 |
|
| Below BBB- and/or Baa3 | $ | 284 |
|
Included in these amounts are certain agreements that could require collateral in the event that either Alabama Power or Georgia Power (affiliate company(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 September 28, 2018, Fitch assigned a negative rating outlook to the ratings of Southern Company and certain of its subsidiaries (including Alabama Power).
Also on September 28, 2018, Moody's revised its rating outlook for Alabama Power from negative to stable.
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 32 to the financial statements of Alabamaunder "Alabama Power under "Retail Regulatory Matters – Rate RSE" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Alabama Power – Rate RSE" herein for additional information.
Financing Activities
In June 2018,February 2019, Alabama Power issued $500repaid at maturity $200 million aggregate principal amount of Series 2018A 4.30%Z 5.125% Senior Notes due JulyFebruary 15, 2048. The proceeds were used to repay outstanding commercial paper and for general corporate purposes, including Alabama Power's continuous construction program.
Subsequent to September 30, 2018, Alabama Power purchased and held $120 million aggregate principal amount of The Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Plant Barry Project), Series 2008. These bonds may be remarketed to the public in the future.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, |
| | 2018 | | 2017 | | 2018 | | 2017 |
| | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | |
| Retail revenues | $ | 2,425 |
| | $ | 2,402 |
| | $ | 6,112 |
| | $ | 5,995 |
|
| Wholesale revenues, non-affiliates | 43 |
| | 45 |
| | 123 |
| | 124 |
|
| Wholesale revenues, affiliates | 4 |
| | 6 |
| | 17 |
| | 23 |
|
| Other revenues | 121 |
| | 93 |
| | 349 |
| | 284 |
|
| Total operating revenues | 2,593 |
| | 2,546 |
| | 6,601 |
| | 6,426 |
|
| Operating Expenses: | | | | | | | |
| Fuel | 480 |
| | 482 |
| | 1,269 |
| | 1,297 |
|
| Purchased power, non-affiliates | 106 |
| | 119 |
| | 338 |
| | 310 |
|
| Purchased power, affiliates | 206 |
| | 161 |
| | 555 |
| | 470 |
|
| Other operations and maintenance | 460 |
| | 430 |
| | 1,325 |
| | 1,248 |
|
| Depreciation and amortization | 232 |
| | 225 |
| | 690 |
| | 669 |
|
| Taxes other than income taxes | 118 |
| | 112 |
| | 332 |
| | 311 |
|
| Estimated loss on Plant Vogtle Units 3 and 4 | — |
| | — |
| | 1,060 |
| | — |
|
| Total operating expenses | 1,602 |
| | 1,529 |
| | 5,569 |
| | 4,305 |
|
| Operating Income | 991 |
| | 1,017 |
| | 1,032 |
| | 2,121 |
|
| Other Income and (Expense): | | | | | | | |
| Interest expense, net of amounts capitalized | (95 | ) | | (105 | ) | | (303 | ) | | (310 | ) |
| Other income (expense), net | 30 |
| | 22 |
| | 104 |
| | 95 |
|
| Total other income and (expense) | (65 | ) | | (83 | ) | | (199 | ) | | (215 | ) |
| Earnings Before Income Taxes | 926 |
| | 934 |
| | 833 |
| | 1,906 |
|
| Income taxes | 262 |
| | 350 |
| | 212 |
| | 705 |
|
| Net Income | 664 |
| | 584 |
| | 621 |
| | 1,201 |
|
| Dividends on Preferred and Preference Stock | — |
| | 4 |
| | — |
| | 13 |
|
Net Income After Dividends
on Preferred and Preference Stock | $ | 664 |
| | $ | 580 |
| | $ | 621 |
| | $ | 1,188 |
|
|
| | | | | | |
| 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, |
| | 2018 | | 2017 | | 2018 | | 2017 |
| | (in millions) | | (in millions) |
| Net Income | $ | 664 |
| | $ | 584 |
| | $ | 621 |
| | $ | 1,201 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
Reclassification adjustment for amounts included in net income,
net of tax of $-, $-, $1, and $1, respectively | 1 |
| | 1 |
| | 3 |
| | 2 |
|
| Total other comprehensive income (loss) | 1 |
| | 1 |
| | 3 |
| | 2 |
|
| Comprehensive Income | $ | 665 |
| | $ | 585 |
| | $ | 624 |
| | $ | 1,203 |
|
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, |
| | 2018 | | 2017 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 621 |
| | $ | 1,201 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 854 |
| | 821 |
|
| Deferred income taxes | (185 | ) | | 328 |
|
| Allowance for equity funds used during construction | (50 | ) | | (29 | ) |
| Pension, postretirement, and other employee benefits | (46 | ) | | (42 | ) |
| Settlement of asset retirement obligations | (82 | ) | | (95 | ) |
| Estimated loss on Plant Vogtle Units 3 and 4 | 1,060 |
| | — |
|
| Other, net | 9 |
| | (51 | ) |
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (205 | ) | | (254 | ) |
| -Fossil fuel stock | 70 |
| | (2 | ) |
| -Prepaid income taxes | 231 |
| | (5 | ) |
| -Other current assets | (36 | ) | | (24 | ) |
| -Accounts payable | 109 |
| | (161 | ) |
| -Accrued taxes | 26 |
| | (52 | ) |
| -Accrued compensation | (32 | ) | | (60 | ) |
| -Retail fuel cost over recovery | — |
| | (84 | ) |
| -Other current liabilities | (111 | ) | | (11 | ) |
| Net cash provided from operating activities | 2,233 |
| | 1,480 |
|
| Investing Activities: | | | |
| Property additions | (2,276 | ) | | (1,907 | ) |
| Nuclear decommissioning trust fund purchases | (638 | ) | | (411 | ) |
| Nuclear decommissioning trust fund sales | 633 |
| | 406 |
|
| Cost of removal, net of salvage | (71 | ) | | (54 | ) |
| Change in construction payables, net of joint owner portion | 72 |
| | 180 |
|
| Payments pursuant to LTSAs | (52 | ) | | (59 | ) |
| Asset dispositions | 138 |
| | 63 |
|
| Other investing activities | (19 | ) | | (52 | ) |
| Net cash used for investing activities | (2,213 | ) | | (1,834 | ) |
| Financing Activities: | | | |
| Increase (decrease) in notes payable, net | 102 |
| | (391 | ) |
| Proceeds — | | | |
| Capital contributions from parent company | 2,335 |
| | 412 |
|
| Senior notes | — |
| | 1,350 |
|
| Short-term borrowings | — |
| | 700 |
|
| Other long-term debt | — |
| | 370 |
|
| Redemptions and repurchases — | | | |
| Senior notes | (1,000 | ) | | (450 | ) |
| Pollution control revenue bonds | (469 | ) | | (65 | ) |
| Short-term borrowings | (150 | ) | | (300 | ) |
| Other long-term debt | (100 | ) | | — |
|
| Payment of common stock dividends | (1,043 | ) | | (961 | ) |
| Premiums on redemption and repurchases of senior notes | (152 | ) | | — |
|
| Other financing activities | (15 | ) | | (48 | ) |
| Net cash provided from (used for) financing activities | (492 | ) | | 617 |
|
| Net Change in Cash, Cash Equivalents, and Restricted Cash | (472 | ) | | 263 |
|
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 852 |
| | 3 |
|
| Cash, Cash Equivalents, and Restricted Cash at End of Period | $ | 380 |
| | $ | 266 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid during the period for — | | | |
| Interest (net of $19 and $17 capitalized for 2018 and 2017, respectively) | $ | 315 |
| | $ | 284 |
|
| Income taxes, net | 141 |
| | 369 |
|
| Noncash transactions — Accrued property additions at end of period | 670 |
| | 470 |
|
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, 2018 | | At December 31, 2017 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 380 |
| | $ | 852 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 747 |
| | 544 |
|
| Unbilled revenues | | 245 |
| | 255 |
|
| Under recovered fuel clause revenues | | 105 |
| | 165 |
|
| Joint owner accounts receivable | | 208 |
| | 262 |
|
| Affiliated | | 39 |
| | 24 |
|
| Other accounts and notes receivable | | 96 |
| | 76 |
|
| Accumulated provision for uncollectible accounts | | (3 | ) | | (3 | ) |
| Fossil fuel stock | | 244 |
| | 314 |
|
| Materials and supplies | | 494 |
| | 504 |
|
| Prepaid expenses | | 77 |
| | 216 |
|
| Other regulatory assets, current | | 199 |
| | 205 |
|
| Other current assets | | 91 |
| | 14 |
|
| Total current assets | | 2,922 |
| | 3,428 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 35,671 |
| | 34,861 |
|
| Less: Accumulated provision for depreciation | | 12,029 |
| | 11,704 |
|
| Plant in service, net of depreciation | | 23,642 |
| | 23,157 |
|
| Nuclear fuel, at amortized cost | | 528 |
| | 544 |
|
| Construction work in progress | | 4,655 |
| | 4,613 |
|
| Total property, plant, and equipment | | 28,825 |
| | 28,314 |
|
| Other Property and Investments: | | | | |
| Equity investments in unconsolidated subsidiaries | | 50 |
| | 53 |
|
| Nuclear decommissioning trusts, at fair value | | 933 |
| | 929 |
|
| Miscellaneous property and investments | | 61 |
| | 59 |
|
| Total other property and investments | | 1,044 |
| | 1,041 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 519 |
| | 516 |
|
| Other regulatory assets, deferred | | 3,041 |
| | 2,932 |
|
| Other deferred charges and assets | | 510 |
| | 548 |
|
| Total deferred charges and other assets | | 4,070 |
| | 3,996 |
|
| Total Assets | | $ | 36,861 |
| | $ | 36,779 |
|
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, 2018 | | At December 31, 2017 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 511 |
| | $ | 857 |
|
| Notes payable | | 102 |
| | 150 |
|
| Accounts payable — | | | | |
| Affiliated | | 515 |
| | 493 |
|
| Other | | 909 |
| | 834 |
|
| Customer deposits | | 275 |
| | 270 |
|
| Accrued taxes | | 345 |
| | 344 |
|
| Accrued interest | | 108 |
| | 123 |
|
| Accrued compensation | | 185 |
| | 219 |
|
| Asset retirement obligations, current | | 193 |
| | 270 |
|
| Other regulatory liabilities, current | | 151 |
| | 191 |
|
| Other current liabilities | | 180 |
| | 198 |
|
| Total current liabilities | | 3,474 |
| | 3,949 |
|
| Long-term Debt | | 9,863 |
| | 11,073 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 2,999 |
| | 3,175 |
|
| Deferred credits related to income taxes | | 3,218 |
| | 3,248 |
|
| Accumulated deferred ITCs | | 264 |
| | 248 |
|
| Employee benefit obligations | | 650 |
| | 659 |
|
| Asset retirement obligations, deferred | | 2,401 |
| | 2,368 |
|
| Other deferred credits and liabilities | | 141 |
| | 128 |
|
| Total deferred credits and other liabilities | | 9,673 |
| | 9,826 |
|
| Total Liabilities | | 23,010 |
| | 24,848 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, without par value — | | | | |
| Authorized — 20,000,000 shares | | | | |
| Outstanding — 9,261,500 shares | | 398 |
| | 398 |
|
| Paid-in capital | | 9,670 |
| | 7,328 |
|
| Retained earnings | | 3,792 |
| | 4,215 |
|
| Accumulated other comprehensive loss | | (9 | ) | | (10 | ) |
| Total common stockholder's equity | | 13,851 |
| | 11,931 |
|
| Total Liabilities and Stockholder's Equity | | $ | 36,861 |
| | $ | 36,779 |
|
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 2018 vs. THIRD QUARTER 2017goals 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 2018 vs. YEAR-TO-DATE 2017Environmental 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 riskscannot 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 Georgia Power's business of providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, reliability, fuel, capital expenditures, and restoration following major storms. Georgia Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Georgia PowerForm 10-K for additional information.
On June 28, 2019, the foreseeable future. On April 3, 2018, the Georgia PSCFERC approved a settlement agreement between Georgia PowerAlabama Municipal Electric Authority and Cooperative Energy and SCS and the stafftraditional 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 Georgia PSC regarding the retail rateOATT settlement agreement will not have a material impact of the Tax Reform Legislation (Tax Reform Settlement Agreement). The Tax Reform Settlement Agreement provides for a total of $330 million in customer refunds for 2018 and 2019 and the deferral of certain revenues and tax benefits to be addressed in Georgia Power's next base rate case, which is scheduled to be filed by July 1, 2019. The Georgia PSC also approved an increase to Georgia Power's retail equity ratio to address the negative cash flow and credit metric impacts of the Tax Reform Legislation. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate Plans" herein for additional information on the Tax Reform Settlement Agreement.financial statements of Alabama Power.
Georgia Power continues to focus on several key performance indicators including, but not limited to, customer satisfaction, plant availability, system reliability, the execution
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). 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 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). Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC has stated the $7.3 billion estimate included in the seventeenth VCM proceeding does not represent a cost cap, Georgia Power did not seek rate recovery for the $0.7 billion increase in costs included in the revised base capital cost forecast (or any related financing costs) in the nineteenth VCM report filed with the Georgia PSC on August 31, 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs included in the revised construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018.
GEORGIAALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
As a result of the increase in the total project capital cost forecast and GeorgiaRetail Regulatory Matters
Alabama Power's decision not to seekrevenues from regulated retail operations are collected through various 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. On September 26, 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 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. Georgia Power is working with the other Vogtle Owners to clarify any interpretive issues related to the operation of certain provisions of the Vogtle Owner Term Sheet.
In September 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. In September 2018, the DOE extended the conditional commitment to March 31, 2019. Any further extension must be approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and aremechanisms 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.
The ultimate outcome of these matters cannot be determined at this time.
See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" and ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" herein for additional information on Plant Vogtle Units 3 and 4.
RESULTS OF OPERATIONS
Net Income
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $84 | | 14.5 | | $(567) | | (47.7) |
Georgia Power's net income after dividends on preferred and preference stock for the third quarter 2018 was $664 million compared to $580 million for the corresponding period in 2017. The increase was primarily due to lower federal income tax expense as a resultoversight of the Tax Reform LegislationAlabama PSC. Alabama Power currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and an increase in retail revenues associated with customer growth and warmer weather inRate NDR. In addition, the third quarter 2018 comparedAlabama PSC issues accounting orders to address current events impacting Alabama Power. See Note 2 to the corresponding periodfinancial statements under "Alabama Power" in 2017. Partially offsetting the increase were revenues deferred as a regulatory liability for future customer bill credits related to the Tax Reform Legislation as well as higher non-fuel operations and maintenance expenses.
For year-to-date 2018, net income after dividends on preferred and preference stock was $621 million compared to $1.19 billion for the corresponding period in 2017. The decrease 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, revenues deferred as a regulatory liability for future customer bill credits related to the Tax Reform Legislation, and higher non-fuel operations and maintenance expenses. Partially offsetting the decrease were lower federal income tax expense as a resultItem 8 of the Tax Reform LegislationForm 10-K and an increase in retail revenues associated with colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 compared to the corresponding periods in 2017.
See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate Plans" herein for additional information on regulatory actions related to the Tax Reform Legislation. Also, see Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information onregarding Alabama Power's rate mechanisms, accounting orders, and the estimated lossrecovery 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 "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 Georgiapublic 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 constructionfinancial statements. See Notes (B) and (C) to the Condensed Financial Statements herein for a discussion of Plant Vogtle Units 3various other contingencies, regulatory matters, and 4.other matters being litigated which may affect future earnings potential.
GEORGIAIn 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
Retail RevenuesRecently Issued Accounting Standards
See Note (A) to the Condensed Financial Statements herein for information regarding Alabama Power's recently adopted accounting standards. |
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $23 | | 1.0 | | $117 | | 2.0 |
InFINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Alabama Power in Item 7 of the third quarter 2018, retail revenues were $2.43 billion comparedForm 10-K for additional information. Alabama Power's financial condition remained stable at June 30, 2019. Alabama Power intends to $2.40 billioncontinue 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 corresponding period in 2017. For year-to-date 2018, retail revenues were $6.11 billion compared to $6.00 billion for the corresponding period in 2017.
Detailsfirst six months of the changes in retail revenues were2019, an increase of $43 million as follows:
|
| | | | | | | | | | | | | |
| | Third Quarter 2018 | | Year-to-Date 2018 |
| | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | $ | 2,402 |
| | | | $ | 5,995 |
| | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | (87 | ) | | (3.6 | ) | | (196 | ) | | (3.2 | ) |
| Sales growth | 44 |
| | 1.9 |
| | 70 |
| | 1.2 |
|
| Weather | 34 |
| | 1.4 |
| | 139 |
| | 2.3 |
|
| Fuel cost recovery | 32 |
| | 1.3 |
| | 104 |
| | 1.7 |
|
| Retail – current year | $ | 2,425 |
| | 1.0 | % | | $ | 6,112 |
| | 2.0 | % |
Revenues associated with changes in rates and pricing decreased in the third quarter and year-to-date 2018 when compared to the corresponding periodsfirst six months of 2018. The increase in 2017net cash provided from operating activities was primarily due to revenues deferred as a regulatory liability for futureincreased fuel cost recovery, partially offset by the prior year impacts of customer bill credits related to the Tax Reform Legislation and decreases in revenues recognized under the NCCR tariff, also primarilybilling reductions related to the Tax Reform Legislation. Partially offsettingNet cash used for investing activities totaled $1.0 billion for the decreasefirst six months of 2019 primarily related to additional capital expenditures for year-to-date 2018 were higherdistribution, 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 variable demand-driven pricingSouthern Company, partially offset by a payment of common stock dividends and a long-term debt maturity. Fluctuations in cash flows from commercialfinancing activities vary from period to period based on capital needs and industrial customers.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 FUTURE EARNINGS POTENTIALNote 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 – "Retail Regulatory Matters – Rate Plans"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 on regulatory actions related toinformation.
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 Tax Reform Legislation. Also, seeForm 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 – "Retail Regulatory Matters – Nuclear Construction""Environmental Matters" of GeorgiaAlabama Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction – Regulatory Matters" herein for additional information relatedon Alabama Power's environmental compliance strategy.
The construction program is subject to the NCCR tariff.
Revenues attributable toperiodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in sales increasedbusiness 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 third quarterexpected environmental compliance program; changes in FERC rules and year-to-date 2018 when compared toregulations; Alabama PSC approvals; changes in legislation; the corresponding periods in 2017. Weather-adjusted residential KWH sales increased 3.3%cost and 1.9%efficiency of construction labor, equipment, and weather-adjusted commercial KWH sales increased 2.1%materials; project scope and 1.8% for the third quarter and year-to-date 2018, respectively, largely due to customer growth. Weather-adjusted industrial KWH sales increased 2.5% and 1.2% for the third quarter and year-to-date 2018, respectively. The increases were primarily driven by increased demand in the paper sector as a result of increased export demand and for shipping supplies resulting from increased electronic commerce, the lumber sector as a result of increased construction activity,design changes; storm impacts; and the rubber sector as a result
Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues increased in the third quarter and year-to-date 2018 when compared to the corresponding periods in 2017 primarily due to increased energy sales driven by higher purchased power costs and warmer weather in the third quarter 2018. Additionally, the increase for year-to-date 2018 was due to colder weather in the first quarter 2018 and warmer weather in the second quarter 2018. 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
GEORGIAALABAMA 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 – 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.
Wholesale Revenues – AffiliatesAlabama 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:
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(2) | | (33.3) | | $(6) | | (26.1) |
|
| | | | | | | | | | | | | | | | | | |
| Expires | | | | |
| 2019 | | 2020 | | 2024 | | Total | | Unused |
| (in millions) |
| $ | 3 |
| | $ | 500 |
| | $ | 800 |
| | $ | 1,303 |
| | $ | 1,303 |
|
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.
For year-to-date 2018, wholesale revenues from sales to affiliates were $17 million compared to $23 million for the corresponding period in 2017. The decrease was due to a 54.3% decrease in KWH sales primarily dueSee Note 8 to the higher cost of Georgia Power-owned generation as compared to the market cost of available energy.
Other Revenues
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $28 | | 30.1 | | $65 | | 22.9 |
In the third quarter 2018, other revenues were $121 million compared to $93 million for the corresponding periodfinancial statements under "Bank Credit Arrangements" in 2017. For year-to-date 2018, other revenues were $349 million compared to $284 million for the corresponding period in 2017. The increases were primarily due to $24 million and $62 million of revenues in the third quarter and year-to-date 2018, respectively, primarily from unregulated sales of products and services that were reclassified as other revenues as a resultItem 8 of the adoption of ASC 606, Revenue from Contracts with Customers (ASC 606). In prior periods, these revenues were included in other income (expense), net. SeeForm 10-K and Note (A)(F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information regarding Georgia Power's adoption of ASC 606.information.
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | | | |
| | Third Quarter 2018
vs.
Third Quarter 2017 | | Year-to-Date 2018
vs.
Year-to-Date 2017 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | (2 | ) | | (0.4 | ) | | $ | (28 | ) | | (2.2 | ) |
| Purchased power – non-affiliates | (13 | ) | | (10.9 | ) | | 28 |
| | 9.0 |
|
| Purchased power – affiliates | 45 |
| | 28.0 |
| | 85 |
| | 18.1 |
|
| Total fuel and purchased power expenses | $ | 30 |
| | | | $ | 85 |
| | |
In the third quarter 2018, total fuel and purchased power expenses were $792 million compared to $762 millionAs reflected in the corresponding periodtable above, in 2017.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 increaseamount of variable rate pollution control revenue bonds outstanding requiring liquidity support was primarily dueapproximately $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 a $43 million net increase relatedbe reoffered within the next 12 months.
Alabama Power also has substantial cash flow from operating activities and access to the volumecapital 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 KWHs generatedAlabama Power and purchased duethe other traditional electric operating companies. Proceeds from such issuances for the benefit of Alabama Power are loaned directly to warmer weather, partially offset by a $13 million decrease related to the average costAlabama Power. The obligations of purchased power primarily due to lower natural gas prices.
For year-to-date 2018, total fueleach traditional electric operating company under these arrangements are several and purchased power expenses were $2.16 billion compared to $2.08 billionthere is no cross-affiliate credit support. Short-term borrowings are included in notes payable in the corresponding period in 2017. The increase was primarily due to a $77 million increase related to the volumebalance sheets.
GEORGIAALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FuelDetails 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 purchased power energy transactions dooperating 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 significant impact on earnings sinceresult 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 fuel expensesamounts 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" ofcertain 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 78 of the Form 10-K for additional information.
Details of Georgia Power's generation and purchased power were as follows:
|
| | | | | | | |
| | Third Quarter 2018 | | Third Quarter 2017 | | Year-to-Date 2018 | | Year-to-Date 2017 |
Total generation (in billions of KWHs) | 18 | | 18 | | 49 | | 48 |
Total purchased power (in billions of KWHs) | 8 | | 7 | | 22 | | 20 |
Sources of generation (percent) — | | | | | | | |
| Gas | 44 | | 41 | | 43 | | 41 |
| Coal | 32 | | 35 | | 30 | | 33 |
| Nuclear | 22 | | 23 | | 25 | | 24 |
| Hydro | 2 | | 1 | | 2 | | 2 |
Cost of fuel, generated (in cents per net KWH) — | | | | | | | |
| Gas | 2.58 | | 2.63 | | 2.64 | | 2.71 |
| Coal | 3.14 | | 3.08 | | 3.25 | | 3.17 |
| Nuclear | 0.83 | | 0.84 | | 0.83 | | 0.84 |
Average cost of fuel, generated (in cents per net KWH) | 2.36 | | 2.38 | | 2.36 | | 2.40 |
Average cost of purchased power (in cents per net KWH)(*) | 4.52 | | 4.68 | | 4.70 | | 4.63 |
| |
(*) | Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider. |
Fuel
For year-to-date 2018, fuel expense was $1.27 billion compared to $1.30 billion in the corresponding period in 2017. The decrease was primarily due to an 8.0% decrease in the volume of KWHs generated by coal largely due to scheduled generation outages and a 2.6% decrease in the average cost of fuel per KWH generated by natural gas, partially offset by a 6.8% increase in the volume of KWHs generated by natural gas and a 2.5% increase in the average cost of fuel per KWH generated by coal.
Purchased Power – Non-AffiliatesFinancing Activities
In the third quarter 2018, purchased power expense from non-affiliates was $106February 2019, Alabama Power repaid at maturity $200 million compared to $119 million in the corresponding period in 2017. The decrease was primarilyaggregate principal amount of Series Z 5.125% Senior Notes due to a 17.8% decrease in the volume of KWHs purchased primarily due to the higher market cost of available energy as compared to Southern Company system resources, partially offset by an 8.3% increase in the average cost per KWH purchased primarily due to higher energy prices.
For year-to-date 2018, purchased power expense from non-affiliates was $338 million compared to $310 million in the corresponding period in 2017. The increase was primarily due to a 10.2% increase in the average cost per KWH purchased primarily due to higher energy prices.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Purchased Power – AffiliatesFebruary 15, 2019.
In the third quarter 2018, purchased power expense from affiliates was $206 million comparedaddition to $161 million in the corresponding period in 2017. The increase was primarily dueany financings that may be necessary to meet capital requirements and contractual obligations, Alabama Power plans to continue, when economically feasible, a 28.3% increase in the volume of KWHs purchased dueprogram to scheduled generation outagesretire higher-cost securities and warmer weather, partially offset by a 3.4% decrease in the average cost per KWH purchased primarily resulting from lower natural gas prices.replace these obligations with lower-cost capital if market conditions permit.
For year-to-date 2018, purchased power expense from affiliates was $555 million compared to $470 million in the corresponding period in 2017. The increase was primarily due to an 11.1% increase in the volume of KWHs purchased due to colder weather in the first quarter 2018 and scheduled generation outages and warmer weather in the second and third quarters 2018.
Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $30 | | 7.0 | | $77 | | 6.2 |
In the third quarter 2018, other operations and maintenance expenses were $460 million compared to $430 million in the corresponding period in 2017. The increase was primarily due to $23 million of expenses from unregulated sales of products and services that were reclassified to other operations and maintenance expenses as a result of the adoption of ASC 606. In prior periods, these expenses were included in other income (expense), net. Also contributing to the increase was $11 million in transmission and distribution costs, primarily due to additional line maintenance and billing adjustments with integrated transmission system owners, partially offset by a decrease of $9 million in certain employee compensation and benefit costs.
For year-to-date 2018, other operations and maintenance expenses were $1.33 billion compared to $1.25 billion in the corresponding period in 2017. The increase was primarily due to $58 million of expenses from unregulated sales of products and services that were reclassified to other operations and maintenance expenses as a result of the adoption of ASC 606. In prior periods, these expenses were included in other income (expense), net. Also contributing to the increase were a $19 million decrease in gains from sales of integrated transmission system assets and increases of $11 million in demand-side management costs related to the timing of new programs, $8 million related to additional distribution line maintenance, and $8 million in billing adjustments with integrated transmission system owners, partially offset by decreases of $14 million in certain employee compensation and benefit costs and $10 million related to affiliate labor billing adjustments.
See Note (A) to the Condensed Financial Statements herein for additional information regarding Georgia Power's adoption of ASC 606.
Depreciation and Amortization
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $7 | | 3.1 | | $21 | | 3.1 |
In the third quarter 2018, depreciation and amortization was $232 million compared to $225 million in the corresponding period in 2017. For year-to-date 2018, depreciation and amortization was $690 million compared to $669 million in the corresponding period in 2017. The increases were primarily due to increases of $8 million and $23 million related to additional plant in service in the third quarter and year-to-date 2018, respectively.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Taxes Other Than Income Taxes
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $6 | | 5.4 | | $21 | | 6.8 |
In the third quarter 2018, taxes other than income taxes were $118 million compared to $112 million in the corresponding period in 2017. For year-to-date 2018, taxes other than income taxes were $332 million compared to $311 million in the corresponding period in 2017. The increases were primarily due to increases in property taxes of $4 million and $11 million in the third quarter and year-to-date 2018, respectively, as a result of an increase in the assessed value of property and increases in municipal franchise fees of $3 million and $10 million in the third quarter and year-to-date 2018, respectively, largely related to higher retail revenues.
Estimated Loss on Plant Vogtle Units 3 and 4
|
| | | | | | |
Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$— | | 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 (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information.
Interest Expense, Net of Amounts Capitalized
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(10) | | (9.5) | | $(7) | | (2.3) |
In the third quarter 2018, interest expense, net of amounts capitalized was $95 million compared to $105 million in the corresponding period in 2017. For year-to-date 2018, interest expense, net of amounts capitalized was $303 million compared to $310 million in the corresponding period in 2017. The decreases were primarily due to a decrease in outstanding borrowings. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information.
Other Income (Expense), Net
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $8 | | 36.4 | | $9 | | 9.5 |
In the third quarter 2018, other income (expense), net was $30 million compared to $22 million in the corresponding period in 2017. For year-to-date 2018, other income (expense), net was $104 million compared to $95 million in the corresponding period in 2017. The increases were primarily due to increases in AFUDC equity of $14 million and $21 million in the third quarter and year-to-date 2018, respectively, resulting from a higher AFUDC rate due to a higher equity ratio and lower short-term borrowings. These increases were partially offset by $3 million and $11 million in the third quarter and year-to-date 2017, respectively, of revenues and expenses, net from unregulated sales of products and services. In 2018, these revenues and expenses are included in other revenues and
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
other operations and maintenance expenses, respectively, as a result of the adoption of ASC 606. See Note (A) to the Condensed Financial Statements herein for additional information regarding Georgia Power's adoption of ASC 606.
Income TaxesRate 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:
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 |
| Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) |
| (% change) |
| (change in millions) | | (% change) |
| $(88) |
| (25.1) |
| $(493) | | (69.9) |
|
| | | | | | | | | |
| 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. |
InGeorgia Power's filing primarily reflects requests to (i) address the third quarter 2018, income taxes were $262 million compared to $350 million in the corresponding period in 2017. For year-to-date 2018, income taxes were $212 million compared to $705 million in the corresponding period in 2017. The decreases were primarily due to a lower federal income tax rate as a resultimpacts of the Tax Reform Legislation, partially offset(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 recognition of a valuation allowance on certain state tax credit carryforwards. Also contributing to the decrease for year-to-date 2018 was the reduction in pre-tax earnings resulting from the estimated probable loss related to Plant Vogtle Units 3 and 4.
See Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information on the estimated loss related to Georgia Power's construction of Plant Vogtle Units 3 and 4. Also, see Note (H) to the Condensed Financial Statements herein for additional information on the Tax Reform Legislation and the net state income tax valuation allowance.
Dividends on Preferred and Preference Stock
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(4) | | (100.0) | | $(13) | | (100.0) |
In the third quarter2019 IRP, the Georgia PSC approved the decertification and year-to-date 2018, there were no dividends on preferredretirement of Plant Hammond Units 1 through 4 (840 MWs) and preference stock compared to $4Plant 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 $13$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 corresponding periods2013 ARP.
For the regulatory asset balances remaining at December 31, 2019, Georgia Power requested recovery in 2017. The decreases were duethe 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 redemptionapplicable unit's remaining useful life through 2035. The ultimate outcome of these matters cannot be determined at this time.
Also in October 2017the 2019 IRP, the Georgia PSC rejected a request to certify approximately 25 MWs of all outstanding sharescapacity 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 preferredproposed environmental compliance strategy associated with ash pond and preference stock.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 under "Outstanding Classesto (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 Capital Stock"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
FUTURE EARNINGS POTENTIALSOUTHERN 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 results of operations discussed abovenatural gas distribution utilities 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,subject to regulation and risks of Georgia Power's business of providing electric service. These factors include Georgia Power's ability to maintain a constructiveoversight by their respective state regulatory environment that continues to allowagencies for the timelyrates 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 prudently-incurredall costs during a time of increasingprudently incurred in purchasing natural gas for customers. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and limitedamounts 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 demand growth overtest year for the next several years.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 Plant Vogtle Units 3 and 4. Financing costs are also major factors. Future earningsrecovered 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 driven primarilyrecovered through AFUDC; however, Georgia Power will not record AFUDC related to any capital costs in excess of the total deemed reasonable by customer growth. Earningsthe 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
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 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 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
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 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 depend upon maintainingrequest 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 Southern Company in the Form 10-K for a discussion of certain risks associated with the licensing, construction, and growing sales, considering,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 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 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 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 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 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, and more multi-family home construction,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 contributehave 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 reductioncash 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 customer usage. Earningsassets 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 includeinclude: 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 competition, new energy contractsconditions; 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 utilities, energy conservation practiced by customers,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 alternative energy sourcesshort-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 customers,$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 priceparent 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 electricity,cash and cash equivalents. To meet short-term cash needs and contingencies, the price elasticitySouthern 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 demand,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 economic growth or decline3.213% 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 Georgia Power's service territory. Demand for electricity is primarily driven by the paceaggregate principal amounts of economic growth$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 affectednecessary 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 regionalSouthern 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 global economic conditions, which may impact future earnings.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.
GEORGIA
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
For additional information relatingSECOND 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 issues, see RISK FACTORSregulatory 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 Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Georgia Power2018. The increase was primarily related to an increase 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 costsretail revenues associated with these environmental lawsthe 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 regulations. The costs, including capital expenditures,lower customer usage as well as increases to operations and maintenance costs,expenses and costs reflected in ARO liabilities, required to comply with environmental laws and regulations and to achieve stated goals may impact future unit retirement and replacement decisions, results of operations, cash flows, and financial condition. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to the transmission system. A major portion of these costs are expected to be recovered through existing ratemaking provisions. The ultimate impact of environmental laws and regulations and the GHG goals discussed below will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed technology, and the outcome of pending and/or future legal challenges.depreciation.
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 fully recovered in rates on a timely basis. Georgia Power's Environmental Compliance Cost Recovery (ECCR) tariff allows for the recovery of capital and operations and maintenance costs related to environmental controls mandated by state and federal regulations. 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 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 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 Laws and Regulations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Water Quality" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the effluent limitations guidelines (ELG) rule.
On May 2, 2018, the EPA updated its anticipated final rulemaking schedule for ELG from September 2020 to December 2019. The impact of any changes to the ELG rule will depend on the content of the final rule and the outcome of any legal challenges and cannot be determined at this time.
Coal Combustion Residuals
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule).
The EPA published certain amendments to the CCR Rule, which became effective August 29, 2018. These amendments extend the date from April 2019 to October 31, 2020 to cease sending CCR and other waste streams to impoundments that demonstrate compliance with all except two specified criteria. These amendments also establish
GEORGIAALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
groundwater protection standards for four constituents that do not have established EPA maximum contaminant levels and allow a participating state director orRetail 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 (where the EPA is the permitting authority)second quarter 2019, retail revenues were $1.38 billion compared to suspend groundwater monitoring requirements under certain circumstances. However, the Georgia Department of Natural Resources has not incorporated these amendments into its state CCR rule. Specific site impacts are being evaluated by Georgia Power.
On October 15, 2018, the U.S. Court of Appeals$1.34 billion for the Districtcorresponding 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 Columbia Circuit issued a mandate that broadens the CCR Rulechanges 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 regulate previously-excluded inactive surface impoundments (legacy units) located at retired generation facilities and challenges both the ability of unlined impoundments to continue operating and the classification of clay lined units. It is anticipated that the EPA will issue a series of rulemakings to address this court action. Georgia Power is evaluating the extent of potential impacts on legacy units but anticipates no significant impacts to its ongoing CCR strategycorresponding periods in 2018 primarily due to this mandate. The ultimate impact of these changes will not be known until the EPA rulemaking and any legal challenges are finalized.
Georgia Power continues to perform engineering studies related to its plans to close the ash ponds at all of its generating plants, including one jointly owned with Gulf Power, in compliance with federal and state CCR rules. Georgia Power also continues to refine its closure strategy and cost estimates for each ash pond and is preparing permit applications as required by the State of Georgia CCR rule. While Georgia Power believes its recorded liability for ash pond closures appropriately reflects its obligations under the current closure strategies it has elected, changes to such strategies and cost estimates would likely result in additional closure costs which would increase the ARO liability. It is not currently possible to quantify the impacts of any increasecustomer bill credits related to a changethe Tax Reform Legislation in closure strategies and/or ongoing engineering studies for the current closure strategies, and the timing of future cash outflows is indeterminable at this time; however, the impact on the ARO liability is expected to be material. As permit applications advance, engineering studies continue, and the timing of individual ash pond closures develops further during the fourth quarter 2018, Georgia Power will record any necessary changes to its ARO liability. Georgia Power expects to continue to periodically update these cost estimates, which could increase further,as well as additional information becomes available.capital investments recovered through Rate CNP Compliance. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
Absent continued recovery of ARO costs through regulated rates, Georgia Power'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.
Nuclear Decommissioning
See Note 12 to the financial statements of Georgiaunder "Alabama Power under "Nuclear Decommissioning"– Rate RSE" and " – Rate CNP Compliance" in Item 8 of the Form 10-K for additional information.
Georgia Power expectsRevenues attributable to complete updated decommissioning cost site studies for Plant Hatch and Plant Vogtle Units 1 and 2changes in sales decreased in the fourthsecond 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 which couldas a result of a decrease in additionaldemand 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 Georgia Power's ARO liability. The ultimate outcomemilder 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 studies cannot be determined at this time.
Global Climate Issues
provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Georgia PowerNote 2 to the financial statements under "Alabama Power" in Item 78 of the Form 10-K for additional information.
On August 31, 2018, the EPA published a proposed Clean Power Plan replacement rule known as the Affordable Clean Energy rule (ACE Rule), which would require states to develop unit-specific emission rate standards based on heat-rate efficiency improvements for existing fossil fuel-fired steam units. As proposed, combustion turbines, including natural gas combined cycles, are not affected sources. As
GEORGIAALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Through 2017,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 has achieved an estimated GHG emission reduction of 36% since 2007. In April 2018, Southern Company established an intermediate goal of a 50% reduction in carbon emissions from 2007 levels by 2030 and a long-term goal of low- to no-carbon operations by 2050. To achieve these goals,system's generation, demand for energy within the Southern Company system expects to continue growing its renewable energy portfolio, optimize technology advancements to modernize its transmissionsystem's service territory, and distribution systems, increase the useavailability of natural gas for generation, complete construction of Plant Vogtle Units 3 and 4, invest in energy efficiency, and continue research and development efforts focused on technologies to lower GHG emissions. Thethe Southern Company system's abilitygeneration. 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 achieve these goals also will be dependent on many external factors, including supportive nationalnon-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 policies, lowdue 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 development, deployment,availability and advancementcost of relevantgenerating 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 technologies.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 ultimate outcomedecrease was primarily due to an 87.4% decrease in KWH sales as a result of this matter cannot be determined at this time.
FERC Matters
Market-Based Rate Authority
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters"decreased coal generation associated with the retirement of Georgia PowerPlant Gorgas Units 8, 9, and 10 and a 6.7% decrease in Item 7the price of energy as a result of lower natural gas prices in the Form 10-K for additional information regarding proceedings relatedsecond quarter 2019 compared to the traditional electric operating companies' (including Georgia Power's) and Southern Power's 2014 and 2017 triennial market power analyses.corresponding period in 2018.
On May 4, 2018,For year-to-date 2019, wholesale revenues from sales to affiliates were $63 million compared to $82 million for the FERC issued an order terminating both proceedings, finding that the traditional electric operating companies (including Georgia Power) and Southern Power satisfy the FERC's standards for market-based rates. On May 9, 2018, the traditional electric operating companies (including Georgia Power) and Southern Power made the compliance filing required by the order. These proceedings are concluded.
Open Access Transmission Tariff
On May 10, 2018, the Alabama Municipal Electric Authority and Cooperative Energy filedcorresponding 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 FERC a complaint against SCSretirement of Plant Gorgas Units 8, 9, and the traditional electric operating companies (including Georgia Power) claiming that the current 11.25% base ROE used in calculating the annual transmission revenue requirements of the traditional electric operating companies' (including Georgia Power's) open access transmission tariff is unjust10 and unreasonable as measured by the applicable FERC standards. The complaint requests that the base ROE be set no higher than 8.65% and that the FERC order refunds for the difference in revenue requirements that results from applying a just and reasonable ROE established in this proceeding upon determining the current ROE is unjust and unreasonable. On June 18, 2018, SCS and the traditional electric operating companies (including Georgia Power) filed their response challenging the adequacy of the showing presented by the complainants and offering support for the current ROE. On September 6, 2018, the FERC issued an order establishing a refund effective date of May 10, 201811.0% decrease in the event a refund isprice of energy due and initiating an investigation and settlement procedures regarding the current base ROE. Through September 30, 2018, the estimated maximum potential refund is not expected to be material to Georgia Power's results of operations. The ultimate outcome of this matter cannot be determined at this time.
Retail Regulatory Matters
Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subjectincreased hydro generation in 2019 as compared to the oversightcorresponding period in 2018.
GEORGIAALABAMA 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.
Rate Plans
See 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 – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate Plans"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 78 of the Form 10-K for additional information regarding Georgia Power's 2013 ARPAROs.
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 PSC's 2018 order relatedPower 2019 Base Rate Case.
Mississippi Power
Kemper County Energy Facility
As the mining permit holder, Liberty Fuels Company, LLC has a legal obligation to the Tax Reform Legislation.
On April 3, 2018, the Georgia PSC approved the Tax Reform Settlement Agreement. Pursuantperform mine reclamation, and Mississippi Power has a contractual obligation to the Tax Reform Settlement Agreement, to reflect the federal income tax rate reduction impactfund all reclamation activities. As a result of the Tax Reform Legislation, Georgia Power will refund to customers a total of $330 million through bill credits. Georgia Power issued bill credits of approximately $130 million in October 2018 and will issue bill credits of approximately $95 million in June 2019 and $105 million in February 2020. In addition, Georgia Power is deferring as a regulatory liability (i) the revenue equivalentabandonment of the tax expense reduction resulting from legislation lowering the Georgia state income tax rate from 6.00% to 5.75%Kemper IGCC, final mine reclamation began in 20192018 and (ii) the entire benefit of approximately $700 million in federal and state excess accumulated deferred income taxes. At September 30, 2018, the related regulatory liability balance totaled $655 million. The amortization of these regulatory liabilities is expected to be addressedsubstantially completed in Georgia Power's next2020, 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 which is scheduled to be filed by July 1, 2019. If there is notwith the Illinois Commission requesting a $230 million increase in annual base rate caserevenues. 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 2019, customers will receive $185 million in annual bill credits beginning in 2020, with any additional federal and state income tax savings deferred as a regulatory liability, until Georgia Power's next base rate case.
Tothe equity ratio from 52% to 54% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation,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 also approved anrequesting a $96 million increase in Georgia Power's retailannual 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 toof 55%. The filing also requests the lower of (i) Georgia Power's actual common equity weight in its capital structure or (ii) 55%, until Georgia Power's next base rate case. At September 30, 2018, Georgia Power's actual retail common equity ratio (on a 13-month average basis) was approximately 53%. Benefits from reduced federal income tax rates in excesscontinuation of the amounts refundedGeorgia rate adjustment mechanism, as previously authorized. Atlanta Gas Light expects the Georgia PSC to customers willissue 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 retaineddetermined 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 Georgia Powerlong-term PPAs, any uncontracted capacity could negatively affect future earnings. Southern Company Gas is engaged in various infrastructure improvement programs designed to coverupdate or expand the carrying costsnatural gas distribution systems of the incremental equity in 2018natural gas distribution utilities to improve reliability and 2019.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
Storm Damage Recovery
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
15 to the financial statements of Georgiaunder "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" and "Southern Power, under "Storm Damage Recovery"" 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 Georgia Power's storm damage reserve.
Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP,Southern Company's capital requirements for incremental operations and maintenance costs of damage from major storms to its transmission and distribution facilities. As of September 30, 2018, the total balance in the regulatory asset related to storm damage was $311 million. During October 2018, Hurricane Michael caused significant damage to Georgia Power's transmission and distribution facilities. Georgia Power currently estimates the costs of repairing the damage will total approximately $125 million to $150 million, which will be charged to the storm damage reserve or capitalized. The rate of storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case, which is scheduled to be filed by July 1, 2019. The ultimate outcome of this matter cannot be determined at this time.subsidiaries' construction programs.
Nuclear Construction
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 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 the Interim Assessment Agreement with the EPC Contractorseveral transitional arrangements to allow construction to continue. The Interim Assessment Agreement expired inIn July 2017, when Georgia Power, acting for itself and as
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
agent for the other Vogtle Owners, and the EPC Contractor entered into the Vogtle Services Agreement. Under 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. Pursuant to the Loan Guarantee Agreement between Georgia Power and the DOE, Georgia Power is required to obtain the DOE's approval
In December 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor.SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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Cost and Schedule
In preparation for its nineteenth VCM filing, Georgia Power requested Southern Nuclear to perform a full cost reforecast for the project. 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) | (in billions) |
Base project capital cost forecast(a)(b) | $ | 8.0 |
| $ | 8.0 |
|
| Construction contingency estimate | 0.4 |
| 0.4 |
|
Total project capital cost forecast(a)(b) | 8.4 |
| 8.4 |
|
Net investment as of September 30, 2018(b) | (4.3 | ) | |
Net investment as of June 30, 2019(b) | | (5.2 | ) |
Remaining estimate to complete(a) | $ | 4.1 |
| $ | 3.2 |
|
| |
| (a) | Excludes financing costs expected to be capitalized through AFUDC of approximately $350$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 $3.2$3.1 billion, of which $1.8$2.0 billion had been incurred through SeptemberJune 30, 2018.2019.
The table above reflectsIn 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 $0.7 billion increase to the baseestimated total project capital cost forecast reported in the second quarter 2018 and is based on the cost reforecast performed prior to the nineteenth VCM filing, which primarily resulted from changed assumptions related to the finalization of contract scopes and management responsibilities for Bechtel and over 60 subcontractors, labor productivity rates, and craft labor incentives, as well as the related levels of project management, oversight, and support, including field supervision and engineering support.
Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC's order in the seventeenth VCM proceeding specifically states that the construction of Plant Vogtle
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Units 3 and 4. The expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4, is not subject to a cost cap, Georgia Power did not seek rate recovery for these cost increases included in the current base capital cost forecast (or any related financing costs) in the nineteenth VCM report that was filed withas previously approved by the Georgia PSC, on August 31, 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs currently included in the construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018, which includes the total increase in the base capital cost forecast and construction contingency estimate.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, availability,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, andor 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. Monthly
The April 2019 cost and schedule validation process established target values for monthly construction production targets requiredand system turnover activities as part of a strategy to maintain and, where possible, build margin to the current project scheduleapproved in-service dates. To support that strategy, monthly production and activity target values will continue to increase significantly through the remainder of 2018 and intothroughout 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 resolutionsubmittal by Southern Nuclear of Inspections, Tests, Analyses, and Acceptance Criteria (ITAAC)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 31, 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 as described above,in conjunction with the nineteenth VCM report, the holders of at least 90% of the ownership
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. OnIn September 26, 2018, the Vogtle Owners unanimously voted to continue construction of Plant Vogtle Units 3 and 4.
AmendmentsRegulatory Matters
See Note 2 to the Vogtle Joint Ownership Agreements
In connection withfinancial statements in Item 8 of the vote to continue construction, Georgia Power entered into (i) the Vogtle Owner Term Sheet with the other Vogtle OwnersForm 10-K 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 amendmentsNote (B) to the Vogtle Joint Ownership AgreementsCondensed 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 purchasebilling 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 PTCsthe Alabama PSC. Alabama Power currently recovers its costs from the other Vogtle Owners,regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and (ii) a term sheet (MEAG Term SheetRate 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 together with10 and reclassified approximately $654 million of the Vogtle Owner Term Sheet, Term Sheets) with MEAG and MEAG SPVJunrecovered asset balances to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 (Project J) under certain circumstances. Pursuantregulatory assets, which are being recovered over the units' remaining useful lives, the latest being through 2037, as established prior to the Vogtle Owner Term Sheet, the Vogtle Joint Ownership Agreements will be modified as follows: (i) each Vogtle Owner will pay its proportionate share of qualifying construction costs for Plant Vogtle Units 3 and 4 based on its ownership percentage updecision to the estimated cost at completion (EAC) for Plant Vogtle Units 3 and 4 which forms the basis of Georgia Power's forecast of $8.4 billion in the nineteenth VCM plus $800retire. Additionally, approximately $700 million of additional construction costs; (ii) Georgia Power will be responsible for 55.7% of actual qualifying constructionnet capitalized asset retirement costs between $800 million and $1.6 billion over the EAC in the nineteenth VCM (resulting in $80 million of potential additional costswere reclassified to Georgia Power), with the remaining Vogtle Owners responsible for 44.3% of such costs pro rataa regulatory asset in accordance with their respective ownership interests;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 (iii)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 will be responsible for 65.7% of qualifyingcurrently 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 between $1.6 billion and $2.1 billion over the EAC in the nineteenth VCM (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests.
If the EAC is revised and exceeds the EAC in the nineteenth VCM by more than $2.1 billion, each of the other Vogtle Owners will have a one-time option to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100% of such Vogtle Owner's remaining share of total construction costs in excess of the EAC in the nineteenth VCM plus $2.1 billion. In this event, Georgia Power will have the option of cancelling the project in lieu of purchasing a portion of the ownership interest of any other Vogtle Owner. If Georgia Power accepts the offer to purchase a portion of another Vogtle Owner's ownership interest in Plant Vogtle Units 3 and 4, the ownership interest(s) to be conveyed from the tendering Vogtle Owner(s) to Georgia Power would be calculated based on the proportion of the cumulative amount of construction costs paid by each such tendering Vogtle Owner(s) and by Georgia Power as of the commercial operation date of Plant Vogtle Unit 4. For purposes of this calculation, payments made by Georgia Power on behalf of another Vogtle Owner in accordance with the second and third items described in the paragraph above would be treated as payments made by the applicable Vogtle Owner.
In the event the actual costs at completion are less than the EAC reflected in the nineteenth VCM report and Plant Vogtle Unit 3 is placed in service by the currently scheduled date of November 2021 or Plant Vogtle Unit 4 is placed in service by the currently scheduled date of November 2022, Georgia Power would be entitled to 60.7% of the cost savings with respect to the relevant unit and the remaining Vogtle Owners would be entitled to 39.3% of such savings on a pro rata basis in accordance with their respective ownership interests.
For purposes of the foregoing provisions, qualifying construction costs would not include costs (i) resulting from force majeure events, including governmental actions or inactions (or significant delays associated with issuance of such actions) that affect the licensing, completion, startup, operations, or financing of Plant Vogtle Units 3 and 4 administrative proceedings or litigation regarding ITAAC or other regulatory challenges to commencement of operation of Plant Vogtle Units 3are being collected through the NCCR tariff and 4, and changes in laws or regulations governing Plant Vogtle Units 3 and 4, (ii) legal fees and legal expenses incurred due to litigation with contractors or subcontractors thatfuel costs are not subsidiaries or affiliates of Southern Company, and (iii) additional costs caused by Vogtle Owner requests other thancollected through a separate fuel cost recovery tariff.
Rate Plans
On June 28, 2019, Georgia Power except forfiled a base rate case (Georgia Power 2019 Base Rate Case) with the exerciseGeorgia 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
GEORGIA POWERSOUTHERN 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 workingnot 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 Vogtle Ownerstwo 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 clarifyrule 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 interpretive issues relateduncontracted 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 operation of certainfinancial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" and "Southern Power," respectively, in Item 8 of the above provisionsForm 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 Vogtle Owner Term Sheet.Form 10-K and "Nuclear Construction" herein for additional information.
UnderAlso 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 Vogtle Owner Term Sheet, the provisionsfinancial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the construction of Plant Vogtle Joint Ownership Agreements requiring thatUnits 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 Owners holding 90% of theUnits 3 and 4. Georgia Power holds a 45.7% ownership interestsinterest 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 votecontinued 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
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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 followingof 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 (Project Adverse Events) will be modified. Pursuant tothat require the Vogtle Joint Ownership Agreements and the Vogtle Owner Term Sheet,vote of the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain Project Adverse Events occur, including: (i)(as amended, and together with the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power publicly announces its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 or the Georgia PSC determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Vogtle Owners pursuant to the Vogtle Owner Term Sheet provisions described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Georgia PSC for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates; and (iv) an incremental extension of one year or more over the most recently approved schedule. Under the Vogtle Owner Term Sheet, Georgia Power may cancel the project at any time in its sole discretion.
In addition, pursuant toNovember 2017 amendment, the Vogtle Joint Ownership Agreements). The Vogtle Joint Ownership Agreements also confirm that the required approvalVogtle 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 holdersGeorgia Power and/or Southern Nuclear as agent, except in cases of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% forwillful misconduct.
As a changeresult of the primary construction contractorincrease in the total project capital cost forecast and (ii) 67% for material amendmentsGeorgia Power's decision not to seek rate recovery of the Vogtle Services Agreement or agreementsincrease in the base capital costs in conjunction with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement.
The Vogtle Owner Term Sheet provides that ifnineteenth VCM report, the holders of at least 90% of the ownership interests fail to vote in favor of continuing the project following any future Project Adverse Event, work on Plant Vogtle Units 3 and 4 wouldwere required to vote to continue for a period of 30 days if the holders of more than 50% of the ownership interests vote in favor of continuing construction (Majority Voting Owners).construction. In such a case,September 2018, the Vogtle Owners (i) would agreeunanimously voted to negotiate in good faith towards the resumption of the project, (ii) if no agreement was reached during such 30-day period, the project would be cancelled, and (iii) in the event of such a cancellation, the Majority Voting Owners would be obligated to reimburse any other Vogtle Owner for the costs it incurred during such 30-day negotiation period.
Purchase of PTCs During Commercial Operation
In addition, under the terms of the Vogtle Owner Term Sheet, Georgia Power agreed to purchase additional PTCs from OPC, Dalton, MEAG SPVM, MEAG SPVP, and MEAG SPVJ (to the extent any MEAG SPVJ PTC rights remain after any purchases required under the MEAG Term Sheet as described below) at varying purchase prices dependent upon the actual cost to completecontinue construction of Plant Vogtle Units 3 and 4 as compared to the EAC included in the nineteenth VCM report. The purchases will be at the option of the applicable Vogtle Owner and will occur during the month after such PTCs are earned.4.
Potential Funding to MEAG Project J
Pursuant to the MEAG Term Sheet, if MEAG SPVJ is unable to make its payments due under the Vogtle Joint Ownership Agreements solely because (i) the conduct of JEA, such as JEA's legal challenges of its obligations under a PPA with MEAG (PPA-J), materially impedes access to capital markets for MEAG for Project J, or (ii) PPA-J is declared void by a court of competent jurisdiction or rejected by JEA under the applicable provisions of the U.S. Bankruptcy Code (each of (i) and (ii), a JEA Default), Georgia Power would purchase from MEAG SPVJ the rights to PTCs attributable to MEAG SPVJ's share of Plant Vogtle Units 3 and 4 (approximately 206 MWs) at varying prices dependent upon the stage of construction of Plant Vogtle Units 3 and 4. The aggregate purchase price of the PTCs, together with any advances made as described in the next paragraph, shall not exceed $300 million.
At the option of MEAG, as an alternative or supplement to Georgia Power's purchase of PTCs as described above, Georgia Power has agreed to provide up to $250 million in funding to MEAG for Project J in the form of advances
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(either advances under the Vogtle Joint Ownership Agreements or the purchase of MEAG Project J bonds, at the discretion of Georgia Power), subject to any required approvals of the Georgia PSC and the DOE.
In the event MEAG SPVJ certifies to Georgia Power that it is unable to fund its obligations under the Vogtle Joint Ownership Agreements as a result of a JEA Default and Georgia Power becomes obligated to provide funding as described above, MEAG is required to (i) assign to Georgia Power its right to vote on any future Project Adverse Event and (ii) diligently pursue JEA for its breach of PPA-J. In addition, Georgia Power agreed that it will not sue MEAG for any amounts due from MEAG SPVJ under MEAG's guarantee of MEAG SPVJ's obligations so long as MEAG SPVJ complies with the terms of the MEAG Term Sheet as to its payment obligations and the other provisions of the Vogtle Joint Ownership Agreements.
Under the terms of the MEAG Term Sheet, Georgia Power may decline to provide any funding in the form of advances, including in the event of a failure to receive any required Georgia PSC or DOE approvals, and cancel the project in lieu of providing such funding.
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
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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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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 |
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| Construction contingency estimate | 0.4 |
|
Total project capital cost forecast(a)(b) | 8.4 |
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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. |
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| (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 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. As of SeptemberAt June 30, 2018,2019, Georgia Power had recovered approximately $1.8$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 Power expects to file on November 9, 2018PSC approved Georgia Power's request to increase the NCCR tariff by approximately $90$88 million annually, effective January 1, 2019, pending Georgia PSC approval.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
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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) certain recommendations made by Georgia Power in thePower's seventeenth VCM report and modifyingmodified 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,
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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 unitUnit is commercially operational. The ROE reductions negatively impacted earnings by approximately $25$100 million in 20172018 and are estimated to have negative earnings impacts of approximately $100$70 million in 20182019 and an aggregate of $680approximately $630 million from 20192020 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.
OnIn February 12, 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. OnIn March 8, 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's final 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 two appeals haveappeal has no merit; however, an adverse outcome in eitherthe appeal combined with subsequent adverse action by the Georgia PSC could have a material impact on Georgia Power'sSouthern Company's results of operations, financial condition, and liquidity.
The Georgia PSC has approved eighteen VCM reports covering the periods through December 31, 2017, including total construction capital costs incurred through that date of $4.9 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds). OnIn August 31, 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
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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 herein andSouthern Company in 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
As of SeptemberAt June 30, 2018,2019, 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. In September 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. In September 2018, the DOE extended the conditional commitment to March 31, 2019. Any further extension must be approved by the DOE. 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 (F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information, including applicable covenants, events of default, mandatory prepayment events, (including any decision not to continue construction of Plant Vogtle Units 3 and 4), and conditions to borrowing.
The ultimate outcome of these matters cannot be determined at this time.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Income TaxOther Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax "Other Matters" of Georgia PowerSouthern Company in Item 7 of the Form 10-Kfor additional information.
Southern Company and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk," Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power," and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation and related regulatory actions.
Other Matters
Georgia Power isits 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, Georgia Power isSouthern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. Georgia Power'sThe 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, 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 Georgia Power'sSouthern 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.
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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.
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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
Georgia PowerSouthern 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 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 Southern Company's results of
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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 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
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 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 GeorgiaAlabama Power in Item 7 of the Form 10-K for a complete discussion of GeorgiaAlabama Power's critical accounting policies and estimates.
Estimated Cost, Schedule, and Rate Recovery
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 Construction of Plant Vogtle Units 3 and 4
In December 2016, the Georgia PSC approved the Vogtle Cost Settlement Agreement, which resolved certain prudency matters in connection with GeorgiaForm 10-K for additional information. Alabama Power's fifteenth VCM report. In December 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendationfinancial condition remained stable at June 30, 2019. Alabama Power intends to continue construction of Plant Vogtle Units 3to monitor its access to short-term and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor,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 modificationpayment 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 Vogtle Cost Settlement Agreement. The Georgia PSC'sForm 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 order stated thatto ash pond facilities, and $310 million in cash and cash equivalents. See Note (A) to the Condensed Financial Statements under the modified Vogtle Cost Settlement Agreement, (i) none"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 $3.3Form 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 costs incurredCapital" 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 December 31, 2015 shouldits 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 disallowedadequately 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 imprudent; (ii)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 costs incurred up to $5.68 billionmarkets and would be presumedlikely 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 reasonablenegatively impacted. The modifications to Rate RSE and prudentother 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 the burdenlower-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 would have the burdenare an integral part of proofthese 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 show that any capital costs above $5.68 billion were prudent; (iv) Georgia Power's total project capital cost forecastPower are an integral part of $7.3 billion (netthese 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 achieving fuel load for Unit 4.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 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 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 its order,2009, the Georgia PSC also stated if other conditions changecertified construction of Plant Vogtle Units 3 and assumptions upon which4 (with electric generating capacity of approximately 1,100 MWs each). Georgia Power's seventeenth VCM report are based do not materialize,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 reserved the right to reconsider the decisionapproved 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). Although, 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 believes these incremental costs are reasonableentered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and necessarycertain of MEAG's wholly-owned subsidiaries, including MEAG Power SPVJ, LLC (MEAG SPVJ), to completetake 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, has statedremain unchanged.
In March 2019, Georgia Power entered into the $7.3Amended 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 estimateof 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 seventeenth VCM proceeding does not representvolume 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 cost cap,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 did not seek rate recovery forPower'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 $0.7second 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 in the nineteenth VCM report filed with the Georgia PSC on August 31, 2018. In connection with future VCM filings,for which Georgia Power may request the Georgia PSC to evaluatedid not seek rate recovery and costs included in the revised construction contingency estimate for which Georgia Power may seek rate recovery as and when theysuch costs are appropriately included in the base capital cost forecast. After consideringSee Note 2 to the significantfinancial 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 uncertaintyGeorgia Power's future earnings depends on numerous factors that existsaffect 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. |
GEORGIA POWER COMPANY
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 recoverabilitygeneration site in Stewart County, Georgia over a three-year period ending December 31, 2022 and (ii) the net book values of costs included inPlant Hammond Units 1 through 4 over a period equal to the construction contingency estimate since theapplicable 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
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 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 outcomeBechtel 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 future assessmentsthe 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 management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power recorded a total pre-tax charge to incomethe Vogtle Owners, Vogtle Owner insolvency, and certain other events.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Cost and Schedule
Georgia Power's revisedapproximate proportionate share of the remaining estimated capital cost estimate reflects anto complete Plant Vogtle Units 3 and 4 by the expected in-service datedates 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 4.4, 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, availability,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, andor 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. Monthly
The April 2019 cost and schedule validation process established target values for monthly construction production targets requiredand system turnover activities as part of a strategy to maintain and, where possible, build margin to the current project scheduleapproved in-service dates. To support that strategy, monthly production and activity target values will continue to increase significantly through the remainder of 2018 and intothroughout 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 resolutionsubmittal 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. AnyHowever, any extension of the in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4regulatory-approved project schedule is currently estimated to result in additional base capital costs of approximately $50
GEORGIA POWER COMPANY
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 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
Givencertificate in accordance with the significant complexity involved2009 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 estimatingconnection with the futurefifteenth 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 completethe 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 and start-up 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 significant management judgment necessaryrevised 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 assesscalculate the related uncertainties surrounding futureNCCR tariff (a) from 10.95% (the ROE rate recoverysetting 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 any projectedlong-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 increases, as well asof 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 potentialVogtle 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 cash flows,liquidity.
In August 2018, Georgia Power considersfiled 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 itemsmatters cannot be determined at this time.
See RISK FACTORS of Georgia Power in 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 be critical accounting estimates.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 38 to the financial statements of Georgia Power under "Retail Regulatory Matters"Long-term Debt – Nuclear Construction"DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (B)(F) to the Condensed Financial Statements under "Nuclear Construction""DOE Loan Guarantee Borrowings" herein for additional information.information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
Recently IssuedThe 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. 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 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 Georgia 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.
Litigation
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
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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. Georgia Power believes the plaintiffs' claims have no merit. 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. The ultimate outcome of this matter cannot be determined at this time.
ACCOUNTING POLICIES
Application of Critical Accounting StandardsPolicies and Estimates
Georgia 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 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 – "Recently Issued"Application of Critical Accounting Standards"Policies and Estimates" of Georgia Power in Item 7 of the Form 10-K for additional information regarding ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). a complete discussion of Georgia Power's critical accounting policies and estimates.
Recently Issued Accounting Standards
See Note (A) to the Condensed Financial Statements herein for information regarding Georgia Power's recently adopted accounting standards.
In 2016, the FASB issued ASU No. 2016-02, which requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and Georgia Power will adopt the new standard effective January 1, 2019.
Georgia Power has elected the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby it will apply the requirements of ASU 2016-02 on a prospective basis as of the adoption date of January 1, 2019, without restating prior periods. Georgia Power expects to elect the package of practical expedients provided by ASU 2016-02 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Georgia Power expects to apply the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and to elect the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed. Georgia Power also expects to make accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and to combine lease and non-lease components in the computations of lease obligations and right-of-use assets for most asset classes.
Georgia Power is continuing to complete the implementation of an information technology system to track and account for its leases and of changes to its internal controls and accounting policies to support the accounting for leases under ASU 2016-02. Georgia Power has substantially completed its lease inventory and determined its most significant leases involve PPAs and real estate. While Georgia Power has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to result in recording lease liabilities and right-of-use assets on Georgia Power's balance sheet each totaling approximately $1.8 billion, with no material impact on Georgia Power's statement of income.
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, 2018.2019. 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 $2.23$1.1 billion for the first ninesix months of 2018 compared to $1.48 billion for the corresponding period in 2017. The increase was primarily due to the timing of vendor2019 and property tax payments, a decrease in current income taxes related to the Tax Reform Legislation, income tax refunds
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
received, increased fuel cost recovery, and the timing of fossil fuel stock purchases, partially offset by payments of customer refunds primarily related to the Guarantee Settlement Agreement.2018. Net cash used for investing activities totaled $2.21$1.8 billion for the first ninesix months of 20182019 primarily related to installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities, including $0.9 billionapproximately $660 million related to the construction of Plant Vogtle Units 3 and 4. Net cash used forprovided from financing activities totaled $492$620 million for the first ninesix months of 20182019 primarily due to paymentsborrowings from the FFB for construction of Plant Vogtle Units 3 and 4, the reoffering of pollution control revenue bonds, and an increase in short-term borrowings, partially offset by payment of common stock dividends and the redemption and repurchase of senior notes, and pollution control revenue bond purchases, partially offset by capital contributions from Southern Company.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 20182019 include recording $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 $2.3$1.2 billion in paid-in capital primarily dueproperty, plant, and equipment to capital contributions received from Southern Company, a decreasecomply 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 borrowings from the redemption and repurchase of senior notes and the purchase of pollution control revenue bonds, and an increase of $0.5 billion in property, plant, and equipment to comply with environmental standards and the construction of generation, transmission, and distribution facilities, net of the $1.1 billion charge related to theFFB for construction of Plant Vogtle Units 3 and 4.4 and the reoffering of pollution control revenue bonds previously purchased and held by Georgia Power. See Note (L) to the Condensed Financial Statements herein for additional information on the adoption of ASC 842. Also see Notes (B) and (F) to the Condensed Financial Statements under "Nuclear Construction""Georgia Power – Nuclear Construction" and "DOE Loan Guarantee Borrowings," respectively, herein for additional information regarding Plant Vogtle Units 3 and 4.4 and the 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 and contractual obligations. Approximately $511$988 million will be required through SeptemberJune 30, 20192020 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.
Georgia Power's construction program is currently estimated to total approximately $3.5 billion for 2018, $3.6 billion for 2019, $2.8 billion for 2020, $2.7 billion for 2021, and $2.4 billion for 2022. These amounts include expenditures of approximately $1.4 billion, $1.4 billion, $0.9 billion, $1.0 billion, and $0.6 billion for the construction of Plant Vogtle Units 3 and 4 in 2018, 2019, 2020, 2021, and 2022, respectively. These amounts also include capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under LTSAs. Estimated capital expenditures to comply with environmental laws and regulations included in these amounts are $0.5 billion, $0.1 billion, $0.2 billion, $0.2 billion, and $0.2 billion for 2018, 2019, 2020, 2021, and 2022, respectively. These estimated expenditures do not include any potential compliance costs associated with pending regulation of CO2 emissions from fossil fuel-fired electric generating units.
Georgia Power also anticipates costs associated with closure and monitoring of ash ponds in accordance with the CCR Rule, which are reflected in Georgia Power's ARO liabilities. These costs, which are expected to change as Georgia Power continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities, are estimated to be $0.2 billion per year for 2018 through 2020 and $0.3 billion per year for 2021 and 2022. For information regarding expected changes to these cost estimates during the fourth quarter 2018, see FUTURE EARNINGS POTENTIAL – "Environmental Matters– Environmental Laws and Regulations – Coal Combustion Residuals" and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein. Also see Note 1 to the financial statements of Georgia Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information on AROs.
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 FERC rules and regulations; Georgia PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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,productivity; challenges with management of contractors, subcontractors, or vendors,vendors; adverse weather conditions,conditions; shortages, anddelays, increased costs, or inconsistent quality of equipment, materials, and labor,labor; contractor or supplier delay, non-performancedelay; nonperformance under construction, operating, or other agreements,agreements; operational readiness, including specialized operator training and required site safety programs, unforeseenprograms; engineering or design problems,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, (includingincluding major equipment failure, and system integration),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 "Georgia Power – Nuclear Construction" herein for information regarding additional factors that may impact construction 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, external security issuances, borrowings from financial institutions, equity contributions from Southern Company, and borrowings from the FFB. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory 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
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) to be madeCosts minus (ii) approximately $1.492 billion (reflecting the amounts received by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, andGuarantee Settlement Agreement less the FFB. As of SeptemberCustomer Refunds). At June 30, 2018,2019, Georgia Power had borrowed $2.6$3.46 billion under the FFB Credit Facility. In July 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.
In September 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. This conditional commitment expires on March 31, 2019, subject to any further extension approved by the DOE. 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 (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, (including any decision not to continue construction of Plant Vogtle Units 3 and 4), and additional conditions to borrowing. Also see Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
At September 30, 2018, Georgia Power's current liabilities exceeded current assets by $552 million primarily due to long-term debt that is due within one year of $511 million. Georgia Power'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. At June 30, 2019, Georgia Power intendsPower's current liabilities exceeded current assets by $2.0 billion primarily due to utilize operating cash flows, external security issuances, borrowings from financial institutions,long-term debt that is due within one year of $988 million and equity contributions from Southern
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Company to fund its short-term capital needs. Georgia Power has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet liquidity needs.notes payable of $555 million.
At SeptemberJune 30, 2018,2019, Georgia Power had approximately $380$10 million of cash and cash equivalents. Georgia Power'sequivalents and a multi-year committed credit arrangement with banks wastotaling $1.75 billion, at September 30, 2018, of which $1.74 billion was unused. In May 2019, Georgia Power amended its bank credit arrangement which, among other things, extended the maturity date from 2022 to 2024. This credit arrangement, expires in 2022.
This bank credit arrangement containsas well as Georgia Power's term loan arrangements, contain 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, 2018,2019, 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 (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, 20182019 was approximately $550 million. In addition, at SeptemberJune 30, 2018,2019, Georgia Power had $345$185 million of pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months.
Georgia Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Georgia Power and the other traditional electric operating 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. Short-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, 2018 | | 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 | $ | 102 |
| | 2.4 | % | | $ | 260 |
| | 2.3 | % | | $ | 480 |
|
|
| | | | | | | | | | | | | | | | | |
| | 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 | $ | 305 |
| | 2.7 | % | | $ | 288 |
| | 2.7 | % | | $ | 485 |
|
| Short-term bank debt | 250 |
| | 2.9 | % | | 69 |
| | 2.9 | % | | 250 |
|
| Total | $ | 555 |
| | 2.8 | % | | $ | 357 |
| | 2.8 | % | | |
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended SeptemberJune 30, 2018.2019. |
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, 2018,2019, 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
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 SeptemberJune 30, 20182019 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 | $ | 1,025 |
| $ | 1,040 |
|
Included in these amounts are certain agreements that could require collateral in the event that Georgia Power or Alabama Power (affiliate company(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 February 28, 2018, Fitch downgraded the senior unsecured long-term debt rating of Georgia Power to A from A+ with a negative outlook. On August 9, 2018, Fitch downgraded the senior unsecured long-term debt rating of Georgia Power to A- from A. On September 28, 2018, Fitch assigned a negative rating outlook to the ratings of Southern Company and certain of its subsidiaries (including Georgia Power).
On August 8, 2018, Moody's downgraded the senior unsecured debt rating of Georgia Power to Baa1 from A3. On September 28, 2018, Moody's revised its rating outlook for Georgia Power from negative to stable.
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 Georgia Power, may be negatively impacted. TheA settlement agreement between Georgia Power and the staff of the Georgia PSC regarding the retail rate impact of the Tax Reform Settlement AgreementLegislation, as approved by the Georgia PSC onin April 3, 2018, is expected to help mitigate these potential adverse impacts to certain credit metrics by allowing a higher retail equity ratio untilthrough 2019, which Georgia Power has requested to extend in the conclusion of Georgia Power's next base rate case, which is scheduled to be filed by July 1, 2019.Power 2019 Base Rate Case. See Note 3(B) to the Condensed Financial Statements and Note 2 to the financial statements of Georgia Power under "Retail Regulatory Matters – Rate Plans" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters"Georgia Power – Georgia Power – Rate Plans" hereinPlans" for additional information.information, including requests for additional capital structure adjustments.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Financing Activities
In January 2018, Georgia Power repaid its outstanding $150 million and $100 million floating rate bank loans due May 31, 2018 and October 26, 2018, respectively.
In April 2018,2019, Georgia Power redeemed all $250approximately $13 million, aggregate principal amount of its Series 2008B 5.40% Senior Notes due June 1, 2018.
In May 2018, through cash tender offers, Georgia Power repurchased$20 million, and retired $89 million of the $250 million aggregate principal amount outstanding of its Series 2007A 5.65% Senior Notes due March 1, 2037, $326 million of the $500 million aggregate principal amount outstanding of its Series 2009A 5.95% Senior Notes due February 1, 2039, and $335 million of the $600 million aggregate principal amount outstanding of its Series 2010B 5.40% Senior Notes due June 1, 2040, for an aggregate purchase price, excluding accrued and unpaid interest, of $902 million.
During 2018, Georgia Power purchased and held the following pollution control revenue bonds, which may be reoffered to the public at a later date:
$104.6$75 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 20131992, Eighth Series 1994, and Second Series 1995, respectively.
GEORGIA POWER COMPANYIn 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.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 20092009;
$55approximately $105 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), FifthFirst Series 19942013; 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 20082008.
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.
$71.73555 million aggregate principal amount of Development Authority of BartowBurke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant BowenVogtle Project), FirstFourth Series 20131994;
$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. 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.
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, |
| | 2018 |
| 2017 | | 2018 | | 2017 |
| | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | |
| Retail revenues | $ | 341 |
| | $ | 375 |
| | $ | 932 |
| | $ | 972 |
|
| Wholesale revenues, non-affiliates | 15 |
| | 14 |
| | 41 |
| | 44 |
|
| Wholesale revenues, affiliates | 40 |
| | 28 |
| | 83 |
| | 75 |
|
| Other revenues | 18 |
| | 20 |
| | 50 |
| | 53 |
|
| Total operating revenues | 414 |
| | 437 |
| | 1,106 |
| | 1,144 |
|
| Operating Expenses: | | | | | | | |
| Fuel | 132 |
| | 127 |
| | 305 |
| | 323 |
|
| Purchased power | 44 |
| | 38 |
| | 135 |
| | 116 |
|
| Other operations and maintenance | 82 |
| | 84 |
| | 248 |
| | 260 |
|
| Depreciation and amortization | 48 |
| | 42 |
| | 142 |
| | 95 |
|
| Taxes other than income taxes | 33 |
| | 33 |
| | 91 |
| | 88 |
|
| Loss on Plant Scherer Unit 3 | — |
| | — |
| | — |
| | 33 |
|
| Total operating expenses | 339 |
| | 324 |
| | 921 |
| | 915 |
|
| Operating Income | 75 |
| | 113 |
| | 185 |
| | 229 |
|
| Other Income and (Expense): | | | | | | | |
| Interest expense, net of amounts capitalized | (13 | ) | | (13 | ) | | (39 | ) | | (37 | ) |
| Other income (expense), net | (3 | ) | | 3 |
| | — |
| | 7 |
|
| Total other income and (expense) | (16 | ) | | (10 | ) | | (39 | ) | | (30 | ) |
| Earnings Before Income Taxes | 59 |
| | 103 |
| | 146 |
| | 199 |
|
| Income taxes (benefit) | (4 | ) | | 40 |
| | (1 | ) | | 78 |
|
| Net Income | 63 |
| | 63 |
| | 147 |
| | 121 |
|
| Dividends on Preference Stock | — |
| | — |
| | — |
| | 4 |
|
| Net Income After Dividends on Preference Stock | $ | 63 |
| | $ | 63 |
| | $ | 147 |
| | $ | 117 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months
Ended September 30, | | For the Nine Months
Ended September 30, |
| | 2018 | | 2017 | | 2018 | | 2017 |
| | (in millions) | | (in millions) |
| Net Income | $ | 63 |
| | $ | 63 |
| | $ | 147 |
| | $ | 121 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
Changes in fair value, net of tax of
$-, $-, $-, and $(1), respectively | — |
| | — |
| | — |
| | (1 | ) |
| Total other comprehensive income (loss) | — |
| | — |
| | — |
| | (1 | ) |
| Comprehensive Income | $ | 63 |
| | $ | 63 |
| | $ | 147 |
| | $ | 120 |
|
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, |
| | 2018 | | 2017 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 147 |
| | $ | 121 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 147 |
| | 100 |
|
| Deferred income taxes | (45 | ) | | 57 |
|
| Loss on Plant Scherer Unit 3 | — |
| | 33 |
|
| Other, net | (10 | ) | | (5 | ) |
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (5 | ) | | (65 | ) |
| -Other current assets | 9 |
| | 18 |
|
| -Accrued taxes | 35 |
| | 21 |
|
| -Accrued compensation | (9 | ) | | (10 | ) |
| -Over recovered regulatory clause revenues | 39 |
| | (8 | ) |
| -Other current liabilities | 10 |
| | 10 |
|
| Net cash provided from operating activities | 318 |
| | 272 |
|
| Investing Activities: | | | |
| Property additions | (207 | ) | | (142 | ) |
| Cost of removal, net of salvage | (18 | ) | | (16 | ) |
| Change in construction payables | 5 |
| | (9 | ) |
| Other investing activities | (18 | ) | | (6 | ) |
| Net cash used for investing activities | (238 | ) | | (173 | ) |
| Financing Activities: | | | |
| Increase (decrease) in notes payable, net | 5 |
| | (268 | ) |
| Proceeds — | | | |
| Common stock issued to parent | — |
| | 175 |
|
| Capital contributions from parent company | 40 |
| | 7 |
|
| Senior notes | — |
| | 300 |
|
| Redemptions — | | | |
| Preference stock | — |
| | (150 | ) |
| Senior notes | — |
| | (85 | ) |
| Payment of common stock dividends | (115 | ) | | (94 | ) |
| Other financing activities | (1 | ) | | (3 | ) |
| Net cash used for financing activities | (71 | ) | | (118 | ) |
| Net Change in Cash, Cash Equivalents, and Restricted Cash | 9 |
| | (19 | ) |
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 28 |
| | 56 |
|
| Cash, Cash Equivalents, and Restricted Cash at End of Period | $ | 37 |
| | $ | 37 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid during the period for — | | | |
| Interest (net of $- and $- capitalized for 2018 and 2017, respectively) | $ | 26 |
| | $ | 24 |
|
| Income taxes, net | 28 |
| | 19 |
|
| Noncash transactions — Accrued property additions at end of period | 31 |
| | 25 |
|
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, 2018 | | At December 31, 2017 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 37 |
| | $ | 28 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 100 |
| | 76 |
|
| Unbilled revenues | | 69 |
| | 67 |
|
| Under recovered regulatory clause revenues | | — |
| | 27 |
|
| Affiliated | | 20 |
| | 14 |
|
| Other | | 5 |
| | 7 |
|
| Accumulated provision for uncollectible accounts | | (1 | ) | | (1 | ) |
| Fossil fuel stock | | 58 |
| | 63 |
|
| Materials and supplies | | 61 |
| | 57 |
|
| Other regulatory assets, current | | 47 |
| | 56 |
|
| Other current assets | | 13 |
| | 21 |
|
| Total current assets | | 409 |
| | 415 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 5,313 |
| | 5,196 |
|
| Less: Accumulated provision for depreciation | | 1,540 |
| | 1,461 |
|
| Plant in service, net of depreciation | | 3,773 |
| | 3,735 |
|
| Construction work in progress | | 152 |
| | 91 |
|
| Total property, plant, and equipment | | 3,925 |
| | 3,826 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 30 |
| | 31 |
|
| Other regulatory assets, deferred | | 495 |
| | 502 |
|
| Other deferred charges and assets | | 46 |
| | 23 |
|
| Total deferred charges and other assets | | 571 |
| | 556 |
|
| Total Assets | | $ | 4,905 |
| | $ | 4,797 |
|
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, 2018 | | At December 31, 2017 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Notes payable | | $ | 50 |
| | $ | 45 |
|
| Accounts payable — | | | | |
| Affiliated | | 64 |
| | 52 |
|
| Other | | 67 |
| | 75 |
|
| Customer deposits | | 35 |
| | 35 |
|
| Accrued taxes | | 45 |
| | 10 |
|
| Accrued interest | | 20 |
| | 9 |
|
| Accrued compensation | | 30 |
| | 39 |
|
| Deferred capacity expense, current | | 22 |
| | 22 |
|
| Asset retirement obligations, current | | 43 |
| | 37 |
|
| Other regulatory liabilities, current | | 69 |
| | — |
|
| Other current liabilities | | 20 |
| | 27 |
|
| Total current liabilities | | 465 |
| | 351 |
|
| Long-term Debt | | 1,285 |
| | 1,285 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 542 |
| | 537 |
|
| Deferred credits related to income taxes | | 380 |
| | 458 |
|
| Employee benefit obligations | | 96 |
| | 102 |
|
| Deferred capacity expense | | 81 |
| | 97 |
|
| Asset retirement obligations, deferred | | 121 |
| | 105 |
|
| Other cost of removal obligations | | 218 |
| | 221 |
|
| Other regulatory liabilities, deferred | | 51 |
| | 43 |
|
| Other deferred credits and liabilities | | 62 |
| | 67 |
|
| Total deferred credits and other liabilities | | 1,551 |
| | 1,630 |
|
| Total Liabilities | | 3,301 |
| | 3,266 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, without par value — | | | | |
| Authorized — 20,000,000 shares | | | | |
| Outstanding — 7,392,717 shares | | 678 |
| | 678 |
|
| Paid-in capital | | 636 |
| | 594 |
|
| Retained earnings | | 291 |
| | 259 |
|
| Accumulated other comprehensive loss | | (1 | ) | | — |
|
| Total common stockholder's equity | | 1,604 |
| | 1,531 |
|
| Total Liabilities and Stockholder's Equity | | $ | 4,905 |
| | $ | 4,797 |
|
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 2018 vs. THIRD QUARTER 2017
AND
YEAR-TO-DATE 2018 vs. YEAR-TO-DATE 2017
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.
On May 20, 2018, Southern Company entered into a stock purchase agreement with NextEra Energy to sell Gulf Power for an aggregate cash purchase price of $5.75 billion (less the amount of indebtedness assumed at closing, which is currently estimated at approximately $1.3 billion), subject to certain adjustments. The completion of the sale is expected to occur in the first quarter 2019 and is subject to the satisfaction or waiver of certain closing conditions. The ultimate outcome of this matter cannot be determined at this time. See Note (J) to the Condensed Financial Statements under "Southern Company's Sale of Gulf Power" herein for additional information.
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 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, 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.
As a continuation of a settlement agreement approved by the Florida PSC in April 2017 (2017 Gulf Power Rate Case Settlement Agreement), on March 26, 2018, the Florida PSC approved a stipulation and settlement agreement among Gulf Power and three intervenors addressing the retail revenue requirement effects of the Tax Reform Legislation (Gulf Power Tax Reform Settlement Agreement).
The Gulf Power Tax Reform Settlement Agreement results in annual reductions to Gulf Power's revenues of $18.2 million from base rates and $15.6 million from environmental cost recovery rates implemented April 1, 2018 and also provided for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to normalization) deferred tax liabilities through a reduced fuel cost recovery rate over the remainder of 2018. Through September 30, 2018, approximately $53 million of this refund has been reflected in customer bills. As a result of the Gulf Power Tax Reform Settlement Agreement, the Florida PSC also approved an increase in Gulf Power's maximum equity ratio from 52.5% to 53.5% for all retail regulatory purposes.
As part of the Gulf Power Tax Reform Settlement Agreement, a limited scope proceeding to address protected deferred tax liabilities consistent with IRS normalization principles was initiated on April 30, 2018. On October 30, 2018, the Florida PSC approved a $9.6 million annual reduction in base rate revenues effective January 2019, which concluded this proceeding. Through September 30, 2018, Gulf Power has deferred $7 million of related 2018 tax benefits as a regulatory liability to be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rate.
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information.
On October 10, 2018, Hurricane Michael made landfall on the Gulf Coast of Florida causing substantial damage in Gulf Power's service territory. Gulf Power currently estimates the costs of repairing the damages to its transmission and distribution lines and uninsured facilities will total approximately $350 million to $400 million, which primarily will be charged to the property damage reserve or capitalized. At September 30, 2018, Gulf Power had a balance of approximately $48 million in its property damage reserve. In accordance with the 2017 Gulf Power Rate Case Settlement Agreement, Gulf Power can petition the Florida PSC to seek recovery of the costs associated with
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Hurricane Michael, along with replenishing the property damage reserve to approximately $40 million. The ultimate outcome of this matter cannot be determined at this time. See Note 1 to the financial statements of Gulf Power under "Property Damage Reserve" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Storm Damage Cost Recovery" herein for additional information.
Gulf Power continues to focus on several key performance indicators including, but not limited to, customer satisfaction, plant availability, system reliability, and net income.
RESULTS OF OPERATIONS
Net Income
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $— | | — | | $30 | | 25.6 |
Gulf Power's net income after dividends on preference stock for the third quarter 2018 and the corresponding period in 2017 was $63 million. Net income reflects lower federal income tax expense as a result of the Tax Reform Legislation, substantially offset by a reduction in retail revenues related to the Gulf Power Tax Reform Settlement Agreement.
Gulf Power's net income after dividends on preference stock for year-to-date 2018 was $147 million compared to $117 million for the corresponding period in 2017. The increase was primarily due to higher retail base revenues effective July 2017 and the first quarter 2017 write-down of $32.5 million ($20 million after tax) of Gulf Power's ownership of Plant Scherer Unit 3 in accordance with the 2017 Gulf Power Rate Case Settlement Agreement, partially offset by depreciation credits recognized in 2017. In addition, the increase in net income reflects lower federal income tax expense as a result of the Tax Reform Legislation, partially offset by a reduction in retail revenues related to the Gulf Power Tax Reform Settlement Agreement.
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information regarding the 2017 Gulf Power Rate Case Settlement Agreement.
Retail Revenues
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(34) | | (9.1) | | $(40) | | (4.1) |
In the third quarter 2018, retail revenues were $341 million compared to $375 million for the corresponding period in 2017. For year-to-date 2018, retail revenues were $932 million compared to $972 million for the corresponding period in 2017.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of the changes in retail revenues were as follows:
|
| | | | | | | | | | | | | |
| | Third Quarter 2018 | | Year-to-Date 2018 |
| | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | $ | 375 |
| | | | $ | 972 |
| | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | (35 | ) | | (9.3 | ) | | (51 | ) | | (5.2 | ) |
| Sales growth (decline) | (2 | ) | | (0.6 | ) | | 2 |
| | 0.2 |
|
| Weather | 6 |
| | 1.6 |
| | 16 |
| | 1.6 |
|
| Fuel and other cost recovery | (3 | ) | | (0.8 | ) | | (7 | ) | | (0.7 | ) |
| Retail – current year | $ | 341 |
| | (9.1 | )% | | $ | 932 |
| | (4.1 | )% |
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 decreased in the third quarter and year-to-date 2018 when compared to the corresponding periods in 2017 primarily due to a decrease in revenues effective January 1, 2018 due to the Gulf Power Tax Reform Settlement Agreement. In addition, the year-to-date 2018 amounts were partially offset by an increase in retail base rates effective July 2017 in accordance with the 2017 Gulf Power Rate Case Settlement Agreement.
Revenues attributable to changes in sales decreased in the third quarter 2018 when compared to the corresponding period in 2017. For the third quarter 2018, weather-adjusted KWH sales to residential customers decreased 3.9% due to lower customer usage, primarily resulting from efficiency improvements, partially offset by customer growth. Weather-adjusted KWH sales to commercial customers decreased 2.5% primarily due to lower energy usage resulting from energy efficiency improvements in appliances and lighting. KWH sales to industrial customers increased 4.8% for the third quarter 2018 primarily due to decreased customer cogeneration levels and other changes in customers' operations.
Revenues attributable to changes in sales increased for year-to-date 2018 when compared to the corresponding period in 2017. For year-to-date 2018, weather-adjusted KWH sales to residential customers were essentially flat due to lower customer usage, primarily resulting from efficiency improvements, offset by customer growth. Weather-adjusted KWH sales to commercial customers decreased 0.7% primarily due to lower energy usage resulting from energy efficiency improvements in appliances and lighting. KWH sales to industrial customers increased 1.3% year-to-date 2018 primarily due to changes in customer cogeneration levels.
Fuel and other cost recovery revenues decreased in the third quarter 2018 when compared to the corresponding period in 2017, primarily due to lower recoverable costs under the fuel cost recovery clause. Fuel and other cost recovery revenues decreased year-to-date 2018 when compared to the corresponding period in 2017, primarily due to lower recoverable costs under the purchased power capacity and fuel cost recovery clauses. Fuel and other cost recovery 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 Gulf Power Rate Case Settlement Agreement.
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" and " – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information regarding cost recovery clauses and the 2017 Gulf Power Rate Case Settlement Agreement, respectively. Also see FUTURE EARNINGS
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
POTENTIAL – "Retail Regulatory Matters – Retail Base Rate Case" herein for additional information regarding the Gulf Power Tax Reform Settlement Agreement.
Wholesale Revenues – Affiliates
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $12 | | 42.9 | | $8 | | 10.7 |
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since the revenue related to these energy sales generally offsets the cost of energy sold.
In the third quarter 2018, wholesale revenues from sales to affiliates were $40 million compared to $28 million for the corresponding period in 2017. The increase was primarily due to a 31.6% increase in KWH sales primarily resulting from increased generation to serve territorial load driven by warmer weather in the third quarter 2018 and a 7.9% increase in the price of energy sold to affiliates attributable to increased sales during peak load hours.
For year-to-date 2018, wholesale revenues from sales to affiliates were $83 million compared to $75 million for the corresponding period in 2017. The increase was primarily due to a 24.5% increase in the price of energy sold due to dispatching higher-priced generating resources driven by the colder weather in January 2018 and warmer weather in the third quarter 2018. Partially offsetting this increase was an 11.3% decrease in KWH sales primarily resulting from lower availability due to planned outages at Gulf Power generating units in the first half of 2018.
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | | |
| | Third Quarter 2018
vs.
Third Quarter 2017 | | Year-to-Date 2018
vs.
Year-to-Date 2017 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | 5 |
| | 3.9 | | $ | (18 | ) | | (5.6 | ) |
| Purchased power | 6 |
| | 15.8 | | 19 |
| | 16.4 |
|
| Total fuel and purchased power expenses | $ | 11 |
| | | | $ | 1 |
| | |
In the third quarter 2018, total fuel and purchased power expenses were $176 million compared to $165 million for the corresponding period in 2017. The increase was primarily the result of a $21 million increase related to the volume of KWHs generated and purchased, partially offset by a $10 million decrease related to the lower average cost of fuel and purchased power due to lower natural gas prices.
For year-to-date 2018, total fuel and purchased power expenses were $440 million compared to $439 million for the corresponding period in 2017. The increase was primarily the result of a $31 million increase related to volume of KWHs generated and purchased, partially offset by a $30 million decrease related to the lower average cost of fuel and purchased power resulting from lower natural gas prices.
Fuel and purchased power transactions do not have a significant impact on earnings since energy and capacity expenses are generally offset by energy and capacity revenues through Gulf Power's fuel and purchased power capacity cost recovery clauses and long-term wholesale contracts. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Retail Fuel Cost Recovery" and " – Purchased Power Capacity Recovery" in Item 8 of the Form 10-K for additional information.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of Gulf Power's generation and purchased power were as follows:
|
| | | | | | | |
| | Third Quarter 2018 | | Third Quarter 2017 | | Year-to-Date 2018 | | Year-to-Date 2017 |
Total generation (in millions of KWHs) | 2,992 | | 2,780 | | 7,002 | | 7,000 |
Total purchased power (in millions of KWHs) | 2,016 | | 1,686 | | 4,997 | | 4,362 |
Sources of generation (percent) – | | | | | | | |
| Coal | 61 | | 59 | | 53 | | 55 |
| Gas | 39 | | 41 | | 47 | | 45 |
Cost of fuel, generated (in cents per net KWH) – | | | | | | | |
| Coal | 3.06 | | 3.04 | | 3.12 | | 3.15 |
| Gas | 3.40 | | 3.71 | | 3.25 | | 3.60 |
Average cost of fuel, generated (in cents per net KWH) | 3.19 | | 3.31 | | 3.18 | | 3.35 |
Average cost of purchased power (in cents per net KWH)(*) | 3.99 | | 4.32 | | 4.33 | | 4.70 |
| |
(*) | 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 2018, fuel expense was $132 million compared to $127 million for the corresponding period in 2017. The increase was primarily due to a 7.6% increase in the volume of KWHs generated primarily to serve higher territorial load driven by warmer weather, partially offset by a 3.6% decrease in the average cost of fuel resulting from lower natural gas prices.
For year-to-date 2018, fuel expense was $305 million compared to $323 million for the corresponding period in 2017. The decrease was primarily due to a 5.1% decrease in the average cost of fuel resulting from lower natural gas prices.
Purchased Power
In the third quarter 2018, purchased power expense was $44 million compared to $38 million for the corresponding period in 2017. The increase was primarily due to a 19.6% increase in the volume of KWHs purchased due to higher territorial load driven by warmer weather, partially offset by a 7.6% decrease in the average cost of purchased power due to lower natural gas prices.
For year-to-date 2018, purchased power expense was $135 million compared to $116 million for the corresponding period in 2017. The increase was primarily due to a 14.6% increase in the volume of KWHs purchased primarily due to higher territorial load driven by colder weather in January 2018 and warmer weather in the third quarter 2018, partially offset by a 7.9% decrease in the average cost of purchased power due to lower natural gas prices.
Energy purchases from non-affiliates and 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. Affiliate purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Operations and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(2) | | (2.4) | | $(12) | | (4.6) |
For year-to-date 2018, other operations and maintenance expenses were $248 million compared to $260 million for the corresponding period in 2017. The decrease was primarily due to decreases of $11 million in planned and routine generation maintenance expenses, including environmental expenditures, $3 million in energy service expenses, and $6 million in employee compensation and benefits, partially offset by a $9 million increase to the property damage reserve accrual. See Note 1 to the financial statements of Gulf Power under "Property Damage Reserve" in Item 8 of the Form 10-K for additional information.
Expenses from energy services did not have a significant impact on earnings since they were generally offset by
associated revenues. Environmental compliance expenses did not have a significant impact on earnings since they were offset by environmental revenues through Gulf Power's environmental cost recovery clause. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Environmental Cost Recovery" in Item 8 of the Form 10-K for additional information.
Depreciation and Amortization
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $6 | | 14.3 | | $47 | | 49.5 |
In the third quarter 2018, depreciation and amortization was $48 million compared to $42 million for the corresponding period in 2017. The increase was primarily due to an increase in depreciation rates as authorized by the 2017 Gulf Power Rate Case Settlement Agreement.
For year-to-date 2018, depreciation and amortization was $142 million compared to $95 million for the corresponding period in 2017. The increase was primarily due to an increase in depreciation rates as authorized by the 2017 Gulf Power Rate Case Settlement Agreement and depreciation credits of $34 million recognized in year-to-date 2017 as authorized in a settlement agreement approved by the Florida PSC in 2013. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information.
Loss on Plant Scherer Unit 3
In the first quarter 2017, Gulf Power recorded a $32.5 million write-down related to its ownership of Plant Scherer Unit 3 in accordance with the 2017 Gulf Power Rate Case Settlement Agreement. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information.
Income Taxes (Benefit)
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(44) | | (110.0) | | $(79) | | (101.3) |
In the third quarter 2018, income tax benefit was $4 million compared to tax expense of $40 million for the corresponding period in 2017. For year-to-date 2018, income tax benefit was $1 million compared to income tax expense of $78 million for the corresponding period in 2017. The changes were primarily due to the reduction in the
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
federal income tax rate and the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation as well as lower pre-tax earnings.
See Note (H) to the Condensed Financial Statements under "Effective Tax Rate" herein for additional information. Also see Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Cases" in Item 8 of the Form 10-K for more information regarding the 2017 Gulf Power Rate Case Settlement Agreement.
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, 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, 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. 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.
On May 20, 2018, Southern Company entered into a stock purchase agreement with NextEra Energy to sell all of the capital stock of Gulf Power for an aggregate cash purchase price of $5.75 billion (less the amount of indebtedness assumed at closing, which is currently estimated at approximately $1.3 billion), subject to (i) customary adjustments for indebtedness and working capital and (ii) reduction by the amount (if any) by which Gulf Power fails to meet a specified capital expenditure target. The completion of the sale is expected to occur in the first quarter 2019 and is subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) approval by the FERC and the Federal Communications Commission, (ii) the entry into certain ancillary agreements, including transmission-related agreements and a transition services agreement, among the parties and their affiliates, and (iii) other customary closing conditions. See Note (J) to the Condensed Financial Statements under "Southern Company's Sale of Gulf Power" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.
Environmental Matters
Gulf 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. Gulf Power maintains comprehensive environmental compliance and GHG strategies to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures, operations and maintenance costs, and costs reflected in ARO liabilities, required to comply with environmental laws and regulations and to achieve stated goals may impact future unit retirement and replacement decisions, results of operations, cash flows, and financial condition. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to the transmission system. A major portion of these costs are expected to be recovered through existing ratemaking provisions. The ultimate impact of environmental laws and regulations and the GHG goals discussed below will depend on various factors, such as state adoption and
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
implementation of requirements, the availability and cost of any deployed technology, and the outcome of pending and/or future legal challenges.
New or revised environmental laws and regulations could affect many areas of Gulf 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. 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. 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 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," "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, including a discussion on the State of Florida's statutory provisions on environmental cost recovery.
Environmental Laws and Regulations
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Water Quality" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the effluent limitations guidelines (ELG) rule.
On May 2, 2018, the EPA updated its anticipated final rulemaking schedule for ELG from September 2020 to December 2019. The impact of any changes to the ELG rule will depend on the content of the final rule and the outcome of any legal challenges and cannot be determined at this time.
Coal Combustion Residuals
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule).
The EPA published certain amendments to the CCR Rule, which became effective August 29, 2018. These amendments extend the date from April 2019 to October 31, 2020 to cease sending CCR and other waste streams to impoundments that demonstrate compliance with all except two specified criteria. These amendments also establish groundwater protection standards for four constituents that do not have established EPA maximum contaminant levels and allow a participating state director or the EPA (where the EPA is the permitting authority) to suspend groundwater monitoring requirements under certain circumstances. Specific site impacts are being evaluated by Gulf Power.
On October 15, 2018, the U.S. Court of Appeals for the District of Columbia Circuit issued a mandate that broadens the CCR Rule to regulate previously-excluded inactive surface impoundments (legacy units) located at retired generation facilities and challenges both the ability of unlined impoundments to continue operating and the classification of clay lined units. It is anticipated that the EPA will issue a series of rulemakings to address this court action. Gulf Power is evaluating the extent of potential impacts on legacy units but anticipates no significant impacts to its ongoing CCR strategy due to this mandate. The ultimate impact of these changes will not be known until the EPA rulemaking and any legal challenges are finalized.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Georgia Power continues to perform engineering studies related to its plans to close the ash ponds at all of its generating plants, including Plant Scherer Unit 3, which is jointly owned with Gulf Power, in compliance with federal and state CCR rules. Georgia Power also continues to refine its closure strategy and cost estimates for each ash pond and is preparing permit applications as required by the State of Georgia CCR rule. While Gulf Power believes its recorded liability for ash pond closures appropriately reflects its obligations under the current closure strategy elected for Plant Scherer Unit 3, changes to such strategy and cost estimate would likely result in additional closure costs which would increase Gulf Power's ARO liability. It is not currently possible to quantify the impacts of any increase related to a change in closure strategy and/or ongoing engineering studies for the current closure strategy, and the timing of future cash outflows is indeterminable at this time; however, the impact on the ARO liability is expected to be material. As permit applications advance, engineering studies continue, and the timing of the ash pond closure for Plant Scherer Unit 3 develops further during the fourth quarter 2018, Gulf Power will record any necessary changes to its ARO liability related to its share of Plant Scherer Unit 3. Gulf Power expects to continue to periodically update these cost estimates, which could increase further, as additional information becomes available. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
Absent continued recovery of ARO costs through regulated rates, Gulf Power'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.
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 August 31, 2018, the EPA published a proposed Clean Power Plan replacement rule known as the Affordable Clean Energy rule (ACE Rule), which would require states to develop unit-specific emission rate standards based on heat-rate efficiency improvements for existing fossil fuel-fired steam units. As proposed, combustion turbines, including natural gas combined cycles, are not affected sources. As of September 30, 2018, Gulf Power has ownership interests in seven fossil fuel-fired steam units to which the proposed ACE Rule is applicable. The ultimate impact of this rule to Gulf Power is currently unknown and will depend on changes between the proposal and the final rule, subsequent state plan developments and requirements, and any associated legal proceedings.
Through 2017, the Southern Company system has achieved an estimated GHG emission reduction of 36% since 2007. In April 2018, Southern Company established an intermediate goal of a 50% reduction in carbon emissions from 2007 levels by 2030 and a long-term goal of low- to no-carbon operations by 2050. To achieve these goals, the Southern Company system expects to continue growing its renewable energy portfolio, optimize technology advancements to modernize its transmission and distribution systems, increase the use of natural gas for generation, invest in energy efficiency, and continue research and development efforts focused on technologies to lower GHG emissions. The Southern Company system's ability to achieve these goals also will be dependent on many external factors, including supportive national energy policies, low natural gas prices, and the development, deployment, and advancement of relevant energy technologies. The ultimate outcome of this matter cannot be determined at this time.
FERC Matters
Market-Based Rate Authority
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 proceedings related to the traditional electric operating companies' (including Gulf Power's) and Southern Power's 2014 and 2017 triennial market power analyses.
On May 4, 2018, the FERC issued an order terminating both proceedings, finding that the traditional electric operating companies (including Gulf Power) and Southern Power satisfy the FERC's standards for market-based
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
rates. On May 9, 2018, the traditional electric operating companies (including Gulf Power) and Southern Power made the compliance filing required by the order. These proceedings are concluded.
Open Access Transmission Tariff
On May 10, 2018, the Alabama Municipal Electric Authority and Cooperative Energy filed with the FERC a complaint against SCS and the traditional electric operating companies (including Gulf Power) claiming that the current 11.25% base ROE used in calculating the annual transmission revenue requirements of the traditional electric operating companies' (including Gulf Power's) open access transmission tariff is unjust and unreasonable as measured by the applicable FERC standards. The complaint requests that the base ROE be set no higher than 8.65% and that the FERC order refunds for the difference in revenue requirements that results from applying a just and reasonable ROE established in this proceeding upon determining the current ROE is unjust and unreasonable. On June 18, 2018, SCS and the traditional electric operating companies (including Gulf Power) filed their response challenging the adequacy of the showing presented by the complainants and offering support for the current ROE. On September 6, 2018, the FERC issued an order establishing a refund effective date of May 10, 2018 in the event a refund is due and initiating an investigation and settlement procedures regarding the current base ROE. Through September 30, 2018, the estimated maximum potential refund is not expected to be material to Gulf Power's results of operations. The ultimate outcome of this matter cannot be determined at this time.
Retail Regulatory Matters
Gulf Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Florida PSC. Gulf Power's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased energy costs, purchased power capacity costs, energy conservation and demand side management programs, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are recovered through base rates. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information. The recovery balance of each regulatory clause for Gulf Power is reported in Note (B) to the Condensed Financial Statements herein.
Storm Damage Cost Recovery
See Note 1 to the financial statements of Gulf Power under "Property Damage Reserve" in Item 8 of the Form 10-K for information on how Gulf Power maintains a reserve for property damage to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generating facilities and other property.
On October 10, 2018, Hurricane Michael made landfall on the Gulf Coast of Florida causing substantial damage in Gulf Power's service territory. Gulf Power currently estimates the costs of repairing the damages to its transmission and distribution lines and uninsured facilities will total approximately $350 million to $400 million, which primarily will be charged to the property damage reserve or capitalized. At September 30, 2018, Gulf Power had a balance of approximately $48 million in its property damage reserve. In accordance with the 2017 Gulf Power Rate Case Settlement Agreement, Gulf Power can petition the Florida PSC to seek recovery of the costs associated with Hurricane Michael, along with replenishing the property damage reserve to approximately $40 million. Any recovery from customers would begin, on an interim basis, 60 days following the filing of the cost recovery petition. The ultimate outcome of this matter cannot be determined at this time.
Retail Base Rate Case
As a continuation of the 2017 Gulf Power Rate Case Settlement Agreement, on March 26, 2018, the Florida PSC approved the Gulf Power Tax Reform Settlement Agreement.
The Gulf Power Tax Reform Settlement Agreement results in annual reductions to Gulf Power's revenues of $18.2 million from base rates and $15.6 million from environmental cost recovery rates implemented April 1, 2018 and also provided for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
normalization) deferred tax liabilities through a reduced fuel cost recovery rate over the remainder of 2018. Through September 30, 2018, approximately $53 million of this refund has been reflected in customer bills. As a result of the Gulf Power Tax Reform Settlement Agreement, the Florida PSC also approved an increase in Gulf Power's maximum equity ratio from 52.5% to 53.5% for all retail regulatory purposes.
As part of the Gulf Power Tax Reform Settlement Agreement, a limited scope proceeding to address protected deferred tax liabilities consistent with IRS normalization principles was initiated on April 30, 2018. On October 30, 2018, the Florida PSC approved a $9.6 million annual reduction in base rate revenues effective January 2019, which concluded this proceeding. Through September 30, 2018, Gulf Power has deferred $7 million of related 2018 tax benefits as a regulatory liability to be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rate.
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information.
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 and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Cost Recovery Clauses" herein 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.
On November 5, 2018, 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 2019. The net effect of the approved changes is a $38 million decrease in annual revenues effective in January 2019, the majority of which will be offset by related expense decreases.
Income Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Gulf Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk," Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power," and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation and related regulatory actions.
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 laws and regulations governing air, water, land, and protection of 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 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.
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 regarding ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). See Note (A) to the Condensed Financial Statements herein for information regarding Gulf Power's recently adopted accounting standards.
In 2016, the FASB issued ASU No. 2016-02, which requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and Gulf Power will adopt the new standard effective January 1, 2019.
Gulf Power has elected the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby it will apply the requirements of ASU 2016-02 on a prospective basis as of the adoption date of January 1, 2019, without restating prior periods. Gulf Power expects to elect the package of practical expedients provided by ASU 2016-02 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Gulf Power expects to apply the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and to elect the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed. Gulf Power also expects to make accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and to combine lease and non-lease components in the computations of lease obligations and right-of-use assets for most asset classes.
Gulf Power is continuing to complete the implementation of an information technology system to track and account for its leases and of changes to its internal controls and accounting policies to support the accounting for leases under ASU 2016-02. Gulf Power has substantially completed its lease inventory and determined its most significant leases involve PPAs and real estate. While Gulf Power has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to result in recording lease liabilities and right-of-use assets on Gulf Power's balance sheet each totaling approximately $200 million, with no material impact on Gulf Power's statement of income.
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, 2018. 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.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Net cash provided from operating activities totaled $318 million for the first nine months of 2018 compared to $272 million for the corresponding period in 2017. The $46 million increase was primarily due to increased fuel cost recovery. Net cash used for investing activities totaled $238 million in the first nine months of 2018 primarily due to property additions. Net cash used for financing activities totaled $71 million for the first nine months of 2018 primarily due to the payment of common stock dividends, partially offset by capital contributions from Southern Company. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first nine months of 2018 include an increase of $99 million in property, plant, and equipment primarily due to additions at generation and distribution facilities; an increase of $69 million in other regulatory liabilities, current primarily due to over recovered cost recovery balances; and a decrease of $78 million in deferred credits related to income taxes primarily as a result of the Gulf Power Tax Reform Settlement Agreement. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Retail Base Rate Case" herein for additional information regarding the Gulf Power Tax Reform Settlement Agreement.
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 and contractual obligations. There are no scheduled maturities of long-term debt through September 30, 2019. 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 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 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, 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 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.
At September 30, 2018, Gulf Power's current liabilities exceeded current assets by $56 million. Gulf Power's current liabilities may 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.
Gulf Power intends to utilize operating cash flows, external security issuances, and borrowings from financial institutions to fund its short-term capital 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 funding needs related to Hurricane Michael. See Note 1 to the financial statements of Gulf Power under "Property Damage Reserve" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Storm Damage Cost Recovery" herein for additional information.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
At September 30, 2018, Gulf Power had approximately $37 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2018 were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Expires | | | | | | Executable Term Loans | | Expires Within One Year |
| 2018 | | 2019 | | 2020 | | Total | | Unused | | One Year | | Term Out | | No Term Out |
| (in millions) |
| $ | 20 |
| | $ | 25 |
| | $ | 235 |
| | $ | 280 |
| | $ | 280 |
| | $ | 45 |
| | $ | 45 |
| | $ | — |
|
See Note 6 to the financial statements of Gulf Power 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 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, 2018, Gulf Power was in compliance with all such covenants. A portion ($40 million) 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.
A portion of the $280 million unused credit arrangements with banks is 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, 2018 was approximately $82 million. In addition, at September 30, 2018, Gulf Power had approximately $58 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 on the balance sheets.
Details of short-term borrowings were as follows:
|
| | | | | | | | | | | | | | | | | | |
| | | Short-term Debt at September 30, 2018 | | 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 | | $ | 50 |
| | 2.5 | % | | $ | 59 |
| | 2.3 | % | | $ | 136 |
|
| |
(*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2018. |
Gulf Power believes the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, short-term bank loans, and operating cash flows.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Credit Rating Risk
At September 30, 2018, 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, 2018 were as follows:
|
| | | |
| Credit Ratings | Maximum Potential Collateral Requirements |
| | (in millions) |
| At BBB- and/or Baa3 | $ | 117 |
|
| Below BBB- and/or Baa3 | $ | 423 |
|
Included in these amounts are certain agreements that could require collateral in the event that Alabama Power or Georgia Power (affiliate companies of Gulf 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 May 21, 2018, S&P revised its rating outlook for Gulf Power from negative to stable.
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 Gulf Power, may be negatively impacted. The Gulf Power Tax Reform Settlement Agreement is expected to help mitigate these potential adverse impacts to Gulf Power's credit metrics by allowing a maximum equity ratio of 53.5% for all retail regulatory purposes. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power" herein for additional information.
Financing Activities
Gulf Power did not issue or redeem any securities during the nine months ended September 30, 2018.
In addition to any financings that may be necessary to meet capital requirements, contractual obligations, and storm recovery, Gulf Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
MISSISSIPPI POWER COMPANY
MISSISSIPPI POWER COMPANY
CONDENSED STATEMENTS OF OPERATIONSINCOME (UNAUDITED)
| | | | For the Three Months
Ended September 30, | | For the Nine Months
Ended September 30, | For the Three Months
Ended June 30, | | For the Six Months
Ended June 30, |
| | 2018 | | 2017 | | 2018 | | 2017 | 2019 | | 2018 | | 2019 | | 2018 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | | | | | | | | |
| Retail revenues | $ | 254 |
| | $ | 243 |
| | $ | 660 |
| | $ | 665 |
| $ | 215 |
| | $ | 212 |
| | $ | 418 |
| | $ | 406 |
|
| Wholesale revenues, non-affiliates | 65 |
| | 72 |
| | 184 |
| | 196 |
| 57 |
| | 59 |
| | 114 |
| | 127 |
|
| Wholesale revenues, affiliates | 28 |
| | 21 |
| | 81 |
| | 40 |
| 37 |
| | 19 |
| | 58 |
| | 54 |
|
| Other revenues | 11 |
| | 5 |
| | 31 |
| | 14 |
| 4 |
| | 7 |
| | 10 |
| | 11 |
|
| Total operating revenues | 358 |
| | 341 |
| | 956 |
| | 915 |
| 313 |
| | 297 |
| | 600 |
| | 598 |
|
| Operating Expenses: | | | | | | | | | | | | | | |
| Fuel | 116 |
| | 120 |
| | 312 |
| | 301 |
| 105 |
| | 98 |
| | 198 |
| | 197 |
|
| Purchased power | 11 |
| | 6 |
| | 27 |
| | 20 |
| 6 |
| | 7 |
| | 9 |
| | 16 |
|
| Other operations and maintenance | 80 |
| | 68 |
| | 222 |
| | 213 |
| 68 |
| | 67 |
| | 127 |
| | 141 |
|
| Depreciation and amortization | 42 |
| | 39 |
| | 126 |
| | 120 |
| 48 |
| | 44 |
| | 95 |
| | 84 |
|
| Taxes other than income taxes | 28 |
| | 25 |
| | 83 |
| | 77 |
| 28 |
| | 27 |
| | 55 |
| | 54 |
|
| Estimated loss on Kemper IGCC | 1 |
| | 34 |
| | 45 |
| | 3,155 |
| 4 |
| | — |
| | 6 |
| | 45 |
|
| Total operating expenses | 278 |
| | 292 |
| | 815 |
| | 3,886 |
| 259 |
| | 243 |
| | 490 |
| | 537 |
|
| Operating Income (Loss) | 80 |
| | 49 |
| | 141 |
| | (2,971 | ) | |
| Operating Income | | 54 |
| | 54 |
| | 110 |
| | 61 |
|
| Other Income and (Expense): | | | | | | | | | | | | | | |
| Allowance for equity funds used during construction | — |
| | 1 |
| | — |
| | 72 |
| |
| Interest expense, net of amounts capitalized | (19 | ) | | 13 |
| | (59 | ) | | (23 | ) | (17 | ) | | (21 | ) | | (35 | ) | | (39 | ) |
| Other income (expense), net | — |
| | 1 |
| | 28 |
| | 4 |
| 5 |
| | 27 |
| | 11 |
| | 27 |
|
| Total other income and (expense) | (19 | ) | | 15 |
| | (31 | ) | | 53 |
| (12 | ) | | 6 |
| | (24 | ) | | (12 | ) |
| Earnings (Loss) Before Income Taxes | 61 |
| | 64 |
| | 110 |
| | (2,918 | ) | |
| Income taxes (benefit) | 14 |
| | 24 |
| | 23 |
| | (885 | ) | |
| Net Income (Loss) | 47 |
| | 40 |
| | 87 |
| | (2,033 | ) | |
| 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 | $ | 47 |
| | $ | 40 |
| | $ | 86 |
| | $ | (2,034 | ) | |
| Net Income After Dividends on Preferred Stock | | $ | 37 |
| | $ | 46 |
| | $ | 74 |
| | $ | 39 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months
Ended September 30, | | For the Nine Months
Ended September 30, |
| | 2018 | | 2017 | | 2018 | | 2017 |
| | (in millions) | | (in millions) |
| Net Income (Loss) | $ | 47 |
| | $ | 40 |
| | $ | 87 |
| | $ | (2,033 | ) |
| Other comprehensive income (loss): |
| |
| |
| |
|
| Qualifying hedges: | | | | | | | |
Changes in fair value, net of tax of
$-, $-, $(1), 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) | $ | 47 |
| | $ | 39 |
| | $ | 87 |
| | $ | (2,032 | ) |
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, |
| | 2018 | | 2017 |
| | (in millions) |
| Operating Activities: | | | |
| Net income (loss) | $ | 87 |
| | $ | (2,033 | ) |
| Adjustments to reconcile net income (loss) to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 129 |
| | 144 |
|
| Deferred income taxes | 420 |
| | (1,159 | ) |
| Allowance for equity funds used during construction | — |
| | (72 | ) |
| Estimated loss on Kemper IGCC | 21 |
| | 3,148 |
|
| Other, net | 5 |
| | (26 | ) |
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (46 | ) | | 438 |
|
| -Fossil fuel stock | (2 | ) | | 21 |
|
| -Other current assets | (5 | ) | | (9 | ) |
| -Accounts payable | (3 | ) | | (21 | ) |
| -Accrued taxes | 57 |
| | 20 |
|
| -Accrued compensation | (9 | ) | | (12 | ) |
| -Over recovered regulatory clause revenues | 20 |
| | (47 | ) |
| -Other current liabilities | (18 | ) | | (31 | ) |
| Net cash provided from operating activities | 656 |
| | 361 |
|
| Investing Activities: | | | |
| Property additions | (117 | ) | | (411 | ) |
| Construction payables | (9 | ) | | (47 | ) |
| Payments pursuant to LTSAs | (28 | ) | | (10 | ) |
| Other investing activities | (16 | ) | | (15 | ) |
| Net cash used for investing activities | (170 | ) | | (483 | ) |
| Financing Activities: | | | |
| Decrease in notes payable, net | (4 | ) | | (23 | ) |
| Proceeds — | | | |
| Senior notes | 600 |
| | — |
|
| Short-term borrowings | 300 |
| | 113 |
|
| Capital contributions from parent company | (2 | ) | | 1,002 |
|
| Long-term debt to parent company | — |
| | 40 |
|
| Redemptions — | | | |
| Other long-term debt | (900 | ) | | (300 | ) |
| Short-term borrowings | (300 | ) | | (109 | ) |
| Pollution control revenue bonds | (43 | ) | | — |
|
| Long-term debt to parent company | — |
| | (591 | ) |
| Other financing activities | (6 | ) | | (3 | ) |
| Net cash provided from (used for) financing activities | (355 | ) | | 129 |
|
| Net Change in Cash, Cash Equivalents, and Restricted Cash | 131 |
| | 7 |
|
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 248 |
| | 224 |
|
| Cash, Cash Equivalents, and Restricted Cash at End of Period | $ | 379 |
| | $ | 231 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
Interest (paid $57 and $73, net of $- and $28 capitalized for 2018
and 2017, respectively) | $ | 57 |
| | $ | 45 |
|
| Income taxes, net | (483 | ) | | (209 | ) |
| Noncash transactions — Accrued property additions at end of period | 23 |
| | 32 |
|
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, 2018 | | At December 31, 2017 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 379 |
| | $ | 248 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 49 |
| | 36 |
|
| Unbilled revenues | | 43 |
| | 41 |
|
| Income taxes receivable, current | | 3 |
| | 4 |
|
| Affiliated | | 35 |
| | 16 |
|
| Other accounts and notes receivable | | 47 |
| | 12 |
|
| Fossil fuel stock | | 19 |
| | 17 |
|
| Materials and supplies, current | | 52 |
| | 44 |
|
| Other regulatory assets, current | | 110 |
| | 125 |
|
| Other current assets | | 4 |
| | 9 |
|
| Total current assets | | 741 |
| | 552 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 4,819 |
| | 4,773 |
|
| Less: Accumulated provision for depreciation | | 1,389 |
| | 1,325 |
|
| Plant in service, net of depreciation | | 3,430 |
| | 3,448 |
|
| Construction work in progress | | 106 |
| | 84 |
|
| Total property, plant, and equipment | | 3,536 |
| | 3,532 |
|
| Other Property and Investments | | 24 |
| | 30 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 34 |
| | 35 |
|
| Other regulatory assets, deferred | | 466 |
| | 437 |
|
| Accumulated deferred income taxes | | — |
| | 247 |
|
| Other deferred charges and assets | | 16 |
| | 33 |
|
| Total deferred charges and other assets | | 516 |
| | 752 |
|
| Total Assets | | $ | 4,817 |
| | $ | 4,866 |
|
|
| | | | | | | | | | | | | | | |
| | 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 BALANCE SHEETSSTATEMENTS OF CASH FLOWS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholder's Equity | | At September 30, 2018 | | At December 31, 2017 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 204 |
| | $ | 989 |
|
| Notes payable | | — |
| | 4 |
|
| Accounts payable — | | | | |
| Affiliated | | 55 |
| | 59 |
|
| Other | | 90 |
| | 96 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 75 |
| | 40 |
|
| Other accrued taxes | | 74 |
| | 101 |
|
| Accrued interest | | 21 |
| | 16 |
|
| Accrued compensation | | 30 |
| | 39 |
|
| Accrued plant closure costs | | 30 |
| | 35 |
|
| Asset retirement obligations, current | | 41 |
| | 37 |
|
| Other current liabilities | | 56 |
| | 47 |
|
| Total current liabilities | | 676 |
| | 1,463 |
|
| Long-term Debt | | 1,532 |
| | 1,097 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 193 |
| | — |
|
| Deferred credits related to income taxes | | 420 |
| | 372 |
|
| Employee benefit obligations | | 111 |
| | 116 |
|
| Asset retirement obligations, deferred | | 136 |
| | 137 |
|
| Other cost of removal obligations | | 181 |
| | 178 |
|
| Other regulatory liabilities, deferred | | 75 |
| | 79 |
|
| Other deferred credits and liabilities | | 17 |
| | 33 |
|
| Total deferred credits and other liabilities | | 1,133 |
| | 915 |
|
| Total Liabilities | | 3,341 |
| | 3,475 |
|
| 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 | | 4,528 |
| | 4,529 |
|
| Accumulated deficit | | (3,119 | ) | | (3,205 | ) |
| Accumulated other comprehensive loss | | (4 | ) | | (4 | ) |
| Total common stockholder's equity | | 1,443 |
| | 1,358 |
|
| Total Liabilities and Stockholder's Equity | | $ | 4,817 |
| | $ | 4,866 |
|
|
| | | | | | | |
| | For the Six Months
Ended June 30, |
| | 2019 | | 2018 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 74 |
| | $ | 40 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 98 |
| | 86 |
|
| Deferred income taxes | (16 | ) | | 289 |
|
| Settlement of asset retirement obligations | (17 | ) | | (15 | ) |
| Estimated loss on Kemper IGCC | 11 |
| | 28 |
|
| Other, net | 1 |
| | 2 |
|
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (8 | ) | | (51 | ) |
| -Other current assets | (3 | ) | | (11 | ) |
| -Accounts payable | (28 | ) | | (15 | ) |
| -Accrued taxes | (43 | ) | | (41 | ) |
| -Accrued compensation | (15 | ) | | (14 | ) |
| -Other current liabilities | 6 |
| | (1 | ) |
| Net cash provided from operating activities | 60 |
| | 297 |
|
| Investing Activities: | | | |
| Property additions | (95 | ) | | (74 | ) |
| Construction payables | (12 | ) | | (9 | ) |
| Payments pursuant to LTSAs | (11 | ) | | (13 | ) |
| Other investing activities | (10 | ) | | (12 | ) |
| Net cash used for investing activities | (128 | ) | | (108 | ) |
| Financing Activities: | | | |
| Decrease in notes payable, net | — |
| | (4 | ) |
| Proceeds — | | | |
| Senior notes | — |
| | 600 |
|
| Short-term borrowings | — |
| | 300 |
|
| Capital contributions from parent company | 7 |
| | 1 |
|
| Pollution control revenue bonds | 43 |
| | — |
|
| Redemptions — | | | |
| Other long-term debt | — |
| | (900 | ) |
| Short-term borrowings | — |
| | (200 | ) |
| Return of capital | (75 | ) | | — |
|
| Other financing activities | (1 | ) | | (6 | ) |
| 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 (net of $(1) and $- capitalized for 2019 and 2018, respectively) | $ | 36 |
| | $ | 39 |
|
| Income taxes, net | 23 |
| | (257 | ) |
| Noncash transactions — Accrued property additions at end of period | 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 June 30, 2019 | | At December 31, 2018 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 199 |
| | $ | 293 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 38 |
| | 34 |
|
| Unbilled revenues | | 44 |
| | 41 |
|
| Affiliated | | 17 |
| | 21 |
|
| Other accounts and notes receivable | | 38 |
| | 31 |
|
| Fossil fuel stock | | 23 |
| | 20 |
|
| Materials and supplies | | 52 |
| | 53 |
|
| Other regulatory assets | | 107 |
| | 116 |
|
| Other current assets | | 13 |
| | 19 |
|
| Total current assets | | 531 |
| | 628 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 4,800 |
| | 4,900 |
|
| Less: Accumulated provision for depreciation | | 1,427 |
| | 1,429 |
|
| Plant in service, net of depreciation | | 3,373 |
| | 3,471 |
|
| Construction work in progress | | 113 |
| | 103 |
|
| Total property, plant, and equipment | | 3,486 |
| | 3,574 |
|
| Other Property and Investments | | 124 |
| | 24 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 33 |
| | 33 |
|
| Regulatory assets – asset retirement obligations | | 207 |
| | 143 |
|
| Other regulatory assets, deferred | | 328 |
| | 332 |
|
| Accumulated deferred income taxes | | 145 |
| | 150 |
|
| Other deferred charges and assets | | 20 |
| | 2 |
|
| Total deferred charges and other assets | | 733 |
| | 660 |
|
| Total Assets | | $ | 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 June 30, 2019 | | At December 31, 2018 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 300 |
| | $ | 40 |
|
| Accounts payable — | | | | |
| Affiliated | | 60 |
| | 60 |
|
| Other | | 49 |
| | 90 |
|
| Accrued taxes | | 52 |
| | 95 |
|
| Accrued interest | | 15 |
| | 15 |
|
| Accrued compensation | | 23 |
| | 38 |
|
| 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 | | 52 |
| | 28 |
|
| Total current liabilities | | 634 |
| | 455 |
|
| Long-term Debt | | 1,318 |
| | 1,539 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 366 |
| | 378 |
|
| Deferred credits related to income taxes | | 362 |
| | 382 |
|
| Employee benefit obligations | | 110 |
| | 115 |
|
| Asset retirement obligations, deferred | | 177 |
| | 126 |
|
| Other cost of removal obligations | | 189 |
| | 185 |
|
| Other regulatory liabilities, deferred | | 79 |
| | 81 |
|
| Other deferred credits and liabilities | | 22 |
| | 16 |
|
| Total deferred credits and other liabilities | | 1,305 |
| | 1,283 |
|
| Total Liabilities | | 3,257 |
| | 3,277 |
|
Common Stockholder's Equity (See accompanying statements) | | 1,617 |
| | 1,609 |
|
| Total Liabilities and Stockholder's Equity | | $ | 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 2019 vs. SECOND QUARTER 2018 vs. THIRD QUARTER 2017
AND
YEAR-TO-DATE 20182019 vs. YEAR-TO-DATE 20172018
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 reliability, fuel, andprojected long-term demand growth, stringent environmental standards, as well as ongoingincluding CCR rules, reliability, fuel, capital and operations and maintenance expenditures, including 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.
On July 27, 2018, Mississippi Power and the Mississippi Public Utilities Staff (MPUS) entered into a settlement agreement with respect to the 2018 PEP filing and all unresolved PEP filings for prior years (PEP Settlement Agreement), which was approved by the Mississippi PSC on August 7, 2018. Rates under the PEP Settlement Agreement, which result in approximately $21.6 million in additional revenue annually, became effective with the first billing cycle of September 2018.
On August 3, 2018, Mississippi Power and the MPUS entered into a settlement agreement to increase rates approximately $17 million annually with respect to the 2018 ECO Plan filing (ECO Settlement Agreement), which was approved by the Mississippi PSC on August 7, 2018. Rates under the ECO Settlement Agreement became effective with the first billing cycle of September 2018.
The PEP and ECO Plan rates are expected to continue through the conclusion of the next base rate proceeding which is scheduled to be filedfile a base rate case in the fourth quarter 2019 (2019(Mississippi Power 2019 Base Rate Case).
On May 8, 2018,7, 2019, the FERC accepted Mississippi PSC issued an order to begin an operations review of Mississippi Power, which beganPower's March 28, 2019 request for a decrease in August 2018,wholesale base revenues under the MRA tariff as agreed upon in a settlement agreement reached with the final report expected by February 28, 2019. Mississippi Power expects that the review will include, but not be limited to, a comparative analysis of its costs, its cost recovery framework, and ways in which it may streamline management operations for the reasonable benefit of ratepayers. The ultimate outcome of this matter cannot be determined at this time.
See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Mississippi Power" herein for additional information.
On October 2, 2018, the Mississippi PSC approved the executed agreements between Mississippi Power and its largest retail customer, Chevron Products Company (Chevron), for Mississippi Power to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038. The new agreements are not expected to have a material impact on earnings. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "General" of Mississippi Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein for additional information.
As of September 30, 2018, Mississippi Power recorded charges to income of an immaterial amount for the third quarter 2018 and $45 million ($34 million after tax) for year-to-date 2018, primarily resulting from the abandonment and related closure activities 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 to cost up to $20 million pre-tax (excluding salvage, net of dismantlement costs), 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 $2 million for the remainder of 2018, $8 million in
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
2019, and $4 million annually beginning in 2020. The ultimate outcome of this matter cannot be determined at this time.
On August 6, 2018, Mississippi Power filed its proposed Reserve Margin Plan (RMP), as required by the Mississippi PSC's order in the docket established for the purposes of pursuing a global settlement of the costswholesale customers (MRA Settlement Agreement) resolving all matters related to the Kemper County energy facility (Kemper Settlement Docket). Under the RMP, Mississippi Power proposes alternatives that would reduce its reserve margin, with the most economic of the alternatives being the two-year and seven-year acceleration of the retirement of Plant Watson Units 4 and 5, respectively,similar to the first quarter 2022 and the four-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively, in order to lower or avoid operating costs. The Plant Greene County unit retirements would require the completion by Alabama Power of proposed transmission and system reliability improvements, as well asretail rate settlement agreement by Alabama Power. The RMP filing also states that, in the event the Mississippi PSC ultimately approves an alternative that includes an accelerated retirement, Mississippi Power would require authorization to defer in a regulatory asset for future recovery the remaining net book value of the units at the time of retirement. Mississippi Power expects the MPUS and other interested parties to review the proposal prior to resolution by the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time. However, if approved by the Mississippi PSC in February 2018 and reflecting the alternatives are not expectedimpacts of the Tax Reform Legislation. Pursuant to have any adverse impact on customer rates.
For additional information on the Kemper County energy facility, seeMRA Settlement Agreement, base rates decreased $3.7 million annually, effective January 1, 2019. See Note 32 to the financial statements of Mississippi Power under "Kemper County Energy Facility""FERC Matters" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Kemper County Energy Facility" and Note (B) to the Condensed Financial Statements under "Kemper County Energy Facility" herein.
In March 2018, Mississippi Power issued $300 million aggregate principal amount of Series 2018A Floating Rate Senior Notes due March 27, 2020 bearing interest based on three-month LIBOR and $300 million aggregate principal amount of Series 2018B 3.95% Senior Notes due March 30, 2028. In March 2018, Mississippi Power also entered into a $300 million short-term floating rate bank loan bearing interest based on one-month LIBOR, of which $200 million was repaid in the second quarter 2018 and $100 million was repaid in the third quarter 2018. Mississippi Power used the proceeds from these financings to repay a $900 million unsecured term loan.for additional information.
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 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $7 | | 17.5 | | $2,120 | | 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 20182019 was $47$37 million compared to $40$46 million for the corresponding period in 2017. The increase in net income2018. This decrease was primarily due to the settlement of Mississippi Power's Deepwater Horizon claim in May 2018 and a decrease in retail revenues due to a new tolling arrangement accounted for as a sales-type lease, partially offset by an increase in retail revenues as a result of PEP and ECO Plan rate increasesrates that became effective for the first billing cycle of September 2018.
For year-to-date 2019, net income was $74 million compared to $39 million for the corresponding period in 2018. This increase was primarily due to lower charges associated with the Kemper IGCC in 2019 and an increase in PEP rates that became effective for the first billing cycle of September 2018, and lower pre-tax charges associated with the Kemper IGCC, partially offset by an increasea decrease in operations and maintenance expenses and interest expense,other income (expense), net due to the settlement of amounts capitalized.
Mississippi Power's net income after dividends on preferred stock for year-to-dateDeepwater Horizon claim in May 2018 was $86 million comparedand a decrease in retail revenues due to a lossnew tolling arrangement accounted for as a sales-type lease.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
to lower pre-tax charges associated with the Kemper IGCC, partially offset by the cessation of AFUDC equity related to the Kemper IGCC in the second quarter 2017 and higher interest expense, net of amounts capitalized.
See Note 3 to the financial statements of Mississippi Power under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Kemper County Energy Facility" herein for additional information regarding the Kemper IGCC.
Retail Revenues
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $11 | | 4.5 | | $(5) | | (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) |
| $3 | | 1.4 | | $12 | | 3.0 |
In the thirdsecond quarter 2018,2019, retail revenues were $254$215 million compared to $243$212 million for the corresponding period in 2017.2018. For year-to-date 2018,2019, retail revenues were $660$418 million compared to $665$406 million for the corresponding period in 2017.2018.
Details of the changes in retail revenues were as follows:
| | | | Third Quarter 2018 | | Year-to-Date 2018 | Second Quarter 2019 | | Year-to-Date 2019 |
| | (in millions) | | (% change) | | (in millions) | | (% change) | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | $ | 243 |
| | | | $ | 665 |
| | | $ | 212 |
| | | | $ | 406 |
| | |
| Estimated change resulting from – | | | | | | | | | | | | | | |
| Rates and pricing | 11 |
| | 4.5 | % | | (3 | ) | | (0.5 | )% | 11 |
| | 5.2 | % | | 26 |
| | 6.4 | % |
| Sales growth | 3 |
| | 1.3 |
| | 1 |
| | 0.2 |
| |
| Sales decline | | (1 | ) | | (0.5 | ) | | — |
| | — |
|
| Weather | 2 |
| | 0.8 |
| | 12 |
| | 1.8 |
| — |
| | — |
| | (9 | ) | | (2.2 | ) |
| Fuel and other cost recovery | (5 | ) | | (2.1 | ) | | (15 | ) | | (2.3 | ) | (7 | ) | | (3.3 | ) | | (5 | ) | | (1.2 | ) |
| Retail – current year | $ | 254 |
| | 4.5 | % | | $ | 660 |
| | (0.8 | )% | $ | 215 |
| | 1.4 | % | | $ | 418 |
| | 3.0 | % |
Revenues associated with changes in rates and pricing increased in the thirdsecond quarter 2018and year-to-date 2019 when compared to the corresponding periodperiods in 20172018 primarily due to theincreases in PEP and ECO Plan rate changesrates that became effective for the first billing cycle of September 2018, resulting in retail revenue increases of $4 million and $9 million, respectively. In addition, as a result of the PEP Settlement Agreement, Mississippi Power recognized revenues of $5 million previously reserved in connection with the 2012 PEP lookback filing, partially offset by a new tolling arrangement accounted for as a sales-type lease effective January 2019. Partially offsetting the recognition of regulatory liabilities of $5 million and $2 million related to the equity ratio provisions of the PEP and ECO Settlement Agreements, respectively.
Revenues associated with changes in rates and pricing decreased year-to-date 2018 when compared to the corresponding period in 2017 primarily due to2019 increase was a rate decrease in annual retail revenues of $12 million for lower base rates related to the Kemper County energy facility that became effective for the first billing cycle of April 2018 and recognition in 2018 of regulatory liabilities of $5 million and $2 million related to the equity ratio provisions of the PEP and ECO Settlement Agreements, respectively, partially offset by higher retail revenues of $5 million for PEP and ECO Plan rates that became effective with the first billing cycle of September 2018, recognition of $5 million previously reserved in connection with the 2012 PEP lookback filing as a result of the PEP Settlement Agreement, and the recognition in the third quarter 2017 of a $7 million regulatory liability.
2018. See Note 32 to the financial statements of Mississippiunder "Mississippi Power under "Retail Regulatory Matters – Performance Evaluation Plan" andPlan," " – Environmental Compliance Overview Plan"Plan," and "Kemper" – Kemper County Energy Facility – Rate Recovery" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters"Note (L) to the Condensed Financial Statements herein for additional information.
Revenues attributable to changes in sales increased fordecreased in the thirdsecond quarter and year-to-date 20182019 when compared to the corresponding periodsperiod in 2017. Weather-adjusted residential and commercial KWH sales increased 2.7% and 1.0%,
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
respectively, in the third quarter 2018 due to increased customer usage and slight customer growth.2018. Weather-adjusted residential KWH sales increased 1.1%0.4% and 1.0% in the second quarter and year-to-date 20182019, respectively, due to increased customer usage. Weather-adjusted commercial KWH sales remained relatively flatdecreased 2.1% and 2.7% in the second quarter and year-to-date 2018.2019, respectively, due to decreased customer usage. Industrial KWH sales increased 2.0%decreased 3.1% and 0.4% for3.5% in the thirdsecond quarter and year-to-date 2018,2019, respectively, primarily due to increaseddecreased customer usage by several large industrial customers.
Revenues associated with weather decreased for year-to-date 2019 when compared to the corresponding period in 2018 primarily due to milder weather.
Fuel and other cost recovery revenues decreased in the thirdsecond quarter and year-to-date 20182019 when compared to the corresponding periods in 20172018 primarily as a result of lower recoverable fuel costs. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power's service territory. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale Revenues – Non-Affiliates
| | | Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 | |
| Second Quarter 2019 vs. Second Quarter 2018 | | 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) | | (change in millions) | | (% change) |
$(7)(2) | | (9.7) | | $(12) | | (6.1) | | (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""FERC Matters" herein for additional information.
In the third quarter 2018,For year-to-date 2019, wholesale revenues from sales to non-affiliates were $65$114 million compared to $72$127 million for the corresponding period in 2017. For year-to-date 2018, wholesale revenues from sales to non-affiliates were $184 million compared to $196 million for the corresponding period in 2017. These decreases2018. This decrease primarily resulted from a $6 million decrease in revenue undercost-based electric tariff revenues due to decreased customer usage, milder weather, and a decrease in rates due to the Shared ServicesMRA Settlement Agreement, (SSA) between Mississippi Powera $5 million decrease due to lower PPA capacity and Cooperative Energy of $6energy sales, and a $3 million and $16 million in the third quarter and year-to-date 2018, respectively, as a result of transmission revenue now being recovered under the Open Access Transmission Tariff (OATT) and included in other revenues on the statements of operations. The year-to-date 2018 decrease wasdue to lower fuel prices, partially offset by ana $1 million increase in sales dueopportunity sales. See Note (B) to colder weather in January 2018the Condensed Financial Statements under "Mississippi Power – Municipal and warmer weather during the second and third quarters 2018.Rural Association Tariff" herein for additional information.
Wholesale Revenues – Affiliates
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $7 | | 33.3 | | $41 | | 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) |
| $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 second quarter 2019, wholesale revenues from sales to affiliates were $37 million compared to $19 million for the corresponding period in 2018. The increase was primarily due to a $15 million increase associated with higher KWH sales due to the dispatch of Mississippi Power's lower cost generation resources to serve the Southern Company system's territorial load and a $2 million increase associated with a higher average sales price.
For year-to-date 2019, wholesale revenues from sales to affiliates were $58 million compared to $54 million for the corresponding period in 2018. The increase was primarily due to a $25 million increase associated with higher KWH sales due to the dispatch of Mississippi Power's lower cost generation resources to serve the Southern Company system's territorial load, 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
In the third quarter 2018, wholesale revenues from sales to affiliates were $28 million compared to $21 million for the corresponding period in 2017. For year-to-date 2018, wholesale revenues from sales to affiliates were $81 million compared to $40 million for the corresponding period in 2017. These increases were primarily due to increases in KWH sales due to increased availability of Mississippi Power's lower cost generation resources to serve the Southern Company system's territorial load in 2018 as compared to 2017.
Other Revenues
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $6 | | N/M | | $17 | | N/M |
N/M - Not meaningful
In the third quarter 2018, other revenues were $11 million compared to $5 million for the corresponding period in 2017. For year-to-date 2018, other revenues were $31 million compared to $14 million for the corresponding period in 2017. These increases were primarily due to increases in transmission revenue related to SSA customers now being recovered under the OATT of $6 million and $16 million in the third quarter and year-to-date 2018, respectively.
Fuel and Purchased Power Expenses
| | | | Third Quarter 2018
vs.
Third Quarter 2017 | | Year-to-Date 2018
vs.
Year-to-Date 2017 | 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 | $ | (4 | ) | | (3.3) | | $ | 11 |
| | 3.7 | $ | 7 |
| | 7.1 | | $ | 1 |
| | 0.5 |
| Purchased power | 5 |
| | 83.3 | | 7 |
| | 35.0 | (1 | ) | | (14.3) | | (7 | ) | | (43.8) |
| Total fuel and purchased power expenses | $ | 1 |
| | $ | 18 |
| | $ | 6 |
| | $ | (6 | ) | |
In the thirdsecond quarter 2018,2019, total fuel and purchased power expenses were $127$111 million compared to $126$105 million for the corresponding period in 2017.2018. The increase was primarily due to an $11a $13 million net increase inassociated with the volume of KWHs generated and purchased, partially offset by a $10net decrease of $7 million decrease in theassociated with lower average cost of natural gas and purchased power.fuel.
For year-to-date 2018,2019, total fuel and purchased power expenses were $339$207 million compared to $321$213 million for the corresponding period in 2017.2018. The increasedecrease was primarily due to a $39$13 million decrease related to the average cost of fuel and purchased power primarily due to a lower average cost of natural gas, partially offset by a $7 million net increase inassociated with the volume of KWHs generated and purchased, partially offset by a $20 million decrease in the cost of natural gas and 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 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 2018 | | Third Quarter 2017 | | Year-to-Date 2018 | | Year-to-Date 2017 |
Total generation (in millions of KWHs) | 4,581 | | 4,453 | | 12,665 | | 11,542 |
Total purchased power (in millions of KWHs)(*) | 348 | | 164 | | 781 | | 527 |
Sources of generation (percent) – | | | | | | | |
| Coal | 8 | | 8 | | 7 | | 8 |
| Gas | 92 | | 92 | | 93 | | 92 |
Cost of fuel, generated (in cents per net KWH) – | | | | | | | |
| Coal | 3.51 | | 3.80 | | 3.50 | | 3.60 |
| Gas | 2.58 | | 2.77 | | 2.57 | | 2.72 |
Average cost of fuel, generated (in cents per net KWH) | 2.66 | | 2.86 | | 2.63 | | 2.80 |
Average cost of purchased power (in cents per net KWH)(*) | 3.18 | | 3.74 | | 3.47 | | 3.78 |
| |
(*) | Year-to-date 2017 includes energy produced during the test period for the Kemper IGCC and accounted for in accordance with FERC guidance. |
Fuel
In the third quarter 2018, fuel expense was $116 million compared to $120 million for the corresponding period in 2017. The decrease was primarily due to a 6.7% decrease in the cost of natural gas, partially offset by a 3.2% increase in the volume of KWHs generated due to warmer weather in the third quarter 2018.
For year-to-date 2018, fuel expense was $312 million compared to $301 million for the corresponding period in 2017. The increase was primarily due to a 10.3% increase in the volume of KWHs generated due to colder weather in January 2018 and warmer weather during the second and third quarters 2018, partially offset by a 5.7% decrease in the cost of natural gas.
Purchased Power
In the third quarter 2018, purchased power expense was $11 million compared to $6 million for the corresponding period in 2017. The increase was primarily due to a $7 million increase in the volume of KWHs purchased, partially offset by a $2 million decrease in the cost of purchased power.
For year-to-date 2018, purchased power expense was $27 million compared to $20 million for the corresponding period in 2017. The increase was primarily due to a $9 million increase in the volume of KWHs purchased, partially offset by a $2 million decrease in the cost of 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. 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 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $12 | | 17.6 | | $9 | | 4.2 |
|
| | | | | | |
| 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 2018,For year-to-date 2019, other operations and maintenance expenses were $80$127 million compared to $68$141 million for the corresponding period in 2017. For year-to-date 2018, other operations and maintenance expenses were $222 million compared to $213 million for the corresponding period in 2017.2018. The increases weredecrease was primarily due to costs
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
decreases of $10 million related to generation maintenance, primarily due to planned outages, and $6 million in employee compensation and benefit expenses due to an employee attrition plan. The year-to-dateplan implemented in the third quarter 2018, increase also reflectspartially offset by a $4 million increase primarily related to additional overhead line maintenance and vegetation management, offset by a $7 million decrease in expenses related to the combined cycle and associated common facilities portion of the Kemper County energy facility.management.
Depreciation and Amortization
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $3 | | 7.7 | | $6 | | 5.0 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $4 | | 9.1 | | $11 | | 13.1 |
In the thirdsecond quarter 2018,2019, depreciation and amortization was $42$48 million compared to $39$44 million for the corresponding period in 2017. The increase2018. For year-to-date 2019, depreciation and amortization was $95 million compared to $84 million for the corresponding period in 2018. These increases were primarily related to a $3 million changeincreases in net amortization associated with ECO Plan regulatory assets.
For year-to-date 2018, depreciation and amortization was $126 million compared to $120 million for the corresponding period in 2017. The increase was primarily related to $5 million of depreciation for additional plant in service and $1 million related to changes in net amortization associated with regulatory assets and liabilities.
See Note 12 to the financial statements of Mississippiunder "Mississippi Power under "Depreciation, Depletion, and Amortization"– Environmental Compliance Overview Plan" in Item 8 of the Form 10-K for additional information.
Taxes Other Than Income Taxes
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $3 | | 12.0 | | $6 | | 7.8 |
In the third quarter 2018, taxes other than income taxes were $28 million compared to $25 million for the corresponding period in 2017. For year-to-date 2018, taxes other than income taxes were $83 million compared to $77 million for the corresponding period in 2017. These increases were primarily related to increases in ad valorem taxes related to an increase in the assessed value of property.
The retail portion of ad valorem taxes is recoverable under Mississippi Power's ad valorem tax cost recovery clause and, therefore, does not affect net income.
Estimated Loss on Kemper IGCC
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(33) | | (97.1) | | $(3,110) | | (98.6) |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $4 | | N/M | | $(39) | | (86.7) |
EstimatedN/M - Not meaningful
In the second quarter and year-to-date 2019, estimated losses on the Kemper IGCC were $1$4 million for the third quarter 2018and $6 million, respectively, compared to an immaterial amount and $45 million, respectively, for year-to-date 2018, resulting from the corresponding periods in 2018. These charges relate to abandonment and related closure activities for the mine and gasifier-related assets as compared to $34 million and $3.2 billion for the corresponding periods in 2017 related to revisions to the estimated construction costs for, and subsequent suspension in June 2017 of, the Kemper IGCC.assets.
See Note 32 to the financial statements of Mississippiunder "Mississippi Power under "Kemper– Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Kemper"Mississippi Power – Kemper County Energy Facility"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
Allowance for Equity Funds Used During Construction
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(1) | | (100.0) | | $(72) | | (100.0) |
For year-to-date 2018, AFUDC equity was immaterialmillion compared to $72$39 million for the corresponding period in 2017. The decrease2018. These decreases primarily resulted from suspension of the Kemper IGCC constructiona decrease in June 2017.average outstanding debt.
See Note 3 to the financial statements of Mississippi Power under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Kemper County Energy Facility" herein for additional information.
Interest Expense,Other Income (Expense), Net of Amounts Capitalized
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $32 | | N/M | | $36 | | 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) |
| $(22) | | (81.5) | | $(16) | | (59.3) |
In the thirdsecond quarter 2018, interest expense,2019, other income (expense), net of amounts capitalized was $19$5 million compared to an interest benefit of $13$27 million for the corresponding period in 2017.2018. For year-to-date 2018, interest expense,2019, other income (expense), net of amounts capitalized was $59$11 million compared to $23$27 million for the corresponding period in 2017. The increases2018. These decreases were primarily reflectdue to a $33$24 million net reduction in interest recordeddecrease in the thirdsecond quarter 2017 following a settlement with the IRS related to research and experimental deductions. The year-to-date 2018 increase also reflects a reduction in AFUDC debt of $24 million related to the Kemper IGCC project suspension in June 2017, offset by decreases of $9 million in interest expense as a result of lower average outstanding debt, $8 million related to uncertain tax positions, and $7 million due to the completion of Kemper IGCC carrying cost amortization in 2017.
See Note 3 to the financial statements of Mississippi Power under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein for additional information.
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(1) | | (100.0) | | $24 | | N/M |
N/M - Not meaningful
For year-to-date 2018, other income (expense), net was $28 million compared to $4 million for the corresponding period in 2017. The increase was primarily2019 due to the settlement of Mississippi Power's Deepwater Horizon claim recorded in May 2018, partially offset by increases of $3 million and $6 million in the second quarter and year-to-date 2019, respectively, due to higher interest income associated with a new tolling arrangement accounted for as a sales-type lease. See Note (L) to the Condensed Financial Statements 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
|
| | | | | | |
| 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 an 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 "General Litigation Matters – Mississippi"Mississippi Power" herein for additional information.
Income Taxes (Benefit)
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(10) | | (41.7) | | $908 | | 102.6 |
In the third quarter 2018, income taxes were $14 million compared to $24 million for the corresponding period in 2017. This change was primarily due to the reduction in the federal corporate income tax rate as a result of the Tax Reform Legislation, partially offset by higher pre-tax earnings due to lower estimated losses on the Kemper IGCC.
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For year-to-date 2018, income taxes were $23 million compared to an income tax benefit of $885 million for the corresponding period in 2017. This change was primarily due to higher pre-tax earnings due to lower estimated losses on the Kemper IGCC, net of the non-deductible AFUDC equity portion and the related state valuation allowance. This change was partially offset by the reduction in the federal corporate income tax rate as a result of the Tax Reform Legislation.
See Note (H) to the Condensed Financial Statements herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Mississippi Power's future earnings potential. The level of Mississippi Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Mississippi Power's business of providing electric service. These factors include Mississippi Power's ability to recover its prudently-incurred costs in a timely manner during a time of increasing costs and limited projected demand growth over the next several years. Mississippi Power is scheduled to file the 2019 Base Rate Case in the fourth quarter 2019. Another factor is Mississippi Power'sits 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, 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.
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For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Mississippi Power in Item 7 of the Form 10-K.
Environmental Matters
Mississippi 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 associated with these environmental laws and regulations. The costs, including capital expenditures, operations and maintenance costs, and costs reflected in ARO liabilities, required to comply with environmental laws and regulations and to achieve stated goals may impact future unit retirement and replacement decisions, results of operations, cash flows, and financial condition.goals. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to theMississippi Power's transmission system.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 areis expected to be recovered through existing ratemaking provisions.retail and wholesale rates. The ultimate impact of environmental laws and regulations and the GHG goals discussed below 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. 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, 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Laws and Regulations
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Water Quality" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the effluent limitations guidelines (ELG) rule.
On May 2, 2018, the EPA updated its anticipated final rulemaking schedule for ELG from September 2020 to December 2019. The impact of any changes to the ELG rule will depend on the content of the final rule and the outcome of any legal challenges and cannot be determined at this time.
Coal Combustion Residuals
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" ofIn June 2019, Mississippi Power in Item 7recorded an increase of the Form 10-Kapproximately $58 million to its AROs for additional information regarding the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule).
The EPA published certain amendmentshigher expected compliance costs related to the CCR Rule which became effective August 29, 2018. These amendments extend(and the date from April 2019 to October 31, 2020 to cease sending CCR and other waste streams to impoundments that demonstrate compliance with all except two specified criteria. These amendments also establish groundwater protection standards for four constituents that do not have established EPA maximum contaminant levels and allow a participating state director or the EPA (where the EPA is the permitting authority) to suspend groundwater monitoring requirements under certain circumstances. Specific site impacts are being evaluated by Mississippi Power.
On October 15, 2018, the U.S. Courtrelated State of Appeals for the District of Columbia Circuit issued a mandate that broadens the CCR Rule to regulate previously-excluded inactive surface impoundments (legacy units) located at retired generation facilities and challenges both the ability of unlined impoundments to continue operating and the classification of clay lined units. It is anticipated that the EPA will issue a series of rulemakings to address this court action. Mississippi Power is evaluating the extent of potential impacts on legacy units but anticipates no significant impacts to its ongoing CCR strategy due to this mandate. The ultimate impact of these changes will not be known until the EPA rulemaking and any legal challenges are finalized.
During the nine months ended September 30, 2018, Mississippi Power recorded increases of approximately $21 million to its AROs related to the CCR Rule.Alabama rule, as applicable). Approximately $11$49 million of the revised cost estimates as of September 30, 2018 are based on information from feasibility studies performed onassociated with an ash pond at Plant Greene County, which is co-ownedjointly owned with Alabama Power. These studies indicated thatThe additional closureestimated costs primarily related to increases in estimated ash volume, water management requirements, and design revisions, will be required to close thethis ash pond under the planned closure-in-place methodology. As the level of work becomes more definedmethodology primarily relate to cost inputs from contractor bids, internal drainage and dewatering system designs, and an increase in the next 12 months, it is likely that these cost estimates will change and the change could be material.estimated ash volume.
As further analysis is performed and closureadditional details are developed with respect to ash pond closures, Mississippi Power expects to periodically update its ARO cost estimates. See Note (A)Additionally, the closure designs and plans in the State of Alabama are subject to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
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 these mattersthis 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
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Mississippi Power in Item 7 of the Form 10-K for additional information.
On August 31, 2018, the EPA published a proposed Clean Power Plan replacement rule known as the Affordable Clean Energy rule (ACE Rule), which would require states to develop unit-specific emission rate standards based on heat-rate efficiency improvements for existing fossil fuel-fired steam units. As proposed, combustion turbines, including natural gas combined cycles, are not affected sources. As of September 30, 2018, ACE Rule. Mississippi Power has ownership interests in six fossil fuel-fired steamtwo coal-fired units to which the proposed ACE Rule is applicable. The ultimate impact of this rulethe ACE Rule, including the repeal and replacement of the CPP, to Mississippi Power is currently unknown and will depend on changes between the proposalstate implementation plan requirements and the final rule, subsequent state plan developments and requirements, andoutcome of any associated legal proceedings.
Through 2017, the Southern Company system has achieved an estimated GHG emission reduction of 36% since 2007. In April 2018, Southern Company established an intermediate goal of a 50% reduction in carbon emissions from 2007 levels by 2030challenges and a long-term goal of low- to no-carbon operations by 2050. To achieve these goals, the Southern Company system expects to continue growing its renewable energy portfolio, optimize technology advancements to modernize its transmission and distribution systems, increase the use of natural gas for generation, invest in energy efficiency, and continue research and development efforts focused on technologies to lower GHG emissions. The Southern Company system's ability to achieve these goals also will be dependent on many external factors, including supportive national energy policies, low natural gas prices, and the development, deployment, and advancement of relevant energy technologies. The ultimate outcome of this matter cannot be determined at this time.
FERC Matters
Municipal and Rural Association Tariff
See Note 32 to the financial statements of Mississippi Power under "FERC Matters – Municipal and Rural Associations Tariff"Matters" in Item 8 of the Form 10-K for additional information.
Municipal and Rural Association Tariff
On May 7, 2019, the FERC accepted Mississippi Power expects to make anPower's March 28, 2019 request for a decrease in wholesale base revenues under the MRA filingtariff as agreed upon in the fourth quarter 2018. The ultimate outcome of this matter cannot be determined at this time.
Fuel Cost Recovery
Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At September 30, 2018, the amount of over-recovered wholesale MRA fuel costs included in other regulatory liabilities, current on the condensed balance sheet was approximately $7 million compared to an immaterial amount at December 31, 2017. Under-recovered wholesale MB fuel costs included in the balance sheets were immaterial at September 30, 2018 and December 31, 2017.
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 proceedingsSettlement Agreement resolving all matters related to the traditional electric operating companies' (including Mississippi Power's) and Southern Power's 2014 and 2017 triennial market power analyses.
On May 4, 2018,Kemper County energy facility similar to the FERC issued an order terminating both proceedings, finding that the traditional electric operating companies (including Mississippi Power) and Southern Power satisfy the FERC's standards for market-based rates. On May 9, 2018, the traditional electric operating companies (including Mississippi Power) and Southern Power made the compliance filing requiredretail rate settlement agreement approved by the order. These proceedings are concluded.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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Cooperative Energy Power Supply Agreement
See Note 3Mississippi PSC in February 2018 and reflecting the impacts of the Tax Reform Legislation. Pursuant to the financial statements of Mississippi Power under "FERC Matters – Cooperative Energy Power Supply Agreement" in Item 8 of the Form 10-K for additional information regarding Cooperative Energy's network integration transmission service agreement (NITSA) with SCS.
On March 23, 2018, the FERC accepted the amendment to the NITSA between Cooperative Energy and SCS,MRA Settlement Agreement, base rates decreased $3.7 million annually, effective AprilJanuary 1, 2018.2019.
Open Access Transmission Tariff
On May 10, 2018,June 28, 2019, the FERC approved a settlement agreement between Alabama Municipal Electric Authority and Cooperative Energy filed with the FERC a complaint againstand SCS and the traditional electric operating companies (including Mississippi Power) claiming that the current 11.25% baseagreeing to an OATT rate reduction based on a 10.6% ROE, used in calculating the annual transmission revenue requirements of the traditional electric operating companies' (including Mississippi Power's) open access transmission tariff is unjust and unreasonable as measured by the applicable FERC standards. The complaint requests that the base ROE be set no higher than 8.65% and that the FERC order refunds for the difference in revenue requirements that results from applyingwith a just and reasonable ROE established in this proceeding upon determining the current ROE is unjust and unreasonable. On June 18, 2018, SCS and the traditional electric operating companies (including Mississippi Power) filed their response challenging the adequacy of the showing presented by the complainants and offering support for the current ROE. On September 6, 2018, the FERC issued an order establishing a refundretroactive effective date of May 10, 2018, inand a five-year moratorium on these parties seeking changes to the eventOATT formula rate. The terms of the OATT settlement agreement will not have a refund is due and initiating an investigation and settlement procedures regardingmaterial impact on the current base ROE. Through September 30, 2018, the estimated maximum potential refund is not expected to be material tofinancial statements of Mississippi Power's results of operations. The ultimate outcome of this matter cannot be determined at this time.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.
On May 8, 2018, the Mississippi PSC issued an order to begin an operations review of Mississippi Power which beganis scheduled to file a base rate case in August 2018, with the final report expected by February 28,fourth quarter 2019. Mississippi Power expects that the review will include, but not be limited to, a comparative analysis of its costs, its cost recovery framework, and ways in which it may streamline management operations for the reasonable benefit of ratepayers. The ultimate outcome of this matter cannot be determined at this time.
See Note 32 to the financial statements of Mississippi Power under "Retail Regulatory Matters" and "Kemper County Energy Facility""Mississippi Power" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Mississippi Power" herein for additional information.
Performance Evaluation Plan
On February 7, 2018, Mississippi Power submitted its revised 2018 projected PEP filing to the Mississippi PSC, which reflected the impacts of the Tax Reform Legislation, requesting an increase in annual retail revenues of $26 million based on a performance-adjusted ROE of 9.33% and an increased equity ratio of 55%.
On March 22, 2018, Mississippi Power submitted its annual PEP lookback filing for 2017, which reflected no surcharge or refund.
On July 27, 2018, Mississippi Power and the MPUS entered into the PEP Settlement Agreement, which was approved by the Mississippi PSC on August 7, 2018. Rates under the PEP Settlement Agreement became effective with the first billing cycle of September 2018. The PEP Settlement Agreement provides for an increase of
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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approximately $21.6 million in annual base retail revenues, which excludes certain compensation costs contested by the MPUS, as well as approximately $2 million which was subsequently approved for recovery through the 2018 Energy Efficiency Cost Rider as discussed below. Under the PEP Settlement Agreement, Mississippi Power is deferring the contested compensation costs for 2018 and 2019 as a regulatory asset, which totaled $3 million as of September 30, 2018 and is included in other regulatory assets, deferred on the condensed balance sheet. The Mississippi PSC is currently expected to rule on the appropriate treatment for such costs in connection with the 2019 Base Rate Case. The ultimate outcome of this matter cannot be determined at this time.
Pursuant to the PEP Settlement Agreement, Mississippi Power's performance-adjusted allowed ROE is 9.31% and its allowed equity ratio remains at 50%, pending further review by the Mississippi PSC. In lieu of the requested equity ratio increase, Mississippi Power retained $44 million of excess accumulated deferred income taxes resulting from the Tax Reform Legislation, which had been proposed to be amortized beginning in 2018, until the conclusion of the 2019 Base Rate Case. Further, Mississippi Power will seek equity contributions sufficient to restore its equity ratio (which was 45% at September 30, 2018) to 50% by December 31, 2018. In the event Mississippi Power's actual average equity ratio for 2018 is more than 1% higher or lower than the 50% target, Mississippi Power will defer the corresponding difference in its revenue requirement as a regulatory asset or liability for resolution in the 2019 Base Rate Case. As of September 30, 2018, Mississippi Power has recorded $5 million in other regulatory liabilities, deferred on the condensed balance sheet related to the estimated December 31, 2018 average equity ratio differential from target applicable to PEP.
Pursuant to the PEP Settlement Agreement, PEP proceedings are suspended until after the conclusion of the 2019 Base Rate Case and Mississippi Power is not required to make any PEP filings for regulatory years 2018, 2019, and 2020. The PEP Settlement Agreement also resolved all open PEP filings with no change to customer rates. As a result, in the third quarter 2018, Mississippi Power recognized revenues of $5 million previously reserved in connection with the 2012 PEP lookback filing.
Energy Efficiency
On May 8, 2018, the Mississippi PSC issued an order approving Mississippi Power's revised annual projected Energy Efficiency Cost Rider 2018 compliance filing, which increased annual retail revenues by approximately $3 million effective with the first billing cycle for June 2018.
Ad Valorem Tax Adjustment
On May 8, 2018, the Mississippi PSC also approved Mississippi Power's annual ad valorem tax adjustment factor filing for 2018, which included an annual rate increase of 0.8%, or $7 million, in annual retail revenues effective with the first billing cycle for June 2018, primarily due to increased assessments.
Environmental Compliance Overview Plan
On August 3, 2018,July 9, 2019, Mississippi Power and the MPUS entered into the ECO Settlement Agreement, which provides for an increase of approximately $17 million in annual base retail revenues and was approved byfiled a request with the Mississippi PSC on August 7, 2018. Rates under the ECO Settlement Agreement became effectivefor a Certificate of Public Convenience and Necessity to complete certain environmental compliance projects, primarily associated with the first billing cyclePlant Daniel coal units co-owned 50% with Gulf Power. The total estimated cost is approximately $125 million, with Mississippi Power's share of September 2018approximately $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 will continue in effect until modified by the Mississippi PSC. These revenues are expected to be sufficient to recover the costs includedis reflected in Mississippi Power's request for 2018, as well as the remaining deferred amounts that were originally expected to be recovered in 2019. In accordance with the ECO Settlement Agreement, ECO Plan proceedings are suspended until after the conclusion of the 2019 Base Rate Case and Mississippi Power is not required to make any ECO Plan filings for 2018, 2019, and 2020, with any necessary true-ups to be reflected in the 2019 Base Rate Case. The ECO Settlement Agreement contains the same terms as the PEP Settlement Agreement described herein with respect to allowed ROE and equity ratio. As of September 30, 2018, Mississippi Power has recorded $2 million in other regulatory liabilities, deferred on the condensed balance sheet relatedARO liabilities. See Note (A) to the estimated December 31, 2018 average equity ratio differential from target applicableCondensed Financial Statements under "Asset Retirement Obligations" herein for additional information on AROs and Note (C) to the ECO Plan.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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Fuel Cost Recovery
At September 30, 2018, the amount of over-recovered retail fuel costs includedCondensed Financial Statements under "Other Matters – Mississippi Power" herein for additional information on MississippiGulf Power's condensed balance sheetownership in customer accounts receivable was approximately $13 million compared to $6 million under recovered at December 31, 2017.
During the fourth quarter 2018, Mississippi Power expects 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.
Mississippi Power's operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in the billing factor should have no significant effect on Mississippi Power's revenues or net income, but will affect cash flow.Plant Daniel.
Kemper County Energy Facility
For additional information on the Kemper County energy facility, seeSee Note 32 to the financial statements of Mississippiunder "Mississippi Power under "Kemper– Kemper County Energy Facility" in Item 8 of the Form 10-K.10-K for additional information.
As the mining permit holder, for the Kemper County energy facility, Liberty Fuels Company, LLC has a legal obligation to perform mine reclamation, and Mississippi Power has a contractual obligation to fund all reclamation activities. MineAs a result of the abandonment of the Kemper IGCC, final mine reclamation began in the first quarter 2018.2018 and is expected to be substantially completed in 2020,
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with monitoring expected to continue through 2027. See Note 16 to the financial statements of Mississippi Power under "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.
As of September 30, 2018,During the second quarter and year-to-date 2019, Mississippi Power recorded pre-tax charges to income of an immaterial amount for the third quarter 2018 and $45$4 million ($343 million after tax) for year-to-date 2018,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 to costat up to $20$10 million pre-tax (excluding salvage,dismantlement costs, net of dismantlement costs)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 $2$7 million for the remainder of 2018, $8 million in 2019 and $4$2 million to $6 million annually beginning in 2020.2020 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.
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 this matterthese matters cannot be determined at this time.
The combined cycle and associated common facilities portions of the Kemper County energy facility were dedicated as Plant Ratcliffe on April 27, 2018.
Reserve Margin Plan
On August 6, 2018, Mississippi Power filed its proposed RMP, as required by the Mississippi PSC's order in the Kemper Settlement Docket. Under the RMP, Mississippi Power proposes alternatives that would reduce its reserve margin, with the most economic of the alternatives being the two-year and seven-year acceleration of the retirement of Plant Watson Units 4 and 5, respectively, to the first quarter 2022 and the four-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively, in order to lower or avoid operating costs. The Plant Greene County unit retirements would require the completion by Alabama Power of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. The RMP filing also states that, in the event the Mississippi PSC ultimately approves an alternative that includes an accelerated retirement, Mississippi Power would require authorization to defer intime; however, they could have a regulatory asset for future recovery the remaining net book value of the units at the time of retirement. Mississippi Power expects the MPUS and other interested parties to review the proposal prior to resolution by the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time. However, if approved by the Mississippi PSC, the alternatives are not expected to have any adversematerial impact on customer rates.
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 FINANCIAL CONDITION AND LIQUIDITY –
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"Credit Rating Risk," Note (B) to the Condensed Financial Statements under "Regulatory Matters – Mississippi Power," and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation and related regulatory actions.Power's financial statements.
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 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 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.
On May 14, 2018, Mississippi Power's claim for lost revenue resulting from the Deepwater Horizon oil spill in theIn conjunction with Southern Company's sale of Gulf of Mexico in 2010 was settled. The settlement proceeds of $18 million, net of expenses and income tax, are included in Mississippi Power's earnings for the nine months ended September 30, 2018.
To mitigate customer rate impacts associated with rising costs and declining sales, Mississippi Power, management approved an employee attrition plan on July 13, 2018. In the third quarter 2018, Mississippi Power recorded $14 million in expenses related to this plan.
On October 2, 2018, the Mississippi PSC approved the executed agreements between Mississippi Power and its largest retail customer, Chevron, forGulf 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 to continue providing retail service tothat Gulf Power will retire its share of the Chevron refinery in Pascagoula, Mississippi through 2038. The new agreements are not expected to have a material impactgenerating capacity of Plant Daniel on earnings.
Litigation
In 2016, a complaint againstJanuary 15, 2024. 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 refiledhas the option to include, among other things, Southern Company as a defendant. The individual plaintiff allegedpurchase Gulf Power's ownership interest for $1 on January 15, 2024, provided that Mississippi Power and Southern Company violatedexercises the Mississippi Unfair Trade Practices Act. All plaintiffs allegedoption no later than 120 days prior to that date. Mississippi Power is assessing the potential operational and Southern Company concealed, falsely represented, and failedeconomic effects of Gulf Power's notice. The ultimate outcome of these matters remains subject to fully disclose important facts concerning the cost and schedulecompletion of the Kemper County energy facility and that these alleged breaches unjustly enriched Mississippi Power and Southern Company. The plaintiffs sought unspecified actual damages and punitive damages; asked the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper County energy facility; asked the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper County energy facility in Mississippi; and sought attorney's fees, costs, and interest. The plaintiffs also sought an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. In June 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. In July 2017, the plaintiffs filed notice of an appeal. On July 13, 2018, Mississippi Power and Southern Company reached a settlement agreement with the plaintiffs and the plaintiffs' appeal was dismissed with prejudice. The settlement had no material impact on Mississippi Power's financial statements.evaluations and applicable regulatory approvals, including by
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Onthe 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 18, 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 September 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.
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 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 thisthese legal challenge haschallenges have no merit; however, an adverse outcome in this proceedingeither of these proceedings could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity. Mississippi Power will vigorously defend itself in this matter, theThe ultimate outcome of whichthese matters cannot be determined at this 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.
Kemper County Energy Facility Closure Costs
As of September 30, 2018, Mississippi Power recorded charges to income of an immaterial amount for the third quarter 2018 and $45 million ($34 million after tax) for year-to-date 2018, primarily resulting from the abandonment and related closure activities 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 to cost up to $20 million pre-tax (excluding salvage, net of dismantlement costs), 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 $2 million for the remainder of 2018, $8 million in 2019, and $4 million annually beginning in 2020. The ultimate outcome of this matter cannot be determined at this time.
See Notes 1 and 3 to the financial statements of Mississippi Power under "Variable Interest Entities" and "Kemper County Energy Facility," respectively, in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Kemper County Energy Facility" 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 regarding ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). See Note (A) to the Condensed Financial Statements herein for information regarding Mississippi Power's recently adopted accounting standards.
In 2016, the FASB issued ASU No. 2016-02, which 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
Mississippi Power has elected the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby it will apply the requirements of ASU 2016-02 on a prospective basis as of theContents
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
adoption date of January 1, 2019, without restating prior periods. Mississippi Power expects to elect the package of practical expedients provided by ASU 2016-02 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Mississippi Power expects to apply the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and to elect the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed. Mississippi Power also expects to make accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and to combine lease and non-lease components in the computations of lease obligations and right-of-use assets for most asset classes.
Mississippi Power is continuing to complete the implementation of an information technology system to track and account for its leases and of changes to its internal controls and accounting policies to support the accounting for leases under ASU 2016-02. Mississippi Power has substantially completed its lease inventory and determined its most significant leases involve equipment and railcar leases. While Mississippi Power has not yet determined the ultimate impact, adoption of ASU 2016-02 is not expected to have a material impact on Mississippi Power's balance sheet or statement of income.
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 for additional information.
Mississippi Power's cash requirements primarily consist of funding ongoing operations, common stock dividends, capital expenditures, and debt maturities. Capital expenditures and other investing activities include investments to maintain existing generation facilities, to comply 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, and for restoration following major storms.
In March 2018, Mississippi Power issued $300 million aggregate principal amount of Series 2018A Floating Rate Senior Notes due March 27, 2020 bearing interest based on three-month LIBOR and $300 million aggregate principal amount of Series 2018B 3.95% Senior Notes due March 30, 2028. In March 2018, Mississippi Power also entered into a $300 million short-term floating rate bank loan bearing interest based on one-month LIBOR, of which $200 million was repaid in the second quarter 2018 and $100 million was repaid in the third quarter 2018. Mississippi Power used the proceeds from these financings to repay a $900 million unsecured term loan.
Net cash provided from operating activities totaled $656$60 million for the first ninesix months of 2018, an increase2019, a decrease of $295$237 million as compared to the corresponding period in 2017.2018. The increasedecrease in net cash provided from operating activities is primarily related to increasedlower income tax refunds in 2018 primarily related to the tax abandonment of the Kemper IGCC, partially offset by an increase inand ad valorem taxestax payments and the timing of collections of receivables. Net cash used for investing activities totaled $170$128 million for the first ninesix months of 20182019 primarily due to gross property additions related to steam production, distribution and transmission.transmission facilities. Net cash used for financing activities totaled $355$26 million for the first ninesix months of 20182019 primarily due to redemptionsa return of long-term debt and short-term borrowings,capital to Southern Company, partially offset by $43 million of pollution control revenue bonds reoffered to the issuance of senior notes and short-term borrowings.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 20182019 include increasesa decrease of $435$221 million in long-term debt, primarily due to the issuancereclassification of $300 million in unsecured senior notes to securities due within one year, partially offset by $43 million in securities reoffered to the public and $131$40 million in variable rate revenue bonds reclassified from securities due within one year. Other significant changes include a decrease of $100 million in plant in service and an increase of $100 million in other property and investments primarily due to a new tolling arrangement, effective January 1, 2019, accounted for as a sales-type lease; a decrease of $94 million in cash and cash equivalents primarily due to tax refunds,equivalents; and a net changedecrease of $440$43 million in accumulated deferred incomeaccrued taxes primarily due to the tax abandonmentpayment of the Kemper IGCC, and a decrease of $785 million in securities due within one year duead valorem taxes. See Note (L) to the repayment of a $900 million unsecured term loan.Condensed Financial Statements herein for additional information.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Mississippi Power in Item 7 of the Form 10-K for a
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
description of Mississippi Power's capital requirements and contractual obligations. Subsequent to September 30, 2018, Mississippi Power completed the redemption of $30Approximately $300 million aggregate principal amount of its Series G 5.40% Senior Notes due July 1, 2035 and $125 million aggregate principal amount of its Series 2009A 5.55% Senior Notes due March 1, 2019. There are no additional scheduled maturities or announced redemptions of long-term debt through September 30, 2019. Approximately $50 million of revenue bonds will be required through June 30, 2020 to be remarketed over the next 12 months.fund maturities of long-term debt. See "Sources of Capital" herein for additional information.
Mississippi Power's purchase commitments related to LTSAs have changed to approximately $43 million for 2018, $28 million for 2019, $28 million for 2020, $29 million for 2021, $49 million for 2022, and $257 million for 2023 and thereafter due to an increase in estimated expenditures covered under the LTSA for the Kemper County energy facility.
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 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 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, lines of credit, bank term loans, external securitysecurities issuances, borrowings from financial institutions, including commercial paper (toto the extent itMississippi Power is eligible to participate), monetization of income tax deductions associated with the abandonment of the gasifier portion of the Kemper County energy facility,participate, and equity contributions 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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
LIQUIDITY – "Capital Requirements and Contractual Obligations" in Item 7 of the Form 10-K for additional information.
As of June 30, 2019, Mississippi Power's current liabilities sometimes exceedexceeded current assets becauseby approximately $103 million primarily as a result of $300 million 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.that is due within one year.
At SeptemberJune 30, 2018,2019, Mississippi Power had approximately $379$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, 2018 were as follows:2019, all of which was unused.
|
| | | | | | | | | | | | | | | | | | | | | | |
| Expires | | | | Executable Term Loans | | Expires Within One Year |
| 2019 | | Total | | Unused | | One Year | | Term Out | | No Term Out |
| (in millions) |
| $ | 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 (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
All of these bank credit arrangements 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, 2018,2019, 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.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 variable rate revenue bonds. The amount of variable rate revenue bonds outstanding requiring liquidity support as of SeptemberJune 30, 20182019 was approximately $40 million. In addition,
Short-term debt, including the average amount and maximum amount outstanding, was immaterial at SeptemberJune 30, 2018, 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 revenue bonds outstanding that were requiredcredit, short-term bank notes, commercial paper to be remarketed within the next 12 months.extent Mississippi Power is eligible to participate, operating cash flows, and other cash.
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) |
| Short-term bank debt | | $ | 50 |
| | 3.3 | % | | $ | 100 |
|
| |
(*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2018. No short-term debt was outstanding at September 30, 2018. |
Credit Rating Risk
At September 30, 2018,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 2, 2018, the Mississippi PSC approved the executed agreements between Mississippi Power and its largest retail customer, Chevron, for Mississippi Power 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, with a net book value of approximately $93 million, 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, 2018,2019, the maximum potential collateral requirements at a rating below BBB- and/or Baa3 equaled approximately $202$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 February 26, 2018, Moody's revised its rating outlook for Mississippi Power from stable to positive. On August 8, 2018, Moody's upgraded Mississippi Power's senior unsecured rating to Baa3 from Ba1 and maintained the positive rating outlook.
On February 28, 2018, Fitch removed Mississippi Power from rating watch negative and revised its rating outlook from stable to positive.110
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
On March 14, 2018, S&P upgraded the senior unsecured long-term debt rating of Mississippi Power to A- from BBB+. The outlook remained negative.
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 Settlement Agreementfilings 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. In addition, Mississippi Power has committed to seek equity contributions sufficient to restore its equity ratio to the 50% target. See Note 32 to the financial statements of Mississippi Power under "Retail Regulatory Matters""Mississippi Power" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Mississippi Power" herein for additional information.
Financing Activities
In March 2018,2019, Mississippi Power issued $300 million aggregate principal amount of Series 2018A Floating Rate Senior Notes due March 27, 2020 bearing interest based on three-month LIBOR and $300 million aggregate principal amount of Series 2018B 3.95% Senior Notes due March 30, 2028. In March 2018, Mississippi Power also entered into a $300 million short-term floating rate bank loan bearing interest based on one-month LIBOR, of which $200 million was repaid inreoffered to the second quarter 2018 and $100 million was repaid in the third quarter 2018. Mississippi Power used the proceeds from these financings to repay a $900 million unsecured term loan.
In July 2018, Mississippi Power purchased and held approximatelypublic $43 million aggregate principal amount of Mississippi Business Finance Corporation Pollution Control Revenue Refunding Bonds, Series 2002.2002, which previously had been purchased and held by Mississippi Power may reoffer these bonds to the public at a later date.
Subsequent to September 30, 2018, Mississippi Power completed the redemption of all 334,210 outstanding shares of its preferred stock (as well as related depositary shares), with an aggregate par value of approximately $33.4 million; all $30 million aggregate principal amount outstanding of its Series G 5.40% Senior Notes due July 1, 2035; and all $125 million aggregate principal amount outstanding of its Series 2009A 5.55% Senior Notes due March 1, 2019.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, |
| | 2018 | | 2017 | | 2018 | | 2017 | 2019 | | 2018 | | 2019 | | 2018 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | | | | | | | | |
| Wholesale revenues, non-affiliates | $ | 496 |
| | $ | 510 |
| | $ | 1,363 |
| | $ | 1,293 |
| $ | 390 |
| | $ | 443 |
| | $ | 743 |
| | $ | 867 |
|
| Wholesale revenues, affiliates | 134 |
| | 105 |
| | 326 |
| | 295 |
| 117 |
| | 109 |
| | 204 |
| | 192 |
|
| Other revenues | 5 |
| | 3 |
| | 10 |
| | 9 |
| 3 |
| | 3 |
| | 6 |
| | 5 |
|
| Total operating revenues | 635 |
| | 618 |
| | 1,699 |
| | 1,597 |
| 510 |
| | 555 |
| | 953 |
| | 1,064 |
|
| Operating Expenses: | | | | | | | | | | | | | | |
| Fuel | 190 |
| | 189 |
| | 511 |
| | 460 |
| 139 |
| | 153 |
| | 284 |
| | 321 |
|
| Purchased power | 37 |
| | 43 |
| | 137 |
| | 113 |
| 32 |
| | 39 |
| | 55 |
| | 100 |
|
| Other operations and maintenance | 94 |
| | 83 |
| | 278 |
| | 272 |
| 79 |
| | 91 |
| | 166 |
| | 184 |
|
| Depreciation and amortization | 130 |
| | 131 |
| | 370 |
| | 379 |
| 119 |
| | 125 |
| | 237 |
| | 240 |
|
| Taxes other than income taxes | 12 |
| | 13 |
| | 36 |
| | 37 |
| 11 |
| | 12 |
| | 21 |
| | 24 |
|
| Asset impairment | 36 |
| | — |
| | 155 |
| | — |
| — |
| | 119 |
| | — |
| | 119 |
|
| Gain on dispositions, net | | (23 | ) | | — |
| | (23 | ) | | — |
|
| Total operating expenses | 499 |
|
| 459 |
| | 1,487 |
| | 1,261 |
| 357 |
| | 539 |
| | 740 |
| | 988 |
|
| Operating Income | 136 |
| | 159 |
| | 212 |
| | 336 |
| 153 |
| | 16 |
| | 213 |
| | 76 |
|
| Other Income and (Expense): | | | | | | | | | | | | | | |
| Interest expense, net of amounts capitalized | (45 | ) | | (47 | ) | | (138 | ) | | (144 | ) | (41 | ) | | (46 | ) | | (84 | ) | | (93 | ) |
| Other income (expense), net | 17 |
| | 3 |
| | 22 |
| | 3 |
| 40 |
| | 2 |
| | 41 |
| | 5 |
|
| Total other income and (expense) | (28 | ) | | (44 | ) | | (116 | ) | | (141 | ) | (1 | ) | | (44 | ) | | (43 | ) | | (88 | ) |
| Earnings Before Income Taxes | 108 |
| | 115 |
| | 96 |
| | 195 |
| |
| Earnings (Loss) Before Income Taxes | | 152 |
| | (28 | ) | | 170 |
| | (12 | ) |
| Income taxes (benefit) | (38 | ) | | (39 | ) | | (210 | ) | | (129 | ) | (51 | ) | | (73 | ) | | (60 | ) | | (172 | ) |
| Net Income | 146 |
| | 154 |
| | 306 |
| | 324 |
| 203 |
| | 45 |
| | 230 |
| | 160 |
|
| Net income attributable to noncontrolling interests | 54 |
| | 30 |
| | 71 |
| | 48 |
| 29 |
| | 23 |
| | — |
| | 17 |
|
| Net Income Attributable to Southern Power | $ | 92 |
| | $ | 124 |
| | $ | 235 |
| | $ | 276 |
| $ | 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, |
| | 2018 | | 2017 | | 2018 | | 2017 |
| | (in millions) | | (in millions) |
| Net Income | $ | 146 |
| | $ | 154 |
| | $ | 306 |
| | $ | 324 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
Changes in fair value, net of tax of
$(4), $15, $(7), and $35, respectively | (11 | ) | | 25 |
| | (19 | ) | | 58 |
|
Reclassification adjustment for amounts included in net income,
net of tax of $4, $(12), $16, and $(42), respectively | 11 |
| | (20 | ) | | 46 |
| | (68 | ) |
| 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 |
| | 28 |
| | (10 | ) |
| Comprehensive Income | 146 |
| | 159 |
| | 334 |
| | 314 |
|
| Comprehensive income attributable to noncontrolling interests | 54 |
| | 30 |
| | 71 |
| | 48 |
|
| Comprehensive Income Attributable to Southern Power | $ | 92 |
| | $ | 129 |
| | $ | 263 |
| | $ | 266 |
|
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, |
| | 2018 | | 2017 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 306 |
| | $ | 324 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 394 |
| | 404 |
|
| Deferred income taxes | (337 | ) | | 240 |
|
| Amortization of investment tax credits | (43 | ) | | (42 | ) |
| Income taxes receivable, non-current | (12 | ) | | (42 | ) |
| Asset impairment | 155 |
| | — |
|
| Other, net | 10 |
| | (4 | ) |
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (41 | ) | | (77 | ) |
| -Prepaid income taxes | 5 |
| | 24 |
|
| -Other current assets | 1 |
| | 14 |
|
| -Accounts payable | (27 | ) | | (31 | ) |
| -Accrued taxes | 256 |
| | 79 |
|
| -Other current liabilities | (1 | ) | | 5 |
|
| Net cash provided from operating activities | 666 |
| | 894 |
|
| Investing Activities: | | | |
| Business acquisitions | (64 | ) | | (1,016 | ) |
| Property additions | (226 | ) | | (218 | ) |
| Change in construction payables | 3 |
| | (166 | ) |
| Payments pursuant to LTSAs | (57 | ) | | (99 | ) |
| Other investing activities | 20 |
| | 7 |
|
| Net cash used for investing activities | (324 | ) | | (1,492 | ) |
| Financing Activities: | | | |
| Decrease in notes payable, net | (68 | ) | | (89 | ) |
| Proceeds — | | | |
| Short-term borrowings | 200 |
| | — |
|
| Other long-term debt | — |
| | 43 |
|
| Redemptions — | | | |
| Senior notes | (350 | ) | | — |
|
| Other long-term debt | (420 | ) | | (4 | ) |
| Return of capital | (650 | ) | | — |
|
| Distributions to noncontrolling interests | (86 | ) | | (89 | ) |
| Capital contributions from noncontrolling interests | 1,333 |
| | 79 |
|
| Payment of common stock dividends | (234 | ) | | (238 | ) |
| Other financing activities | (15 | ) | | (27 | ) |
| Net cash used for financing activities | (290 | ) | | (325 | ) |
| Net Change in Cash, Cash Equivalents, and Restricted Cash | 52 |
| | (923 | ) |
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 140 |
| | 1,112 |
|
| Cash, Cash Equivalents, and Restricted Cash at End of Period | $ | 192 |
| | $ | 189 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
| Interest (net of $14 and $7 capitalized for 2018 and 2017, respectively) | $ | 138 |
| | $ | 144 |
|
| Income taxes, net | (102 | ) | | (343 | ) |
| Noncash transactions — Accrued property additions at end of period | 37 |
| | 16 |
|
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, 2018 | | At December 31, 2017 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 192 |
| | $ | 129 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 150 |
| | 117 |
|
| Affiliated | | 71 |
| | 50 |
|
| Other | | 62 |
| | 98 |
|
| Materials and supplies | | 214 |
| | 278 |
|
| Prepaid income taxes | | 44 |
| | 50 |
|
| Assets held for sale, current | | 18 |
| | 1 |
|
| Other current assets | | 29 |
| | 35 |
|
| Total current assets | | 780 |
| | 758 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 13,603 |
| | 13,755 |
|
| Less: Accumulated provision for depreciation | | 2,087 |
| | 1,910 |
|
| Plant in service, net of depreciation | | 11,516 |
| | 11,845 |
|
| Construction work in progress | | 586 |
| | 511 |
|
| Total property, plant, and equipment | | 12,102 |
| | 12,356 |
|
| Other Property and Investments: | | | | |
Intangible assets, net of amortization of $66 and $47
at September 30, 2018 and December 31, 2017, respectively | | 391 |
| | 411 |
|
| Total other property and investments | | 391 |
| | 411 |
|
| Deferred Charges and Other Assets: | | | | |
| Prepaid LTSAs | | 106 |
| | 118 |
|
| Accumulated deferred income taxes | | 1,281 |
| | 925 |
|
| Income taxes receivable, non-current | | 84 |
| | 72 |
|
| Assets held for sale | | 185 |
| | — |
|
| Other deferred charges and assets | | 426 |
| | 566 |
|
| Total deferred charges and other assets | | 2,082 |
| | 1,681 |
|
| Total Assets | | $ | 15,355 |
| | $ | 15,206 |
|
|
| | | | | | | | | | | | | | | |
| | For the Three Months
Ended June 30, | | For the Six Months
Ended June 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
| | (in millions) | | (in millions) |
| Net Income | $ | 203 |
| | $ | 45 |
| | $ | 230 |
| | $ | 160 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
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) | (8 | ) | | 4 |
| | (13 | ) | | 28 |
|
| Comprehensive Income | 195 |
| | 49 |
| | 217 |
| | 188 |
|
| Comprehensive income attributable to noncontrolling interests | 29 |
| | 23 |
| | — |
| | 17 |
|
| Comprehensive Income Attributable to Southern Power | $ | 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 BALANCE SHEETSSTATEMENTS OF CASH FLOWS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholders' Equity | | At September 30, 2018 | | At December 31, 2017 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | — |
| | $ | 770 |
|
| Notes payable | | 237 |
| | 105 |
|
| Accounts payable — | | | | |
| Affiliated | | 86 |
| | 102 |
|
| Other | | 88 |
| | 103 |
|
| Accrued income taxes | | 233 |
| | — |
|
| Liabilities held for sale, current | | 4 |
| | — |
|
| Other current liabilities | | 165 |
| | 152 |
|
| Total current liabilities | | 813 |
| | 1,232 |
|
| Long-term Debt | | 5,029 |
| | 5,071 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 111 |
| | 199 |
|
| Accumulated deferred ITCs | | 1,842 |
| | 1,884 |
|
| Other deferred credits and liabilities | | 259 |
| | 322 |
|
| Total deferred credits and other liabilities | | 2,212 |
| | 2,405 |
|
| Total Liabilities | | 8,054 |
| | 8,708 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, par value $0.01 per share — | | | | |
| Authorized — 1,000,000 shares | | | | |
| Outstanding — 1,000 shares | | — |
| | — |
|
| Paid-in capital | | 2,604 |
| | 3,662 |
|
| Retained earnings | | 1,478 |
| | 1,478 |
|
| Accumulated other comprehensive income (loss) | | 31 |
| | (2 | ) |
| Total common stockholder's equity | | 4,113 |
| | 5,138 |
|
| Noncontrolling interests | | 3,188 |
| | 1,360 |
|
| Total stockholders' equity | | 7,301 |
| | 6,498 |
|
| Total Liabilities and Stockholders' Equity | | $ | 15,355 |
| | $ | 15,206 |
|
|
| | | | | | | |
| | For the Six Months
Ended June 30, |
| | 2019 | | 2018 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 230 |
| | $ | 160 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 251 |
| | 256 |
|
| Deferred income taxes | (63 | ) | | (252 | ) |
| Amortization of investment tax credits | (122 | ) | | (29 | ) |
| Asset impairment | — |
| | 119 |
|
| Other, net | (69 | ) | | (10 | ) |
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (9 | ) | | (30 | ) |
| -Prepaid income taxes | 520 |
| | (36 | ) |
| -Other current assets | 4 |
| | 3 |
|
| -Accounts payable | (17 | ) | | (41 | ) |
| -Accrued compensation | (9 | ) | | (9 | ) |
| -Other current liabilities | 3 |
| | (4 | ) |
| Net cash provided from operating activities | 719 |
| | 127 |
|
| Investing Activities: | | | |
| Business acquisitions | (2 | ) | | (64 | ) |
| Property additions | (123 | ) | | (198 | ) |
| Proceeds from dispositions and asset sales | 540 |
| | — |
|
| Change in construction payables | (23 | ) | | 2 |
|
| Investment in unconsolidated subsidiaries | (116 | ) | | — |
|
| Payments pursuant to LTSAs | (31 | ) | | (32 | ) |
| Other investing activities | 9 |
| | 15 |
|
| Net cash provided from (used for) investing activities | 254 |
| | (277 | ) |
| Financing Activities: | | | |
| 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 | — |
| | (350 | ) |
| Other long-term debt | — |
| | (420 | ) |
| Return of capital | (505 | ) | | (250 | ) |
| Distributions to noncontrolling interests | (82 | ) | | (42 | ) |
| Capital contributions from noncontrolling interests | 5 |
| | 1,210 |
|
| Payment of common stock dividends | (103 | ) | | (156 | ) |
| Other financing activities | (5 | ) | | (15 | ) |
| Net cash provided from (used for) financing activities | (784 | ) | | 152 |
|
| 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 $10 capitalized for 2019 and 2018, respectively) | $ | 106 |
| | $ | 109 |
|
| Income taxes, net | (421 | ) | | 109 |
|
| Noncash transactions — Accrued property additions at end of period | 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 June 30, 2019 | | At December 31, 2018 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 370 |
| | $ | 181 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 153 |
| | 111 |
|
| Affiliated | | 49 |
| | 55 |
|
| Other | | 59 |
| | 116 |
|
| Materials and supplies | | 185 |
| | 220 |
|
| Prepaid income taxes | | 489 |
| | 25 |
|
| Other current assets | | 33 |
| | 37 |
|
| Total current assets | | 1,338 |
| | 745 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 12,862 |
| | 13,271 |
|
| Less: Accumulated provision for depreciation | | 2,255 |
| | 2,171 |
|
| Plant in service, net of depreciation | | 10,607 |
| | 11,100 |
|
| Construction work in progress | | 419 |
| | 430 |
|
| Total property, plant, and equipment | | 11,026 |
| | 11,530 |
|
| Other Property and Investments: | | | | |
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 | | 457 |
| | 345 |
|
| Deferred Charges and Other Assets: | | | | |
| Operating lease right-of-use assets, net of amortization | | 370 |
| | — |
|
| Prepaid LTSAs | | 107 |
| | 98 |
|
| Accumulated deferred income taxes | | 296 |
| | 1,186 |
|
| Income taxes receivable, non-current | | 36 |
| | 30 |
|
| Assets held for sale | | 599 |
| | 576 |
|
| Other deferred charges and assets | | 289 |
| | 373 |
|
| Total deferred charges and other assets | | 1,697 |
| | 2,263 |
|
| Total Assets | | $ | 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 June 30, 2019 | | At December 31, 2018 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 899 |
| | $ | 599 |
|
| Notes payable | | — |
| | 100 |
|
| Accounts payable — | | | | |
| Affiliated | | 72 |
| | 92 |
|
| Other | | 60 |
| | 77 |
|
| Accrued income taxes | | 23 |
| | 6 |
|
| Accrued interest | | 23 |
| | 36 |
|
| Liabilities held for sale | | 10 |
| | 15 |
|
| Other current liabilities | | 116 |
| | 106 |
|
| Total current liabilities | | 1,203 |
| | 1,031 |
|
| Long-term Debt | | 4,112 |
| | 4,418 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 106 |
| | 105 |
|
| Accumulated deferred ITCs | | 1,737 |
| | 1,832 |
|
| Operating lease obligations | | 373 |
| | — |
|
| Other deferred credits and liabilities | | 169 |
| | 213 |
|
| Total deferred credits and other liabilities | | 2,385 |
| | 2,150 |
|
| Total Liabilities | | 7,700 |
| | 7,599 |
|
Total Stockholders' Equity (See accompanying statements) | | 6,818 |
| | 7,284 |
|
| Total Liabilities and Stockholders' Equity | | $ | 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 2019 vs. SECOND QUARTER 2018 vs. THIRD QUARTER 2017
AND
YEAR-TO-DATE 20182019 vs. YEAR-TO-DATE 20172018
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 partnership interests, development and construction of new generating facilities, and entry into PPAs primarily with investor-owned utilities, independent power producers, municipalities, electric cooperatives, and other load-serving entities, as well as commercial and industrial customers. In general, Southern Power has committedcommits to the construction or acquisition of new generating capacity only after entering into or assuming long-term PPAs for the new facilities.
In May 2018,On June 13, 2019, Southern Power completed the sale of a 33%its equity interestinterests in SPSH, a limited partnership indirectly owning substantially allNacogdoches Power, LLC, the owner of Southern Power's solar facilities,an approximately 115-MW biomass facility located in Nacogdoches County, Texas, to Austin Energy, for an aggregate cash purchase price of approximately $1.2 billion. In addition,$461 million, including working capital adjustments.
On June 14, 2019, Southern Power entered into an agreement with Bloom Energy to sell allacquire 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 its equity interests in Plant Oleander and Plant Stanton Unit A (together, the Florida Plants), for an aggregate purchase pricetransfer of $195 million. The salethe facilities is expected to occur in the firstthird quarter 2019. 2019; however, the ultimate outcome of this matter cannot be determined at this time.
On October 31, 2018,May 4, 2019, Southern Power entered into agreementsachieved commercial operation of the 385-MW natural gas expansion unit at Plant Mankato and started providing energy under a PPA with three financial investors for theNorthern States Power on June 1, 2019. The sale of a noncontrolling interest for approximately $1.2 billion in tax equity in SP Wind, which owns a portfolio of eight operating wind facilities. The transaction isPlant Mankato to Northern States Power remains subject to Public Utility Commission of Texas approval and is expected to close by the end of 2018. On November 5, 2018, Southern Power entered into an agreement to sell all of its equity interests in Plant Mankato (including the 385-MW expansion currently under construction) for an aggregate purchase price of $650 million. The transaction is subject to the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act (HSR Act) and FERC and state commission approvals and is expected to close mid-2019. See FUTURE EARNINGS POTENTIAL and Note (J)in fall 2019. If these state commission approvals are not obtained by October 1, 2019, either party has the option to terminate the Condensed Financial Statements under "Southern Power" herein for additional information.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 these mattersthis matter cannot be determined at this time.
During the ninesix months ended SeptemberJune 30, 2018,2019, Southern Power acquired and placed in service the 20-MW Gaskell West 1 solar facility, placed in service the 148-MW Cactus Flats wind facility, acquired and begancontinued construction of the 100-MW Wild HorseWildhorse Mountain and the 200-MW Reading wind facilities, and continued construction of the expansion of the 385-MW Mankato natural gas facility.facilities. See FUTURE EARNINGS POTENTIAL –"Acquisitions" and "Construction Projects" herein for additional information.
At SeptemberJune 30, 2018,2019, Southern Power's average investment coverage ratio for its generating assets (including the Florida and Mankato Plants)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 discussed herein)construction) as the investment amount, was 93% through 20222023 and 91% through 2027,2028, with an average remaining contract duration of approximately 15 years. See FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" herein for additional information.
See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for information regarding Southern Power's revised capital expenditure forecasts for 2018 through 2022.
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.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
Net Income Attributable to Southern Power
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(32) | | (25.8) | | $(41) | | (14.9) |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $152 | | N/M | | $87 | | 60.8 |
N/M - Not meaningful
Net income attributable to Southern Power for the thirdsecond quarter 20182019 was $92$174 million compared to $124$22 million for the corresponding period in 2017.2018. The decrease wasincrease is primarily due to a $36 millionnet 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 ($27in 2018 and gains on sale, partially offset by decreases in 2019 operating income primarily from PPA capacity revenues) totaling approximately $168 million after tax) on wind turbine equipment held for development projects and $23net income increases totaling $22 million from a reduction in income tax benefits primarily from ITCs relatedlitigation settlement relating to the Roserock solar facilities placed in service,facility and sales of wind equipment. The increases were partially offset by $11reductions in net income of approximately $22 million, net, related to the SP Wind tax equity partnership entered into in state income tax benefits arising from the reorganization of legal entities that own and operate certain of Southern Power's wind facilities.2018.
Net income attributable to Southern Power for year-to-date 20182019 was $235$230 million compared to $276$143 million for the corresponding period in 2017.2018. The decrease wasincrease is primarily due to a $119 million asset impairment charge as a result ofnet impacts from the pending saledispositions of the Florida Plants in the second quarter 2018 and a $36 millionPlant Nacogdoches in 2019 (including an asset impairment charge in 2018 and gains on wind turbine equipment held for development projects (together $116sale, partially offset by decreases in 2019 operating income primarily from PPA capacity revenues) totaling approximately $162 million after tax) and $25net income increases totaling $23 million from a reduction in income tax benefits primarily from ITCs relatedlitigation settlement relating to the Roserock solar facilities placed in service,facility and sales of wind equipment. The increases were partially offset by approximately $65$54 million in state income tax benefits recorded in 2018 arising from reorganizationsthe reorganization of Southern Power's legal entities that own and operate certain solar facilities and reductions in net income of Southern Power'sapproximately $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 8 of the Form 10-K for additional information on the tax equity partnerships, the legal entity reorganization, and 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 Note (K) to the Condensed Financial Statements herein for additional information on the disposition of Plant Nacogdoches and sales of wind facilities.equipment.
Operating Revenues
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $17 | | 2.8 | | $102 | | 6.4 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(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 from Southern Power's generation 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.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 2018 | | Third Quarter 2017 | | Year-to-Date 2018 | | Year-to-Date 2017 | Second Quarter 2019 | | Second Quarter 2018 | | Year-to-Date 2019 | | Year-to-Date 2018 |
| | (in millions) | (in millions) |
| PPA capacity revenues | $ | 168 |
| | $ | 169 |
| | $ | 450 |
| | $ | 466 |
| $ | 125 |
| | $ | 144 |
| | $ | 252 |
| | $ | 282 |
|
| PPA energy revenues | 336 |
| | 299 |
| | 892 |
| | 765 |
| 291 |
| | 302 |
| | 518 |
| | 556 |
|
| Total PPA revenues | 504 |
| | 468 |
| | 1,342 |
| | 1,231 |
| 416 |
| | 446 |
| | 770 |
| | 838 |
|
| Non-PPA revenues | 126 |
| | 147 |
| | 347 |
| | 357 |
| 91 |
| | 106 |
| | 177 |
| | 221 |
|
| Other revenues | 5 |
| | 3 |
| | 10 |
| | 9 |
| 3 |
| | 3 |
| | 6 |
| | 5 |
|
| Total operating revenues | $ | 635 |
| | $ | 618 |
| | $ | 1,699 |
| | $ | 1,597 |
| $ | 510 |
| | $ | 555 |
| | $ | 953 |
| | $ | 1,064 |
|
In the thirdsecond quarter 2018,2019, total operating revenues were $635$510 million, reflecting a $17$45 million, or 3%8%, increasedecrease from the corresponding period in 2017.2018. The increase in operating revenues was primarily due to the following:
PPA energy revenues increased $37 million, or 12%, primarily due to increases of $20 million from new natural gas PPAs from existing facilities, $9 million from renewable facilities primarily due to an increase in the volume of KWHs sold, and $8 million in fuel costs that are contractually recovered through existing PPAs.
Non-PPA revenues decreased $21 million, or 14%, primarily due to the volume of KWHs sold from uncovered natural gas capacity through short-term sales.
For year-to-date 2018, total operating revenues were $1.7 billion, reflecting an $102 million, or 6%, increase from the corresponding period in 2017. The increasedecrease in operating revenues was primarily due to the following:
PPA capacity revenues decreased $16$19 million, or 3%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.PPA, partially offset by a $6 million increase in new PPA capacity revenues from existing gas facilities.
PPA energy revenues increased $127decreased $11 million, or 17%4%, primarily due to increasesa $7 million decrease related to a decrease in the average cost of $56fuel and purchased power and a $4 million from new natural gas PPAs from existing facilities, $45 milliondecrease in fuel costs that are contractually recovered through existing PPAs,sales related to solar and $27 million from renewablewind facilities primarily due to an increasedriven by a decrease in the volume of KWHs sold.generated.
Non-PPA revenues decreased $10$15 million, or 3%14%, primarily due to a $16 million decrease in the volume of KWHs sold from uncovered natural gas capacity through short-term sales.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2019, total operating revenues were $953 million, reflecting a $111 million, or 10%, decrease from the corresponding period in 2018. The decrease in operating revenues was primarily due to the following:
PPA capacity revenues decreased $30 million, or 11%, primarily due to decreases of $38 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 an $11 million increase in new PPA capacity revenues from existing natural gas facilities.
PPA energy revenues decreased $38 million, or 7%, primarily due to a $30 million decrease in sales from natural gas facilities, primarily driven by a $51 million decrease in the average cost of fuel and purchased power, partially offset by a $23 million increase in the volume of KWHs sold due to increased customer load, and an $8 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 $44 million, or 20%, due to a $36 million decrease in the volume of KWHs sold through short-term sales and an $8 million decrease in the market price of energy.
Fuel and Purchased Power Expenses
Fuel costs constitute the largest expense for Southern Power. In addition, Southern Power purchases a portion of its electricity needs from the wholesale market including the power pool. Details of Southern Power's generation and purchased power were as follows:
| | | | Third Quarter 2018 | Third Quarter 2017 | | Year-to-Date 2018 | Year-to-Date 2017 | Second Quarter 2019 | Second Quarter 2018 | | Year-to-Date 2019 | Year-to-Date 2018 |
| | (in billions of KWHs) | (in billions of KWHs) |
| Generation | 13.3 | 12.5 | | 35.3 | 33.2 | 11.7 | 12.2 | | 21.9 | 22.0 |
| Purchased power | 0.9 | 1.2 | | 3.1 | 3.4 | 1.0 | 1.2 | | 1.8 | 2.2 |
| Total generation and purchased power | 14.2 | 13.7 | | 38.4 | 36.6 | 12.7 | 13.4 | | 23.7 | 24.2 |
| | | |
| Total generation and purchased power, excluding solar, wind, and tolling agreements | 8.2 | 7.2 | | 22.2 | 17.8 | 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.
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 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 | 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 | $ | 1 |
| | 0.5 | | $ | 51 |
| | 11.1 | $ | (14 | ) | | (9.2) | | $ | (37 | ) | | (11.5) |
| Purchased power | (6 | ) | | (14.0) | | 24 |
| | 21.2 | (7 | ) | | (17.9) | | (45 | ) | | (45.0) |
| Total fuel and purchased power expenses | $ | (5 | ) | | $ | 75 |
| | $ | (21 | ) | | $ | (82 | ) | |
In the third quarter 2018, total fuel and purchased power expenses decreased $5 million, or 2%, compared to the corresponding period in 2017. Fuel expense increased $1 million primarily due to a $43 million increase in the volume
For year-to-date 2018, total fuel and purchased power expenses increased $75 million, or 13%, compared to the corresponding period in 2017. Fuel expense increased $51 million primarily due to a $152 million increase in the volume of KWHs generated, excluding solar, wind, and tolling agreements, partially offset by a $101 million decrease in the average cost of natural gas per KWH generated. Purchased power expense increased $24 million primarily due to a $33 million increase in the average cost of purchased power primarily in first quarter 2018, partially offset by a $9 million decrease in the volume of KWHs purchased.Contents
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In the second quarter 2019, total fuel and purchased 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
|
| | | | | | |
| 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 second quarter 2019, other operations and maintenance expenses were $79 million compared to $91 million for the corresponding period in 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 2019, other operations and maintenance expenses were $166 million compared to $184 million for the corresponding period in 2018. The decrease was primarily due to a $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 facility litigation settlement.
Asset Impairment
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $36 | | N/M | | $155 | | N/M |
N/M - Not meaningful
In the second quarter 2018, a $119 million asset impairment charge was recorded in contemplationanticipation of the sale of the Florida Plants. In addition, in the third quarter 2018, a $36 million asset impairment charge was recorded on wind turbine equipment held for development projects. See Note (J)15 to the financial statements in Item 8 of the Form 10-K under "Southern Power – Sale of FloridaNatural Gas Plants" and " – Development Projects"for additional information.
Gain on Dispositions, net
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 Income (Expense), Netnet
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $14 | | N/M | | $19 | | 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) |
| $38 | | N/M | | $36 | | N/M |
N/M - Not meaningful
In the thirdsecond quarter 2018,2019, other income (expense), net was $17$40 million compared to $3$2 million for the corresponding period in 2017.2018. For year-to-date 2018,year-to date 2019, other income (expense), net was $22$41 million compared to $3$5 million for the corresponding period in 2017. These2018. The increases were primarily due to a $14$36 million gain arising from a joint-development wind project, which is attributable to Southern Power's partner in the project and fully offset within noncontrolling interests.
Income Taxes (Benefit)
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1 | | 2.6 | | $(81) | | (62.8) |
In the third quarter 2018, income tax benefit was $38 million compared to $39 million for the corresponding period in 2017. For year-to-date 2018, income tax benefit was $210 million compared to $129 million for the corresponding period in 2017. These changes were primarily due to lower pre-tax earnings, primarily resulting from asset impairment charges, and income tax benefitssettlement of litigation related to certain changes in state apportionment rates arising from reorganizations of Southern Power's legal entities that own and operate certain of itsthe Roserock solar and wind facilities, partially offset by a decrease in income tax benefits from solar ITCs, primarily as a result of a decrease in the number of facilities placed in service in 2018 as compared to 2017.facility. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Legal Entity Reorganizations" and 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)
|
| | | | | | |
| 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 second quarter 2019, income tax benefit was $51 million compared to $73 million for the corresponding period in 2018. This change was primarily due to a $43 million increase in income tax expense as a result of higher pre-tax earnings and a $41 million reduction of tax benefits from 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 2019, income tax benefit was $60 million compared to $172 million for the corresponding period in 2018. This change was primarily due to an $80 million reduction of tax benefits from wind PTCs primarily as a result of the sale of a noncontrolling tax equity interest in SP Wind, $54 million in 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 expense as a result of higher pre-tax earnings, partially offset by a $75 million tax benefit resulting from 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.
Net Income Attributable to Noncontrolling Interests
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $24 | | 80.0 | | $23 | | 47.9 |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $6 | | 26.1 | | $(17) | | N/M |
N/M - Not meaningful
In the thirdsecond quarter 2018,2019, net income attributable to noncontrolling interests was $54$29 million compared to $30$23 million for the corresponding period in 2017.2018. The increase was due to $14 million of other income allocations attributable to a joint-development wind project and $10 million of net income allocations primarily due to an allocation of approximately $26 million of income to the salenoncontrolling interest partner related to the Roserock solar facility litigation settlement, partially offset by $25 million of a 33%losses attributable to noncontrolling interests related to the tax equity interest in SPSHpartnerships entered into in 2018.
For year-to-date 2018,2019, net income attributable to noncontrolling interests was $71 millionimmaterial compared to $48$17 million for the corresponding period in 2017.2018. The increasedecrease was primarily due to $21$48 million of net income allocations due to the sale of a 33% equity interest in SPSH in 2018 and $14 million of other income allocationslosses attributable to a joint-development wind project, partially offset by a reduction of $10 million of net income allocations primarily duenoncontrolling interests related to the tax equity partnership for Gaskell West 1.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 (J)(C) to the Condensed Financial Statements under "Southern"General Litigation Matters – Southern Power" herein and 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.
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 successful remarketing
In May 2018, Southern Power completed the sale of a 33% equity interest in SPSH, a limited partnership indirectly owning substantially all of Southern Power's solar facilities, to Global Atlantic Financial Group Limited (Global Atlantic) for approximately $1.2 billion. Accordingly, Global Atlantic will receive 33% of all cash distributions paid by SPSH. Southern Power continues to consolidate the assets and liabilities of SPSH with Global Atlantic's share of partnership earnings reflected in net income attributable to noncontrolling interests in the Condensed Consolidated Statements of Income.
Also in May 2018, Southern Power entered into an equity interest purchase agreement with NextEra Energy to sell all of its equity interests in the Florida Plants for an aggregate purchase price of $195 million, subject to customary working capital and timing adjustments. The ultimate purchase price will decrease $110,000 per day for each day after December 31, 2018 through the closing of the transaction. Conversely, the ultimate purchase price will increase $110,000 per day for each day the closing occurs prior to December 31, 2018. The sale is expected to occur in the first quarter 2019. Pre-tax net income for the Florida Plants was $18 million and $11 million for the three months ended September 30, 2018 and 2017, respectively, and $40 million and $28 million for the nine months ended September 30, 2018 and 2017, respectively. The ultimate outcome of this matter cannot be determined at this time.
On October 31, 2018, Southern Power entered into agreements with three financial investors for the sale of a noncontrolling interest for approximately $1.2 billion in Class A tax equity in SP Wind, which owns a portfolio of eight operating wind facilities. The transaction is subject to Public Utility Commission of Texas approval and is expected to close by the end of 2018. Upon closing, the tax equity partners will have a claim to certain cash distributions and an allocation of tax attributes. See "Income Tax Matters – Legal Entity Reorganizations" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.
On November 5, 2018, Southern Power entered into an agreement with Northern States Power to sell all of its equity interests in Plant Mankato (including the 385-MW expansion currently under construction) for an aggregate purchase price of $650 million, subject to customary working capital and timing adjustments. The ultimate purchaseContents
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 through the development or acquisition of renewable facilities and other energy projects.
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 will decrease $66,667 per dayof approximately $461 million, including working capital adjustments. The pre-tax income related to Plant Nacogdoches was $16 million and $13 million for each day afterthe six months ended June 1,30, 2019 ifand 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 the expansion has nottransfer 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. 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 but such decrease will not exceed $15 million. This transaction isof 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 the expiration or termination of the waiting period under the HSR Act and FERC and state commission approvals and is expected to close mid-2019.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. 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 expected to occur in the 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, transmission constraints, cost of generation from units within the power pool, and operational limitations. For additional information relating to these factors, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Power in Item 7 of the Form 10-K.
Power Sales Agreements
See BUSINESS – "The Southern Company System – Southern Power" in Item 1 of the Form 10-K for additional information regarding Southern Power's PPAs. Generally, under the solar and wind generation PPAs, the purchasing party retains the right to keep or resell the renewable energy credits.
At September 30, 2018, Southern Power's average investment coverage ratio for its generating assets (including the Florida and Mankato Plants), 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 and acquisitions discussed herein) as the investment amount, was 93% through 2022 and 91% through 2027, with an average remaining contract duration of approximately 15 years.
Environmental Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Power in Item 7 of the Form 10-K for information on the development by federal and state environmental regulatory agencies of additional control strategies for emissions of air pollution from industrial sources, including electric generating facilities. Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, water quality, or other environmental and health concerns could also significantly affect Southern Power. While Southern Power's PPAs generally contain provisions that permit charging the counterparty with some of the new costs incurred as a result of changes in environmental laws and regulations, the full impact of any such legislative or regulatory changes cannot be determined at this time.
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Water Quality"125
On May 2, 2018, the EPA updated its anticipated final rulemaking schedule for ELG from September 2020 to December 2019. The impact of any changes to the ELG rule will depend on the content of the final rule and the outcome of any legal challenges and 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 proceedings related to the traditional electric operating companies' and Southern Power's 2014 and 2017 triennial market power analyses.
On May 4, 2018, the FERC issued an order terminating both proceedings, finding that the traditional electric operating companies and Southern Power satisfy the FERC's standards for market-based rates. On May 9, 2018, the traditional electric operating companies and Southern Power made the compliance filing required by the order. These proceedings are concluded.Contents
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Acquisitions
During the nine months ended September 30, 2018, one of Southern Power's wholly-owned subsidiaries acquired and completed construction of the Gaskell West 1 solar facility. Acquisition-related costs were expensed as incurred and were not material. See Note (J) 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 |
Gaskell West 1 | Solar | 20 | Kern County, CA | 100% of Class B | (*) | March 2018 | Southern California Edison | 20 years |
| |
(*) | Southern Power owns 100% of the class B membership interests under a tax equity partnership agreement. |
The Gaskell West 1 facility did not have operating revenues or activities prior to completion of construction and the assets being placed in service during March 2018.
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 in Progress and/or Completed
During the ninesix months ended SeptemberJune 30, 2018,2019, Southern Power started, continued, or completed construction of and placed in service the 385-MW Plant Mankato expansion and continued construction of two other projects set forthas described in the table below. Total aggregate construction costs, excluding the acquisition costs, are expected to be between $575$405 million and $640$450 million for the Mankato, Wild HorseWildhorse Mountain and Reading facilities. At SeptemberJune 30, 2018,2019, total costs of construction costsincurred for these projects were $186 million and are included in CWIP related to these projects totaled $246 million.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 Counterparties | PPA Contract Period |
Cactus Flats(a)
Projects Completed During the Six Months Ended June 30, 2019 | Wind | 148 | Concho County, TX | July 2018 | General Motors, LLC
and
General Mills Operations, LLC | 12 years
and
15 years |
Mankato expansion(a) | Natural Gas | 385 | Mankato, MN | First halfMay 2019 | Northern States Power Company | 20 years |
| Projects Under Construction as of June 30, 2019 | | |
Wild HorseWildhorse 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) | In July 2017, Southern Power purchased 100% of the Cactus Flats facility and commenced construction. In July 2018, the facility was placed in service and, in AugustNovember 2018, Southern Power closedentered 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 a tax equity partnership agreement and owns 100% of the class B membership interests.June 1, 2019. |
| |
| (b) | In May 2018, Southern Power purchased 100% of the Wild HorseWildhorse Mountain facility and commenced construction.facility. Southern Power may enterentered into a tax equity partnership agreement, in which case it would then own 100%June 2019 with funding of the class B membership interests.tax equity amounts expected to occur upon commercial operation. |
| |
| (c) | In August 2018, Southern Power purchased 100% of the membership interests of the Reading facility from the joint development arrangement with Renewable Energy Systems Americas, Inc. and commenced construction. Southern Power may enter into a tax equity partnership, agreement, in which case it would then own 100% of the class B membership interests. |
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Development Projects
During 2017, as part of its renewable development strategy, SouthernSee Note 15 to the financial statements under "Southern Power purchased wind turbine equipment from Siemens Gamesa Renewable Energy Inc. and Vestas-American Wind Technology, Inc. to be used for various development and construction projects. Any wind projects using this equipment and reaching commercial operation by the end of 2021 are expected to qualify for 80% PTCs.
During 2016, Southern Power entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct wind projects. In addition,– Development Projects" in 2016, Southern Power purchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for constructionItem 8 of the facilities. Any wind projects using this equipment and reaching commercial operation by the end of 2020 are expected to qualifyForm 10-K for 100% PTCs.additional information.
In response to the previously disclosed decrease of planned expenditures for plant acquisitions and placeholder growth, Southern Power continues to evaluate and refine the deployment of the 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 constructed. During the third quarter 2018, as a result of a review of various options for probable dispositions ofsix months ended June 30, 2019, certain wind turbine equipment not already deployed to development or construction projects, Southern Power recordedwas sold, resulting in a $36 million asset impairment chargegain on the equipment.
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 FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation.additional information.
Legal Entity Reorganizations
In April 2018, Southern Power completed the final stage of a legal entity reorganization of various direct and indirect subsidiaries that own and operate substantially all of its solar facilities, including certain subsidiaries owned in partnership with various third parties. The reorganization resulted in net state tax benefits related to certain changes in apportionment rates totaling approximately $54 million, which were recorded in the first half of 2018.
In September 2018, Southern Power also completed a legal reorganization of eight operating wind facilities under a new holding company, SP Wind, which resulted in net state tax benefits totaling approximately $11 million related to certain changes in apportionment rates.
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 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
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 regulatoryother business 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 Southern Power's financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIESSouthern Power indirectly owns a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock facility in Pecos County, Texas. Prior to the facility being placed in service in 2016, certain solar panels were damaged during installation by the construction contractor, McCarthy Building Companies, Inc. (McCarthy), and certain solar panels were damaged by a hail event that also occurred during construction. In connection therewith, Southern Power withheld payment of approximately $26 million to the construction contractor, which placed a lien on the Roserock facility for the same amount. In 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas against XL Insurance America, Inc. and North American Elite Insurance Company seeking recovery from an insurance policy for damages resulting from the hail event and McCarthy's installation practices. In June 2018, the court granted Roserock's motion for partial summary judgment, finding that the insurers were in breach of contract and in violation of the Texas Insurance Code for failing to pay any monies owed for the hail claim. Separate lawsuits were filed between Roserock and McCarthy, as well as other parties, and that litigation was consolidated in the U.S. District Court for the Western District of Texas. On April 18, 2019, Roserock and the parties to the state and federal lawsuits executed a settlement agreement and mutual release that resolved both lawsuits. Following execution of the agreement, the lawsuits were dismissed, Southern Power paid 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 noncontrolling interests and Southern Power recognized a $12 million after-tax gain.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Power prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in 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.
Recently Issued Accounting Standards
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Southern Power in Item 7 of the Form 10-K for additional information regarding ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). See Note (A) to the Condensed Financial Statements herein for information regarding Southern Power's recently adopted accounting standards.
In 2016, the FASB issued ASU No. 2016-02, which requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and Southern Power will adopt the new standard effective January 1, 2019.
Southern Power has elected the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby it will apply the requirements of ASU 2016-02 on a prospective basis as of the adoption date of January 1, 2019, without restating prior periods. Southern Power expects to elect the package of practical expedients provided by ASU 2016-02 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Southern Power expects to apply the use-of-hindsight practical expedient in determining lease terms as of the date of adoption. Southern Power also expects to make accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and to combine lessee lease and non-lease components in the computations of lease obligations and right-of-use assets for most asset classes, while lessor lease and non-lease components will be accounted for separately.
Southern Power is continuing to complete the implementation of an information technology system to track and account for its leases and of changes to its internal controls and accounting policies to support the accounting for leases under ASU 2016-02. Southern Power has substantially completed its lease inventory and determined its most significant leases as a lessee involve real estate. While Southern Power has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to result in recording lease liabilities and right-of-use assets on Southern Power's balance sheet each totaling approximately $0.5 billion, with no material impact on Southern Power's statement of income.
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, 2018.2019. 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 also utilizes third-party tax equity partnerships, as one of the financing sources to fund its renewable growth strategy where the tax partner takes significantly all of the federal tax benefits.benefits, as a financing source. These tax equity partnerships are consolidated in Southern Power's financial statements and are accounted for using a hypothetical liquidation at book value (HLBV)HLBV methodology to allocate partnership gains and losses to Southern Power.losses. During the first ninesix months of 2018,2019, Southern Power obtained third-partydid not receive any material tax equity funding for the Gaskell West 1 solar project and the Cactus Flats wind project of approximately $26 million and $122 million, respectively.amounts. See Note (A)1 to the Condensed Financial Statementsfinancial statements under "Hypothetical"Hypothetical Liquidation at Book Value" hereinValue" in Item 8 of the Form 10-K for additional information on the HLBV methodology.
In May 2018, Southern Power received approximately $1.2 billion from the sale of a 33% equity interest in SPSH, a limited partnership indirectly owning substantially all of Southern Power's solar facilities. The proceeds were used to repay $770 million of existing indebtedness, to return capital of $250 million to Southern Company, and for other general corporate purposes, including working capital.
On October 31, 2018, Southern Power entered into agreements with three financial investors for the sale of a noncontrolling interest for approximately $1.2 billion in tax equity in SP Wind, which owns a portfolio of eight operating wind facilities. The transaction is subject to Public Utility Commission of Texas approval and is expected to close by the end of 2018. Southern Power intends to use the proceeds to return capital of approximately $1.0 billion to Southern Company. The ultimate outcome of this matter cannot be determined at this time.
Net cash provided from operating activities totaled $666$719 million for the first ninesix months of 20182019 compared to $894$127 million for the first ninesix months of 2017.2018. The decreaseincrease in net cash provided from operating activities was primarily due to lowerthe utilization of income tax refunds primarily due to taxable gains arising from the salecredits of a 33% equity interest$520 million in SPSH. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Bonus Depreciation" of Southern Power in Item 7 of the Form 10-K for additional information.2019. Net cash used forprovided from investing activities totaled $324$254 million for the first ninesix months of 20182019 primarily due to proceeds from the disposition of Plant Nacogdoches and wind equipment sales, partially offset by Southern Power's investment in DSGP and ongoing construction of generating facilities and payments for renewable acquisitions.activities. Net cash used for financing activities totaled $290$784 million for the first ninesix months of 20182019 primarily due to debt repayments, returns of capital and payments ofto Southern Company, common stock dividends, to Southern Company,the repayment of a short-term bank loan, and distributions to noncontrolling interests, partially offset by proceeds from the sale of a 33% equity interest in SPSH.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 20182019 include a $1.8 billion$464 million increase in noncontrolling interestsprepaid income taxes due to the expected utilization of tax credits for the remainder of the 2019 tax year, a $493 million decrease in plant in service primarily as a result of the 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 Southern Power's investment in DSGP, and a $466 million decrease in stockholder's equity primarily due to the salereturns of SPSH, a $1.1 billion reduction in paid in capital which includes $410 million relatedto Southern Company. See Note (K) under "Southern Power" and Note (L) to the sale of SPSH and $250 million and $400 million of capital returned to Southern Company in the second and third quarters 2018, respectively, a $770 million decrease in securities due within one year due to repayments of debt in the second quarter 2018, and a $356 million increase in accumulated deferred income tax assets primarily due to the sale of SPSH.Condensed Financial Statements herein for additional information.
See FUTURE EARNINGS POTENTIAL – "Acquisitions," "Construction Projects," and "Income Tax Matters – Legal Entity Reorganizations" 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 and contractual obligations. There are no scheduledApproximately $900 million will be required through June 30, 2020 to fund maturities of long-term debt through September 30, 2019.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. Subsequent to the Tax Reform Legislation, planned expenditures for plant acquisitions and placeholder growth are now expected to average approximately $0.5 billion per year for 2018 through 2022 and may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. Southern Power's capital expenditures for committed construction, capital improvements, and work to be performed
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
under LTSAs remain unchanged and total approximately $0.9 billion for the five years ending 2022. Actual construction costs, including acquisitions, 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 laws and regulations; the outcome of any legal challenges to 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 FUTURE EARNINGS POTENTIAL – "Acquisitions" and "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, external securities issuances, 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.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Power's current liabilities sometimes exceed current assets due to the use of short-term debt as a funding source and construction payables, as well as fluctuations in cash needs due to 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, 2018,2019, Southern Power had cash and cash equivalents of approximately $192$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 sheets.
Details of short-term borrowings were as follows:
| | | | Short-term Debt at September 30, 2018 | | Short-term Debt During the Period (*) | Short-term Borrowings During the Period (*) |
| | Amount Outstanding | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | (in millions) | | | (in millions) | | | | (in millions) | (in millions) | | | | (in millions) |
| Commercial paper | $ | 37 |
| 2.5 | % | | $ | 44 |
| | 2.3 | % | | $ | 185 |
| $ | 7 |
| | 2.6 | % | | $ | 75 |
|
| Short-term loans | 200 |
| 2.8 | % | | 200 |
| | 2.7 | % | | 200 |
| 58 |
| | 3.1 | % | | 100 |
|
| Total | $ | 237 |
| 2.8 | % | | $ | 244 |
| | 2.6 | % | | | $ | 65 |
| | 3.0 | % | |
|
|
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended SeptemberJune 30, 2018.2019. No short-term debt was outstanding at June 30, 2019. |
At September 30, 2018,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. The Facility expires in 2022. 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 (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
The Facility as well as Southern Power's term loan agreements, 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
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 20192021 for standby letters of credit. At SeptemberJune 30, 2018, $982019, $90 million has been used for letters of credit, primarily as credit support for PPA requirements, and $22$30 million remains unused.
In addition, at SeptemberJune 30, 2018,2019, Southern Power had $103$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.
The maximum potential collateral requirements under these contracts at SeptemberJune 30, 20182019 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 | $ | 378 |
| $ | 339 |
|
At BB+ and/or Ba1(*) | $ | 932 |
| $ | 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 September 28, 2018, Fitch assigned a negative rating outlook to the ratings of Southern Company and certain of its subsidiaries (including Southern Power).
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 Southern Power, may be negatively impacted. Absent actions by Southern Power to mitigate the resulting impacts, which, among other alternatives, could include adjusting Southern Power's capital structure, Southern Power's credit ratings could be negatively affected.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Financing Activities
In May 2018,2019, Southern Power entered into tworepaid at maturity a $100 million short-term floating rate bank loans, each for an aggregate principal amount of $100 million, which bear interest based on one-month LIBOR.
In the second quarter 2018, Southern Power repaid $420 million aggregate principal amount of long-term floating rate bank loans and $350 million aggregate principal amount of Series 2015A 1.50% Senior Notes due June 1, 2018.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)
| | | | 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, |
| | 2018 | | 2017 | | 2018 | | 2017 | 2019 | | 2018 | | 2019 | | 2018 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | | | | | | | | |
Natural gas revenues (includes revenue taxes of
$9, $9, $83, and $75, respectively) | $ | 487 |
| | $ | 532 |
| | $ | 2,829 |
| | $ | 2,737 |
| |
Natural gas revenues (includes revenue taxes of
$23, $23, $78, and $74, respectively) | | $ | 688 |
| | $ | 710 |
| | $ | 2,163 |
| | $ | 2,341 |
|
| Alternative revenue programs | 5 |
| | — |
| | (23 | ) | | 9 |
| 1 |
| | (4 | ) | | — |
| | (27 | ) |
| Other revenues | — |
| | 33 |
| | 55 |
| | 95 |
| — |
| | 24 |
| | — |
| | 55 |
|
| Total operating revenues | 492 |
| | 565 |
| | 2,861 |
| | 2,841 |
| 689 |
| | 730 |
| | 2,163 |
| | 2,369 |
|
| Operating Expenses: | | | | | | | | | | | | | | |
| Cost of natural gas | 104 |
| | 134 |
| | 1,053 |
| | 1,085 |
| 191 |
| | 228 |
| | 877 |
| | 949 |
|
| Cost of other sales | — |
| | 7 |
| | 12 |
| | 20 |
| — |
| | 5 |
| | — |
| | 12 |
|
| Other operations and maintenance | 216 |
| | 206 |
| | 730 |
| | 675 |
| 199 |
| | 238 |
| | 433 |
| | 514 |
|
| Depreciation and amortization | 119 |
| | 125 |
| | 374 |
| | 370 |
| 119 |
| | 126 |
| | 238 |
| | 255 |
|
| Taxes other than income taxes | 32 |
| | 26 |
| | 157 |
| | 140 |
| 46 |
| | 48 |
| | 128 |
| | 125 |
|
| Gain on dispositions, net | (353 | ) | | — |
| | (317 | ) | | — |
| |
| Goodwill impairment | — |
| | — |
| | 42 |
| | — |
| — |
| | — |
| | — |
| | 42 |
|
| Loss on disposition | | — |
| | 36 |
| | — |
| | 36 |
|
| Total operating expenses | 118 |
| | 498 |
| | 2,051 |
| | 2,290 |
| 555 |
| | 681 |
| | 1,676 |
| | 1,933 |
|
| Operating Income | 374 |
| | 67 |
| | 810 |
| | 551 |
| 134 |
| | 49 |
| | 487 |
| | 436 |
|
| Other Income and (Expense): | | | | | | | | | | | | | | |
| Earnings from equity method investments | 34 |
| | 32 |
| | 108 |
| | 100 |
| 31 |
| | 31 |
| | 80 |
| | 74 |
|
| Interest expense, net of amounts capitalized | (52 | ) | | (51 | ) | | (170 | ) | | (145 | ) | (59 | ) | | (59 | ) | | (118 | ) | | (118 | ) |
| Other income (expense), net | 6 |
| | 19 |
| | 21 |
| | 30 |
| 6 |
| | 3 |
| | 10 |
| | 15 |
|
| Total other income and (expense) | (12 | ) | | — |
| | (41 | ) | | (15 | ) | (22 | ) | | (25 | ) | | (28 | ) | | (29 | ) |
| Earnings Before Income Taxes | 362 |
| | 67 |
| | 769 |
| | 536 |
| 112 |
| | 24 |
| | 459 |
| | 407 |
|
| Income taxes | 316 |
| | 52 |
| | 475 |
| | 233 |
| 6 |
| | 55 |
| | 83 |
| | 159 |
|
| Net Income | $ | 46 |
| | $ | 15 |
| | $ | 294 |
| | $ | 303 |
| |
| Net Income (Loss) | | $ | 106 |
| | $ | (31 | ) | | $ | 376 |
| | $ | 248 |
|
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months
Ended September 30, | | For the Nine Months
Ended September 30, |
| | 2018 | | 2017 | | 2018 | | 2017 |
| | (in millions) | | (in millions) |
| Net Income | $ | 46 |
| | $ | 15 |
| | $ | 294 |
| | $ | 303 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
Changes in fair value, net of tax of
$-, $-, $1, and $(2), respectively | — |
| | — |
| | 2 |
| | (3 | ) |
Reclassification adjustment for amounts included in net income,
net of tax of $-, $-, $1, and $-, respectively | — |
| | — |
| | 2 |
| | — |
|
| Pension and other postretirement benefit plans: | | | | | | | |
Reclassification adjustment for amounts included in net income,
net of tax of $2, $-, $2, and $(1), respectively | 6 |
| | — |
| | 5 |
| | — |
|
| Total other comprehensive income (loss) | 6 |
| | — |
| | 9 |
| | (3 | ) |
| Comprehensive Income | $ | 52 |
| | $ | 15 |
| | $ | 303 |
| | $ | 300 |
|
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
|
| | | | | | | |
| | For the Nine Months
Ended September 30, |
| | 2018 | | 2017 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 294 |
| | $ | 303 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 374 |
| | 370 |
|
| Deferred income taxes | (83 | ) | | 265 |
|
| Mark-to-market adjustments | 23 |
| | (32 | ) |
| Gain on dispositions, net | (317 | ) | | — |
|
| Goodwill impairment | 42 |
| | — |
|
| Other, net | (41 | ) | | (46 | ) |
| Changes in certain current assets and liabilities — | | | |
| -Receivables | 445 |
| | 531 |
|
| -Natural gas for sale | 87 |
| | — |
|
| -Prepaid income taxes | (23 | ) | | (7 | ) |
| -Other current assets | 21 |
| | (42 | ) |
| -Accounts payable | (59 | ) | | (169 | ) |
| -Accrued taxes | (64 | ) | | (24 | ) |
| -Accrued compensation | 2 |
| | (11 | ) |
| -Other current liabilities | 35 |
| | 8 |
|
| Net cash provided from operating activities | 736 |
| | 1,146 |
|
| Investing Activities: | | | |
| Property additions | (1,029 | ) | | (1,093 | ) |
| Cost of removal, net of salvage | (67 | ) | | (45 | ) |
| Change in construction payables, net | (14 | ) | | 49 |
|
| Investment in unconsolidated subsidiaries | (90 | ) | | (128 | ) |
| Dispositions | 2,631 |
| | — |
|
| Other investing activities | 18 |
| | 28 |
|
| Net cash provided from (used for) investing activities | 1,449 |
| | (1,189 | ) |
| Financing Activities: | | | |
| Decrease in notes payable, net | (1,382 | ) | | (323 | ) |
| Proceeds — | | | |
| First mortgage bonds | 100 |
| | 200 |
|
| Capital contributions from parent company | 35 |
| | 79 |
|
| Senior notes | — |
| | 450 |
|
| Redemptions — Gas facility revenue bonds | (200 | ) | | — |
|
| Return of capital | (400 | ) | | — |
|
| Payment of common stock dividends | (351 | ) | | (332 | ) |
| Other financing activities | (3 | ) | | (29 | ) |
| Net cash provided from (used for) financing activities | (2,201 | ) | | 45 |
|
| Net Change in Cash, Cash Equivalents, and Restricted Cash | (16 | ) | | 2 |
|
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 78 |
| | 24 |
|
| Cash, Cash Equivalents, and Restricted Cash at End of Period | $ | 62 |
| | $ | 26 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid during the period for — | | | |
| Interest (net of $5 and $9 capitalized for 2018 and 2017, respectively) | $ | 175 |
| | $ | 146 |
|
| Income taxes, net | 682 |
| | 17 |
|
| Noncash transactions — Accrued property additions at end of period | 121 |
| | 112 |
|
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, 2018 | | At December 31, 2017 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 56 |
| | $ | 73 |
|
| Receivables — | | | | |
| Energy marketing receivables | | 498 |
| | 607 |
|
| Customer accounts receivable | | 180 |
| | 400 |
|
| Unbilled revenues | | 58 |
| | 285 |
|
| Affiliated | | 23 |
| | 12 |
|
| Other accounts and notes receivable | | 110 |
| | 91 |
|
| Accumulated provision for uncollectible accounts | | (18 | ) | | (28 | ) |
| Natural gas for sale | | 486 |
| | 595 |
|
| Prepaid expenses | | 62 |
| | 53 |
|
| Assets from risk management activities, net of collateral | | 87 |
| | 135 |
|
| Other regulatory assets, current | | 72 |
| | 94 |
|
| Other current assets | | 88 |
| | 78 |
|
| Total current assets | | 1,702 |
| | 2,395 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 14,771 |
| | 15,833 |
|
| Less: Accumulated depreciation | | 4,351 |
| | 4,596 |
|
| Plant in service, net of depreciation | | 10,420 |
| | 11,237 |
|
| Construction work in progress | | 660 |
| | 491 |
|
| Total property, plant, and equipment | | 11,080 |
| | 11,728 |
|
| Other Property and Investments: | | | | |
| Goodwill | | 5,015 |
| | 5,967 |
|
| Equity investments in unconsolidated subsidiaries | | 1,529 |
| | 1,477 |
|
Other intangible assets, net of amortization of $133 and $120
at September 30, 2018 and December 31, 2017, respectively | | 113 |
| | 280 |
|
| Miscellaneous property and investments | | 20 |
| | 21 |
|
| Total other property and investments | | 6,677 |
| | 7,745 |
|
| Deferred Charges and Other Assets: | | | | |
| Other regulatory assets, deferred | | 721 |
| | 901 |
|
| Other deferred charges and assets | | 218 |
| | 218 |
|
| Total deferred charges and other assets | | 939 |
| | 1,119 |
|
| Total Assets | | $ | 20,398 |
| | $ | 22,987 |
|
|
| | | | | | | | | | | | | | | |
| | 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 BALANCE SHEETSSTATEMENTS OF CASH FLOWS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholder's Equity | | At September 30, 2018 | | At December 31, 2017 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 515 |
| | $ | 157 |
|
| Notes payable | | 136 |
| | 1,518 |
|
| Energy marketing trade payables | | 521 |
| | 546 |
|
| Accounts payable — | | | | |
| Affiliated | | 37 |
| | 21 |
|
| Other | | 346 |
| | 425 |
|
| Customer deposits | | 136 |
| | 128 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | — |
| | 40 |
|
| Other accrued taxes | | 61 |
| | 78 |
|
| Accrued interest | | 66 |
| | 51 |
|
| Accrued compensation | | 71 |
| | 74 |
|
| Liabilities from risk management activities, net of collateral | | 28 |
| | 69 |
|
| Other regulatory liabilities, current | | 132 |
| | 135 |
|
| Other current liabilities | | 122 |
| | 159 |
|
| Total current liabilities | | 2,171 |
| | 3,401 |
|
| Long-term Debt | | 5,393 |
| | 5,891 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 944 |
| | 1,089 |
|
| Deferred credits related to income taxes | | 930 |
| | 1,063 |
|
| Employee benefit obligations | | 412 |
| | 415 |
|
| Other cost of removal obligations | | 1,577 |
| | 1,646 |
|
| Accrued environmental remediation, deferred | | 269 |
| | 342 |
|
| Other deferred credits and liabilities | | 79 |
| | 118 |
|
| Total deferred credits and other liabilities | | 4,211 |
| | 4,673 |
|
| Total Liabilities | | 11,775 |
| | 13,965 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, par value $0.01 per share — | | | | |
| Authorized — 100 million shares | | | | |
| Outstanding — 100 shares | | — |
| | — |
|
| Paid in capital | | 8,863 |
| | 9,214 |
|
| Accumulated deficit | | (273 | ) | | (212 | ) |
| Accumulated other comprehensive income | | 33 |
| | 20 |
|
| Total common stockholder's equity | | 8,623 |
| | 9,022 |
|
| Total Liabilities and Stockholder's Equity | | $ | 20,398 |
| | $ | 22,987 |
|
|
| | | | | | | |
| | 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 BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| 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)
|
| | | | | | | | |
| 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 SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | Paid-In
Capital | | Retained
Earnings (Accumulated Deficit) | | Accumulated
Other
Comprehensive
Income (Loss) | | Total |
| | (in millions) |
| Balance at December 31, 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 financial statements.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRDSECOND QUARTER 2019 vs. SECOND QUARTER 2018 vs. THIRD QUARTER 2017
AND
YEAR-TO-DATE 20182019 vs. YEAR-TO-DATE 20172018
OVERVIEW
Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas. Subsequent to the dispositions of Elizabethtown Gas, Elkton Gas, and Florida City Gas discussed below, Southern Company Gas has natural gas distributionthrough utilities in four states – Nicor Gas in Illinois, Atlanta Gas Light in Georgia, Virginia Natural Gas in Virginia, and 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 (L)(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. These 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 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.
Atlanta Gas Light filed a rate case on June 3, 2019 and Nicor Gas filed a rate case in November 2018. Both rate cases are expected to be finalized in 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 under "Southern Company Gas – Rate Proceedings" in Item 8 of the Form 10-K for additional information.
During 2018, Southern Company Gas completed the following sales, resulting in approximately $2.7 billion in aggregate proceeds.
On June 4, 2018, Southern Company Gas completed the stock sale of Pivotal Home Solutions to American Water Enterprises LLC for a total cash purchase price of $365 million, which includes the final working capital adjustment. This disposition resulted in an estimated net loss of $73 million, which includes $39 million of income tax expense, the calculation of which is expected to be finalized in the fourth quarter 2018. In contemplation of the transaction, a goodwill impairment charge of $42 million was recorded during the first quarter 2018.LLC.
On July 1, 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. for a total cash purchase price of $1.7 billion and an additional $40 million for working capital, subject to a final working capital adjustment expected in the fourth quarter 2018. This disposition resulted in an estimated pre-tax gain of approximately $230 million and an after-tax gain of approximately $18 million, the calculations of which are expected to be finalized in the fourth quarter 2018.
On July 29, 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI Corporation, completed the stock sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energy for a total cash purchase price of $530 million (less $3 million of indebtedness assumed at closing for customer deposits) and an additional $60 million for cash and other working capital, which includes the final working capital adjustment. This disposition resulted in an estimated pre-tax gain of approximately $121 million and an after-tax gain of approximately $20 million, the calculations of which are expected to be finalized in the fourth quarter 2018.Energy.
The after-tax impacts of these dispositions included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. See Note (J)15 to the Condensed Financial Statementsfinancial statements in Item 8 of the Form 10-K under "Southern"Southern Company Gas" hereinGas" for additional information.information on these 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 – OVERVIEW – "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 Nicor Gas, Southern Company Gas has various regulatory mechanisms, such as weather normalization 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 to reducelimit the negative earnings impactincome impacts in the event of warmer-than-normal weather, while retaining mosta significant portion of the earnings upsidepositive benefits of colder-than-normal weather for these businesses.
The number of customers served by gas distribution operations and gas marketing services can be impacted by natural gas prices, economic conditions, and competition from alternative fuels. Gas marketing services' customers are primarily located in Georgia, Illinois, and Ohio.
Southern Company Gas' natural gas volume metrics for gas distribution operations and gas marketing services illustrate the effects of weather and customer demand for natural gas. Wholesale gas services' physical sales volumes represent the daily average natural gas volumes sold to its customers.
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)
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $31 | | 206.7 | | $(9) | | (3.0) |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $137 | | N/M | | $128 | | 51.6 |
Southern Company Gas'N/M - Not meaningful
In the second quarter 2019, net income for the third quarter 2018 was $46$106 million compared to $15a net loss of $31 million for the corresponding period in 2017. The increase was primarily due to the gains resulting from the sales of Elizabethtown Gas, Elkton Gas, and Florida City Gas and higher commercial activity at wholesale gas services, partially offset by derivative losses at wholesale gas services, disposition-related costs, and2018. Excluding a 2017 gain from the settlement of contractor litigation claims. Third quarter 2017 also included a deferred tax expense related to the enactment of the State of Illinois income tax legislation and new income tax apportionment factors in several states.
For year-to-date 2018, net income was $294$73 million compared to $303 million for the corresponding period in 2017. The decrease was primarily due to the net loss resultingin 2018 from the Southern Company Gas Dispositions and a goodwill impairment charge recorded$7 million net income in 2019 from the sale of Triton, net income increased $57 million. This increase was primarily due to an 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 excess 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 contemplationearnings from equity method investments in 2019. Partially offsetting these increases were a decrease of the sale$13 million at wholesale gas services, a contractor litigation
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Solutions, derivative losses at wholesale gas services, disposition-related costs,settlement recorded in the first quarter 2018, and lower gains from the settlement of contractor litigation claims in 2018 comparedincreased depreciation and amortization primarily due to the corresponding period in 2017, partially offset by higher commercial activity at wholesale gas services, additional revenues fromcontinued infrastructure investments recovered through replacement programs less the associated increase in depreciation as well as base rate changes at gas distribution operations,operations.
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 lower federal income tax rate andForm 10-K for additional information on Atlanta Gas Light's stipulation reflecting the flowback of excess deferred taxes as a resultimpacts of the Tax Reform Legislation. Year-to-date 2017 also included a deferred tax expense related toLegislation and the enactment of the State of Illinois income tax legislation and new income tax apportionment factors in several states.
For additional information, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Southern Company Gas in Item 7 of the Form 10-K and Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein.contractor litigation settlement, respectively.
Natural Gas Revenues, including Alternative Revenue Programs
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(40) | | (7.5) | | $60 | | 2.2 |
|
| | | | | | |
| 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 2018,2019, natural gas revenues, including alternative revenue programs, were $492$689 million compared to $532$706 million for the corresponding period in 2017.2018. For year-to-date 2018,2019, natural gas revenues, including alternative revenue programs, were $2.8$2.2 billion compared to $2.7$2.3 billion for the corresponding period in 2017.2018.
Details of the changes in natural gas revenues, including alternative revenue programs, were as follows:
| | | | Third Quarter 2018 | | Year-to-Date 2018 | Second Quarter 2019 | | Year-to-Date 2019 |
| | (in millions) | | (% change) | | (in millions) | | (% change) | (in millions) | | (% change) | | (in millions) | | (% change) |
| Natural gas revenues – prior year | $ | 532 |
|
|
|
| $ | 2,746 |
|
|
|
| $ | 706 |
|
|
|
| $ | 2,314 |
|
|
|
|
| Estimated change resulting from – | | | | | | | | | | | | | | |
| Infrastructure replacement programs and base rate changes | — |
|
| — |
|
| 53 |
|
| 1.9 |
| 10 |
|
| 1.4 | % |
| 42 |
|
| 1.8 | % |
| Gas costs and other cost recovery | (16 | ) |
| (3.0 | ) |
| (24 | ) |
| (0.9 | ) | (13 | ) |
| (1.8 | ) |
| 49 |
|
| 2.1 |
|
| Weather | 1 |
|
| 0.2 |
|
| 17 |
|
| 0.6 |
| (7 | ) |
| (1.1 | ) |
| — |
|
| — |
|
| Wholesale gas services | 17 |
|
| 3.2 |
|
| 46 |
|
| 1.7 |
| 64 |
|
| 9.1 |
|
| (16 | ) |
| (0.7 | ) |
Dispositions(*) | (43 | ) | | (8.1 | ) | | (30 | ) | | (1.1 | ) | |
| Southern Company Gas Dispositions | | (70 | ) | | (9.9 | ) | | (237 | ) | | (10.2 | ) |
| Other | 1 |
|
| 0.2 |
|
| (2 | ) |
| — |
| (1 | ) |
| (0.1 | ) |
| 11 |
|
| 0.5 |
|
| Natural gas revenues – current year | $ | 492 |
| | (7.5 | )% | | $ | 2,806 |
| | 2.2 | % | $ | 689 |
| | (2.4 | )% | | $ | 2,163 |
| | (6.5 | )% |
| |
(*) | Includes Pivotal Utility Holdings' disposition of Elizabethtown Gas and Elkton Gas as well as NUI Corporation's disposition of Pivotal Utility Holdings, which primarily consisted of Florida City Gas. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
|
Revenues from infrastructure replacement programs and base rate changes increased forin 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 gas distribution operations' 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 rate cases, partially offset by revenue reductions for the impacts of the Tax Reform Legislation. See Note (B)2 to the Condensed Financial Statements hereinfinancial statements under "Regulatory Matters"Southern Company Gas – Southern Company Gas"Rate Proceedings" in Item 8 of the Form 10-K for additional information.
Revenues associated with gas costs and other cost recovery decreased in the thirdsecond quarter 2018 decreased due to reduced natural gas prices during the third quarter 20182019 and increased year-to-date 2019 compared to the corresponding periodperiods in 20172018. The decrease in the second quarter 2019 is primarily due to lower natural gas prices and decreased volumes of natural gas sold in the third quarter 2018 as a result of fewer customers served following the dispositions. Revenues associated with gas costs and other cost recoverysold. The increase for year-to-date 2018 decreased2019 is primarily due to reducedincreased natural gas prices during 2018 compared toin the corresponding period in 2017,first quarter 2019, partially offset by increased
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
decreased volumes of natural gas sold in 2018 as a result of colder weather. See "Cost of Natural Gas" herein for additional information.
Revenues increased due to colder weather in 2018 compared to the corresponding periods in 2017 that affected the utility customers in Illinois and the gas marketing services customers in Georgia and Illinois. See the weather discussion herein for additional information.
Revenues from wholesale gas services increased primarily due to increased commercial activity, partially offset by derivative losses. See "Wholesale Gas Services" herein for additional information.
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
Revenues decreased in the second quarter 2019 due to warmer weather in Illinois and Georgia compared to the corresponding period in 2018. See the weather discussion herein for additional information.
Revenues from wholesale gas services 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 "Segment Information – Wholesale Gas Services" herein for additional information.
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 Heating Season. The following table presents the Heating Degree Days information for Illinois and Georgia, the primary locations where Southern Company Gas' operations are impacted by weather.
| | | | | Year-to-Date | | 2018 vs. 2017 | 2018 vs. normal | Second Quarter | | 2019
vs.
2018 | 2019
vs.
normal | | Year-to-Date | | 2019 vs. 2018 | 2019 vs. normal |
| | | Normal(*) | 2018 | 2017 | | colder | colder (warmer) | Normal(*) | 2019 | 2018 | | (warmer) | colder (warmer) | | Normal(*) | 2019 | 2018 | | colder (warmer) |
| Illinois | | 3,758 |
| 3,858 |
| 3,146 |
| | 22.6 | % | 2.7 | % | 635 |
| 659 |
| 767 |
| | (14.1 | )% | 3.8 | % | | 3,679 |
| 3,956 |
| 3,809 |
| | 3.9 | % | 7.5 | % |
| Georgia | | 1,578 |
| 1,542 |
| 1,008 |
| | 53.0 | % | (2.3 | )% | 124 |
| 86 |
| 175 |
| | (50.9 | )% | (30.6 | )% | | 1,566 |
| 1,298 |
| 1,539 |
| | (15.7 | )% | (17.1 | )% |
| |
| (*) | Normal represents the 10-year average from January 1, 20082009 through SeptemberJune 30, 20172018 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. |
Southern Company Gas hedged its exposure to warmer-than-normal weather in Illinois for gas distribution operations and in Illinois and Georgia for gas marketing services, which limited the negative incomeservices. The remaining impacts of weather on earnings are reflected in the chart below.
| | | | Gas Distribution Operations | | Gas Marketing Services | Gas Distribution Operations | | Gas Marketing Services |
| | Year-to-Date | | Year-to-Date | Second Quarter | | Year-to-Date | | Second Quarter | | Year-to-Date |
| | 2018 | 2017 | | 2018 | 2017 | 2019 | 2018 | | 2019 | 2018 | | 2019 | 2018 | | 2019 | 2018 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Pre-tax | $ | 2 |
| $ | (6 | ) | | $ | (1 | ) | $ | (10 | ) | $ | — |
| $ | 4 |
| | $ | 2 |
| $ | 2 |
| | $ | (1 | ) | $ | 2 |
| | $ | (1 | ) | $ | (1 | ) |
| After tax | 2 |
| (3 | ) | | (1 | ) | (6 | ) | — |
| 3 |
| | 2 |
| 2 |
| | (1 | ) | 1 |
| | (1 | ) | (1 | ) |
The following table provides the number of customers served by Southern Company Gas at June 30, 2019 and 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
The following table provides the number of customers served by Southern Company Gas at September 30, 2018 and 2017:
|
| | | | | | | | |
| | September 30, | | |
| | 2018 | | 2017 | | 2018 vs. 2017 |
| | (in thousands, except market share %) | | (% change) |
Gas distribution operations(a) | 4,177 |
| | 4,555 |
| | (8.3 | )% |
Gas marketing services(b) | | | | | |
Energy customers(c) | 685 |
| | 756 |
| | (9.4 | )% |
| Market share of energy customers in Georgia | 29.2 | % | | 28.8 | % | |
|
|
| |
(a) | Includes total customers of approximately 404,000 at September 30, 2017 related to Elizabethtown Gas, Elkton Gas, and Florida City Gas, which were sold in July 2018. See Note (J) to the Condensed Financial Statements under "Southern Company Gas – Sale of Elizabethtown Gas and Elkton Gas" and " – Sale of Florida City Gas" herein for additional information.
|
| |
(b) | On June 4, 2018, Southern Company Gas completed the sale of Pivotal Home Solutions, which served approximately 1.2 million contracts prior to disposition. See Note (J) to the Condensed Financial Statements under "Southern Company Gas – Sale of Pivotal Home Solutions" herein for additional information. |
| |
(c) | The decrease at September 30, 2018 is primarily due to approximately 70,000 fewer customers in Ohio contracted through an annual auction process to serve for 12 months beginning April 1, 2018. At September 30, 2017, there were approximately 140,000 customers in Ohio contracted through an annual auction process to serve for 12 months 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. Southern Company Gas uses a variety of targeted marketing programs to attract new customers and to retain existing customers.
Other Revenues
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(33) | | N/M | | $(40) | | (42.1) |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(24) | | (100.0) | | $(55) | | (100.0) |
N/M - Not meaningful
In the third quarter 2018, there were no other revenues compared to $33 million for the corresponding period in 2017. For year-to-date 2018, other revenues were $55 million compared to $95 million for the corresponding period in 2017. Other revenues related to Pivotal Home Solutions, which was sold onin June 4, 2018. See Note (J)15 to the Condensed Financial Statementsfinancial statements in Item 8 of the Form 10-K under "Southern"Southern Company Gas – Sale of Pivotal Home Solutions" herein for additional information.
Cost of Natural Gas
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(30) | | (22.4) | | $(32) | | (2.9) |
|
| | | | | | |
| Second Quarter 2019 vs. Second Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(37) | | (16.2) | | $(72) | | (7.6) |
NaturalExcluding 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 gas distribution operations. Cost of natural gas at gas distribution operations represented 75%80% and 83%85% of total cost of natural gas for the thirdsecond quarter and year-to-date 2018,2019, respectively. For additional information, seeSee MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – "Cost of Natural Gas and Other Sales"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
In the third quarter 2018, cost of natural gas was $104 million compared to $134 million for the corresponding period in 2017. The decrease reflects $14 million related to the Southern Company Gas Dispositions, which resulted in a decrease in the volume of natural gas sold in the third quarter 2018 as a result of fewer gas distribution operations customers, and a 3.2% decrease in natural gas prices during the third quarter 2018 compared to the corresponding period in 2017.
For year-to-date 2018, cost of natural gas was $1.05 billion compared to $1.09 billion for the corresponding period in 2017. The decrease reflects $8 million related to the Southern Company Gas Dispositions, which resulted in a decrease in the volume of natural gas sold in 2018 as a result of fewer gas distribution operations customers, as well as an 8.4% decrease in natural gas prices during 2018, partially offset by an increase in the volume of natural gas sold in 2018 as a result of colder weather compared to the corresponding period in 2017.
The following table details the volumes of natural gas sold during all periods presented.
| | | | Third Quarter | 2018
vs.
2017 | | Year-to-Date | 2018
vs.
2017 | Second Quarter | 2019
vs.
2018 | | Year-to-Date | 2019
vs.
2018 |
| | 2018 | 2017 | | 2018 | 2017 | 2019 | 2018 | | 2019 | 2018 |
Gas distribution operations (mmBtu in millions) | Gas distribution operations (mmBtu in millions) | | | | Gas distribution operations (mmBtu in millions) | | | |
| Firm | 69 |
| 73 |
| (5.5 | )% | | 503 |
| 438 |
| 14.8 | % | 99 |
| 119 |
| (16.8 | )% | | 396 |
| 434 |
| (8.8 | )% |
| Interruptible | 22 |
| 22 |
| — | % | | 71 |
| 71 |
| — | % | 22 |
| 25 |
| (12.0 | )% | | 46 |
| 49 |
| (6.1 | )% |
| Total | 91 |
| 95 |
| (4.2 | )% | | 574 |
| 509 |
| 12.8 | % | |
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) | |
| | |
| Gas marketing services (mmBtu in millions) | |
| | |
|
| Firm: | |
|
| | |
|
| |
|
| | |
|
|
| Georgia | 3 |
| 4 |
| (25.0 | )% | | 25 |
| 20 |
| 25.0 | % | 4 |
| 5 |
| (20.0 | )% | | 19 |
| 22 |
| (13.6 | )% |
| Illinois | 1 |
| 1 |
| — | % | | 9 |
| 8 |
| 12.5 | % | 2 |
| 2 |
| — |
| | 8 |
| 8 |
| — |
|
| Ohio | 1 |
| 2 |
| (50.0 | )% | | 12 |
| 6 |
| 100.0 | % | 1 |
| 2 |
| (50.0 | )% | | 8 |
| 11 |
| (27.3 | )% |
| Other | 1 |
| 1 |
| — | % | | 3 |
| 4 |
| (25.0 | )% | 1 |
| 1 |
| — |
| | 2 |
| 2 |
| — |
|
| Interruptible large commercial and industrial | 3 |
| 3 |
| — | % | | 10 |
| 10 |
| — | % | 3 |
| 3 |
| — |
| | 7 |
| 7 |
| — |
|
| Total | 9 |
| 11 |
| (18.2 | )% | | 59 |
| 48 |
| 22.9 | % | 11 |
| 13 |
| (15.4 | )% | | 44 |
| 50 |
| (12.0 | )% |
Wholesale gas services (mmBtu in millions/day) | |
|
| | |
|
| |
| Daily physical sales | 6.8 |
| 6.3 |
| 7.9 | % | | 6.7 |
| 6.4 |
| 4.7 | % | |
| |
| (*) | 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
| | | Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 | |
| Second Quarter 2019 vs. Second Quarter 2018 | | 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) | | (change in millions) | | (% change) |
$(7)(5) | | N/M | | $(8) | | (40.0) | | (100.0) | | $(12) | | (100.0) |
N/M - Not meaningful
In the third quarter 2018, there was no cost of other sales compared to $7 million for the corresponding period in 2017. For year-to-date 2018, cost of other sales was $12 million compared to $20 million for the corresponding period in 2017. Cost of other sales related to Pivotal Home Solutions, which was sold onin June 4, 2018. See Note (J)15 to the Condensed Financial Statementsfinancial statements in Item 8 of the Form 10-K under "Southern"Southern Company Gas – Sale of Pivotal Home Solutions" herein for additional information.
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) |
| $(39) | | (16.4) | | $(81) | | (15.8) |
In the second quarter 2019, other operations and maintenance expenses were $199 million compared to $238 million for the corresponding period in 2018. Excluding a $34 million decrease related to the Southern Company Gas Dispositions, other operations and maintenance expenses decreased $5 million. This decrease was primarily due 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 maintenance 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 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
Other Operations and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $10 | | 4.9 | | $55 | | 8.1 |
In the third quartera one-time adjustment in 2018 other operations and maintenance expenses were $216 million compared to $206 million for the corresponding period in 2017. The increase was primarily due to $21 million of disposition-related costs and a $12 million increase in compensation and benefit costs, partially offset by a $24 million decrease related to the Southern Company Gas Dispositions and a $7 million decrease in bad debt expense at gas distribution operations.
For year-to-date 2018, other operations and maintenance expenses were $730 million compared to $675 million for the corresponding period in 2017. The increase was primarily due to $29 million of disposition-related costs, a $48 million increase in compensation and benefit costs, including a $12 million one-time increase for the adoption of a new paid time off policy, to align with the Southern Company system,disposition-related costs incurred during 2018, and an $11 million reserve for a settlement of class action litigation to facilitate the sale of Pivotal Home Solutions. These increases weredecreased compensation and benefits costs, partially offset by an $11 million decrease related to the Southern Company Gas Dispositionsincrease in expenses associated with pipeline compliance and a $15 million decrease in bad debt expense at gas distribution operations. See Notes (B) and (J) to the Condensed Financial Statements under "General Litigation Matters – Southern Company Gas" and "Southern Company Gas," respectively, herein for additional information.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 on the new paid time off policy.information.
Depreciation and Amortization
| | | Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 | |
| Second Quarter 2019 vs. Second Quarter 2018 | | 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) | | (change in millions) | | (% change) |
$(6)(7) | | (4.8) | | $4 | | 1.1 | | (5.6) | | $(17) | | (6.7) |
In the thirdsecond quarter 2018,2019, depreciation and amortization was $119 million compared to $126 million for the corresponding period in 2018. Excluding a $10 million decrease related to the Southern Company Gas Dispositions, depreciation and amortization increased $3 million. This increase was primarily due to continued infrastructure investments at gas distribution operations.
For year-to-date 2019, depreciation and amortization was $238 million compared to $255 million for the corresponding period in 2018. Excluding a $26 million decrease related to the Southern Company Gas Dispositions, depreciation and amortization increased $9 million. This increase was primarily due to continued infrastructure investments at gas distribution operations.
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) |
| $(2) | | (4.2) | | $3 | | 2.4 |
In the second quarter 2019, taxes other than income taxes were $46 million compared to $48 million for the corresponding period in 2018. 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 2017. The decrease was primarily due to2018. Excluding a $15$6 million decrease related to the Southern Company Gas Dispositions, partially offset by continued infrastructure investments recovered through replacement programs at gas distribution operations and lower amortization of intangible assets as a result of fair value adjustments in acquisition accounting at gas marketing services.
For year-to-date 2018, depreciation and amortization was $374 million compared to $370 million for the corresponding period in 2017. The increase was primarily due to continued infrastructure investments recovered through replacement programs at gas distribution operations, partially offset by a $20 million decrease related to the Southern Company Gas Dispositions and lower amortization of intangible assets as a result of fair value adjustments in acquisition accounting at gas marketing services.
See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information on the Southern Company Gas Dispositions.
Taxes Other Than Income Taxes
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $6 | | 23.1 | | $17 | | 12.1 |
In the third quarter 2018, taxes other than income taxes were $32 million compared to $26 million for the corresponding period in 2017.increased $9 million. This increase primarily reflects a $5 million creditincreases in 2017 to establish a regulatory asset related to Nicor Gas' invested capital tax.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2018, taxes other than income taxes were $157 million compared to $140 million for the corresponding period in 2017. This increase primarily reflects an $8 million increase intax as a result of increased infrastructure investments and increased revenue tax expenses as a result of higher natural gas revenues a $5 million credit in 2017at Nicor Gas, both of which are passed through to establish a regulatory asset related to Nicor Gas' invested capital tax, and a $2 million increase in payroll taxes related to benefits under the new paid time off policy.customers.
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 on the new paid time off policy. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information on the Southern Company Gas Dispositions.
Gain on Dispositions, Net
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $353 | | N/M | | $317 | | N/M |
N/M - Not meaningful
In the third quarter 2018, gain on dispositions, net of $353 million reflects the July 1, 2018 sales of the assets of Elizabethtown Gas and Elkton Gas, the July 29, 2018 sale of Pivotal Utility Holdings, and the final working capital adjustment for the sale of Pivotal Home Solutions. The year-to-date 2018 amount also reflects a $36 million pre-tax loss on the June 4, 2018 sale of Pivotal Home Solutions recorded during the second quarter 2018. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
Goodwill Impairment
|
| | | | | | |
ThirdSecond Quarter 20182019 vs. ThirdSecond Quarter 20172018 | | Year-to-Date 20182019 vs. Year-to-Date 20172018 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $— | | N/M | | $42(42) | | N/M |
N/M - Not meaningful
For year-to-date 2018, aA goodwill impairment charge of $42 million was recorded during the first quarter 2018 in contemplation of the sale of Pivotal Home Solutions. See Notes (A) and (J)Note 15 to the Condensed Financial Statementsfinancial statements in Item 8 of the Form 10-K under "Goodwill and Other Intangible Assets" and "Southern"Southern Company Gas – Sale of Pivotal Home Solutions," respectively, hereinSolutions" for additional information.
Earnings from Equity Method Investments
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $2 | | 6.3 | | $8 | | 8.0 |
In the third quarter 2018, earnings from equity method investments were $34 million compared to $32 million for the corresponding period in 2017. For year-to-date 2018, earnings from equity method investments were $108 million compared to $100 million for the corresponding period in 2017. These increases were primarily due to higher earnings from Southern Company Gas' equity method investment in SNG. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.Table of ContentsSOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Interest Expense, Net of Amounts CapitalizedLoss on Disposition
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1 | | 2.0 | | $25 | | 17.2 |
|
| | | | | | |
| 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
|
| | | | | | |
| 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 second quarter 2019 and 2018, earnings from equity method investments were $31 million. For year-to-date 2018, interest expense, net of amounts capitalized was $1702019, earnings from equity method investments were $80 million compared to $145$74 million for the corresponding period in 2017. This increase was primarily due to $202018. For both the second quarter and year-to-date 2019, earnings from equity method investments reflect higher earnings from SNG as 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 additional interest expense on new debt issuances and additional commercial paper borrowings, and a $5 million reductionTriton in capitalized interest dueMay 2019. See Note (E) to the Dalton Pipeline being placed in service in August 2017.Condensed Financial Statements under "Southern Company Gas" herein for additional information.
Other Income (Expense), Net
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(13) | | (68.4) | | $(9) | | (30.0) |
|
| | | | | | |
| 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 2018,For year-to-date 2019, other income (expense), net was $6$10 million compared to $19$15 million for the corresponding period in 2017.2018. This decrease was primarily due to a $14 million gain from the settlement of contractor litigation claimssettlement in 2017.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.
For year-to-date 2018, otherIncome 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) |
| $(49) | | (89.1) | | $(76) | | (47.8) |
In the second quarter 2019, income (expense), net was $21taxes were $6 million compared to $30$55 million for the corresponding period in 2017.2018. Excluding a $38 million decrease related to the Southern Company Gas Dispositions, income taxes decreased $11 million. The decrease was primarily due 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 $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 $9an 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 $13 million lower gains fromfederal income tax valuation allowance in connection with the settlementsale of contractor litigation claimsTriton in 2018 compared to the corresponding period in 2017.May 2019.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
See Note (B)(E) to the Condensed Financial Statements under "Regulatory Matters – Southern Company Gas – Atlanta Gas Light's Pipeline Replacement Program" herein for additional information.
Income Taxes
|
| | | | | | |
| Third Quarter 2018 vs. Third Quarter 2017 | | Year-to-Date 2018 vs. Year-to-Date 2017 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $264 | | N/M | | $242 | | N/M |
N/M - Not meaningful
In the third quarter 2018, income taxes were $316 million compared to $52 million for the corresponding period in 2017. For year-to-date 2018, income taxes were $475 million compared to $233 million for the corresponding period in 2017. These increases were primarily due to tax expense resulting from the Southern Company Gas Dispositions, including tax expenseinformation on the goodwillsale of Triton and Note 2 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for which a deferred tax liability had not been previously provided, partially offset by a lower federal income tax rate andadditional information on the flowback of excess deferred taxes as a resultAtlanta Gas Light stipulation reflecting the impacts of the Tax Reform Legislation. In addition, third quarter and year-to-date 2017 included a $23 million deferred tax expense related to the enactment of the State of Illinois income tax legislation and new income tax apportionment factors in several states.
See Notes (H) and (J)Also see Note (G) to the Condensed Financial Statements under "Effective Tax Rate" and "Southern Company Gas," respectively, herein for additional information.
Performance and Non-GAAP Measures
Adjusted operating margin is a non-GAAP measure that is calculated as operating revenues less 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 gainloss on dispositions, net,disposition, which are included in the calculation of operating income as calculated in accordance with GAAP and reflected in the 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
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
Adjusted operating margin should not be considered an alternative to, or a more meaningful indicator of, Southern Company Gas' operating performance than 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.
| | | | Third Quarter 2018 | Third Quarter 2017 | | Year-to-Date 2018 | Year-to-Date 2017 | Second Quarter 2019 | Second Quarter 2018 | | Year-to-Date 2019 | Year-to-Date 2018 |
| | (in millions) | (in millions) |
| Operating Income | $ | 374 |
| $ | 67 |
| | $ | 810 |
| $ | 551 |
| $ | 134 |
| $ | 49 |
| | $ | 487 |
| $ | 436 |
|
Other operating expenses(a) | 14 |
| 357 |
| | 986 |
| 1,185 |
| 364 |
| 448 |
| | 799 |
| 972 |
|
Revenue taxes(b) | (8 | ) | (8 | ) | | (81 | ) | (74 | ) | (22 | ) | (23 | ) | | (76 | ) | (73 | ) |
| Adjusted Operating Margin | $ | 380 |
| $ | 416 |
| | $ | 1,715 |
| $ | 1,662 |
| $ | 476 |
| $ | 474 |
| | $ | 1,210 |
| $ | 1,335 |
|
| |
| (a) | Includes other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, goodwill impairment, and gainloss on dispositions, net.disposition. |
| |
| (b) | Nicor Gas' revenue tax expenses, which are passed through directly to customers. |
Segment Information
Adjusted operating margin, operating expenses, and net income for each segment is illustrated in the tables below. See Note (L) to the Condensed Financial Statements herein for additional information.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Third Quarter 2018 |
| Third Quarter 2017 |
| Adjusted Operating Margin(a) | | Operating Expenses(a)(b) | | Net Income (Loss)(b) | | Adjusted Operating Margin(a) | | Operating Expenses(a) | | Net Income (Loss) |
| | (in millions) | | (in millions) |
| Gas distribution operations | $ | 355 |
|
| $ | (80 | ) |
| $ | 74 |
|
| $ | 379 |
|
| $ | 272 |
|
| $ | 52 |
|
| Gas marketing services | 19 |
|
| 28 |
|
| (8 | ) |
| 51 |
|
| 48 |
|
| 1 |
|
| Wholesale gas services | (8 | ) |
| 14 |
|
| (18 | ) |
| (25 | ) |
| 11 |
|
| (23 | ) |
| Gas midstream operations | 15 |
|
| 15 |
|
| 16 |
|
| 12 |
|
| 13 |
|
| 14 |
|
| All other | 1 |
|
| 31 |
|
| (18 | ) |
| 2 |
|
| 8 |
|
| (29 | ) |
| Intercompany eliminations | (2 | ) |
| (2 | ) |
| — |
|
| (3 | ) |
| (3 | ) |
| — |
|
| Consolidated | $ | 380 |
| | $ | 6 |
| | $ | 46 |
| | $ | 416 |
| | $ | 349 |
| | $ | 15 |
|
| |
(a) | Adjusted operating margin and operating expenses are adjusted for Nicor Gas revenue tax expenses, which are passed through directly to customers. |
| |
(b) | Operating expenses for gas distribution operations and gas marketing services include the gain on dispositions, net. Net income for gas distribution operations and gas marketing services includes the gain on dispositions, net and the associated income tax expense. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
|
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Segment Information
Adjusted operating margin, operating expenses, and net income for each segment are provided in the table below. See Note (M) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
| | | | Year-to-Date 2018 | | Year-to-Date 2017 | Second Quarter 2019 |
| Second Quarter 2018 |
| | Adjusted Operating Margin(a) | | Operating Expenses(a)(b)(c) | | Net Income (Loss)(c) | | Adjusted Operating Margin(a) | | Operating Expenses(a) | | Net Income (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 | $ | 1,341 |
|
| $ | 540 |
|
| $ | 290 |
|
| $ | 1,329 |
|
| $ | 870 |
|
| $ | 223 |
| $ | 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 | 194 |
|
| 209 |
|
| (71 | ) |
| 213 |
|
| 149 |
|
| 36 |
| 27 |
|
| 31 |
|
| (3 | ) |
| 48 |
| | 87 |
| | (76 | ) |
| Wholesale gas services | 139 |
|
| 50 |
|
| 65 |
|
| 93 |
|
| 40 |
|
| 28 |
| |
| Gas midstream operations | 44 |
|
| 44 |
|
| 54 |
|
| 28 |
|
| 38 |
|
| 38 |
| |
| All other | 3 |
|
| 68 |
|
| (44 | ) |
| 7 |
|
| 22 |
|
| (22 | ) | 7 |
|
| 12 |
|
| 3 |
|
| 6 |
|
| 26 |
|
| (23 | ) |
| Intercompany eliminations | (6 | ) |
| (6 | ) |
| — |
|
| (8 | ) |
| (8 | ) |
| — |
| (1 | ) |
| (1 | ) |
| — |
|
| (1 | ) |
| (1 | ) |
| — |
|
| Consolidated | $ | 1,715 |
| | $ | 905 |
| | $ | 294 |
| | $ | 1,662 |
| | $ | 1,111 |
| | $ | 303 |
| $ | 476 |
| | $ | 342 |
| | $ | 106 |
| | $ | 474 |
| | $ | 425 |
| | $ | (31 | ) |
| |
| (a) | Adjusted operating margin and operating expenses are adjusted for Nicor GasGas' revenue tax expenses, which are passed through directly to customers. |
| |
| (b) | Operating2018 adjusted operating margin, operating expenses, for gas marketing services include a goodwill impairment charge of $42 million recorded during the first quarter 2018 in contemplation of the sale of Pivotal Home Solutions. See Note (A) to the Condensed Financial Statements under "Goodwill and Other Intangible Assets" and Note (J) to the Condensed Financial Statements under "Southern Company Gas – Sale of Pivotal Home Solutions" herein for additional information.
|
| |
(c) | Operating expensesnet income for gas distribution operations and gas marketing services include the gain on dispositions, net. Netimpacts 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.
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | 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) | Adjusted 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 includesinclude the gain on dispositions, net andimpacts of the associated income tax expense.Southern Company Gas Dispositions. See Note (J)15 to the Condensed Financial Statementsfinancial statements in Item 8 of the Form 10-K under "Southern"Southern Company Gas" hereinGas" 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.
OnIn July 1, 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. OnAlso in July 29, 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 (J)15 to the financial statements in Item 8 of the Form 10-K under "Southern"Southern Company Gas" hereinGas" for additional information.
ThirdExcluding 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 2019 vs. Second Quarter 2018 vs. Third Quarter 2017
In the thirdsecond quarter 2018,2019, net income increased $22decreased $7 million, or 42.3%10.8%, compared to the corresponding period in 2017. This2018. The $10 million increase primarily relates to a $352 million decrease in operating expenses, partially offset by a $24 million decrease in adjusted operating margin an $18 million decreaseprimarily reflects additional revenue from continued investments recovered through infrastructure replacement programs, partially offset by warmer weather in total other income (expense), net, and a $288Illinois during the second quarter 2019 compared to the corresponding period in 2018. The $26 million increase in income tax expense.
Excluding a $381 million decrease attributable to the utilities sold during 2018, including the related gain, operating expenses includes increased $29 million, which primarily reflectscompensation and benefit 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 serviceservice. The $9 million increase in interest expense results from the issuance of first mortgage bonds at Nicor Gas in the prior year. Income tax expense decreased $18 million primarily due to an increase in the flowback of excess deferred income taxes at Atlanta Gas Light in 2019 and lower pre-tax earnings.
Year-to-Date 2019 vs. Year-to-Date 2018
For year-to-date 2019, net income increased $8 million, or 4.4%, compared to the corresponding period in 2018. The $65 million increase in adjusted operating margin primarily 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 benefit costs, partially offset by ahigher 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 bad debt expense. Excludingother income (expense), net is primarily due to a contractor litigation settlement in the first quarter 2018. The $17 million increase in interest expense is primarily from the issuance of first mortgage bonds at Nicor Gas in the prior year. The $23 million decrease in income tax expense is primarily due to
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
a $29 million decreasean increase in adjusted operating margin attributable to the utilities sold during 2018, adjusted operating margin increased $5 million, which primarily reflects additional revenue from continued infrastructure investments recovered through replacement programs and base rates, partially offset by lower rates and revenue deferrals for regulatory liabilities associated with Tax Reform Legislation impacts. The decrease in other income (expense), net primarily reflects a $14 million gain from the settlement of contractor litigation claims in 2017 and $7 million of additional interest expense primarily from the issuance of first mortgage bonds at Nicor Gas. Excluding a $314 million decrease attributable to the utilities sold in 2018, income tax expense decreased $26 million, primarily due to a lower federal income tax rate and the flowback of excess deferred income taxes as a resultin 2019, primarily at Atlanta Gas Light and 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.Legislation and the contractor litigation settlement, respectively.
Year-to-Date 2018 vs. Year-to-Date 2017Gas Pipeline Investments
ForGas 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 2018,2019, net income increased $67$4 million, or 30.0%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 2017.2018. This increase primarily relates to a $12$57 million increase in adjusted operating margin and a $330$4 million decrease in operating expenses, partially offset by a $23an increase of $18 million decrease in total other income (expense), net, and a $252 million increase in income tax expense.
Excluding a $21 million decrease attributable to the utilities sold during 2018, adjusted operating margin increased $33 million, which primarily reflects additional revenue from continued infrastructure investments recovered through replacement programs and base rates and colder weather in 2018, partially offset by lower rates and revenue deferrals for regulatory liabilities associated with Tax Reform Legislation impacts. Excluding a $378 million decrease attributable to the utilities sold during 2018, including the related gain, operating expenses increased $48 million, which primarily reflects $27 million of additional depreciation primarilyexpense due to additional assets placed in service and increased compensation and benefit costs, partially offset by a decrease in bad debt expense. The decrease in otherhigher pre-tax earnings. For year-to-date 2019, net income (expense), net primarily reflects $16decreased $13 million, of additional interest expense primarily from the issuance of first mortgage bonds at Nicor Gas and commercial paper borrowings and $9 million lower gains from the settlement of contractor litigation claims during 2018or 15.7%, compared to the corresponding period in 2017,2018. This decrease primarily relates to a $22 million decrease in adjusted operating margin, partially offset by an increase in interest income. Excluding a $307$7 million decrease attributablein 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 prior 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 utilities soldcorresponding period in 2018 income tax expense decreased $55 million,was primarily due to significant natural gas price volatility that resulted from prolonged cold weather during 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 lower federal income tax ratenumber 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 flowbackability of excess deferred taxes as awholesale 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 Tax Reform Legislation.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 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 Services
Gas marketing services consists of several businesses that provideprovides energy-related products and services to natural gas markets.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 (J)15 to the financial statements in Item 8 of the Form 10-K under "Southern"Southern Company Gas" hereinGas" for additional information.
ThirdSecond Quarter 2019 vs. Second Quarter 2018 vs. Third Quarter 2017
In the thirdsecond quarter 2018,2019, net incomeloss decreased $9$73 million compared to the corresponding period in 2017.2018. This decrease primarily relates to a $32 million decrease in adjusted operating margin, partially offset by a $20$56 million decrease in operating expenses and a $4 million decrease in income tax expense.
Excluding a $26 million decrease attributable to Pivotal Home Solutions, adjusted operating margin decreased $6 million, which primarily reflects a $5 million decrease due to the timing of revenue recognition for fixed and guaranteed bill revenue as a result of adopting a new revenue recognition standard. The decrease in operating expenses primarily reflects a $19 million decrease attributable to Pivotal Home Solutions. The decrease in income tax expense was driven by a higher pretax loss, partially offset by a lower federal income tax rate.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Year-to-Date 2018 vs. Year-to-Date 2017
For year-to-date 2018, net income decreased $107 million compared to the corresponding period in 2017. This decrease primarily relates to a $19 million decrease in adjusted operating margin, a $60 million increase in operating expenses, and a $28 million increase in income tax expense.
Excluding a $33 million decrease attributable to Pivotal Home Solutions, adjusted operating margin increased $14 million, which primarily reflects colder weather in 2018. Excluding a $62 million increase attributable to Pivotal Home Solutions that includes the loss on disposition and the goodwill impairment charge, operating expense decreased $2 million primarily due to a decrease in depreciation and amortization primarily due to lower amortization of intangible assets as a result of fair value adjustments recorded during acquisition accounting, partially offset by higher bad debt expenses and compensation and benefit costs. The increase in income tax expense was driven by higher pretax earnings, partially offset by a lower federal income tax rate.
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.
Third Quarter 2018 vs. Third Quarter 2017
In the third quarter 2018, net loss decreased $5 million, or 21.7%, compared to the corresponding period in 2017. This increase primarily relates to a $17 million increase in adjusted operating margin, partially offset by a $3 million increase in operating expenses and an $8 million decrease in income tax benefit. Details of the increase in adjusted operating margin are provided in the table below. The increase in operating expenses primarily reflects higher compensation and benefit expense. The decrease in income tax benefit was driven by a lower pretax loss, partially offset by a lower federal income tax rate.
Year-to-Date 2018 vs. Year-to-Date 2017
For year-to-date 2018, net income increased $37 million, or 132.1%, compared to the corresponding period in 2017. This increase primarily relates to a $46 million increase in adjusted operating margin and a $2$36 million decrease in income tax expense, partially offset by a $10$21 million increase in operating expenses. Details of the increasedecrease in adjusted operating margin are provided in the table below. The increase in operating expenses primarily reflects higher compensation and benefit expense.margin. The decrease in income tax expense was driven by a lower federal income tax rate.
|
| | | | | | | | | | | | | |
| | Third Quarter 2018 | Third Quarter 2017 | | Year-to-Date 2018 | Year-to-Date 2017 |
| | (in millions) |
| Commercial activity recognized | $ | 33 |
| $ | 3 |
| | $ | 212 |
| $ | 80 |
|
| Gain (loss) on storage derivatives | (3 | ) | 4 |
| | (2 | ) | 13 |
|
| Gain (loss) on transportation and forward commodity derivatives | (33 | ) | (22 | ) | | (70 | ) | 14 |
|
| Purchase accounting adjustments to fair value inventory and contracts | (5 | ) | (10 | ) | | (1 | ) | (14 | ) |
| Adjusted operating margin | $ | (8 | ) | $ | (25 | ) | | $ | 139 |
| $ | 93 |
|
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Change in Commercial Activity
The increase in commercial activity in the third quarter and year-to-date 2018 comparednet loss is primarily attributable to the corresponding periods in 2017 was primarily due to natural gas price volatility that was generated by favorable weather and a corresponding increase in power generation volumes coupled with decreased natural gas supply.2018 disposition of Pivotal Home Solutions.
Change in Storage and Transportation DerivativesYear-to-Date 2019 vs. Year-to-Date 2018
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. Forward storage or time spreads applicable to the locations of wholesale gas services' specific storage positions in 2018 resulted in storage derivative losses. Transportation and forward commodity derivative losses in 2018 are primarily the result of widening transportation spreads due to favorable weather, which impacted forward prices at natural gas receipt and delivery points, primarily in the Northeast and Midwest regions.
Withdrawal Schedule and Physical Transportation Transactions
The expected natural gas withdrawals from storage and expected offset to prior hedge losses/gains associated with the transportation portfolio of wholesale gas services are presented in the following table, along with the net operating revenues expected at the time of withdrawal from storage and the physical flow of natural gas between contracted transportation receipt and delivery points. Wholesale gas services' expected net operating revenues exclude storage and transportation demand charges, as well as other variable fuel, withdrawal, receipt, and delivery charges, 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 September 30, 2018. 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 gains(c) |
| | (in mmBtu in millions) | | (in millions) | | (in millions) |
| 2018 | 10.2 |
| | $ | 4 |
| | $ | 5 |
|
| 2019 and thereafter | 26.1 |
| | 9 |
| | 65 |
|
| Total at September 30, 2018 | 36.3 |
| | $ | 13 |
| | $ | 70 |
|
| |
(a) | At September 30, 2018, the WACOG of wholesale gas services' expected natural gas withdrawals from storage was $2.51 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 periods associated with the transportation derivative gains and (losses) during which the derivatives will be settled 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.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 (K) to the Condensed Financial Statements herein and Note 4 to the financial statements of Southern Company Gas in Item 8 of the Form 10-K for additional information.
Third Quarter 2018 vs. Third Quarter 2017
In the third quarter 2018,year-to-date 2019, net income increased $2$121 million or 14.3%, compared to the corresponding period in 2017.2018. This increase primarily relates to a $3$119 million increasedecrease in adjusted operating margin primarily due to the Dalton Pipeline being placed in service in August 2017expenses and a $2$33 million net increasedecrease in earnings from equity method investments in SNG and PennEast Pipeline,income tax expense, partially offset by a $2$33 million increase in interest expense primarily due to a reduction in capitalized interest after the Dalton Pipeline was placed in service.
Year-to-Date 2018 vs. Year-to-Date 2017
For year-to-date 2018, net income increased $16 million, or 42.1%, compared to the corresponding period in 2017. This increase primarily relates to a $16 million increasedecrease in adjusted operating margin primarily duemargin.
Excluding a $43 million decrease attributable to the Dalton Pipeline being placed in service in August 2017, partially offset by2018 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 reduction in storage revenues. The increase in net income also relates$118 million decrease attributable to an $8 million net increase in earnings from equity method investments primarily at SNG, partially offset by a $7 million increase in interestthe 2018 disposition of Pivotal Home Solutions that includes the related goodwill impairment charge, operating expense primarily due to a reduction in capitalized interest after the Dalton Pipeline was placed in service.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.
ThirdSecond Quarter 20182019 vs. ThirdSecond Quarter 20172018
In the thirdsecond quarter 2018,2019, net loss decreased $11income increased $26 million compared to the corresponding period in 2017.2018. This increase primarily reflects a $14 million decrease includesin operating expenses and a $27$13 million decrease in income tax expense primarily related to the 2017 enactment of the State of Illinois income tax legislation and new income tax apportionment factors in several states and a $4 milliontaxes. The decrease in interest expense, net of amounts capitalizedoperating expenses was primarily due to decreased interest expense on lower commercial paper borrowings, partially offset by $21 million of disposition-related costs andincurred during 2018. The decrease in income taxes reflects lower taxes due to the reversal of a lower federal income tax ratevaluation allowance in 2018.connection with the sale of Triton.
Year-to-Date 20182019 vs. Year-to-Date 20172018
For year-to-date 2018,2019, net lossincome increased $22$36 million compared to the corresponding period in 2017.2018. This increase primarily reflects a $46$31 million increasedecrease in operating expenses and a $2$10 million increasedecrease in interest expense, net of amounts capitalized,income taxes, partially offset by a $27$2 million decrease in income tax expense.adjusted operating margin. The increasedecrease in operating expenses primarily reflects $29 million of disposition-related costs and a $12 million increaseone-time adjustment in compensation expense resulting fromthe first quarter 2018 for the adoption of thea new paid time off policy. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Southern Company Gaspolicy, disposition-related costs incurred during 2018, and a decrease in Item 7 of the Form 10-K for additional information on the new paid time off policy.depreciation and amortization. The decrease in income tax expense was primarily relatedtaxes reflects lower taxes due to the 2017 enactmentreversal of the State of Illinois income tax legislation and new income tax apportionment factors in several states, partially offset by a lower federal income tax ratevaluation allowance in 2018.connection with the sale of Triton.
Segment Reconciliations
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Segment Reconciliations
Reconciliations of operating income to adjusted operating margin for the second quarter and year-to-date 2019 and 2018 are reflected in the following tables. See Note (M) to the Condensed Financial Statements herein for additional information.
| |
| Third Quarter 2018 | Second Quarter 2019 |
| Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services | Gas Midstream Operations | All Other | Intercompany Elimination | Consolidated | Gas Distribution Operations | Gas Pipeline Investments | Wholesale Gas Services | Gas Marketing Services | All Other | Intercompany Elimination | Consolidated |
| (in millions) | (in millions) |
| Operating Income (Loss) | $ | 435 |
| $ | (9 | ) | $ | (22 | ) | $ | — |
| $ | (30 | ) | $ | — |
| $ | 374 |
| $ | 107 |
| $ | 5 |
| $ | 31 |
| $ | (4 | ) | $ | (5 | ) | $ | — |
| $ | 134 |
|
Other operating expenses(a) | (72 | ) | 28 |
| 14 |
| 15 |
| 31 |
| (2 | ) | 14 |
| 309 |
| 3 |
| 10 |
| 31 |
| 12 |
| (1 | ) | 364 |
|
Revenue tax expense(b) | (8 | ) | — |
| — |
| — |
| — |
| — |
| (8 | ) | (22 | ) | — |
| — |
| — |
| — |
| — |
| (22 | ) |
| Adjusted Operating Margin | $ | 355 |
| $ | 19 |
| $ | (8 | ) | $ | 15 |
| $ | 1 |
| $ | (2 | ) | $ | 380 |
| $ | 394 |
| $ | 8 |
| $ | 41 |
| $ | 27 |
| $ | 7 |
| $ | (1 | ) | $ | 476 |
|
| | | | Third Quarter 2017 | Second Quarter 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) | $ | 107 |
| $ | 3 |
| $ | (36 | ) | $ | (1 | ) | $ | (6 | ) | $ | — |
| $ | 67 |
| $ | 133 |
| $ | 5 |
| $ | (30 | ) | $ | (39 | ) | $ | (20 | ) | $ | — |
| $ | 49 |
|
Other operating expenses(a) | 280 |
| 48 |
| 11 |
| 13 |
| 8 |
| (3 | ) | 357 |
| 319 |
| 3 |
| 14 |
| 87 |
| 26 |
| (1 | ) | 448 |
|
Revenue tax expense(b) | (8 | ) | — |
| — |
| — |
| — |
| — |
| (8 | ) | (23 | ) | — |
| — |
| — |
| — |
| — |
| (23 | ) |
| Adjusted Operating Margin | $ | 379 |
| $ | 51 |
| $ | (25 | ) | $ | 12 |
| $ | 2 |
| $ | (3 | ) | $ | 416 |
| $ | 429 |
| $ | 8 |
| $ | (16 | ) | $ | 48 |
| $ | 6 |
| $ | (1 | ) | $ | 474 |
|
| | | | Year-to-Date 2018 | Year-to-Date 2019 |
| | Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services | Gas Midstream Operations | All Other | Intercompany Elimination | Consolidated | Gas Distribution Operations | Gas Pipeline Investments | Wholesale Gas Services | Gas Marketing Services | All Other | Intercompany Elimination | Consolidated |
| | (in millions) | (in millions) |
| Operating Income (Loss) | $ | 801 |
| $ | (15 | ) | $ | 89 |
| $ | — |
| $ | (65 | ) | $ | — |
| $ | 810 |
| $ | 317 |
| $ | 10 |
| $ | 96 |
| $ | 80 |
| $ | (16 | ) | $ | — |
| $ | 487 |
|
Other operating expenses(a) | 621 |
| 209 |
| 50 |
| 44 |
| 68 |
| (6 | ) | 986 |
| 677 |
| 6 |
| 29 |
| 62 |
| 29 |
| (4 | ) | 799 |
|
Revenue tax expense(b) | (81 | ) | — |
| — |
| — |
| — |
| — |
| (81 | ) | (76 | ) | — |
| — |
| — |
| — |
| — |
| (76 | ) |
| Adjusted Operating Margin | $ | 1,341 |
| $ | 194 |
| $ | 139 |
| $ | 44 |
| $ | 3 |
| $ | (6 | ) | $ | 1,715 |
| $ | 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
| | | | Year-to-Date 2017 | 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) | $ | 459 |
| $ | 64 |
| $ | 53 |
| $ | (10 | ) | $ | (15 | ) | $ | — |
| $ | 551 |
| $ | 366 |
| $ | 10 |
| $ | 111 |
| $ | (6 | ) | $ | (45 | ) | $ | — |
| $ | 436 |
|
Other operating expenses(a) | 944 |
| 149 |
| 40 |
| 38 |
| 22 |
| (8 | ) | 1,185 |
| 693 |
| 6 |
| 36 |
| 181 |
| 60 |
| (4 | ) | 972 |
|
Revenue tax expense(b) | (74 | ) | — |
| — |
| — |
| — |
| — |
| (74 | ) | (73 | ) | — |
| — |
| — |
| — |
| — |
| (73 | ) |
| Adjusted Operating Margin | $ | 1,329 |
| $ | 213 |
| $ | 93 |
| $ | 28 |
| $ | 7 |
| $ | (8 | ) | $ | 1,662 |
| $ | 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 gainloss on dispositions, net.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 OFFINANCIAL 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 Southern 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 constructive regulatory environments that allow for the timely recovery of prudently-incurred costs, the completion and subsequent operation of ongoing infrastructure and other construction projects, creditworthiness of customers, its ability to optimize its transportation and storage positions, and its ability to re-contract storage rates at favorable prices.
Future earnings will be driven by customer growth and 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 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.
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, 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.
On June 4, 2018, Southern Company Gas completed the stock sale
On July 1, 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. Prior to these dispositions, 2018 net income attributable to Elizabethtown Gas and Elkton Gas was $45 million. Southern Company Gas and South Jersey Industries, Inc. entered into transition services agreements whereby Southern Company Gas will provide certain administrative and operational services through no later than January 31, 2020.SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
On July 29, 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI Corporation, completed the stock sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energy. Prior to its disposition, 2018 net income attributable to Florida City Gas was $29 million. Southern Company Gas and NextEra Energy entered into a transition services agreement whereby Southern Company Gas will provide certain administrative and operational services through no later than July 29, 2020.MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Due to 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 2018 net income is2019 results are not necessarily indicative of the results to be expected for any other period.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information on these dispositions. See OVERVIEW – "Seasonality of Results" for additional information on seasonality.
Environmental Matters
New or revised environmental laws and regulations could affect many areas of Southern Company Gas' 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. Further, increased 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 (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 under "Environmental Remediation" in Item 8 of the Form 10-K for additional information.
Regulatory Matters
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 additional information regarding Southern Company Gas' regulatory matters.
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.
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
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 have separate rate riders that provide for timely recovery of capital expenditures for specific infrastructure replacement programs. Infrastructure expenditures incurred under these programs in the first six months of 2019 were as follows:
|
| | | | |
| 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 April 8, 2019, Virginia Natural Gas filed an application with the Virginia 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 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.
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 15, 2019, the Virginia Commission approved 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 material impact on its financial statements.
FERC Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Southern Company Gas in Item 7 of the Form 10-K and Notes 7 and 9 to the financial statements under "Southern Company Gas – Equity Method Investments" and "Guarantees," respectively, in Item 8 of the Form 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 Form 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 business. The
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 Gas' 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.
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 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 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 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.
Recently Issued Accounting Standards
See Note (A) to the Condensed Financial Statements herein for information regarding Southern Company Gas' recently adopted accounting standards.
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. Southern Company Gas' financial condition remained stable at June 30, 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. At June 30, 2019, the amount of subsidiary retained earnings restricted to dividend totaled $888 million. This restriction did not impact Southern Company Gas' ability to meet its cash obligations.
Net cash provided from operating activities totaled $931 million for the first six months of 2019, a decrease of $387 million from the corresponding period in 2018. The decrease was primarily due to the impacts of the Southern Company Gas Dispositions and the timing of vendor payments, partially offset by the timing of collection of customer receivables. Net cash used for investing activities totaled $586 million for the first six months of 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 and infrastructure investments recovered through replacement programs at gas distribution operations and capital contributed to equity method pipeline investments, partially offset by proceeds from the sale of Triton. Net cash used for financing activities totaled $355 million for the first six months of 2019 primarily due to repayments of commercial paper borrowings and a common stock dividend payment to Southern Company. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first six months of 2019 include a decrease of $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 to net repayments of commercial paper borrowings. Other significant balance sheet changes include decreases of $440 million and $463 million in energy marketing receivables and payables, respectively, due to lower natural gas 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 and 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. 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 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 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 from sources similar to those used in the past, which were primarily from operating cash flows, 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 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.
Subsequent to June 30, 2019, Southern Company Gas received a $400 million capital contribution from Southern Company.
Southern Company Gas' current liabilities exceeded current assets by $682 million primarily as a result of $492 million in notes 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 AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
At June 30, 2019, Southern Company Gas had $56 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2019 were as follows:
|
| | | | | | | |
| Company | Expires 2024 | | Unused |
| | (in millions) |
Southern Company Gas Capital(a) | $ | 1,250 |
| | $ | 1,245 |
|
| Nicor Gas | 500 |
| | 500 |
|
Total(b) | $ | 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. |
See Note 8 to the consolidated 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.
In May 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 (Facility) contains a covenant that limits the debt levels 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 June 30, 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. Short-term borrowings are included in notes payable in the balance sheets.
Details of short-term borrowings were as follows:
|
| | | | | | | | | | | | | | | | | |
| | Short-Term Debt at June 30, 2019 | | Short-Term Debt During the Period(*) |
| | Amount
Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| Commercial paper: | (in millions) | | | | (in millions) | | | | (in millions) |
| Southern Company Gas Capital | $ | 372 |
| | 2.6 | % | | $ | 297 |
| | 2.7 | % | | $ | 436 |
|
| Nicor Gas | 120 |
| | 2.6 |
| | 27 |
| | 2.6 |
| | 120 |
|
| Total | $ | 492 |
| | 2.6 | % | | $ | 324 |
| | 2.7 | % | | |
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 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 requirement under these contracts at June 30, 2019 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.
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 Southern Company Gas, may be negatively impacted. Southern Company Gas 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' 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 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' balance sheets includes both principal and non-principal components. As of June 30, 2019, the non-principal components totaled $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.
Southern Company Gas did not issue or redeem any securities during the six months ended June 30, 2019.
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.
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 second quarter 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 (I) and (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. 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. For the periods presented below, the changes in net fair value of Southern Company Gas' derivative contracts were as follows:
|
| | | | | | | | | | | | | |
| | Second Quarter 2019 | Second Quarter 2018 | | Year-to-Date 2019 | Year-to-Date 2018 |
| | (in millions) |
| Contracts outstanding at beginning of period, assets (liabilities), net | $ | (128 | ) | $ | (70 | ) | | $ | (167 | ) | $ | (106 | ) |
| Contracts realized or otherwise settled | 5 |
| 2 |
| | — |
| 51 |
|
Current period changes(a) | 33 |
| (22 | ) | | 77 |
| (35 | ) |
| Contracts outstanding at the end of period, assets (liabilities), net | $ | (90 | ) | $ | (90 | ) |
| $ | (90 | ) | $ | (90 | ) |
| Netting of cash collateral | 178 |
| 183 |
| | 178 |
| 183 |
|
Cash collateral and net fair value of contracts outstanding at end of period(b) | $ | 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 contracts outstanding excludes premium and the intrinsic value associated with weather derivatives of $0 million and $3 million at June 30, 2019 and 2018, respectively. |
The maturities of Southern Company Gas' energy-related derivative contracts at June 30, 2019 were as follows:
|
| | | | | | | | | | | | | | | |
| | | | Fair Value Measurements |
| | | | June 30, 2019 |
| | Total
Fair Value | | Maturity |
| | | Year 1 | | Years 2 & 3 | | Years 4 and thereafter |
| | (in millions) |
Level 1(a) | $ | (135 | ) | | $ | (46 | ) | | $ | (62 | ) | | $ | (27 | ) |
Level 2(b) | 55 |
| | 27 |
| | 25 |
| | 3 |
|
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 $178 million as well as premium and associated intrinsic value associated with weather derivatives of $0 million at June 30, 2019. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS
FOR
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA POWER COMPANY
MISSISSIPPI POWER COMPANY
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
(UNAUDITED)
INDEX TO THE NOTES TO THE CONDENSED FINANCIAL STATEMENTS
|
| | |
| 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, D, F, G, H, I, J, L |
| Georgia Power | A, B, C, D, F, G, H, I, J, L |
| Mississippi Power | A, B, C, D, F, G, H, I, J, L |
| Southern Power | A, 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
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, 2018 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended June 30, 2019 and 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.
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)
Goodwill and Other Intangible Assets
Goodwill at June 30, 2019 and December 31, 2018 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 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 |
|
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
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 (F) under "Financing 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.
The following tables provide a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed balance sheets that total to the amounts shown in the condensed statements of cash flows for the registrants that had restricted cash at June 30, 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 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Natural Gas for Sale
Southern Company Gas, with the exception of Nicor Gas, carries natural gas inventory on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value. Southern Company Gas recorded 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. Nicor Gas had no inventory decrement at June 30, 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 Alabama and Georgia are subject to approval by environmental regulatory agencies. Absent continued recovery of ARO costs through regulated rates, Southern Company's 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.
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 |
|
| |
| (*) | In 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 in Item 8 of the Form 10-K for information relating to various lawsuits and other 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 laws and regulations governing air, water, land, and protection of
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 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 against each registrant and any subsidiaries cannot be determined at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such registrant's financial statements.
Southern Company
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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 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.
Georgia Power
In 2011, plaintiffs filed a putative class action against Georgia Power in the Superior Court of Fulton County, Georgia alleging that Georgia Power's collection in rates of amounts for municipal franchise fees (which fees are paid to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state 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. Georgia Power believes the plaintiffs' claims have no merit. 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. 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
Southern Power indirectly owns a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock facility in Pecos County, Texas. Prior to the facility being placed in service in 2016, certain solar panels were damaged during installation by the construction contractor, McCarthy Building Companies, Inc. (McCarthy), and certain solar panels were damaged by a hail event that also occurred during construction. In connection therewith, Southern Power withheld payment of approximately $26 million to the construction contractor, which placed a lien on the Roserock facility for the same amount. In 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas against XL Insurance America, Inc. and North American Elite Insurance Company seeking recovery from an insurance policy for damages resulting from the hail event and McCarthy's installation practices. In June 2018, the court granted Roserock's motion for partial summary judgment, finding that the insurers were in breach of contract and in violation of the Texas Insurance Code for failing to pay any monies owed for the hail claim. Separate lawsuits were filed between Roserock and McCarthy, as well as other parties, and that litigation was consolidated in the U.S. District Court for the Western District of Texas. On April 18, 2019, Roserock and the parties to the state and federal lawsuits executed a settlement agreement and mutual release that resolved both lawsuits. Following execution of the agreement, the lawsuits were dismissed, Southern Power paid 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 noncontrolling interests and Southern Power recognized a $12 million after-tax gain.
Environmental RemediationMarket Price Risk
SubsequentOther than the items discussed below, there were no material changes to the disposition of Elizabethtown Gas, Southern Company Gas is subject to environmental remediation liabilities associated with 40 former manufactured gas plant sites in four different states. Accrued environmental remediation costs decreased at September 30, 2018 primarily due toGas' disclosures about market price risk during the dispositionsecond quarter 2019. For an in-depth discussion of $85 million that related to Elizabethtown Gas.
See Note (B) under "Environmental Matters–Environmental Remediation" to the Condensed Financial Statements herein andSouthern Company Gas' market price risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company Gas in Item 7 and Note 3 to the financial statements of Southern Company Gas under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
FERC Matters
See MANAGEMENT'S DISCUSSION FINANCIAL CONDITION AND ANALYSIS LIQUIDITY – FUTURE EARNINGS POTENTIAL – "FERC Matters""Market Price Risk" of Southern Company Gas in Item 7 of the Form 10-K for additional information.
The Atlantic Coast Pipeline has experienced challenges to its permits since construction began earlier in 201810-K. Also see Notes (I) and continues to work with the appropriate agencies to obtain the necessary permits. The PennEast Pipeline continues to work with state and federal agencies to obtain the required permits to begin construction. Any material permitting delays may impact forecasted capital expenditures and in-service dates. The ultimate outcome of these matters cannot be determined at this time.
Regulatory Matters
See Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters" in Item 8 of the Form 10-K and Note (B)(J) to the Condensed Financial Statements under "Regulatory Matters – Southern Company Gas" herein for additional information regarding Southern Company Gas' regulatory matters.
Riders
On April 19, 2018, the Illinois Commission approved Nicor Gas' variable income tax adjustment rider. This rider provides for refund or recovery of changes in income tax expense that result from income tax rates that differ from those used in Nicor Gas' last rate case. Customer refunds, via bill credits, began on July 1, 2018 relatedrelating to the impacts of the Tax Reform Legislation from January 25, 2018 through May 4, 2018. The impact of the Tax Reform Legislation subsequent to May 4, 2018 was addressed in Nicor Gas' approved rehearing request discussed herein under "Settled Base Rate Cases."
Natural Gas Cost Recoveryderivative instruments.
Southern Company Gas has establishedis exposed to market risks, primarily commodity price risk, interest rate risk, and weather risk. Due to various cost recovery mechanisms, the natural gas cost recovery rates approved bydistribution utilities of Southern Company Gas that sell natural gas directly to end-use customers have limited exposure to market volatility of natural gas prices. Certain natural gas distribution utilities of Southern Company Gas may manage fuel-hedging programs implemented per the relevantguidelines of their respective state regulatory agencies into hedge the statesimpact of market fluctuations 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 inprices for customers. For the billing factor will not have a significant effect onweather risk associated with Nicor Gas, Southern Company Gas' revenues or net income, but will affect cash flows.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Base Rate Cases
Settled Base Rate Cases
On February 23, 2018, Atlanta Gas Light revised its annual base rate filinghas a corporate weather hedging program that utilizes weather derivatives to reflectreduce the impactsrisk of the Tax Reform Legislationlower 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 requested a $16 million rate reduction in 2018. On May 15, 2018, the Georgia PSC approved a stipulation for Atlanta Gas Light's annual base rates to remain at the 2017 level for 2018 and 2019, with customer credits of $8 million in each of July 2018 and October 2018 to reflect the impacts of the Tax Reform Legislation. The Georgia PSC maintained Atlanta Gas Light's previously authorized earnings band based on a ROE between 10.55% and 10.95% and increased the allowed equity ratio by 4% to an equity ratio of 55% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation. Additionally, Atlanta Gas Light is required to file a traditional base rate case on or before June 1, 2019 for rates effective January 1, 2020.
On May 2, 2018, the Illinois Commission approved Nicor Gas' rehearing request for revised base rates to incorporate the reductionweather risks inherent in the federal income tax ratenatural gas industry. These instruments include a variety of exchange-traded and over-the-counter energy contracts, such as a resultforward 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. For the Tax Reform Legislation. periods presented below, the changes in net fair value of Southern Company Gas' derivative contracts were as follows:
|
| | | | | | | | | | | | | |
| | Second Quarter 2019 | Second Quarter 2018 | | Year-to-Date 2019 | Year-to-Date 2018 |
| | (in millions) |
| Contracts outstanding at beginning of period, assets (liabilities), net | $ | (128 | ) | $ | (70 | ) | | $ | (167 | ) | $ | (106 | ) |
| Contracts realized or otherwise settled | 5 |
| 2 |
| | — |
| 51 |
|
Current period changes(a) | 33 |
| (22 | ) | | 77 |
| (35 | ) |
| Contracts outstanding at the end of period, assets (liabilities), net | $ | (90 | ) | $ | (90 | ) |
| $ | (90 | ) | $ | (90 | ) |
| Netting of cash collateral | 178 |
| 183 |
| | 178 |
| 183 |
|
Cash collateral and net fair value of contracts outstanding at end of period(b) | $ | 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 contracts outstanding excludes premium and the intrinsic value associated with weather derivatives of $0 million and $3 million at June 30, 2019 and 2018, respectively. |
The resulting decreasematurities of approximately $44 million in annual base rate revenues became effective May 5, 2018. NicorSouthern Company Gas' previously-authorized capital structure and ROE of 9.8% were not addressed in the rehearing and remain unchanged. The impact of the Tax Reform Legislation prior to May 5, 2018 was addressed in the variable income tax rider discussed herein under "Riders."
On October 15, 2018, the Tennessee Public Utility Commission (PUC) approved a $1 million increase in Chattanooga Gas' annual base rate revenues, which was based on a projected test year endingenergy-related derivative contracts at June 30, 2019 and a ROEwere as follows:
|
| | | | | | | | | | | | | | | |
| | | | Fair Value Measurements |
| | | | June 30, 2019 |
| | Total
Fair Value | | Maturity |
| | | Year 1 | | Years 2 & 3 | | Years 4 and thereafter |
| | (in millions) |
Level 1(a) | $ | (135 | ) | | $ | (46 | ) | | $ | (62 | ) | | $ | (27 | ) |
Level 2(b) | 55 |
| | 27 |
| | 25 |
| | 3 |
|
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 $178 million as well as premium and associated intrinsic value associated with weather derivatives of $0 million at June 30, 2019. |
Other
The Virginia Commission issued an order effective January 1, 2018 requiring utilities in the state to defer as a regulatory liability the impact of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of the flowback of excess deferred income taxes. Through September 30, 2018, Virginia Natural Gas had deferred a total of $9 million. On August 30, 2018, Virginia Natural Gas filed an annual information form, which was subsequently revised on October 25, 2018, proposing to reduce annual base rates effective January 1, 2019 due to lower tax expense as a result of the lower corporate income tax rate and the impact of the flowback of excess deferred income taxes. This filing also proposes for Virginia Natural Gas to issue customer refunds, via bill credits, for the related amounts deferred as a regulatory asset. The Virginia Commission is expected to rule on the filing during the fourth quarter 2018. If approved as filed, Virginia Natural Gas' annual base rate revenues would be reduced by $14 million. The ultimate outcome of this matter cannot be determined at this time.NOTES TO THE CONDENSED FINANCIAL STATEMENTS
Asset Management AgreementsFOR
Upon closing the sales of Elizabethtown Gas and Elkton Gas, an affiliate of South Jersey Industries, Inc. assumed the asset management agreements with wholesale gas services for Elizabethtown Gas and Elkton Gas. The sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energy did not impact the asset management agreement between wholesale gas services and Florida City Gas, which will remain in effect until its original maturity of March 31, 2019. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information on these dispositions. For additional information, see MANAGEMENT'S DISCUSSIONTHE SOUTHERN COMPANY AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Asset Management Agreements" of Southern Company Gas in Item 7 of the Form 10-K.SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA POWER COMPANY
MISSISSIPPI POWER COMPANY
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF(UNAUDITED)
INDEX TO THE NOTES TO THE CONDENSED FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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. Excluding the natural gas distribution utilities sold in July 2018, infrastructure expenditures incurred in the first nine months of 2018 were as follows:STATEMENTS
|
| | | | |
| Utility | Program | Year-to-Date 2018 |
| | | (in millions) |
| Nicor Gas | Investing in Illinois | $ | 267 |
|
| Atlanta Gas Light | Georgia Rate Adjustment Mechanism (GRAM) infrastructure spending | 217 |
|
| Virginia Natural Gas | Steps to Advance Virginia's Energy | 33 |
|
| Total | | $ | 517 |
|
|
| | |
| Note | | Page Number |
| A | | |
| B | | |
| C | | |
| D | | |
| E | | |
| F | | |
| G | | |
| H | | |
| I | | |
| J | | |
| K | | |
| L | | |
| M | | |
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 3
INDEX TO APPLICABLE NOTES TO FINANCIAL STATEMENTS BY REGISTRANT
The following unaudited notes to the condensed financial statements of Southern Company Gas under "Regulatory Matters – Regulatory Infrastructure Programs" in Item 8 ofare a combined presentation. The list below indicates the Form 10-K for additional information.registrants to which each footnote applies.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Southern Company Gas in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk," Note (B) to the Condensed Financial Statements under "Regulatory Matters – Southern Company Gas," and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation and related regulatory actions. |
| |
| Registrant | Applicable Notes |
| Southern Company | A, B, C, D, E, F, G, H, I, J, K, L, M |
| Alabama Power | A, B, C, D, F, G, H, I, J, L |
| Georgia Power | A, B, C, D, F, G, H, I, J, L |
| Mississippi Power | A, B, C, D, F, G, H, I, J, L |
| Southern Power | A, 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 |
Other Matters
Southern Company Gas is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company Gas is subject to certain claims and legal actions arising in the ordinary course of business. The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company Gas' financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies and regulatory matters, and other matters being litigated which may affect future earnings potential.
Southern Company Gas owns a 50% interest in a planned LNG liquefaction and storage facility in Jacksonville, Florida, which was placed in service in October 2018. This facility is outfitted with a 2.0 million gallon storage tank with the capacity to produce in excess of 120,000 gallons of LNG per day.160
Application of Critical Accounting Policies and Estimates
Southern Company Gas prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Company Gas in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Company Gas' results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSIONTHE SOUTHERN COMPANY 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.SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA POWER COMPANY
MISSISSIPPI POWER COMPANY
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
NOTES TO THE CONDENSED FINANCIAL CONDITION AND RESULTS OF OPERATIONSSTATEMENTS:
(UNAUDITED)
Recently Issued Accounting Standards(A) INTRODUCTION
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards"The condensed quarterly financial statements of Southern Company Gaseach 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, 2018 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended June 30, 2019 and 2018. Certain information and footnote disclosures normally included in Item 7annual 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 for additional information regarding ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). See Note (A) to theare generally omitted from this Quarterly Report on Form 10-Q unless specifically required by GAAP. Therefore, these Condensed Financial Statements hereinshould 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 information regarding Southern Company Gas' recently adopted accounting standards.energy, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.
Certain prior year data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on the results of operations, financial position, or cash flows of any registrant.
Recently Adopted Accounting Standards
In 2016, the FASB issued ASU No. 2016-02, whichLeases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02unchanged and there is effectiveno change to the accounting for fiscal years beginning after December 15, 2018 and Southern Company Gas will adoptexisting 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)
Goodwill and Other Intangible Assets
Goodwill at June 30, 2019 and December 31, 2018 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 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 |
|
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
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 (F) under "Financing Activities" for additional information. At both June 30, 2019 and December 31, 2018, Southern Company Gas has electedhad restricted cash held as collateral for worker's compensation, life insurance, and long-term disability insurance.
The following tables provide a reconciliation of cash, cash equivalents, and restricted cash reported within the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby it will applycondensed balance sheets that total to the requirements of ASU 2016-02 on a prospective basis as of the adoption date of January 1, 2019, without restating prior periods. Southern Company Gas expects to elect the package of practical expedients provided by ASU 2016-02 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Southern Company Gas expects to apply the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and to elect the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed. Southern Company Gas also expects to make accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and to combine lease and non-lease componentsamounts shown in the computationscondensed statements of lease obligations and right-of-use assetscash flows for most asset classes.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 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Natural Gas for Sale
Southern Company Gas, with the exception of Nicor Gas, carries natural gas inventory on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is continuingrecorded to completereduce the implementationvalue of an information technology systemnatural gas inventories to track and account for its leases and of changes to its internal controls and accounting policies to support the accounting for leases under ASU 2016-02.market value. Southern Company Gas has substantially completed its lease inventoryrecorded adjustments of $7 million and determined its most significant leases involve real estate and fleet vehicles. While Southern Company Gas has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to result in recording lease liabilities and right-of-use assets on Southern Company Gas' balance sheet each totaling approximately $90 million, with no material impact on Southern Company Gas' statement of income.
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. Southern Company Gas' financial condition remained stable at September 30, 2018. 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. At September 30, 2018, the amount of subsidiary retained earnings restricted to dividend totaled $786 million. This restriction did not impact Southern Company Gas' ability to meet its cash obligations.
Net cash provided from operating activities totaled $736$10 million for the first ninethree and six months of 2018,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 decrease of $410 million fromLIFO basis. Inventory decrements occurring during the corresponding period in 2017. The decrease was primarily dueyear that are restored prior to higher income tax payments dueyear end are charged to the net taxable gains from the Southern Company Gas Dispositions, partially offset by increased volumescost of natural gas sold duringat the first nine monthsestimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of 2018 as a resultnatural gas at the actual LIFO cost of colder weather comparedthe inventory layers liquidated. Nicor Gas had no inventory decrement at June 30, 2019.
Asset Retirement Obligations
See Note 6 to the prior year. Net cash provided from investing activities totaled $1.4 billion for the first nine months of 2018 primarily due to proceeds from the Southern Company Gas Dispositions, partially offset by gross property additions primarily related to utility capital expenditures and pre-approved rider and infrastructure investments recovered through
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
replacement programs at gas distribution operations as well as capital contributed to equity method investments in pipelines. Net cash used for financing activities totaled $2.2 billion for the first nine months of 2018 primarily due to net repayments of commercial paper borrowings, the redemption of gas facility revenue bonds, and common stock dividend payments and return of capital to Southern Company, partially offset by proceeds from the issuance of first mortgage 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 nine months of 2018 include $2.8 billion and $404 million in total assets and liabilities sold, respectively, associated with the Southern Company Gas Dispositions as described in Note (J) to the Condensed Financial Statements herein under "Southern Company Gas," a decrease of $109 million in natural gas for sale due to the use of stored natural gas, and a $1.4 billion decrease in notes payable primarily related to net repayments of commercial paper borrowings. Other significant balance sheet changes include decreases of $63 million in accounts payable as well as $109 million and $25 million in energy marketing receivables and payables, respectively, due to lower natural gas prices and an increase of $714 million in total property, plant, and equipment primarily due to utility capital expenditures and pre-approved rider and infrastructure investments recovered through replacement programs.
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 and contractual obligations. Subsequent to September 30, 2018, Southern Company Gas Capital repaid at maturity $155 million aggregate principal amount of 3.50% Series B Senior Notes. An additional $350 million will be required through September 30, 2019 to fund maturities of long-term 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 3 to the consolidated financial statements of Southern Company Gas in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information regarding additional factors that may impact infrastructure investment expenditures.AROs.
Sources of Capital
Southern Company Gas plans to obtain the funds to meet its future capital needs through operating cash flows, external securities issuances, borrowings from financial institutions, and borrowings and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, depend upon prevailing market conditions, regulatory approval, and other factors. The issuance of securities by Nicor Gas is generally subject to the approvalDetails of the Illinois Commission. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital"AROs included in the condensed balance sheets of Southern Company, GasAlabama 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 Alabama and Georgia are subject to approval by environmental regulatory agencies. Absent continued recovery of ARO costs through regulated rates, Southern Company's 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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
(B) REGULATORY MATTERS
See Note 2 to the financial statements in Item 78 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 |
|
| |
| (*) | In 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.
Southern Company Gas' current liabilities exceeded current assets by $469Georgia 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, primarily as$145 million, and $234 million effective January 1, 2020, January 1, 2021, and January 1, 2022, respectively. These increases are based on a resultproposed retail ROE of $515 million in securities due within one year. Southern Company Gas' current liabilities frequently exceed current assets because10.90% and a proposed equity ratio of commercial paper borrowings used56% and reflect levelized revenue requirements during the three-year period, with the exception of incremental compliance costs related to fund daily operations, scheduled maturities of long-term debt,CCR AROs, Demand-Side Management programs, and significant seasonal fluctuations in cash needs. Southern Company Gas intends to utilize operating cash flows, external securities issuances, borrowings from financial institutions, borrowings and equity contributions from Southern Company, and the proceeds from its dispositions to fund its short-term capital needs. Southern Company Gas has substantial cash flow from operating activities and accessadjustments to the capital markets and financial institutions to meet liquidity needs.Municipal Franchise Fee tariff.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF166
NOTES TO THE CONDENSED FINANCIAL CONDITION AND RESULTS OF OPERATIONSSTATEMENTS: (Continued)
(UNAUDITED)
At September 30, 2018, Southern Company Gas had $56 millionGeorgia Power has requested recovery of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2018 werethe proposed increases through its existing base rate tariffs as follows:
|
| | | | | | | |
| Company | Expires 2022 | | Unused |
| | (in millions) |
Southern Company Gas Capital(a) | $ | 1,400 |
| | $ | 1,395 |
|
| Nicor Gas | 500 |
| | 500 |
|
Total(b) | $ | 1,900 |
| | $ | 1,895 |
|
|
| | | | | | | | | |
| 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) | Southern Company Gas guarantees the obligationsExcludes financing costs expected to be capitalized through AFUDC of Southern Company Gas Capital.approximately $315 million. |
| |
| (b) | Pursuant toNet of $1.7 billion received from Toshiba under the credit arrangement, the allocations between Southern Company Gas CapitalGuarantee Settlement Agreement and Nicor Gas may be adjusted.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 68 to the consolidated financial statements of Southern Company Gas under "Bank Credit Arrangements""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 Condensed Financial StatementsKemper 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 "Bank Credit Arrangements" herein"Mississippi Power – Environmental Compliance Overview Plan" in Item 8 of the Form 10-K for additional information.
The multi-year credit arrangement of Southern Company Gas Capitalinformation on Mississippi Power's ECO Plan. See Note (A) under "Asset Retirement Obligations" for additional information on AROs and Nicor Gas (Facility) contains a covenant that limits the ratio of debt to capitalization (as defined in the Facility) to a maximum of 70% for each of Southern Company Gas and Nicor Gas and contains a cross-acceleration provision to other indebtedness (including guarantee obligations) of the applicable company. Such cross-acceleration provision to other indebtedness would trigger an event of default of the applicable company if Southern Company Gas or Nicor Gas defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2018, 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 makes short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Commercial paper borrowings are included in notes payable in the balance sheets.
Details of short-term borrowings were as follows:
|
| | | | | | | | | | | | | | | | | |
| | Short-Term Debt at September 30, 2018 | | Short-Term Debt During the Period(*) |
| | Amount
Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| Commercial paper: | (in millions) | | | | (in millions) | | | | (in millions) |
| Southern Company Gas Capital | $ | — |
| | — | % | | $ | 18 |
| | 2.4 | % | | $ | 573 |
|
| Nicor Gas | 136 |
| | 2.4 | % | | 67 |
| | 2.3 | % | | 154 |
|
| Short-term loans: | | | | | | | | | |
| Southern Company Gas | — |
| | — | % | | 12 |
| | 2.8 | % | | 276 |
|
| Total | $ | 136 |
| | 2.4 | % | | $ | 97 |
| | 2.3 | % | | |
| |
(*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2018. |
Southern Company Gas believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and operating cash flows.
Additionally, prior to its sale, Pivotal Utility Holdings redeemed five series of gas facility revenue bonds issuedNote (C) under loan agreements with the New Jersey Economic Development Authority and Brevard County, Florida totaling
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
$200 million during the second quarter 2018. See "Financing Activities""Other Matters – Mississippi Power" herein for additional information regardingon Gulf Power's ownership in Plant Daniel.
Kemper County Energy Facility
As the redemption of these bonds.
Credit Rating Risk
Southernmining permit holder, Liberty Fuels Company, Gas does not have any credit arrangements that would require material changes in payment schedules or terminations asLLC has a result oflegal obligation to perform mine reclamation, and Mississippi Power has a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change below BBB- and/or Baa3. These contracts are for physical gas purchases and sales and energy price risk management. The maximum potential collateral requirement under these contracts at September 30, 2018 was approximately $10 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 Gascontractual obligation to access capital markets and would be likely to impact the cost at which it does so.
On September 28, 2018, Fitch assigned a negative rating outlook to the ratings of Southern Company and certain of its subsidiaries (including Southern Company Gas, Southern Company Gas Capital, and Nicor Gas).
fund all reclamation activities. As a result of the Tax Reform Legislation,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 financial metrics, such asproperty that is to be retained by Mississippi Power. In connection with the funds from operations to debt percentage, used byDOE closeout discussions, on April 29, 2019, the credit rating agencies to assessCivil Division of the Department of Justice informed Southern Company and its subsidiaries, including 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 may be negatively impacted. Southern Company
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 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' 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 increasedan 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 Southern Company Gas under "Regulatory Matters" in Item 8 of the Form 10-K for information relating to various lawsuits and Note (B)other 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 laws and regulations governing air, water, land, and protection of
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 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 against each registrant and any subsidiaries cannot be determined at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such registrant's financial statements.
Southern Company
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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 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.
Georgia Power
In 2011, plaintiffs filed a putative class action against Georgia Power in the Superior Court of Fulton County, Georgia alleging that Georgia Power's collection in rates of amounts for municipal franchise fees (which fees are paid to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state 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 Condensed Financial Statements under "Regulatory Matters – Southern Company Gas" hereintrial court. Georgia Power filed a petition for additional information.
Financing Activities
The long-term debt on Southern Company Gas' balance sheets includes both principal and non-principal components. Aswrit of September 30,certiorari with the Georgia Supreme Court, which was granted in 2017. In June 2018, the non-principal components totaled $469 million, which consistedGeorgia Supreme Court affirmed the judgment of the unamortized portionsGeorgia 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 fair value adjustment recorded in purchase accounting, debt premiums, debt discounts, and debt issuance costs.
On January 4, 2018, Southern Company Gas issuedproper application of the municipal franchise fee schedule pursuant to the Georgia PSC's orders. Georgia Power also filed a floating rate promissory note to Southern Company in an aggregate principalnotice 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 merit. The amount of $100 million bearing interest based on one-month LIBOR. On March 28, 2018, Southern Company Gas repaidany possible losses cannot be calculated at this promissory note.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 ultimate outcome of this matter cannot be determined at this time.
Prior to its sale, in the second quarter 2018, Pivotal Utility Holdings caused $200 million aggregate principal amount of gas facility revenue bonds to be redeemed. Also in the second quarter 2018, Pivotal Utility Holdings, as borrower, and Southern Company Gas, as guarantor, entered into a $181 million short-term delayed draw floating rate bank term loan bearing interest based on one-month LIBOR, which Pivotal Utility Holdings used to repay the gas facility revenue bonds. In July 2018, Pivotal Utility Holdings repaid this short-term loan.Mississippi Power
In May 2018, Southern Company Gas Capital borrowed $95and 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, pursuantas 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 short-term uncommitted bank credit arrangement, guaranteedmaterial 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
Southern Power indirectly owns a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock facility in Pecos County, Texas. Prior to the facility being placed in service in 2016, certain solar panels were damaged during installation by the construction contractor, McCarthy Building Companies, Inc. (McCarthy), and certain solar panels were damaged by a hail event that also occurred during construction. In connection therewith, Southern Power withheld payment of approximately $26 million to the construction contractor, which placed a lien on the Roserock facility for the same amount. In 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas against XL Insurance America, Inc. and North American Elite Insurance Company seeking recovery from an insurance policy for damages resulting from the hail event and McCarthy's installation practices. In June 2018, the court granted Roserock's motion for partial summary judgment, finding that the insurers were in breach of contract and in violation of the Texas Insurance Code for failing to pay any monies owed for the hail claim. Separate lawsuits were filed between Roserock and McCarthy, as well as other parties, and that litigation was consolidated in the U.S. District Court for the Western District of Texas. On April 18, 2019, Roserock and the parties to the state and federal lawsuits executed a settlement agreement and mutual release that resolved both lawsuits. Following execution of the agreement, the lawsuits were dismissed, Southern Power paid 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 Company Gas, bearing interest at a rate agreed upon by Southern Company Gas Capital and the bank from time to time and payable on no less than 30 days' demand by the bank. The proceedsPower in excess of the loaninitial replacement costs were usedrecognized as a gain and included in other income (expense), net in 2019. A portion of the pre-tax gain was allocated to repay short-term debt. In July 2018,noncontrolling interests and Southern Company Gas Capital repaid this loan.Power recognized a $12 million after-tax gain.
In July 2018, Nicor Gas agreed to issue $300 million aggregate principal amount of first mortgage bonds in a private placement, $100 million of which was issued in August 2018 and $200 million of which was issued inSOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
November 2018. The proceeds will be used for the repayment of short-term debt, capital expenditures, and other general corporate purposes.
Subsequent to September 30, 2018, Southern Company Gas Capital repaid at maturity $155 million aggregate principal amount of 3.50% Series B Senior Notes.
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 thirdsecond quarter 2018.2019. 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 (D)(I) and (I)(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. 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. For the periods presented below, the changes in net fair value of Southern Company Gas' derivative contracts were as follows:
| | | | Third Quarter 2018 | Third Quarter 2017 | | Year-to-Date 2018 | Year-to-Date 2017 | Second Quarter 2019 | Second Quarter 2018 | | Year-to-Date 2019 | Year-to-Date 2018 |
| | (in millions) | (in millions) |
| Contracts outstanding at beginning of period, assets (liabilities), net | $ | (90 | ) | $ | 51 |
| | $ | (106 | ) | $ | 12 |
| $ | (128 | ) | $ | (70 | ) | | $ | (167 | ) | $ | (106 | ) |
| Contracts realized or otherwise settled | 6 |
| (6 | ) | | 57 |
| (22 | ) | 5 |
| 2 |
| | — |
| 51 |
|
Current period changes(a) | (34 | ) | (16 | ) | | (69 | ) | 39 |
| 33 |
| (22 | ) | | 77 |
| (35 | ) |
| Contracts outstanding at the end of period, assets (liabilities), net | $ | (118 | ) | $ | 29 |
|
| $ | (118 | ) | $ | 29 |
| $ | (90 | ) | $ | (90 | ) |
| $ | (90 | ) | $ | (90 | ) |
| Netting of cash collateral | 189 |
| 76 |
| | 189 |
| 76 |
| 178 |
| 183 |
| | 178 |
| 183 |
|
Cash collateral and net fair value of contracts outstanding at end of period(b) | $ | 71 |
| $ | 105 |
|
| $ | 71 |
| $ | 105 |
| $ | 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 contracts outstanding excludes premium and the intrinsic value associated with weather derivatives of $5$0 million and $3 million at SeptemberJune 30, 2019 and 2018, and includes premium and the intrinsic value associated with weather derivatives of $13 million at September 30, 2017.respectively. |
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The maturities of Southern Company Gas' energy-related derivative contracts at SeptemberJune 30, 20182019 were as follows:
| | | | | | Fair Value Measurements | | | Fair Value Measurements |
| | | | September 30, 2018 | | | 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) | $ | (145 | ) | | $ | (8 | ) | | $ | (106 | ) | | $ | (31 | ) | $ | (135 | ) | | $ | (46 | ) | | $ | (62 | ) | | $ | (27 | ) |
Level 2(b) | 27 |
| | 2 |
| | 25 |
| | — |
| 55 |
| | 27 |
| | 25 |
| | 3 |
|
Fair value of contracts outstanding at end of period(c) | $ | (118 | ) | | $ | (6 | ) | | $ | (81 | ) | | $ | (31 | ) | |
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 $189$178 million as well as premium and associated intrinsic value associated with weather derivatives of $5$0 million at SeptemberJune 30, 2018.2019. |
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, D, F, G, H, I, J, L |
| Georgia Power | A, B, C, D, F, G, H, I, |
Gulf Power | A, B, C, D, F, G, H, I, J, L |
| Mississippi Power | A, B, C, D, F, G, H, I, J, L |
| Southern Power | A, C, D, E, F, G, H, I, J, K, L |
| Southern Company Gas | A, B, C, D, E, F, G, H, I, J, K, |
Southern Company Gas | A, B, C, D, 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, 20172018 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, 20182019 and 2017.2018. 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.
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
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.
Revenue
In 2014,2016, 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 isASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize revenueon 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 depict the transfer of goods or services to customers ataccounting for existing leveraged leases. The registrants adopted the amount expected to be collected. ASC 606 becamenew standard effective on January 1, 20182019. See Note (L) for additional information and the registrants adopted it using the modified retrospective method applied to open contracts and only to the versionrelated disclosures.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
ASC 606 provided additional clarity on financial statement presentation that resulted in reclassifications into other revenuesGoodwill and other operationsOther Intangible Assets
Goodwill at June 30, 2019 and maintenance from other income/(expense), net at Alabama Power and Georgia Power relatedDecember 31, 2018 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 is not amortized but is subject to certain unregulated salesan annual impairment test during the fourth quarter of products and services. In addition, contract assets related to certain fixed retail revenues at Georgia Power and Southern Company's unregulated distributed generation business have been reclassified from unbilled revenue in accordance with the guidance in ASC 606. These reclassifications did not affect the timingeach year or amountmore frequently if impairment indicators arise. A goodwill impairment charge of revenues recognized or cash flows. ASC 606 also provided additional guidance on revenue recognized over time, resulting in a change$32 million was recorded in the timingsecond quarter 2019 in contemplation of revenue recognized from guaranteed and fixed billing arrangements at the July 22, 2019 sale of one of PowerSecure's business units. See Note (K) under "Southern Company Gas. The changes in natural gas revenues recognized in the third quarter and year-to-date 2018 relate primarily to the seasonal nature" for additional information.
The net impact of accounting for revenue under ASC 606 decreased Southern Company's and Southern Company Gas' consolidated net income by $4 million for the three months ended September 30, 2018 and increased Southern Company's and Southern Company Gas' consolidated net income by $1 million for the nine months ended September 30, 2018.
The specific impacts of applying ASC 606 to revenues from contracts with customers on the financial statements of Southern Company, Alabama Power, Georgia Power, and Southern Company Gas compared to previously recognized guidance is shown below.
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 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | For the Three Months Ended
September 30, 2018 | | For the Nine Months Ended
September 30, 2018 |
| Condensed Statements of Income | As Reported | Balances Without Adoption of
ASC 606 | Effect of Change | | As Reported | Balances Without Adoption of ASC 606 | Effect of Change |
| | (in millions) | | (in millions) |
| Southern Company | | | | | | | |
| Natural gas revenues | $ | 492 |
| $ | 497 |
| $ | (5 | ) | | $ | 2,806 |
| $ | 2,805 |
| $ | 1 |
|
| Other revenues | 199 |
| 198 |
| 1 |
| | 1,007 |
| 1,003 |
| 4 |
|
| Other operations and maintenance | 1,404 |
| 1,387 |
| 17 |
| | 4,217 |
| 4,178 |
| 39 |
|
| Operating income | 2,174 |
| 2,195 |
| (21 | ) | | 3,613 |
| 3,647 |
| (34 | ) |
| Other income (expense), net | 57 |
| 41 |
| 16 |
| | 195 |
| 160 |
| 35 |
|
| Earnings (loss) before income taxes | 1,845 |
| 1,850 |
| (5 | ) | | 2,629 |
| 2,628 |
| 1 |
|
| Income taxes (benefit) | 623 |
| 624 |
| (1 | ) | | 598 |
| 598 |
| — |
|
| Consolidated net income (loss) | 1,222 |
| 1,226 |
| (4 | ) | | 2,031 |
| 2,030 |
| 1 |
|
| Consolidated net income (loss) attributable to Southern Company | 1,164 |
| 1,168 |
| (4 | ) | | 1,948 |
| 1,947 |
| 1 |
|
| | | | | | | | |
| Alabama Power | | | | | | | |
| Other revenues | $ | 68 |
| $ | 59 |
| $ | 9 |
| | $ | 199 |
| $ | 173 |
| $ | 26 |
|
| Other operations and maintenance | 401 |
| 390 |
| 11 |
| | 1,191 |
| 1,159 |
| 32 |
|
| Operating income | 561 |
| 563 |
| (2 | ) | | 1,313 |
| 1,319 |
| (6 | ) |
| Other income (expense), net | 9 |
| 7 |
| 2 |
| | 24 |
| 18 |
| 6 |
|
| | | | | | | | |
| Georgia Power | | | | | | | |
| Other revenues | $ | 121 |
| $ | 97 |
| $ | 24 |
| | $ | 349 |
| $ | 287 |
| $ | 62 |
|
| Other operations and maintenance | 460 |
| 437 |
| 23 |
| | 1,325 |
| 1,268 |
| 57 |
|
| Operating income (loss) | 991 |
| 990 |
| 1 |
| | 1,032 |
| 1,027 |
| 5 |
|
| Other income (expense), net | 30 |
| 31 |
| (1 | ) | | 104 |
| 109 |
| (5 | ) |
| | | | | | | | |
| Southern Company Gas | | | | | | | |
| Natural gas revenues | $ | 487 |
| $ | 492 |
| $ | (5 | ) | | $ | 2,829 |
| $ | 2,828 |
| $ | 1 |
|
| Operating income | 374 |
| 379 |
| (5 | ) | | 810 |
| 809 |
| 1 |
|
| Earnings before income taxes | 362 |
| 367 |
| (5 | ) | | 769 |
| 768 |
| 1 |
|
| Income taxes | 316 |
| 317 |
| (1 | ) | | 475 |
| 475 |
| — |
|
| Net income (loss) | 46 |
| 50 |
| (4 | ) | | 294 |
| 293 |
| 1 |
|
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
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 (F) under "Financing 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.
The following tables provide a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed balance sheets that total to the amounts shown in the condensed statements of cash flows for the registrants that had restricted cash at June 30, 2019 and/or December 31, 2018:
|
| | | | | | | | | |
| | For the Nine Months Ended
September 30, 2018 |
| Condensed Statements of Cash Flows | As Reported | Balances Without Adoption of ASC 606 | Effect of Change |
| | (in millions) |
| Southern Company | | | |
| Consolidated net income | $ | 2,031 |
| $ | 2,030 |
| $ | 1 |
|
| Changes in certain current assets and liabilities: | | | |
| Receivables | 37 |
| 27 |
| 10 |
|
| Other current assets | (90 | ) | (80 | ) | (10 | ) |
| Other current liabilities | (67 | ) | (68 | ) | 1 |
|
| | | | |
| Georgia Power | | | |
| Changes in certain current assets and liabilities: | | | |
| Receivables | $ | (205 | ) | $ | (242 | ) | $ | 37 |
|
| Other current assets | (36 | ) | 1 |
| (37 | ) |
| | | | |
| Southern Company Gas | | | |
| Net income | $ | 294 |
| $ | 293 |
| $ | 1 |
|
| Changes in certain current assets and liabilities: | | | |
| Other current liabilities | 35 |
| 34 |
| 1 |
|
|
| | | | | | | |
| | 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. |
|
| | | | | | | | | |
| | At September 30, 2018 |
| Condensed Balance Sheets | As Reported | Balances Without Adoption of ASC 606 | Effect of Change |
| | (in millions) |
| Southern Company | | | |
| Unbilled revenues | $ | 738 |
| $ | 776 |
| $ | (38 | ) |
| Other accounts and notes receivable | 690 |
| 691 |
| (1 | ) |
| Other current assets | 232 |
| 193 |
| 39 |
|
| Other current liabilities | 763 |
| 764 |
| (1 | ) |
| Retained earnings | 9,048 |
| 9,047 |
| 1 |
|
| | | | |
| Georgia Power | | | |
| Unbilled revenues | $ | 245 |
| $ | 310 |
| $ | (65 | ) |
| Other accounts and notes receivable | 96 |
| 97 |
| (1 | ) |
| Other current assets | 91 |
| 25 |
| 66 |
|
| | | | |
| Southern Company Gas | | | |
| Other current liabilities | 122 |
| 123 |
| (1 | ) |
| Accumulated deficit | (273 | ) | (274 | ) | 1 |
|
|
| | | | | | | | | |
| | 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 |
|
Other
In 2016, the FASB issued ASU No. 2016-18, Statement164
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
investing, and financing activities in the statements of cash flows. In addition, the net change in cash and cash equivalents during the period includes amounts generally described as restricted cash or restricted cash equivalents. The registrants adopted ASU 2016-18 effective January 1, 2018 with no material impact on their financial statements. Southern Company, Southern Power, and Natural Gas for Sale
Southern Company Gas, retrospectively applied ASU 2016-18 effective January 1, 2018 and have restated prior periodswith the exception of Nicor Gas, carries natural gas inventory on a WACOG basis. For any declines in market prices below the statementsWACOG considered to be other than temporary, an adjustment is recorded to reduce the value of cash flows by immaterial amounts. The change in restricted cash in the statements of cash flows was previously disclosed in operating activities for Southern Company andnatural gas inventories to market value. Southern Company Gas recorded adjustments of $7 million and in investing activities for Southern Company and Southern Power. See "Restricted Cash" herein for additional information.
In March 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 statements of income outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. The registrants adopted ASU 2017-07 effective January 1, 2018 with no material impact on their financial statements. ASU 2017-07 has been applied retrospectively for the presentation of the service cost component and the other components of net periodic benefit costs in the statements of income for Southern Company, the traditional electric operating companies, and Southern Company Gas. Since Southern Power did not participate in the qualified pension and postretirement benefit plans until December 2017, no retrospective presentation of Southern Power's net periodic benefits costs is required. The requirement to limit capitalization to the service cost component of net periodic benefit costs has been applied on a prospective basis from the date of adoption for all registrants. The presentation changes resulted in a decrease in operating income and an increase in other income$10 million for the three and ninesix months ended SeptemberJune 30, 20182019, respectively, and 2017 for Southern Company, the traditional electric operating companies, and Southern Company Gas.
In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12). 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, with early adoption permitted. The registrants adopted ASU 2017-12 effective January 1, 2018 with no material impactadjustments for the comparable periods in 2018.
Nicor Gas' natural gas inventory is carried at cost on their financial statements. See Note (I) for disclosures required by ASU 2017-12.
On February 14, 2018,a LIFO basis. Inventory decrements occurring during the FASB issued ASU No. 2018-02, Income Statement – Reporting Comprehensive Income (Topic 220): Reclassificationyear that are restored prior to year end are charged to cost of Certain Tax Effects from Accumulated Other Comprehensive Income (ASU 2018-02)natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to addressyear end are charged to cost of natural gas at the application of ASC 740, Income Taxes (ASC 740) to certain provisionsactual LIFO cost of the Tax Reform Legislation. ASU 2018-02 specifically addresses the ASC 740 requirement that the effect of a change in tax laws or rates on deferred tax assets and liabilities be included in income from continuing operations, even when the tax effects were initially recognized directly in OCIinventory layers liquidated. Nicor Gas had no inventory decrement at the previous rate, which strands the income tax rate differential in accumulated OCI. The amendments in ASU 2018-02 allow a reclassification from accumulated OCI to retained earnings for stranded tax effects resulting from the Tax Reform Legislation. The registrants adopted ASU 2018-02 effective January 1, 2018 with no material impact on their financial statements.June 30, 2019.
Asset Retirement ObligationsGoodwill and Other Intangible Assets
Goodwill at June 30, 2019 and December 31, 2018 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 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 1 to the financial statements of (K) under "Southern Company and the traditional electric operating companies under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K" for additional information regarding each company's AROs and the EPA's Disposalinformation.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
As of September 30, 2018, details of the AROs, including those related to the CCR Rule, included in the condensed balance sheets of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi PowerOther 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 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Southern Company | | Alabama Power | | Georgia Power | | Gulf
Power | | Mississippi Power |
| | (in millions) |
| Balance at December 31, 2017 | $ | 4,824 |
| | $ | 1,709 |
| | $ | 2,638 |
| | $ | 142 |
| | $ | 174 |
|
| Liabilities incurred | 2 |
| | — |
| | — |
| | — |
| | — |
|
| Liabilities settled | (160 | ) | | (31 | ) | | (82 | ) | | (23 | ) | | (22 | ) |
| Accretion | 153 |
| | 72 |
| | 70 |
| | 3 |
| | 4 |
|
| Cash flow revisions | 1,510 |
| | 1,451 |
| | (32 | ) | | 42 |
| | 21 |
|
| Reclassification to held for sale | (164 | ) | | — |
| | — |
| | — |
| | — |
|
| Balance at September 30, 2018 | $ | 6,165 |
| | $ | 3,201 |
| | $ | 2,594 |
| | $ | 164 |
| | $ | 177 |
|
In June 2018, Alabama Power recorded an increase of approximately $1.2 billion to its AROs related to the CCR Rule. Mississippi Power also recorded an increase of approximately $11 million to its AROs related to an ash pond at Plant Greene County, which is jointly-owned with Alabama Power. The revised cost estimates were based on information from feasibility studies performed on ash ponds in use at plants operated by Alabama Power, including Plant Greene County. During the second quarter 2018, Alabama Power's management completed its analysis of these studies which indicated that additional closure costs, primarily related to increases in estimated ash volume, water management requirements, and design revisions, will be required to close these ash ponds under the planned closure-in-place methodology. As the level of work becomes more defined in the next 12 months, it is likely that these cost estimates will change and the change could be material.
Georgia Power continues to perform engineering studies related to its plans to close the ash ponds at all of its generating plants, including Plant Scherer Unit 3, which is jointly owned with Gulf Power, in compliance with federal and state CCR rules. Georgia Power also continues to refine its closure strategy and cost estimates for each ash pond and is preparing permit applications as required by the State of Georgia CCR rule. While Georgia Power and Gulf Power believe their recorded liabilities for ash pond closures appropriately reflect their obligations under the current closure strategies they have elected, changes to such strategies and cost estimates would likely result in additional closure costs which would increase their ARO liabilities. It is not currently possible to quantify the impacts of any increase related to a change in closure strategies and/or ongoing engineering studies for the current closure strategies, and the timing of future cash outflows is indeterminable at this time; however, the impact on Georgia Power's and Gulf Power's ARO liabilities is expected to be material. As permit applications advance, engineering studies continue, and the timing of individual ash pond closures develops further during the fourth quarter 2018, Georgia Power and Gulf Power will record any necessary changes to their ARO liabilities.
The traditional electric operating companies expect to continue to periodically update their ARO cost estimates, which could increase further, as additional information becomes available. Absent continued recovery of ARO costs through regulated rates, Southern Company's and the traditional electric operating companies' results of operations, cash flows, and financial condition could be materially impacted. The ultimate outcome of this matter cannot be determined at this time.
In June 2018, Alabama Power completed an updated decommissioning cost site study for Plant Farley. The estimated cost of decommissioning based on the study resulted in an increase in Southern Company's and Alabama Power's ARO liability of approximately $300 million. See "Nuclear Decommissioning" below for additional information.
Georgia Power expects to complete updated decommissioning cost site studies for Plant Hatch and Plant Vogtle Units 1 and 2 in the fourth quarter 2018, which could result in additional changes to Southern Company's and Georgia Power's ARO liability. The ultimate outcome of these studies cannot be determined at this time.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
The reclassification of a portion of the ARO liability to liabilities held for sale by Southern Company represents the AROsAmortization 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
At December 31, 2018, Georgia Power had restricted cash related to Gulf Power.the redemption of pollution control revenue bonds, which were redeemed in January 2019. See Note (J)(F) under "Southern Company's Sale of Gulf Power" and "Assets Held for SaleFinancing 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.
Nuclear Decommissioning
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 Southern Company and Alabama Power under "Nuclear Decommissioning" in Item 8 ofcash flows for the Form 10-K for additional information.
Inregistrants that had restricted cash at June 2018, Alabama Power completed an updated decommissioning cost site study for Plant Farley. The estimated costs of decommissioning based on the 2018 site study are as follows:30, 2019 and/or December 31, 2018:
|
| | | |
| Decommissioning periods: | |
| Beginning year | 2037 |
|
| Completion year | 2076 |
|
| | |
| | (in millions) |
| Site study costs: | |
| Radiated structures | $ | 1,621 |
|
| Non-radiated structures | 99 |
|
| Total site study costs | $ | 1,720 |
|
|
| | | | | | | |
| | 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. |
The decommissioning cost estimates are based on prompt dismantlement and removal |
| | | | | | | | | |
| | 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 |
|
For ratemaking purposes, Alabama Power's decommissioning costs are based on the site study. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and a trust earnings rate of 7.0%. The next site study is expected to be completed in 2023.
Amounts previously contributed to the external trust funds are currently projected to be adequate to meet the updated decommissioning obligations. Alabama Power will continue to provide site specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC's approval to address any changes in a manner consistent with the NRC and other applicable requirements.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Natural Gas for Sale
Southern Company Gas, with the exception of Nicor Gas, carries natural gas inventory on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value. Southern Company Gas recorded 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. Nicor Gas had no inventory decrement at June 30, 2019.
Goodwill and Other Intangible Assets
The following table presents year-to-date changes in goodwill balances for Southern CompanyGoodwill at June 30, 2019 and Southern Company Gas:December 31, 2018 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 |
| | Southern Company | | Southern Company Gas |
| | | Gas Distribution Operations | Gas Marketing Services | Total |
| | (in millions) |
| Balance at December 31, 2017 | $ | 6,268 |
| | $ | 4,702 |
| $ | 1,265 |
| $ | 5,967 |
|
Impairment(a) | (42 | ) | | — |
| (42 | ) | (42 | ) |
Dispositions(b) | (910 | ) | | (668 | ) | (242 | ) | (910 | ) |
| Balance at September 30, 2018 | $ | 5,315 |
| (c) | $ | 4,034 |
| $ | 981 |
| $ | 5,015 |
|
| |
(a) | On April 11, 2018, Southern Company Gas entered into a stock purchase agreement for the sale of Pivotal Home Solutions. In contemplation of the transaction, a goodwill impairment charge of $42 million was recorded in the first quarter 2018. See Note (J) under "Southern Company Gas" for additional information.
|
| |
(b) | Gas distribution operations reflects goodwill allocated to Elizabethtown Gas, Elkton Gas, and Florida City Gas, which were sold during the third quarter 2018. Gas marketing services reflects goodwill associated with Pivotal Home Solutions, which was sold on June 4, 2018. See Note (J) under "Southern Company Gas" for additional information.
|
| |
(c) | Total does not add due to rounding. |
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, 2018 | | At December 31, 2017 |
| | 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(*) | $ | 223 |
| $ | (87 | ) | $ | 136 |
| | $ | 288 |
| $ | (83 | ) | $ | 205 |
|
Trade names(*) | 70 |
| (18 | ) | 52 |
| | 159 |
| (17 | ) | 142 |
|
| Storage and transportation contracts | 64 |
| (49 | ) | 15 |
| | 64 |
| (34 | ) | 30 |
|
| PPA fair value adjustments | 456 |
| (66 | ) | 390 |
| | 456 |
| (47 | ) | 409 |
|
| Other | 11 |
| (5 | ) | 6 |
| | 17 |
| (5 | ) | 12 |
|
| Total other intangible assets subject to amortization | $ | 824 |
| $ | (225 | ) | $ | 599 |
|
| $ | 984 |
| $ | (186 | ) | $ | 798 |
|
| Other intangible assets not subject to amortization: | | | | | | | |
| Federal Communications Commission licenses | 75 |
| — |
| 75 |
| | 75 |
| — |
| 75 |
|
| Total other intangible assets | $ | 899 |
| $ | (225 | ) | $ | 674 |
| | $ | 1,059 |
| $ | (186 | ) | $ | 873 |
|
| | | | | | | | |
| Southern Power | | | | | | | |
| Other intangible assets subject to amortization: | | | | | | | |
| PPA fair value adjustments | $ | 456 |
| $ | (66 | ) | $ | 390 |
| | $ | 456 |
| $ | (47 | ) | $ | 409 |
|
| | | | | | | | |
| Southern Company Gas | | | | | | | |
| Other intangible assets subject to amortization: | | | | | | | |
Gas marketing services(*) | | | | | | | |
| Customer relationships | $ | 156 |
| $ | (78 | ) | $ | 78 |
| | $ | 221 |
| $ | (77 | ) | $ | 144 |
|
| Trade names | 26 |
| (6 | ) | 20 |
| | 115 |
| (9 | ) | 106 |
|
| Wholesale gas services | | | | | | | |
| Storage and transportation contracts | 64 |
| (49 | ) | 15 |
| | 64 |
| (34 | ) | 30 |
|
| Total other intangible assets subject to amortization | $ | 246 |
| $ | (133 | ) | $ | 113 |
| | $ | 400 |
| $ | (120 | ) | $ | 280 |
|
| |
(*) | Balances as of September 30, 2018 reflect Southern Company Gas' sale of Pivotal Home Solutions. See Note (J) under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.
|
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 |
|
|
| | | | | | |
| | Three Months Ended | Nine Months Ended |
| | September 30, 2018 |
| | (in millions) |
| Southern Company | $ | 21 |
| $ | 70 |
|
| Southern Power | $ | 6 |
| $ | 19 |
|
| Southern Company Gas | $ | 12 |
| $ | 42 |
|
| |
| (a) | Recorded as a reduction to operating revenues. |
| |
| (b) | Included in depreciation and amortization. |
Restricted Cash
The registrants adopted ASU 2016-18 as of January 1, 2018. See "Recently Adopted Accounting Standards – Other" herein for additional information.
At December 31, 2017, Southern2018, Georgia Power had restricted cash primarily related to certain acquisitions and construction projects.the redemption of pollution control revenue bonds, which were redeemed in January 2019. See Note (F) under "Financing Activities" for additional information. At both SeptemberJune 30, 20182019 and December 31, 2017,2018, Southern Company Gas had restricted cash held as collateral for worker's compensation, life insurance, and long-term disability insurance.
The following tables provide a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed balance sheets that total to the amounts shown in the condensed statements of cash flows for the registrants that had restricted cash at SeptemberJune 30, 20182019 and/or December 31, 2017:2018:
| | | | Southern Company | | Southern Company Gas | Southern Company | | Southern Company Gas |
| | (in millions) | (in millions) |
| At September 30, 2018 | | | | |
| At June 30, 2019 | | | | |
| Cash and cash equivalents | $ | 1,847 |
| | $ | 56 |
| $ | 1,383 |
| | $ | 56 |
|
| Cash and cash equivalents classified as assets held for sale | 37 |
| | — |
| |
| Restricted cash: | | | | | | |
| Other accounts and notes receivable | 6 |
| | 6 |
| 4 |
| | 4 |
|
| Total cash, cash equivalents, and restricted cash | $ | 1,891 |
| (*) | $ | 62 |
| $ | 1,386 |
| (*) | $ | 60 |
|
| |
| (*) | Total does not add due to rounding. |
| | | | Southern Company | Southern Power | Southern Company Gas | Southern Company | Georgia Power | Southern Company Gas |
| | (in millions) | (in millions) |
| At December 31, 2017 | | |
| At December 31, 2018 | | |
| Cash and cash equivalents | $ | 2,130 |
| $ | 129 |
| $ | 73 |
| $ | 1,396 |
| $ | 4 |
| $ | 64 |
|
| Cash and cash equivalents held for sale | | 9 |
| — |
| — |
|
| Restricted cash: | | |
| Restricted cash | | — |
| 108 |
| — |
|
| Other accounts and notes receivable | 5 |
| — |
| 5 |
| 114 |
| — |
| 6 |
|
| Deferred charges and other assets | 12 |
| 11 |
| — |
| |
| Total cash, cash equivalents, and restricted cash | $ | 2,147 |
| $ | 140 |
| $ | 78 |
| $ | 1,519 |
| $ | 112 |
| $ | 70 |
|
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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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, 2018.2019.
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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
(B) REGULATORY MATTERS
See Note 2 to the lower of weighted average cost or current market price, with cost determined on a WACOG basis. For any declinesfinancial statements in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value. Southern Company Gas had no material LOCOM adjustment in any period presented.
Hypothetical Liquidation at Book Value
Southern Power has consolidated renewable generation projects that are partially funded by a third-party tax equity investor. The related contractual provisions represent profit-sharing arrangements because the allocations of cash distributions and tax benefits are not based on fixed ownership percentages. Therefore, the noncontrolling interest is accounted for under a balance sheet approach utilizing the hypothetical liquidation at book value (HLBV) method. The HLBV method calculates each partner's share of income based on the change in net equity the partner can legally claim in a hypothetical liquidation at the endItem 8 of the period comparedForm 10-K for additional information relating to the beginningregulatory matters.
The recovery balances for certain of the period.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)
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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,
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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)
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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 laws and regulations governing air, water, land, and protection of
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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 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
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 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 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 June 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. In JulyAlso in 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition in September
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
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2017. Onopposition. In March 29, 2018, the U.S. District Court for the Northern District of Georgia, Atlanta Division,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. OnIn April 26, 2018, the defendants filed a motion for reconsideration of the court's order, seeking dismissal of the remaining claims in the lawsuit. OnIn August 10, 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 and, in May 2017, Judy Mesirov filed a shareholder derivative lawsuit, each 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 August 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. OnIn April 25, 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, State of Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper 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. OnIn May 4, 2018, the court entered an
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
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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 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.
Alabama Power
On March 2, 2018, the Alabama Department of Environmental Management (ADEM) issued proposed administrative orders assessing a penalty of $1.25 million to Alabama Power for unpermitted discharge of fluids and/or pollutants to groundwater at five electric generating plants. The orders were finalized and Alabama Power paid the penalty on September 27, 2018. This matter is now concluded.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 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 August 2017. OnIn June 18, 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. On August 27, 2018,
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
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Following a motion by Georgia Power, filed a motionon February 13, 2019, the Superior Court of Fulton County ordered the parties to stay the case and requested the trial court refer the casesubmit petitions to the Georgia PSC for a declaratory ruling.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 merit and will continue to vigorously defend itself in this matter.merit. 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 will ultimately be certified; the scope of such a class, if certified; and whether any losses would be subject to recovery from any municipalities. The ultimate outcome of this matter cannot be determined at this time.
Mississippi Power
In 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 to include, among other things, Southern Company as a defendant. The individual plaintiff alleged that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs 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 County energy facility and that these alleged breaches unjustly enriched Mississippi Power and Southern Company. The plaintiffs sought unspecified actual damages and punitive damages; asked the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper County energy facility; asked the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper County energy facility in Mississippi; and sought attorney's fees, costs, and interest. The plaintiffs also sought an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. In June 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. In July 2017, the plaintiffs filed notice of an appeal. On July 13, 2018, Mississippi Power and Southern Company reached a settlement agreement with the plaintiffs and the plaintiffs' appeal was dismissed with prejudice. The settlement had no material impact on Southern Company's or Mississippi Power's financial statements.
On May 18, 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 September 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. Southern Company and Mississippi Power will vigorously defend themselves in this matter, theThe ultimate outcome of whichthis matter cannot be determined at this time.
On MayIn 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, 2018,2019. The amended complaint included four additional plaintiffs and additional claims for
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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 claim for lost revenue resulting from the Deepwater Horizon oil spill in the Gulfresults of Mexico in 2010 was settled.operations, financial condition, and liquidity. The settlement proceedsultimate outcome of $18 million, net of expenses and income tax, are included in Southern Company's and Mississippi Power's earnings for the nine months ended September 30, 2018.this matter cannot be determined at this time.
Southern Power
Southern Power indirectly owns a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock facility in Pecos County, Texas. Prior to the facility being placed in service in November 2016, certain solar panels were damaged during installation by the construction contractor, McCarthy Building Companies, Inc. (McCarthy), and certain solar panels were damaged by a hail event that also occurred during construction. In Mayconnection therewith, Southern Power withheld payment of approximately $26 million to the construction contractor, which placed a lien on the Roserock facility for the same amount. In 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas (State Court lawsuit) against XL Insurance America, Inc. (XL) and North American Elite Insurance Company (North American Elite) seeking recovery from an insurance policy for damages resulting from the hail stormevent and McCarthy's installation practices. OnIn June 1, 2018, the court in the State Court lawsuit granted Roserock's motion for partial summary judgment, finding that the insurers were in breach of contract and in violation of the Texas Insurance Code for failing to pay any monies owed for the hail claim. In addition to the State Court lawsuit,Separate lawsuits were filed between Roserock
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and McCarthy, as well as other parties, and that litigation has beenwas consolidated in the U.S. District Court for the Western District of Texas. On April 18, 2019, Roserock and the parties to the state and federal lawsuits executed a settlement agreement and mutual release that resolved both lawsuits. Following execution of the agreement, the 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 Energy Services Company, doing business as Pivotal Home Solutions, formerly a wholly-owned subsidiary of Southern Company Gas, was a defendant in a putative class action initially filed in 2017 in the state court in Indiana. The plaintiffs purported to represent a classMcCarthy released its lien. As part of the customers who purchased products from Nicor Energy Services Companysettlement, Roserock received funds that covered all related legal costs, damages, and alleged that the marketing, sale, and billingreplacement costs of certain solar panels. Funds received by Southern Power in excess of the products violated the Indiana Consumer Fraudinitial replacement costs were recognized as a gain and Deceptive Business Practices Act, constituting common law fraud and resulting in unjust enrichment of these entities. In 2018, Nicor Energy Services Company was named in a second class action filed in the state court of Ohio asserting nearly identical allegations and legal claims. The plaintiffs sought, on behalf of the classes they purported to represent, actual and punitive damages, interest costs, attorney fees, and injunctive relief. To facilitate the sale of Pivotal Home Solutions, Southern Company Gas retained most of the financial responsibility for these lawsuits following the completion of the sale. On June 12, 2018, the parties settled these claims and Southern Company Gas recorded an $11 million charge, which is included in other operationsincome (expense), net in 2019. A portion of the pre-tax gain was allocated to noncontrolling interests and maintenance expenses for the nine months ended September 30, 2018.Southern Power recognized a $12 million after-tax gain.
Environmental Remediation
The Southern Company system must comply with environmental laws and regulations governing the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companies and the natural gas distribution utilities in Illinois and Georgia have alleach 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 $25$18 million and $22$23 million as of SeptemberJune 30, 20182019 and December 31, 2017,2018, 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 $48 million and $52 million as of September 30, 2018 and December 31, 2017, 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.
At September 30, 2018, Southern Company Gas' environmental remediation liability was $283 million and $294 million as of June 30, 2019 and December 31, 2018, respectively, based on the estimated cost of environmental investigation and remediation associated with known current and former manufactured gas plant operating sites. At December 31, 2017, Southern Company Gas' total environmental remediation liability was $388 million, of which $85 million related to Elizabethtown Gas, which was sold on July 1, 2018. 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 $2 million of the total accrued remediation costs. See Note (J) under "Southern Company Gas" for information regarding Southern Company Gas' sale of Elizabethtown Gas.
The ultimate outcome of these matters cannot be determined at this time; however, as a result of the regulatory treatment for environmental remediation expenses described above, the final disposition of these matters is not expected to have a material impact on the financial statements of Southern Company, Georgia Power, Gulf Power, or Southern Company Gas.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
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FERC MattersNuclear Fuel Disposal Costs
Market-Based Rate Authority
See Note 3In 2014, Alabama Power and Georgia Power filed lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plants Farley, Hatch, and Vogtle Units 1 and 2 for the period from January 1, 2011 through December 31, 2013. The damage period was subsequently extended to December 31, 2014. 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 be recognized in the financial statements until the court enters final judgment on the remaining damages. The final outcome of these matters cannot be determined at this 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, the traditional electric operating companies, and SouthernCompany's, Alabama Power's, or Georgia Power's net income is expected.
Other Matters
Alabama Power under "FERC Matters" in Item 8 of the Form 10-K for additional information regarding proceedings related to the traditional electric operating companies' and Southern Power's 2014 and 2017 triennial market power analyses.
On May 4, 2018, the FERC issued an order terminating both proceedings, finding that the traditional electric operating companies and Southern Power satisfy the FERC's standards for market-based rates. On May 9, 2018, the traditional electric operating companies and Southern Power made the compliance filing required by the order. These proceedings are concluded.
Open Access Transmission Tariff
On May 10, 2018,17, 2019, the Alabama Municipal Electric AuthorityDepartment 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 Cooperative Energy filed with the FERC a complaint against SCS and the traditional electric operating companies claiming that the current 11.25% base ROE used in calculating the annual transmission revenue requirementsquarterly progress reports. Alabama Power is awaiting finalization of the traditional electric operating companies' open access transmission tariff is unjustorder and unreasonable as measured by the applicable FERC standards. The complaint requests that the base ROE be set no higher than 8.65% and that the FERC order refunds for the difference in revenue requirements that results from applying a just and reasonable ROE established in this proceeding upon determining the current ROE is unjust and unreasonable. On June 18, 2018, SCS and the traditional electric operating companies filed their response challenging the adequacy of the showing presented by the complainants and offering support for the current ROE. On September 6, 2018, the FERC issued an order establishing a refund effective date of May 10, 2018 in the event a refund is due and initiating an investigation and settlement procedures regarding the current base ROE. Through September 30, 2018, the estimated maximum potential refund is not expected to be material to Southern Company's or the traditional electric operating companies' results of operations. The ultimate outcome of this matter cannot be determined at this time.
Fuel Cost Recovery
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.
Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At September 30, 2018, the amount of over-recovered wholesale MRA fuel costs included in other regulatory liabilities, current on the condensed balance sheet was approximately $7 million compared to an immaterial amount at December 31, 2017. Under-recovered wholesale MB fuel costs included in the balance sheets were immaterial at September 30, 2018 and December 31, 2017.
Cooperative Energy Power Supply Agreement
See Note 3 to the financial statements of Mississippi Power under "FERC Matters – Cooperative Energy Power Supply Agreement" in Item 8 of the Form 10-K for additional information regarding Cooperative Energy's network integration transmission service agreement (NITSA) with SCS.
On March 23, 2018, the FERC accepted the amendment to the NITSA between Cooperative Energy and SCS, effective April 1, 2018.
Regulatory Matters
Alabama Power
See Note 3 to the financial statements of Southern Company and Alabama Power under "Regulatory Matters – Alabama Power" and "Retail Regulatory Matters," respectively, in Item 8 of the Form 10-K for additional
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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,
2018 | December 31,
2017 |
| | | (in millions) |
| Rate CNP Compliance | Deferred under recovered regulatory clause revenues | $ | — |
| $ | 17 |
|
| | Under recovered regulatory clause revenues | 7 |
| — |
|
| Rate CNP PPA | Deferred under recovered regulatory clause revenues | 30 |
| 12 |
|
| Retail Energy Cost Recovery | Deferred under recovered regulatory clause revenues | 58 |
| 25 |
|
| | Under recovered regulatory clause revenues | 41 |
| — |
|
| Natural Disaster Reserve | Other regulatory liabilities, deferred | 24 |
| 38 |
|
On May 1, 2018, the Alabama PSC approved modifications to Rate RSE and other commitments designed to position Alabama Power to address the growing pressure on its credit quality resulting from the Tax Reform Legislation, without increasing retail rates under Rate RSE in the near term. Alabama Power plans to reduce growth in total debt by increasing equity, with corresponding reductions in debt issuances, thereby de-leveraging its capital structure. Alabama Power's goaltime; however, it is to achieve an equity ratio of approximately 55% by the end of 2025. At September 30, 2018, Alabama Power's equity ratio was approximately 47%.
Rate RSE
The approved modifications to Rate RSE became effective June 2018 and are applicable for January 2019 billings and thereafter. The modifications include reducing the top of the allowed weighted common equity return (WCER) range from 6.21% to 6.15% and modifications to the refund mechanism applicable to prior year actual results. The modifications to the refund mechanism allow Alabama Power to retain a portion of the revenue that causes the actual WCER for a given year to exceed the allowed range.
Generally, if Alabama Power's actual WCER range is between 6.15% and 7.65%, customers will receive 25% of the amount between 6.15% and 6.65%, 40% of the amount between 6.65% and 7.15%, and 75% of the amount between 7.15% and 7.65%. Customers will receive all amounts in excess of an actual WCER of 7.65%.
In conjunction with these modifications to Rate RSE, on May 8, 2018, Alabama Power consented to a moratorium on any upward adjustments under Rate RSE for 2019 and 2020. Additionally, Alabama Power will return $50 million to customers through bill credits in 2019.
In accordance with an established retail tariff that provides for an interim adjustment to customer billings to recognize the impact of a change in the statutory income tax rate, Alabama Power has returned $151 million through September 30, 2018 and anticipates returning a total of approximately $257 million to retail customers through bill credits by December 31, 2018 as a result of the change in the federal income tax rate under the Tax Reform Legislation.
Rate ECR
On May 1, 2018, the Alabama PSC approved an increase to Rate ECR from 2.015 cents per KWH to 2.353 cents per KWH effective July 2018 which isnot expected to result in additional collections of approximately $100 million through December 31, 2018. The approved increase in the Rate ECR factor will have no significant effecta material impact on Alabama Power's net income, butincome.
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 increase operating cash flows related to fuel cost recovery in 2018. Absent any further order from the Alabama PSC, in January 2019, the rate will return to the originally authorized 5.910 cents per KWH.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Accounting Order
On May 1, 2018, the Alabama PSC approved an accounting order that authorizes Alabama Power to defer the benefits of federal excess deferred income taxes associated with the Tax Reform Legislation for the year ending December 31, 2018 as a regulatory liability and to use up to $30 million of such deferrals to offset under recovered amounts under Rate ECR. Any remaining amounts will be used for the benefit of customers as determined by the Alabama PSC. As of September 30, 2018, Alabama Power had applied the full $30 million to offset the under recovered balance under Rate ECR and expects the total deferrals for the year ending December 31, 2018 to be approximately $50 million. See Note 5 to the financial statements of Southern Company and Alabama Power under "Federal Tax Reform Legislation" and of Alabama Power under "Current and Deferred Income Taxes" in Item 8retire its share of the Form 10-K for additional information.
generating capacity of Plant Greene County
Alabama Power jointly owns Plant Greene County with an affiliate, Mississippi Power. See Note 4 to the financial statements of Alabama Power in Item 8 of the Form 10-K for additional information regarding the joint ownership agreement. On August 6, 2018,Daniel on January 15, 2024. Mississippi Power filed its proposed Reserve Margin Plan (RMP) withhas the option to purchase Gulf Power's ownership interest for $1 on January 15, 2024, provided that Mississippi PSC, which proposes a four-year acceleration ofPower exercises the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively. Mississippi Power's proposed Plant Greene County unit retirements would require the completion of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. Alabama Power will monitor Mississippi Power's proposed RMP and associated regulatory process as well as the proposed transmission and system reliability improvements. Alabama Power will review all the facts and circumstances and will evaluate all its alternativesoption no later than 120 days prior to reaching a final determination onthat date. Mississippi Power is assessing the ongoing operationspotential operational and economic effects of Plant Greene County.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.
Georgia Power
Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, Environmental Compliance Cost Recovery tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to 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 "Nuclear Construction" herein and Note 3 to the financial statements of (K) under "Southern Company under "Nuclear Construction" and Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K" for additional information regarding the NCCR tariff. Also see "Fuel Cost Recovery" herein and Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Fuel Cost Recovery" and Georgia Power under "Retail Regulatory Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding fuel cost recovery.
Rate Plans
See Note 3 to the financial statements of Southern Company and Georgia Power under "Regulatory Matters – Georgia Power – Rate Plans" and "Retail Regulatory Matters – Rate Plans," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's 2013 ARP and the Georgia PSC's 2018 order related to the Tax Reform Legislation.
On April 3, 2018, the Georgia PSC approved a settlement agreement between Georgia Power and the staff of the Georgia PSC regarding the retail rate impact of the Tax Reform Legislation (Georgia Power Tax Reform Settlement Agreement). Pursuant to the Georgia Power Tax Reform Settlement Agreement, to reflect the federal income tax rate reduction impact of the Tax Reform Legislation, Georgia Power will refund to customers a total of $330 million through bill credits. Georgia Power issued bill credits of approximately $130 million in October 2018 and will issue bill credits of approximately $95 million in June 2019 and $105 million in February 2020. In addition, Georgia Power is deferring as a regulatory liability (i) the revenue equivalent of the tax expense reduction resulting from
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
legislation lowering the Georgia state income tax rate from 6.00% to 5.75% in 2019 and (ii) the entire benefit of approximately $700 million in federal and state excess accumulated deferred income taxes. At September 30, 2018, Georgia Power's related regulatory liability balance totaled $655 million. The amortization of these regulatory liabilities is expected to be addressed in Georgia Power's next base rate case, which is scheduled to be filed by July 1, 2019. If there is not a base rate case in 2019, customers will receive $185 million in annual bill credits beginning in 2020, with any additional federal and state income tax savings deferred as a regulatory liability, until Georgia Power's next base rate case.
To address the negative cash flow and credit metric impacts of the Tax Reform Legislation, the Georgia PSC also approved an increase in Georgia Power's retail equity ratio to the lower of (i) Georgia Power's actual common equity weight in its capital structure or (ii) 55%, until Georgia Power's next base rate case. At September 30, 2018, Georgia Power's actual retail common equity ratio (on a 13-month average basis) was approximately 53%. Benefits from reduced federal income tax rates in excess of the amounts refunded to customers will be retained by Georgia Power to cover the carrying costs of the incremental equity in 2018 and 2019.
Fuel Cost Recovery
As of September 30, 2018 and December 31, 2017, Georgia Power's under recovered fuel balance totaled $105 million and $165 million, respectively, and is included as under recovered fuel clause revenues on Southern Company's and Georgia Power's condensed balance sheets. On August 16, 2018, the Georgia PSC approved the deferral of Georgia Power's next fuel case to no later than March 16, 2020, with rates to be effective June 1, 2020. Georgia Power continues to be allowed to adjust its fuel cost recovery rates under an interim fuel rider prior to the next fuel case if the under or over recovered fuel balance exceeds $200 million.
Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's or Georgia Power's revenues or net income, but will affect cash flow.
Storm Damage Recovery
See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Storm Damage Recovery" and Note 1 to the financial statements of Georgia Power under "Storm Damage Recovery" in Item 8 of the Form 10-K for additional information regarding Georgia Power's storm damage reserve.
Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, for incremental operations and maintenance costs of damage from major storms to its transmission and distribution facilities. As of September 30, 2018, the total balance in Georgia Power's regulatory asset related to storm damage was $311 million. During October 2018, Hurricane Michael caused significant damage to Georgia Power's transmission and distribution facilities. Georgia Power currently estimates the costs of repairing the damage will total approximately $125 million to $150 million, which will be charged to Georgia Power's storm damage reserve or capitalized. The rate of storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case, which is scheduled to be filed by July 1, 2019. The ultimate outcome of this matter cannot be determined at this time.
Gulf Power
See Note 3 to the financial statementssale 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.
Storm Damage Cost Recovery
See Note 1 to the financial statements of Gulf Power under "Property Damage Reserve" in Item 8 of the Form 10-K for information on how Gulf Power maintains a reserve for property damage to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generating facilities and other property.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
On October 10, 2018, Hurricane Michael made landfall on the Gulf Coast of Florida causing substantial damage in Gulf Power's service territory. Gulf Power currently estimates the costs of repairing the damages to its transmission and distribution lines and uninsured facilities will total approximately $350 million to $400 million, which primarily will be charged to Gulf Power's property damage reserve or capitalized. At September 30, 2018, Gulf Power had a balance of approximately $48 million in its property damage reserve. In accordance with the 2017 Gulf Power Rate Case Settlement Agreement, Gulf Power can petition the Florida PSC to seek recovery of the costs associated with Hurricane Michael, along with replenishing the property damage reserve to approximately $40 million. Any recovery from customers would begin, on an interim basis, 60 days following the filing of the cost recovery petition. The ultimate outcome of this matter cannot be determined at this time.
Retail Base Rate Case
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.
As a continuation of a settlement agreement approved by the Florida PSC in April 2017 (2017 Gulf Power Rate Case Settlement Agreement), on March 26, 2018, the Florida PSC approved a stipulation and settlement agreement among Gulf Power and three intervenors addressing the retail revenue requirement effects of the Tax Reform Legislation (Gulf Power Tax Reform Settlement Agreement).
The Gulf Power Tax Reform Settlement Agreement results in annual reductions to Gulf Power's revenues of $18.2 million from base rates and $15.6 million from environmental cost recovery rates implemented April 1, 2018 and also provided for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to normalization) deferred tax liabilities through a reduced fuel cost recovery rate over the remainder of 2018. Through September 30, 2018, approximately $53 million of this refund has been reflected in customer bills. As a result of the Gulf Power Tax Reform Settlement Agreement, the Florida PSC also approved an increase in Gulf Power's maximum equity ratio from 52.5% to 53.5% for all retail regulatory purposes.
As part of the Gulf Power Tax Reform Settlement Agreement, a limited scope proceeding to address protected deferred tax liabilities consistent with IRS normalization principles was initiated on April 30, 2018. On October 30, 2018, the Florida PSC approved a $9.6 million annual reduction in base rate revenues effective January 2019, which concluded this proceeding. Through September 30, 2018, Gulf Power has deferred $7 million of related 2018 tax benefits as a regulatory liability to be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rate.
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, as approved by the Florida PSC. Regulatory clause recovery balances included in the balance sheets are as follows:
|
| | | | | | | |
| Regulatory Clause | Balance Sheet Line Item | September 30,
2018 | December 31,
2017 |
| | | (in millions) |
| Fuel Cost Recovery | Under recovered regulatory clause revenues | $ | — |
| $ | 22 |
|
| Fuel Cost Recovery | Other regulatory liabilities, current | 23 |
| — |
|
| Purchased Power Capacity Recovery | Other regulatory liabilities, current | 4 |
| — |
|
| Purchased Power Capacity Recovery | Under recovered regulatory clause revenues | — |
| 2 |
|
Environmental Cost Recovery(*) | Other regulatory liabilities, current | 13 |
| — |
|
Environmental Cost Recovery(*) | Under recovered regulatory clause revenues | — |
| 2 |
|
| Energy Conservation Cost Recovery | Other regulatory liabilities, current | 2 |
| — |
|
| |
(*) | At September 30, 2018 and December 31, 2017, the over and under recovered balances, respectively, included in the balance sheets represents the current portion of the regulatory assets associated with projected environmental expenditures of approximately $8 million and $13 million, respectively, net of the over recovered environmental cost recovery balance of approximately $21 million and $11 million, respectively. |
On November 5, 2018, 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 2019. The net effect of the approved changes is a $38 million decrease in annual revenues effective in January 2019, the majority of which will be offset by related expense decreases.
Mississippi Power
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.
On May 8, 2018, the Mississippi PSC issued an order to begin an operations review of Mississippi Power, which began in August 2018, with the final report expected by February 28, 2019. Mississippi Power expects that the review will include, but not be limited to, a comparative analysis of its costs, its cost recovery framework, and ways in which it may streamline management operations for the reasonable benefit of ratepayers. The ultimate outcome of this matter cannot be determined at this time.
Performance Evaluation Plan
In 2013, the Mississippi Public Utilities Staff (MPUS) contested Mississippi Power's PEP lookback filing for 2012, which indicated a refund due to customers of $5 million. In each of 2014, 2015, 2016, and 2017, Mississippi Power submitted its annual PEP lookback filing for the prior year, which for 2013 and 2014 each indicated no surcharge or refund and for each of 2015 and 2016 indicated a $5 million surcharge. Additionally, in July 2016, in November 2016, and on November 15, 2017, Mississippi Power submitted its annual projected PEP filings for 2016, 2017, and 2018, respectively, which for 2016 and 2017 indicated no change in rates and for 2018 indicated a rate increase of 4%, or $38 million in annual revenues. The Mississippi PSC suspended each of these filings to allow more time for review.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
On February 7, 2018, Mississippi Power submitted its revised 2018 projected PEP filing to the Mississippi PSC, which reflected the impacts of the Tax Reform Legislation, requesting an increase in annual retail revenues of $26 million based on a performance-adjusted ROE of 9.33% and an increased equity ratio of 55%.
On March 22, 2018, Mississippi Power submitted its annual PEP lookback filing for 2017, which reflected no surcharge or refund.
On July 27, 2018, Mississippi Power and the MPUS entered into a settlement agreement with respect to the 2018 PEP filing and all unresolved PEP filings for prior years (PEP Settlement Agreement), which was approved by the Mississippi PSC on August 7, 2018. Rates under the PEP Settlement Agreement became effective with the first billing cycle of September 2018. The PEP Settlement Agreement provides for an increase of approximately $21.6 million in annual base retail revenues, which excludes certain compensation costs contested by the MPUS, as well as approximately $2 million which was subsequently approved for recovery through the 2018 Energy Efficiency Cost Rider as discussed below. Under the PEP Settlement Agreement, Mississippi Power is deferring the contested compensation costs for 2018 and 2019 as a regulatory asset, which totaled $3 million as of September 30, 2018 and is included in other regulatory assets, deferred on Mississippi Power's condensed balance sheet. The Mississippi PSC is currently expected to rule on the appropriate treatment for such costs in connection with Mississippi Power's next base rate case, which is scheduled to be filed in the fourth quarter 2019 (2019 Base Rate Case). The ultimate outcome of this matter cannot be determined at this time.
Pursuant to the PEP Settlement Agreement, Mississippi Power's performance-adjusted allowed ROE is 9.31% and its allowed equity ratio remains at 50%, pending further review by the Mississippi PSC. In lieu of the requested equity ratio increase, Mississippi Power retained $44 million of excess accumulated deferred income taxes resulting from the Tax Reform Legislation, which had been proposed to be amortized beginning in 2018, until the conclusion of the 2019 Base Rate Case. Further, Mississippi Power will seek equity contributions sufficient to restore its equity ratio (which was 45% at September 30, 2018) to 50% by December 31, 2018. In the event Mississippi Power's actual average equity ratio for 2018 is more than 1% higher or lower than the 50% target, Mississippi Power will defer the corresponding difference in its revenue requirement as a regulatory asset or liability for resolution in the 2019 Base Rate Case. As of September 30, 2018, Mississippi Power has recorded $5 million in other regulatory liabilities, deferred on Mississippi Power's condensed balance sheet related to the estimated December 31, 2018 average equity ratio differential from target applicable to PEP.
Pursuant to the PEP Settlement Agreement, PEP proceedings are suspended until after the conclusion of the 2019 Base Rate Case and Mississippi Power is not required to make any PEP filings for regulatory years 2018, 2019, and 2020. The PEP Settlement Agreement also resolved all open PEP filings with no change to customer rates. As a result, in the third quarter 2018, Mississippi Power recognized revenues of $5 million previously reserved in connection with the 2012 PEP lookback filing.
Energy Efficiency
On May 8, 2018, the Mississippi PSC issued an order approving Mississippi Power's revised annual projected Energy Efficiency Cost Rider 2018 compliance filing, which increased annual retail revenues by approximately $3 million effective with the first billing cycle for June 2018.
Ad Valorem Tax Adjustment
On May 8, 2018, the Mississippi PSC also approved Mississippi Power's annual ad valorem tax adjustment factor filing for 2018, which included an annual rate increase of 0.8%, or $7 million, in annual retail revenues effective with the first billing cycle for June 2018, primarily due to increased assessments.
Environmental Compliance Overview Plan
On August 3, 2018, Mississippi Power and the MPUS entered into a settlement agreement with respect to the 2018 ECO Plan filing (ECO Settlement Agreement), which provides for an increase of approximately $17 million in annual base retail revenues and was approved by the Mississippi PSC on August 7, 2018. Rates under the ECO Settlement Agreement became effective with the first billing cycle of September 2018 and will continue in effect
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
until modified by the Mississippi PSC. These revenues are expected to be sufficient to recover the costs included in Mississippi Power's request for 2018, as well as the remaining deferred amounts that were originally expected to be recovered in 2019. In accordance with the ECO Settlement Agreement, ECO Plan proceedings are suspended until after the conclusion of the 2019 Base Rate Case and Mississippi Power is not required to make any ECO Plan filings for 2018, 2019, and 2020, with any necessary true-ups to be reflected in the 2019 Base Rate Case. The ECO Settlement Agreement contains the same terms as the PEP Settlement Agreement described herein with respect to allowed ROE and equity ratio. As of September 30, 2018, Mississippi Power has recorded $2 million in other regulatory liabilities, deferred on Mississippi Power's condensed balance sheet related to the estimated December 31, 2018 average equity ratio differential from target applicable to the ECO Plan.
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 Form10-K for additional information regarding Mississippi Power's retail fuel cost recovery.
At September 30, 2018, the amount of over-recovered retail fuel costs included on Mississippi Power's condensed balance sheet in customer accounts receivable was approximately $13 million compared to $6 million under recovered at December 31, 2017.
Mississippi Power's operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in the billing factor should have no significant effect on Mississippi Power's revenues or net income, but will affect cash flow.
Southern Company Gas
See Note 3 to the financial statementsThe future performance of Southern Company and Southern Company Gas under "Regulatory Matters – Southern Company Gas" and "Regulatory Matters," respectively,Gas' natural gas storage facility consisting of two salt dome caverns in Item 8 of the Form 10-K for additional information regardingLouisiana, as well as Southern Company Gas' regulatory matters.
Riders
On April 19, 2018, the Illinois Commission approved Nicor Gas' variable income tax adjustment rider. This rider provides for refund or recovery oftwo other natural gas storage facilities located in California and Texas, could be impacted by ongoing changes in income tax expense that result from income tax rates that differ from those used in Nicor Gas' last rate case. Customer refunds, via bill credits, began on July 1, 2018 related to the impacts of the Tax Reform Legislation from January 25, 2018 through May 4, 2018. The impact of the Tax Reform Legislation subsequent to May 4, 2018 was addressed in Nicor Gas' approved rehearing request discussed herein under "Settled Base Rate Cases."
Natural Gas Cost Recovery
Southern Company Gas has establishedU.S. 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 recoverablestorage market. Recent sales of natural gas costs and amounts billedstorage facilities have resulted 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
Settled Base Rate Cases
On February 23, 2018, Atlanta Gas Light revised its annual base rate filing to reflect the impacts of the Tax Reform Legislation and requested a $16 million rate reduction in 2018. On May 15, 2018, the Georgia PSC approved a stipulation for Atlanta Gas Light's annual base rates to remain at the 2017 level for 2018 and 2019, with customer credits of $8 million in each of July 2018 and October 2018 to reflect the impacts of the Tax Reform Legislation. The Georgia PSC maintained Atlanta Gas Light's previously authorized earnings band based on a ROE between
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
10.55% and 10.95% and increased the allowed equity ratio by 4% to an equity ratio of 55% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation. Additionally, Atlanta Gas Light is required to file a traditional base rate case on or before June 1, 2019 for rates effective January 1, 2020.
On May 2, 2018, the Illinois Commission approved Nicor Gas' rehearing request for revised base rates to incorporate the reduction in the federal income tax rate as a result of the Tax Reform Legislation. The resulting decrease of approximately $44 million in annual base rate revenues became effective May 5, 2018. Nicor Gas' previously-authorized capital structure and ROE of 9.8% were not addressed in the rehearing and remain unchanged. The impact of the Tax Reform Legislation prior to May 5, 2018 was addressed in the variable income tax rider discussed herein under "Riders."
On October 15, 2018, the Tennessee Public Utility Commission (PUC) approved a $1 million increase in Chattanooga Gas' annual base rate revenues, which was based on a projected test year ending June 30, 2019 and a ROE of 9.80%. The new rates became effective November 1, 2018.
Other
The Virginia Commission issued an order effective January 1, 2018 requiring utilities in the state to defer as a regulatory liability the impact of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of the flowback of excess deferred income taxes. Through September 30, 2018, Virginia Natural Gas had deferred a total of $9 million. On August 30, 2018, Virginia Natural Gas filed an annual information form, which was subsequently revised on October 25, 2018, proposing to reduce annual base rates effective January 1, 2019 due to lower tax expense as a result of the lower corporate income tax rate and the impact of the flowback of excess deferred income taxes. This filing also proposes for Virginia Natural Gas to issue customer refunds, via bill credits,losses for the related amounts deferred as a regulatory asset. The Virginia Commission is expected to rulesellers and may imply an impact on the filing during the fourth quarter 2018. If approved as filed, Virginia Natural Gas' annual base rate revenues would be reduced by $14 million. The ultimate outcome of this matter cannot be determined at this time.
Regulatory Infrastructure Programs
future rates and/or asset values. Southern Company Gas is engaged in various infrastructure programs that update or expandevaluating these recent market transactions for impacts on its gas distribution systemsplans 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. 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 8one of the Form 10-K for additional information.
Atlanta Gas Light's Pipeline Replacement Program
Onesalt dome caverns in Louisiana back to service in 2021. Sustained diminished natural gas storage values could trigger impairment of the capital projects under Atlanta Gas Light's Pipeline Replacement Program experienced construction issues and Atlanta Gas Light was required to complete mitigation work prior to placing it in service. In the first quarter 2018, Atlanta Gas Light recovered $7 million from the final settlement of contractor litigation claims. Mitigation costs recovered through the legal process are retained by Atlanta Gas Light. For additional information on the Pipeline Replacement Program settlement, see Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters – PRP Settlement" in Item 8 of the Form 10-K.
Nuclear Construction
See Note 3 to the financial statements of Southern Company and Georgia Power under "Nuclear Construction" and "Retail Regulatory Matters – Nuclear Construction," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's construction of Plant Vogtle Units 3 and 4, VCM reports, and the NCCR tariff.
In 2009, the Georgia PSC certified construction of 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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
(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 Vogtle Owners, entered into the Interim Assessment Agreement with the EPC Contractor to allow construction to continue. The Interim Assessment Agreement expired in July 2017 when Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Vogtle Services Agreement. Under the Vogtle Services Agreement, 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 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, ofone or all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. Pursuant to the Loan Guarantee Agreement between Georgia Power and the DOE, 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 December 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor.
Cost and Schedule
In preparation for its nineteenth VCM filing, Georgia Power requested Southern Nuclear to perform a full cost reforecast for the project. 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 September 30, 2018(b) | (4.3 | ) |
Remaining estimate to complete(a) | $ | 4.1 |
|
| |
(a) | Excludes financing costs expected to be capitalized through AFUDC of approximately $350 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 $3.2 billion, of which $1.8 billion had been incurred through September 30, 2018.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
The table above reflects the $0.7 billion increase to the base capital cost forecast reported in the second quarter 2018 and is based on the cost reforecast performed prior to the nineteenth VCM filing, which primarily resulted from changed assumptions related to the finalization of contract scopes and management responsibilities for Bechtel and over 60 subcontractors, labor productivity rates, and craft labor incentives, as well as the related levels of project management, oversight, and support, including field supervision and engineering support.
Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC's order in the seventeenth VCM proceeding specifically states that the construction of Plant Vogtle Units 3 and 4 is not subject to a cost cap, Georgia Power did not seek rate recovery for these cost increases included in the current base capital cost forecast (or any related financing costs) in the nineteenth VCM report that was filed with the Georgia PSC on August 31, 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs currently included in the construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcomenatural gas storage facilities, which have a combined net book value of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018, which includes the total increase in the base capital cost forecast and construction contingency estimate.
As construction continues, challenges with management of contractors, subcontractors, and vendors; labor productivity, availability, and/or cost escalation; procurement, fabrication, delivery, assembly, and/or installation, including any required engineering changes, of plant systems, structures, and components (some of which are based on new technology that only recently began initial operation in the global nuclear industry$438 million at this scale); or other issues could arise and change the projected schedule and estimated cost. Monthly construction production targets required to maintain the current project schedule continue to increase significantly through the remainder of 2018 and intoJune 30, 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers 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 resolution of Inspections, Tests, Analyses, and Acceptance Criteria (ITAAC) and the related approvals by the NRC, 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 extensiontime, but could have a material impact on Southern Company's and Southern Company Gas' financial statements.
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 August 31, 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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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.(D) REVENUE FROM CONTRACTS WITH CUSTOMERS
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 as described above, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. On September 26, 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, and (ii) a term sheet (MEAG Term Sheet and, together with the Vogtle Owner Term Sheet, Term Sheets) with MEAG and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 (Project J) under certain circumstances. Pursuant to the Vogtle Owner Term Sheet, the Vogtle Joint Ownership Agreements will be modified as follows: (i) each Vogtle Owner will pay its proportionate share of qualifying construction costs for Plant Vogtle Units 3 and 4 based on its ownership percentage up to the estimated cost at completion (EAC) for Plant Vogtle Units 3 and 4 which forms the basis of Georgia Power's forecast of $8.4 billion in the nineteenth VCM plus $800 million of additional construction costs; (ii) Georgia Power will be responsible for 55.7% of actual qualifying construction costs between $800 million and $1.6 billion over the EAC in the nineteenth VCM (resulting in $80 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests; and (iii) Georgia Power will be responsible for 65.7% of qualifying construction costs between $1.6 billion and $2.1 billion over the EAC in the nineteenth VCM (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests.
If the EAC is revised and exceeds the EAC in the nineteenth VCM by more than $2.1 billion, each of the other Vogtle Owners will have a one-time option to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100% of such Vogtle Owner's remaining share of total construction costs in excess of the EAC in the nineteenth VCM plus $2.1 billion. In this event, Georgia Power will have the option of cancelling the project in lieu of purchasing a portion of the ownership interest of any other Vogtle Owner. If Georgia Power accepts the offer to purchase a portion of another Vogtle Owner's ownership interest in Plant Vogtle Units 3 and 4, the ownership interest(s) to be conveyed from the tendering Vogtle Owner(s) to Georgia Power would be calculated based on the proportion of the cumulative amount of construction costs paid by each such tendering Vogtle Owner(s) and by Georgia Power as of the commercial operation date of Plant Vogtle Unit 4. For purposes of this calculation, payments made by Georgia Power on behalf of another Vogtle Owner in accordance with the second and third items described in the paragraph above would be treated as payments made by the applicable Vogtle Owner.
In the event the actual costs at completion are less than the EAC reflected in the nineteenth VCM report and Plant Vogtle Unit 3 is placed in service by the currently scheduled date of November 2021 or Plant Vogtle Unit 4 is placed in service by the currently scheduled date of November 2022, Georgia Power would be entitled to 60.7% of the cost savings with respect to the relevant unit and the remaining Vogtle Owners would be entitled to 39.3% of such savings on a pro rata basis in accordance with their respective ownership interests.
For purposes of the foregoing provisions, qualifying construction costs would not include costs (i) resulting from force majeure events, including governmental actions or inactions (or significant delays associated with issuance of
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
such actions) that affect the licensing, completion, startup, operations, or financing of Plant Vogtle Units 3 and 4, administrative proceedings or litigation regarding ITAAC or other regulatory challenges to commencement of operation of Plant Vogtle Units 3 and 4, and changes in laws or regulations governing Plant Vogtle Units 3 and 4, (ii) legal fees and legal expenses incurred due to litigation with contractors or subcontractors that are not subsidiaries or affiliates of Southern Company, and (iii) additional costs caused by Vogtle Owner requests other than Georgia Power, except for the exercise of a right to vote granted under the Vogtle Joint Ownership Agreements, that increase costs by $100,000 or more.
Georgia Power is working with the other Vogtle Owners to clarify any interpretive issues related to the operation of certain of the above provisions of the Vogtle Owner Term Sheet.
Under the Vogtle Owner Term Sheet, the provisions of the Vogtle Joint Ownership Agreements requiring that Vogtle Owners holding 90% of the ownership interests in Plant Vogtle Units 3 and 4 vote to continue construction following certain adverse events (Project Adverse Events) will be modified. Pursuant to the Vogtle Joint Ownership Agreements and the Vogtle Owner 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 Project Adverse Events occur, including: (i) the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power publicly announces its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 or the Georgia PSC determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Vogtle Owners pursuant to the Vogtle Owner Term Sheet provisions described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Georgia PSC for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates; and (iv) an incremental extension of one year or more over the most recently approved schedule. Under the Vogtle Owner Term Sheet, Georgia Power may cancel the project at any time in its sole discretion.
In addition, pursuant to the Vogtle Joint Ownership Agreements, 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 Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement.
The Vogtle Owner Term Sheet provides that if the holders of at least 90% of the ownership interests fail to vote in favor of continuing the project following any future Project Adverse Event, work on Plant Vogtle Units 3 and 4 would continue for a period of 30 days if the holders of more than 50% of the ownership interests vote in favor of continuing construction (Majority Voting Owners). In such a case, the Vogtle Owners (i) would agree to negotiate in good faith towards the resumption of the project, (ii) if no agreement was reached during such 30-day period, the project would be cancelled, and (iii) in the event of such a cancellation, the Majority Voting Owners would be obligated to reimburse any other Vogtle Owner for the costs it incurred during such 30-day negotiation period.
Purchase of PTCs During Commercial Operation
In addition, under the terms of the Vogtle Owner Term Sheet, Georgia Power agreed to purchase additional PTCs from OPC, Dalton, MEAG SPVM, MEAG SPVP, and MEAG SPVJ (to the extent any MEAG SPVJ PTC rights remain after any purchases required under the MEAG Term Sheet as described below) at varying purchase prices dependent upon the actual cost to complete construction of Plant Vogtle Units 3 and 4 as compared to the EAC included in the nineteenth VCM report. The purchases will be at the option of the applicable Vogtle Owner and will occur during the month after such PTCs are earned.
Potential Funding to MEAG Project J
Pursuant to the MEAG Term Sheet, if MEAG SPVJ is unable to make its payments due under the Vogtle Joint Ownership Agreements solely because (i) the conduct of JEA, such as JEA's legal challenges of its obligations under a PPA with MEAG (PPA-J), materially impedes access to capital markets for MEAG for Project J, or (ii)
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
PPA-J is declared void by a court of competent jurisdiction or rejected by JEA under the applicable provisions of the U.S. Bankruptcy Code (each of (i) and (ii), a JEA Default), Georgia Power would purchase from MEAG SPVJ the rights to PTCs attributable to MEAG SPVJ's share of Plant Vogtle Units 3 and 4 (approximately 206 MWs) at varying prices dependent upon the stage of construction of Plant Vogtle Units 3 and 4. The aggregate purchase price of the PTCs, together with any advances made as described in the next paragraph, shall not exceed $300 million.
At the option of MEAG, as an alternative or supplement to Georgia Power's purchase of PTCs as described above, Georgia Power has agreed to provide up to $250 million in funding to MEAG for Project J in the form of advances (either advances under the Vogtle Joint Ownership Agreements or the purchase of MEAG Project J bonds, at the discretion of Georgia Power), subject to any required approvals of the Georgia PSC and the DOE.
In the event MEAG SPVJ certifies to Georgia Power that it is unable to fund its obligations under the Vogtle Joint Ownership Agreements as a result of a JEA Default and Georgia Power becomes obligated to provide funding as described above, MEAG is required to (i) assign to Georgia Power its right to vote on any future Project Adverse Event and (ii) diligently pursue JEA for its breach of PPA-J. In addition, Georgia Power agreed that it will not sue MEAG for any amounts due from MEAG SPVJ under MEAG's guarantee of MEAG SPVJ's obligations so long as MEAG SPVJ complies with the terms of the MEAG Term Sheet as to its payment obligations and the other provisions of the Vogtle Joint Ownership Agreements.
Under the terms of the MEAG Term Sheet, Georgia Power may decline to provide any funding in the form of advances, including in the event of a failure to receive any required Georgia PSC or DOE approvals, and cancel the project in lieu of providing such funding.
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. As of September 30, 2018, Georgia Power had recovered approximately $1.8 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. Georgia Power expects to file on November 9, 2018 to increase the NCCR tariff by approximately $90 million annually, effective January 1, 2019, pending Georgia PSC approval.
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) certain recommendations made by Georgia Power in the seventeenth VCM report and modifying 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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 $25 million in 2017 and are estimated to have negative earnings impacts of approximately $100 million in 2018 and an aggregate of $680 million from 2019 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.
On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. On March 8, 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's final decision and denial of Georgia Watch's motion for reconsideration. Georgia Power believes the two appeals have no merit; however, an adverse outcome in either 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.
The Georgia PSC has approved eighteen VCM reports covering the periods through December 31, 2017, including total construction capital costs incurred through that date of $4.9 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds). On August 31, 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.
The ultimate outcome of these matters cannot be determined at this time.
DOE Financing
As of September 30, 2018, 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. In September 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. In September 2018, the DOE extended the conditional commitment to March 31, 2019. Any further extension must be approved by the DOE. 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 (F) under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
events (including any decision not to continue construction of Plant Vogtle Units 3 and 4), and conditions to borrowing.
The ultimate outcome of these matters cannot be determined at this time.
Kemper County Energy Facility
For additional information on the Kemper County energy facility, see Note 3 to the financial statements of Southern Company and Mississippi Power under "Kemper County Energy Facility" in Item 8 of the Form 10-K.
As the mining permit holder for the Kemper County energy facility, Liberty Fuels Company, LLC has a legal obligation to perform mine reclamation, and Mississippi Power has a contractual obligation to fund all reclamation activities. Mine reclamation began in the first quarter 2018. See Note 1 to the financial statements of Southern Company and Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" and of Mississippi Power under "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.
As of September 30, 2018, Mississippi Power recorded charges to income of an immaterial amount for the third quarter 2018 and $45 million ($34 million after tax) for year-to-date 2018, primarily resulting from the abandonment and related closure activities 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 to cost up to $20 million pre-tax (excluding salvage, net of dismantlement costs), 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 $2 million for the remainder of 2018, $8 million in 2019, and $4 million annually beginning in 2020. The ultimate outcome of this matter cannot be determined at this time.
Reserve Margin Plan
On August 6, 2018, Mississippi Power filed its proposed RMP, as required by the Mississippi PSC's order in the docket established for the purposes of pursuing a global settlement of the costs related to the Kemper County energy facility. Under the RMP, Mississippi Power proposes alternatives that would reduce its reserve margin, with the most economic of the alternatives being the two-year and seven-year acceleration of the retirement of Plant Watson Units 4 and 5, respectively, to the first quarter 2022 and the four-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively, in order to lower or avoid operating costs. The Plant Greene County unit retirements would require the completion by Alabama Power of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. The RMP filing also states that, in the event the Mississippi PSC ultimately approves an alternative that includes an accelerated retirement, Mississippi Power would require authorization to defer in a regulatory asset for future recovery the remaining net book value of the units at the time of retirement. Mississippi Power expects the MPUS and other interested parties to review the proposal prior to resolution by the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time. However, if approved by the Mississippi PSC, the alternatives are not expected to have any adverse impact on customer rates.
Other Matters
Investments in Leveraged Leases
See Note 1 to the financial statements of Southern Company under "Leveraged Leases" in Item 8 of the Form 10-K for additional information regarding the leveraged lease agreements of a subsidiary of Southern Company Holdings Inc. (Southern Holdings) and concerns about the financial and operational performance of one of the lessees and the associated generation assets.
The ability of the lessees to make required payments to the Southern Holdings subsidiary is dependent on the operational performance of the assets. As a result of operational improvements in the first half of 2018, the June 2018 lease payment was paid in full and the December 2018 lease payment is currently expected to be paid in full. However, operational issues and the resulting cash liquidity challenges persist and significant concerns continue
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
regarding the lessee's ability to make the remaining semi-annual lease payments. These operational challenges may also impact the expected residual value of the assets at the end of the lease term in 2047. If any future lease payment is not paid in full, the Southern Holdings subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. Failure to make the required payment to the debtholders would represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the generation assets from the Southern Holdings subsidiary, in effect terminating the lease and resulting in the write-off of the related lease receivable, which would result in a reduction in net income of approximately $86 million after tax based on the lease receivable balance as of September 30, 2018. Southern Company has evaluated the recoverability of the lease receivable and the expected residual value of the generation assets at the end of the lease under various scenarios and has concluded that its investment in the leveraged lease is not impaired as of September 30, 2018. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments. The ultimate outcome of this matter 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 (DNR). 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, 2018, the facility's property, plant, and equipment had a net book value of $110 million, of which the cavern itself represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including compliance with an order from the Louisiana DNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining core samples to determine the composition of the sheath surrounding the edge of the salt dome.
The cavern continues to maintain its pressures and overall structural integrity. Southern Company Gas intends to monitor the cavern and comply with the Louisiana DNR order through 2020 and place the cavern back in service in 2021. These events were considered in connection with Southern Company Gas' 2017 long-lived asset impairment analysis, which determined there was no impairment. Any future changes in results of monitoring activities, rates at which expiring capacity contracts are re-contracted, timing of placing the cavern back in service, or Louisiana DNR requirements could trigger impairment. Further, 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 and a material impact on Southern Company Gas' financial statements.
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(C) | 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 (A)1 to the financial statements under "Recently"Recently Adopted Accounting Standards– Revenue"Revenue" in Item 8 of the Form 10-K for additional information on the adoption of ASC 606 for revenue from contracts with customers.
The majoritycustomers and Note 1 to the financial statements under "Revenues" and "Other Taxes" in Item 8 of the revenuesForm 10-K for additional information on the revenue policies of the traditional electric operating companiesregistrants. 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 are generated from contracts with retail electric andGas" in Item 8 of the Form 10-K for alternative revenue programs at the natural gas distribution customers. Revenues from this integrated service to deliver electricity or gas whenutilities, and if called upon by the customer is recognized as a single performance obligation satisfied over time and is recognized at a tariff rate as electricity or gas is deliveredNote 2 to the customer duringfinancial statements in Item 8 of the month. The traditional electric operating companies and Southern Company Gas exclude taxes imposed on the customer and collected on behalfForm 10-K for cost recovery mechanisms.
The traditional electric operating companies and Southern Power also have contracts with multiple performance obligations, such as capacity and energy in a wholesale PPA, where the contract's total transaction price is allocated
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
to each performance obligation based on the standalone selling price. The standalone selling price is primarily determined by the price charged to customers for the specific goods or services transferred with the performance obligations. Generally, the registrants recognize revenue as the performance obligations are satisfied over time as electricity or natural gas is delivered to the customer or as generation capacity is available to the customer. At Southern Company Gas, the performance obligations related to wholesale gas services are satisfied, and revenue is recognized, at a point in time when natural gas is delivered to the customer.
The registrants generally have a right to consideration in an amount that corresponds directly with the value to the customer of the entity's performance completed to date and may recognize revenue in the amount to which the entity has a right to invoice and has elected to recognize revenue for its sales of electricity, capacity, and natural gas using the invoice practical expedient. In addition, payment for goods and services rendered is typically due in the subsequent month following satisfaction of the registrants' performance obligation.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
The following tables disaggregate revenue sources for the three and ninesix months ended SeptemberJune 30, 2019 and 2018:
| | | | For the Three Months Ended September 30, 2018 | For the Nine Months Ended September 30, 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) | (in millions) |
| Southern Company | | |
| Operating revenues | | |
Retail electric revenues(a) | | |
| Residential | $ | 2,148 |
| $ | 5,266 |
| $ | 1,488 |
| $ | 1,579 |
| $ | 2,776 |
| $ | 3,118 |
|
| Commercial | 1,527 |
| 4,084 |
| 1,258 |
| 1,315 |
| 2,350 |
| 2,557 |
|
| Industrial | 901 |
| 2,471 |
| 763 |
| 814 |
| 1,440 |
| 1,569 |
|
| Other | 29 |
| 92 |
| 31 |
| 32 |
| 57 |
| 64 |
|
Natural gas distribution revenues | 433 |
| 2,299 |
| 562 |
| 642 |
| 1,724 |
| 1,865 |
|
Alternative revenue programs(b)(c) | 5 |
| (23 | ) | 1 |
| (4 | ) | — |
| (27 | ) |
| Total retail electric and gas distribution revenues | $ | 5,043 |
| $ | 14,189 |
| $ | 4,103 |
| $ | 4,378 |
| $ | 8,347 |
| $ | 9,146 |
|
Wholesale energy revenues(d)(e) | 516 |
| 1,444 |
| 410 |
| 464 |
| 777 |
| 937 |
|
Wholesale capacity revenues(d)(e) | 177 |
| 479 |
| 132 |
| 152 |
| 264 |
| 302 |
|
Other natural gas revenues(e)(g) | 54 |
| 530 |
| 126 |
| 68 |
| 439 |
| 476 |
|
Other revenues(f)(h) | 369 |
| 1,516 |
| 327 |
| 565 |
| 683 |
| 1,138 |
|
| Total operating revenues | $ | 6,159 |
| $ | 18,158 |
| $ | 5,098 |
| $ | 5,627 |
| $ | 10,510 |
| $ | 11,999 |
|
| |
| (a) | Retail electric revenues include $17$8 million, $18 million, $16 million, and $54$36 million of revenues accounted for as leases for the three and nine months ended SeptemberJune 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, and a (net reduction) or net increase of $(98)$(14) million, $68 million, $(117) million and $4$101 million for the three and nine months ended SeptemberJune 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. See Note 3 to the financial statements of Southern Company under "Regulatory Matters" in Item 8 of the Form 10-K for additional information on cost recovery mechanisms. |
| |
| (b) | See Note 1 to the financial statements of Southern Company under "Revenues" in Item 8Natural gas distribution revenues include $5 million for each of the Form 10-Kthree months ended June 30, 2019 and 2018 and $8 million for additional information on alternative revenue programs ateach of the natural gas distribution utilities. 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. |
| |
(c)(d) | Wholesale energy revenues include $63$30 million, $61 million, $82 million, and $217$155 million for the three and nine months ended September 30, 2018, respectively, 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. See Note (I) for additional information on energy-related derivative contracts. |
| |
(d)(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 $130$22 million, $31 million, $47 million, and $31$61 million respectively, for the three months ended SeptemberJune 30, 2019 and 2018 and $318 million and $92 million, respectively, for the ninesix months ended SeptemberJune 30, 2019 and 2018, of PPA contractsrespectively, related to PPAs accounted for as leases. |
| |
(e)(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 $1.6$1.2 billion, $1.3 billion, $3.1 billion, and $4.8$3.3 billion for the three and nine months ended SeptemberJune 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, of which $0.9$0.8 billion, $0.7 billion, $2.0 billion, and $2.7$1.8 billion, respectively, relates to contracts that are accounted for as derivatives. See Note (L)(M) under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues. |
| |
(f)(g) | Other natural gas revenues include $92$10 million and $274$27 million for the three and ninesix months ended SeptemberJune 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 606.606, 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 | Gulf Power | Mississippi Power | Alabama Power | Georgia Power | Mississippi Power |
| | (in millions) | (in millions) |
| For the Three Months Ended September 30, 2018 | | |
| For the Three Months Ended June 30, 2019 | | |
| Operating revenues | | |
Retail revenues(a)(b) | | |
| Residential | $ | 721 |
| $ | 1,142 |
| $ | 200 |
| $ | 85 |
| $ | 588 |
| $ | 831 |
| $ | 69 |
|
| Commercial | 464 |
| 877 |
| 103 |
| 82 |
| 418 |
| 767 |
| 73 |
|
| Industrial | 392 |
| 385 |
| 37 |
| 86 |
| 366 |
| 327 |
| 70 |
|
| Other | 7 |
| 21 |
| 1 |
| 1 |
| 6 |
| 21 |
| 3 |
|
| Total retail electric revenues | $ | 1,584 |
| $ | 2,425 |
| $ | 341 |
| $ | 254 |
| $ | 1,378 |
| $ | 1,946 |
| $ | 215 |
|
Wholesale energy revenues(c) | 62 |
| 33 |
| 48 |
| 92 |
| 41 |
| 14 |
| 93 |
|
| Wholesale capacity revenues | 26 |
| 14 |
| 7 |
| 1 |
| 25 |
| 22 |
| 1 |
|
Other revenues(b)(d) | 68 |
| 121 |
| 18 |
| 11 |
| 69 |
| 135 |
| 4 |
|
| Total operating revenues | $ | 1,740 |
| $ | 2,593 |
| $ | 414 |
| $ | 358 |
| $ | 1,513 |
| $ | 2,117 |
| $ | 313 |
|
| | | |
| For the Nine Months Ended September 30, 2018 | | |
| For the Three Months Ended June 30, 2018 | | |
| Operating revenues | | |
Retail revenues(a)(b) | | |
| Residential | $ | 1,848 |
| $ | 2,671 |
| $ | 537 |
| $ | 209 |
| $ | 557 |
| $ | 785 |
| $ | 65 |
|
| Commercial | 1,238 |
| 2,343 |
| 291 |
| 212 |
| 402 |
| 749 |
| 68 |
|
| Industrial | 1,103 |
| 1,036 |
| 100 |
| 233 |
| 372 |
| 335 |
| 76 |
|
| Other | 19 |
| 62 |
| 4 |
| 6 |
| 7 |
| 20 |
| 3 |
|
| Total retail electric revenues | $ | 4,208 |
| $ | 6,112 |
| $ | 932 |
| $ | 660 |
| $ | 1,338 |
| $ | 1,889 |
| $ | 212 |
|
Wholesale energy revenues(c) | 234 |
| 99 |
| 104 |
| 259 |
| 71 |
| 26 |
| 77 |
|
| Wholesale capacity revenues | 75 |
| 41 |
| 20 |
| 6 |
| 25 |
| 13 |
| 1 |
|
Other revenues(b)(d) | 199 |
| 349 |
| 50 |
| 31 |
| 69 |
| 120 |
| 7 |
|
| Total operating revenues | $ | 4,716 |
| $ | 6,601 |
| $ | 1,106 |
| $ | 956 |
| $ | 1,503 |
| $ | 2,048 |
| $ | 297 |
|
| |
| (a) | Retail revenues at Alabama Power, Georgia Power, Gulf Power, and Mississippi Power include a net increase or (net reduction) of $(12)$(11) million, $(47) million, $(36)$(5) million, and $(3)$2 million, respectively, for the three months ended SeptemberJune 30, 20182019 and $113$78 million, $(35) million, $(63)$3 million, and $(11)$(1) million, respectively, for the ninethree months ended SeptemberJune 30, 2018 related to certain cost recovery mechanisms that are not accounted for as revenue under ASC 606. See Note 3 to the financial statements of Alabama Power, Georgia Power, Gulf Power, and Mississippi Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information on cost recovery mechanisms. |
| |
| (b) | Retail revenues and other revenues at Georgia Power include $17$8 million and $34$11 million, respectively, for the three months ended SeptemberJune 30, 20182019 and $54$18 million and $100$33 million, respectively, for the ninethree months ended SeptemberJune 30, 2018 of revenues accounted for as leases. |
| |
| (c) | Wholesale energy revenues at Alabama Power, and Georgia Power, and Mississippi Power include $6$3 million, $4 million, and $8$1 million, respectively, for the three months ended SeptemberJune 30, 20182019 and $14$4 million, $5 million, and $21$1 million, respectively, for the ninethree months ended SeptemberJune 30, 2018 accounted for as derivatives primarily related to physical energy sales in the wholesale electricity market. See Note (I) for additional information on energy-related derivative contracts. |
| |
| (d) | Other revenues at Alabama Power and Georgia Power and Gulf Power include $27 million, $28$31 million and $2$30 million, respectively, for the three months ended SeptemberJune 30, 20182019 and $79 million, $80$26 million and $5$26 million, respectively, for the ninethree months ended SeptemberJune 30, 2018 of revenues not accounted for under ASC 606. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | |
| | For the Three Months Ended September 30, 2018 | For the Nine Months Ended September 30, 2018 |
| | (in millions) |
| Southern Power | | |
PPA capacity revenues(a) | $ | 168 |
| $ | 450 |
|
PPA energy revenues(a) | 336 |
| 892 |
|
Non-PPA revenues(b) | 126 |
| 347 |
|
| Other revenues | 5 |
| 10 |
|
| Total operating revenues | $ | 635 |
| $ | 1,699 |
|
|
| | | | | | | | | |
| | 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) | PPA capacityRetail revenues at Alabama Power, Georgia Power, and PPA energy revenuesMississippi Power include $47a net increase or (net reduction) of $(68) million, $(52) million, and $139$3 million, respectively, for the threesix months ended SeptemberJune 30, 20182019 and $141$125 million, $12 million, and $342$(8) million, respectively, for the ninesix months ended SeptemberJune 30, 2018 related to PPAscertain cost recovery mechanisms that are not accounted for as leases. See Note 1 torevenue under ASC 606. |
| |
| (b) | Retail revenues and other revenues at Georgia Power include $16 million and $23 million, respectively, for the financial statementssix months ended June 30, 2019 and $36 million and $66 million, respectively, for the six months ended June 30, 2018 of Southern Power under "Revenues" in Item 8 of the Form 10-K for additional information on capacity revenues accounted for as leases. |
| |
(b)(c) | Non-PPAWholesale 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 $47$39 million, $47 million, $80 million, and $176$94 million for the three and nine months ended SeptemberJune 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. See Note 1 to the financial statements of Southern Power under "Revenues" in Item 8 of the Form 10-K and Note (I) for additional information on energy-related derivative contracts. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| | | | For the Three Months Ended September 30, 2018 | For the Nine Months Ended September 30, 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) | (in millions) |
| Southern Company Gas | | |
| Operating revenues | | |
Natural gas distribution revenues | | |
| Residential | $ | 149 |
| $ | 1,082 |
| $ | 229 |
| $ | 273 |
| $ | 830 |
| $ | 933 |
|
| Commercial | 45 |
| 313 |
| 65 |
| 76 |
| 235 |
| 268 |
|
| Transportation | 203 |
| 708 |
| 213 |
| 228 |
| 469 |
| 505 |
|
| Industrial | 4 |
| 28 |
| 5 |
| 7 |
| 22 |
| 24 |
|
| Other | 32 |
| 168 |
| 50 |
| 58 |
| 168 |
| 135 |
|
Alternative revenue programs(a)(b) | 5 |
| (23 | ) | 1 |
| (4 | ) | — |
| (27 | ) |
| Total natural gas distribution revenues | $ | 438 |
| $ | 2,276 |
| $ | 563 |
| $ | 638 |
| $ | 1,724 |
| $ | 1,838 |
|
Gas marketing services(b) | 44 |
| 403 |
| |
Gas pipeline investments(c) | | 8 |
| 8 |
| 16 |
| 16 |
|
Wholesale gas services(c)(d) | (10 | ) | 121 |
| 48 |
| (15 | ) | 114 |
| 131 |
|
| Gas midstream operations | 20 |
| 60 |
| |
Gas marketing services(e) | | 58 |
| 89 |
| 287 |
| 359 |
|
| Other revenues | — |
| 1 |
| 12 |
| 10 |
| 22 |
| 25 |
|
| Total operating revenues | $ | 492 |
| $ | 2,861 |
| $ | 689 |
| $ | 730 |
| $ | 2,163 |
| $ | 2,369 |
|
| |
| (a) | See Note 1 to the financial statements of Southern Company Gas under "Revenues" in Item 8Natural gas distribution revenues include $5 million for each of the Form 10-Kthree months ended June 30, 2019 and 2018 and $8 million for additional information on alternative revenue programs ateach of the natural gas distribution utilities. 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. |
| |
(b)(c) | Gas marketing services includes $4Revenues from gas pipeline investments include $8 million and $16 million for the ninethree and six months ended SeptemberJune 30, 2018 of revenues not2019, respectively, accounted for under ASC 606.as leases. |
| |
(c)(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 $1.6$1.2 billion, $1.3 billion, $3.1 billion, and $4.8$3.3 billion for the three and nine months ended SeptemberJune 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, of which $0.9$0.8 billion, $0.7 billion, $2.0 billion, and $2.7$1.8 billion, respectively, relates to contracts that are accounted for as derivatives. See Note (L)(M) under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues and Note (I) for additional information on energy-related derivative contracts.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 SeptemberJune 30, 2019 and December 31, 2018:
| | | | Receivables | | Contract Assets | | Contract Liabilities | Receivables | | Contract Assets | | Contract Liabilities |
| | (in millions) | June 30, 2019 | December 31, 2018 | | June 30, 2019 | December 31, 2018 | | June 30, 2019 | December 31, 2018 |
| Southern Company | $ | 2,778 |
| | $ | 99 |
| | $ | 34 |
| |
| | | (in millions) |
Southern Company(*) | | $ | 2,343 |
| $ | 2,630 |
| | $ | 70 |
| $ | 102 |
| | $ | 58 |
| $ | 32 |
|
| Alabama Power | 649 |
| | 1 |
| | 14 |
| 629 |
| 520 |
| | — |
| — |
| | 10 |
| 12 |
|
| Georgia Power | 924 |
| | 70 |
| | 3 |
| 807 |
| 721 |
| | 30 |
| 58 |
| | 26 |
| 7 |
|
| Gulf Power | 186 |
| | — |
| | — |
| |
| Mississippi Power | 96 |
| | — |
| | — |
| 93 |
| 100 |
| | — |
| — |
| | 7 |
| — |
|
| Southern Power | 142 |
| | — |
| | 17 |
| 119 |
| 118 |
| | — |
| — |
| | 1 |
| 11 |
|
| Southern Company Gas | 523 |
| | — |
| | 1 |
| 550 |
| 952 |
| | — |
| — |
| | 1 |
| 2 |
|
| |
| (*) | Includes amounts related to held for sale investments. |
As of SeptemberJune 30, 2019 and December 31, 2018, Alabama Power had contract liabilities for outstanding performance obligations primarily related to extended service agreements. 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. Southern Power'sAlabama 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 Georgia Power.a tolling arrangement accounted for as a sales-type lease. Southern Company's unregulated distributed generation business had $27$32 million and $17$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 aswhen the performance obligations are satisfied overduring 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. RevenuesRegistrants with revenues from contracts with customers related to these performance obligations remaining at SeptemberJune 30, 2018 are expected2019 expect the revenues to be recognized as follows:
|
| | | | | | | | | | | | | | | | | | |
| | 2018 | 2019 | 2020 | 2021 | 2022 | 2023 and Thereafter |
| | (in millions) |
Southern Company(*) | $ | 168 |
| $ | 406 |
| $ | 322 |
| $ | 322 |
| $ | 310 |
| $ | 2,112 |
|
| Alabama Power | 6 |
| 22 |
| 22 |
| 26 |
| 23 |
| 161 |
|
| Georgia Power | 10 |
| 41 |
| 38 |
| 40 |
| 30 |
| 113 |
|
| Gulf Power | 5 |
| 22 |
| — |
| — |
| — |
| — |
|
| Mississippi Power | 1 |
| 3 |
| 3 |
| 1 |
| — |
| — |
|
Southern Power(*) | 75 |
| 310 |
| 283 |
| 277 |
| 276 |
| 2,005 |
|
|
| | | | | | | | | | | | | | | | | | |
| | 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 |
|
| |
(*) | Excludes amounts related to held for sale assets. See Note (J) under "Southern Company's Sale of Gulf Power" and "Southern Power – Sale of Florida Plants" for additional information.
|
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)
| |
(D) | FAIR VALUE MEASUREMENTS |
As(E) CONSOLIDATED ENTITIES AND EQUITY METHOD INVESTMENTS
Southern Power
Consolidated Variable Interest Entities
See Note 7 to the financial statements in Item 8 of September 30, 2018,the Form 10-K for additional information on Southern Power's consolidated VIEs.
Southern Power has certain subsidiaries that are determined to be VIEs. Southern Power is considered the primary 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 measured at fair value on a recurring basis duringare non-recourse to the period, togethergeneral 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 associated levelpartnership interest percentage. Under the terms of the fair value hierarchy, werelimited 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 follows: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 7 to the financial statements in Item 8 of the Form 10-K for additional information on Southern Company Gas' equity method investments.
|
| | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using: | | |
| As of September 30, 2018: | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Net Asset Value as a Practical Expedient (NAV) | | Total |
| | (in millions) |
| Southern Company | | | | | | | | | |
| Assets: | | | | | | | | | |
Energy-related derivatives(a)(b) | $ | 271 |
| | $ | 150 |
| | $ | — |
| | $ | — |
| | $ | 421 |
|
| Foreign currency derivatives | — |
| | 122 |
| | — |
| | — |
| | 122 |
|
Nuclear decommissioning trusts(c) | 828 |
| | 1,007 |
| | — |
| | 37 |
| | 1,872 |
|
| Non-qualified deferred compensation trusts: | | | | | | | | | |
| Domestic equity | — |
| | 11 |
| | — |
| | — |
| | 11 |
|
| Foreign equity | — |
| | 6 |
| | — |
| | — |
| | 6 |
|
| Pooled funds – fixed income | — |
| | 13 |
| | — |
| | — |
| | 13 |
|
| Cash equivalents | 15 |
| | — |
| | — |
| | — |
| | 15 |
|
| Other | 9 |
| | — |
| | — |
| | — |
| | 9 |
|
| Cash equivalents | 1,309 |
| | — |
| | — |
| | — |
| | 1,309 |
|
| Total | $ | 2,432 |
| | $ | 1,309 |
| | $ | — |
| | $ | 37 |
| | $ | 3,778 |
|
| Liabilities: | | | | | | | | | |
Energy-related derivatives(a)(b) | $ | 416 |
| | $ | 159 |
| | $ | — |
| | $ | — |
| | $ | 575 |
|
| Interest rate derivatives | — |
| | 72 |
| | — |
| | — |
| | 72 |
|
| Foreign currency derivatives | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
| Contingent consideration | — |
| | — |
| | 22 |
| | — |
| | 22 |
|
| Total | $ | 416 |
| | $ | 254 |
| | $ | 22 |
| | $ | — |
| | $ | 692 |
|
| | | | | | | | | | |
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 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using: | | |
| As of September 30, 2018: | 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 | $ | — |
| | $ | 7 |
| | $ | — |
| | $ | — |
| | $ | 7 |
|
Nuclear decommissioning trusts:(d) | | | | | | | | |
|
|
| Domestic equity | 469 |
| | 89 |
| | — |
| | — |
| | 558 |
|
| Foreign equity | 60 |
| | 56 |
| | — |
| | — |
| | 116 |
|
| U.S. Treasury and government agency securities | — |
| | 18 |
| | — |
| | — |
| | 18 |
|
| Corporate bonds | 26 |
| | 154 |
| | — |
| | — |
| | 180 |
|
| Mortgage and asset backed securities | — |
| | 22 |
| | — |
| | — |
| | 22 |
|
| Private equity | — |
| | — |
| | — |
| | 37 |
| | 37 |
|
| Other | 7 |
| | — |
| | — |
| | — |
| | 7 |
|
| Cash equivalents | 513 |
| | — |
| | — |
| | — |
| | 513 |
|
| Total | $ | 1,075 |
| | $ | 346 |
| | $ | — |
| | $ | 37 |
| | $ | 1,458 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 10 |
| | $ | — |
| | $ | — |
| | $ | 10 |
|
| | | | | | | | | | |
| Georgia Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | 8 |
|
Nuclear decommissioning trusts:(d)(e) | | | | | | | | | |
| Domestic equity | 250 |
| | 1 |
| | — |
| | — |
| | 251 |
|
| Foreign equity | — |
| | 134 |
| | — |
| | — |
| | 134 |
|
| U.S. Treasury and government agency securities | — |
| | 236 |
| | — |
| | — |
| | 236 |
|
| Municipal bonds | — |
| | 82 |
| | — |
| | — |
| | 82 |
|
| Corporate bonds | — |
| | 163 |
| | — |
| | — |
| | 163 |
|
| Mortgage and asset backed securities | — |
| | 42 |
| | — |
| | — |
| | 42 |
|
| Other | 16 |
| | 9 |
| | — |
| | — |
| | 25 |
|
| Cash equivalents | 350 |
| | — |
| | — |
| | — |
| | 350 |
|
| Total | $ | 616 |
| | $ | 675 |
| | $ | — |
| | $ | — |
| | $ | 1,291 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 22 |
| | $ | — |
| | $ | — |
| | $ | 22 |
|
| Interest rate derivatives | — |
| | 6 |
| | — |
| | — |
| | 6 |
|
| Total | $ | — |
| | $ | 28 |
| | $ | — |
| | $ | — |
| | $ | 28 |
|
| | | | | | | | | | |
| Gulf Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Cash equivalents | $ | 27 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 27 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | 8 |
|
| | | | | | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using: | | |
| As of September 30, 2018: | 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 | 346 |
| | — |
| | — |
| | — |
| | 346 |
|
| Total | $ | 346 |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 349 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 9 |
| | $ | — |
| | $ | — |
| | $ | 9 |
|
| | | | | | | | | | |
| Southern Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 3 |
|
| Foreign currency derivatives | — |
| | 122 |
| | — |
| | — |
| | 122 |
|
| Total | $ | — |
| | $ | 125 |
| | $ | — |
| | $ | — |
| | $ | 125 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 7 |
| | $ | — |
| | $ | — |
| | $ | 7 |
|
| Foreign currency derivatives | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
| Contingent consideration | — |
| | — |
| | 22 |
| | — |
| | 22 |
|
| Total | $ | — |
|
| $ | 30 |
|
| $ | 22 |
|
| $ | — |
|
| $ | 52 |
|
| | | | | | | | | | |
| Southern Company Gas | | | | | | | | | |
| Assets: | | | | | | | | | |
Energy-related derivatives(a)(b) | $ | 271 |
| | $ | 129 |
| | $ | — |
| | $ | — |
| | $ | 400 |
|
| Non-qualified deferred compensation trusts: | | | | | | | | | |
| Domestic equity | — |
| | 11 |
| | — |
| | — |
| | 11 |
|
| Foreign equity | — |
| | 6 |
| | — |
| | — |
| | 6 |
|
| Pooled funds – fixed income | — |
| | 13 |
| | — |
| | — |
| | 13 |
|
| Cash equivalents | 4 |
| | — |
| | — |
| | — |
| | 4 |
|
| Cash equivalents | 26 |
| | — |
| | — |
| | — |
| | 26 |
|
| Total | $ | 301 |
|
| $ | 159 |
|
| $ | — |
|
| $ | — |
|
| $ | 460 |
|
| Liabilities: | | | | | | | | | |
Energy-related derivatives(a)(b) | $ | 416 |
| | $ | 101 |
| | $ | — |
| | $ | — |
| | $ | 517 |
|
| |
(a)(*) | Excludes $5 million associated with premiums and certain weather derivatives accounted for based on intrinsic value rather than fair value. |
| |
(b) | Excludes cash collateral of $189 million. |
| |
(c) | For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table. |
| |
(d) | Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. |
| |
(e) | Includes the investment securities pledged to creditors and collateral received and excludes payables relatedDecrease primarily relates to the securities lending program. Assale of September 30, 2018, approximately $37 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.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 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. The fair value of the funds, including reinvested interest and dividends and excluding the funds' expenses, increased for the three and nine months ended September 30, 2018 and 2017 by the amounts shown in the table below. The increases were recorded as a change to the regulatory assets and liabilities related to AROs for Georgia Power and Alabama Power, respectively.
|
| | | | | | | | | | | | |
| | Three Months Ended September 30, 2018 | Three Months Ended September 30, 2017 | Nine Months Ended September 30, 2018 | Nine Months Ended September 30, 2017 |
| | (in millions) |
| Southern Company | $ | 58 |
| $ | 50 |
| $ | 68 |
| $ | 168 |
|
| Alabama Power | 39 |
| 25 |
| 49 |
| 87 |
|
| Georgia Power | 19 |
| 25 |
| 19 |
| 81 |
|
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 (I) 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 1 to the financial statements of Southern Company, Alabama Power, and Georgia Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.
Southern Power has contingent payment obligations related to certain acquisitions whereby Southern Power is primarily obligated to make generation-based payments to the seller, which commenced at the commercial operation date 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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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.
"Other investments" include investments that are not traded in the open market. The fair value of these investments has been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan executions.
As of September 30, 2018, the fair value measurements of private equity investments held in the nuclear decommissioning trusts that are calculated at net asset value per share (or its equivalent) as a practical expedient, as well as the nature and risks of those investments, were as follows:
|
| | | | | | | |
| As of September 30, 2018: | Fair Value | | Unfunded Commitments |
| | (in millions) |
| Southern Company | $ | 37 |
| | $ | 47 |
|
| Alabama Power | $ | 37 |
| | $ | 47 |
|
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. Liquidations are expected to occur at various times over the next 10 years.
As of September 30, 2018, other financial instruments for which the carrying amount did not equal fair value were as follows:
|
| | | | | | | |
| | Carrying Amount | | Fair Value |
| | (in millions) |
| Long-term debt, including securities due within one year: | | | |
| Southern Company | $ | 45,524 |
| | $ | 45,500 |
|
| Alabama Power | 8,120 |
| | 8,321 |
|
| Georgia Power | 10,227 |
| | 10,159 |
|
| Gulf Power | 1,285 |
| | 1,290 |
|
| Mississippi Power | 1,736 |
| | 1,702 |
|
| Southern Power | 5,029 |
| | 5,058 |
|
| Southern Company Gas | 5,908 |
| | 5,935 |
|
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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| |
(E)(*) | STOCKHOLDERS' EQUITYDecrease primarily relates to the sale of Triton. |
Earnings per ShareTriton
ForOn May 29, 2019, Southern Company the only differenceGas sold its investment in computing basic and diluted earnings per share is attributable to awards outstanding under stock-based compensation plans. See Note 8 to the financial statements ofTriton, a cargo container leasing company that was aggregated into Southern Company Gas' all other segment. This disposition resulted in Item 8a pre-tax loss of the Form 10-K for$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 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
September 30, 2018 | Three Months Ended
September 30, 2017 | Nine Months Ended
September 30, 2018 | Nine Months Ended
September 30, 2017 |
| | (in millions) |
| As reported shares | 1,023 |
| 1,003 |
| 1,016 |
| 998 |
|
| Effect of stock-based compensation | 6 |
| 7 |
| 5 |
| 7 |
|
| Diluted shares | 1,029 |
| 1,010 |
| 1,021 |
| 1,005 |
|
Stock-based compensation awards that were not included in the diluted earnings per share calculation because they were anti-dilutive were immaterialSNG for the three and ninesix months ended SeptemberJune 30, 2019 and 2018 and 2017.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Changes in Stockholders' Equity
The following table presents year-to-date changes in stockholders' equity of Southern Company: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 |
|
|
| | | | | | | | | | | | | | | | | |
| | Number of Common Shares | | Common
Stockholders'
Equity | Preferred and Preference Stock of Subsidiaries | | Total
Stockholders'
Equity |
| | Issued | Treasury | | Noncontrolling Interests(a) |
| | (in thousands) | | (in millions) |
| Balance at December 31, 2017 | 1,008,532 |
| (929 | ) | | $ | 24,167 |
| $ | — |
| $ | 1,361 |
| $ | 25,528 |
|
| Consolidated net income attributable to Southern Company | — |
| — |
| | 1,948 |
| — |
| — |
| 1,948 |
|
| Other comprehensive income | — |
| — |
| | 52 |
| — |
| — |
| 52 |
|
| Stock issued | 21,342 |
| — |
| | 878 |
| — |
| — |
| 878 |
|
| Stock-based compensation | — |
| — |
| | 74 |
| — |
| — |
| 74 |
|
| Cash dividends on common stock | — |
| — |
| | (1,805 | ) | — |
| — |
| (1,805 | ) |
| Contributions from noncontrolling interests | — |
| — |
| | — |
| — |
| 154 |
| 154 |
|
| Distributions to noncontrolling interests | — |
| — |
| | — |
| — |
| (87 | ) | (87 | ) |
| Net income attributable to noncontrolling interests | — |
| — |
| | — |
| — |
| 71 |
| 71 |
|
Sale of noncontrolling interests(b) | — |
| — |
| | (410 | ) | — |
| 1,690 |
| 1,280 |
|
| Other | — |
| (57 | ) | | (27 | ) | — |
| (1 | ) | (28 | ) |
| Balance at September 30, 2018 | 1,029,874 |
| (986 | ) | | $ | 24,877 |
| $ | — |
| $ | 3,188 |
| $ | 28,065 |
|
| | | | | | | | |
| 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 |
|
| |
(a) | Primarily related to Southern Power and excludes redeemable noncontrolling interests. See Note 10 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information. |
| |
(b) | See Note (J) under "Southern Power – Sale of Solar Facility Interests" for additional information.
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)(F) FINANCING
(UNAUDITED)
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 SeptemberJune 30, 20182019 was approximately $1.5$1.4 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia Power, $82 million at Gulf
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Power, and $40 million at Mississippi Power). In addition, at SeptemberJune 30, 2018,2019, the traditional electric operating companies had approximately $573$272 million (comprised of approximately $120$87 million at Alabama Power $345and $185 million at Georgia Power, $58 million at Gulf Power, and $50 million at Mississippi Power) of revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to September 30, 2018, Alabama Power purchased and held its approximately $120 million of outstanding pollution control revenue bonds required to be remarketed. See Note 68 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.
The following table outlines the committed credit arrangements by company as of SeptemberJune 30, 2018:2019:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | 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 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Expires | | | | Executable Term Loans | | Expires Within One Year |
| Company | 2018 | 2019 | 2020 | 2022 | | Total | | Unused | | One Year | | Term Out | | No Term Out |
| | (in millions) |
Southern Company(a) | $ | — |
| $ | — |
| $ | — |
| $ | 2,000 |
| | $ | 2,000 |
| | $ | 1,999 |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Alabama Power | — |
| 33 |
| 500 |
| 800 |
| | 1,333 |
| | 1,333 |
| | — |
| | — |
| | 33 |
|
| Georgia Power | — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,736 |
| | — |
| | — |
| | — |
|
| Gulf Power | 20 |
| 25 |
| 235 |
| — |
| | 280 |
| | 280 |
| | 45 |
| | 45 |
| | — |
|
| Mississippi Power | — |
| 100 |
| — |
| — |
| | 100 |
| | 100 |
| | — |
| | — |
| | — |
|
Southern Power Company(b) | — |
| — |
| — |
| 750 |
| | 750 |
| | 728 |
| | — |
| | — |
| | — |
|
Southern Company Gas(c) | — |
| — |
| — |
| 1,900 |
| | 1,900 |
| | 1,895 |
| | — |
| | — |
| | — |
|
| Other | — |
| 30 |
| — |
| — |
| | 30 |
| | 30 |
| | — |
| | — |
| | 30 |
|
| Southern Company Consolidated | $ | 20 |
| $ | 188 |
| $ | 735 |
| $ | 7,200 |
| | $ | 8,143 |
| | $ | 8,101 |
| | $ | 45 |
| | $ | 45 |
| | $ | 63 |
|
| |
| (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 2019,2021, of which $2230 million remains was unused at SeptemberJune 30, 20182019. 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 $1.41.25 billion of these arrangements.this arrangement. Southern Company Gas' committed credit arrangementsarrangement also include 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 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.
DOE Loan Guarantee BorrowingsSouthern Company
See Note 6In 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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 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.
Georgia Power
In 2011, plaintiffs filed a putative class action against Georgia Power in the Superior Court of Fulton County, Georgia alleging that Georgia Power's collection in rates of amounts for municipal franchise fees (which fees are paid to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state 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. Georgia Power believes the plaintiffs' claims have no merit. 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. 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
Southern Power indirectly owns a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock facility in Pecos County, Texas. Prior to the facility being placed in service in 2016, certain solar panels were damaged during installation by the construction contractor, McCarthy Building Companies, Inc. (McCarthy), and certain solar panels were damaged by a hail event that also occurred during construction. In connection therewith, Southern Power withheld payment of approximately $26 million to the construction contractor, which placed a lien on the Roserock facility for the same amount. In 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas against XL Insurance America, Inc. and North American Elite Insurance Company seeking recovery from an insurance policy for damages resulting from the hail event and McCarthy's installation practices. In June 2018, the court granted Roserock's motion for partial summary judgment, finding that the insurers were in breach of contract and in violation of the Texas Insurance Code for failing to pay any monies owed for the hail claim. Separate lawsuits were filed between Roserock and McCarthy, as well as other parties, and that litigation was consolidated in the U.S. District Court for the Western District of Texas. On April 18, 2019, Roserock and the parties to the state and federal lawsuits executed a settlement agreement and mutual release that resolved both lawsuits. Following execution of the agreement, the lawsuits were dismissed, Southern Power paid 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 noncontrolling interests and Southern Power recognized a $12 million after-tax gain.
Environmental Remediation
The Southern Company system must comply with environmental laws and regulations governing the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companies and the natural gas distribution utilities in Illinois and Georgia have each received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies.
Georgia Power's environmental remediation liability was $18 million and $23 million as of June 30, 2019 and December 31, 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.
Southern Company Gas' environmental remediation liability was $283 million and $294 million as of June 30, 2019 and December 31, 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 $2 million of the total accrued remediation costs.
The ultimate outcome of these matters cannot be determined at this time; however, as a result of the regulatory treatment for environmental remediation expenses described above, the final disposition of these matters is not expected to have a material impact on the financial statements of Southern Company, Georgia Power, or Southern Company Gas.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Nuclear Fuel Disposal Costs
In 2014, Alabama Power and Georgia Power filed lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plants Farley, Hatch, and Vogtle Units 1 and 2 for the period from January 1, 2011 through December 31, 2013. The damage period was subsequently extended to December 31, 2014. 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 be recognized in the financial statements until the court enters final judgment on the remaining damages. The final outcome of these matters cannot be determined at this 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
Alabama 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 quarterly 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 (K) under "DOE Loan Guarantee Borrowings""Southern Company" for information regarding the sale of Gulf Power.
Southern Company Gas
The future 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 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 and Southern Company Gas' financial statements.
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 1 to the financial statements under "Recently Adopted Accounting Standards – Revenue" in Item 8 of the Form 10-K for additional information regarding Georgia Power's Loan Guarantee Agreement.
On July 27, 2017, Georgia Power entered into an amendmenton the adoption of ASC 606 for revenue from contracts with customers and Note 1 to the Loan Guarantee Agreement (LGA Amendment)financial statements under "Revenues" and "Other Taxes" in connection withItem 8 of the DOE's consentForm 10-K for additional 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 Georgia Power's entry into the Vogtle Services Agreementfinancial 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 relatedfinancial statements in Item 8 of the Form 10-K for cost recovery mechanisms.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
intellectual property licenses (IP Licenses). UnderThe following tables disaggregate revenue sources for the termsthree 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. |
In September 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. In September 2018, the DOE extended the conditional commitment to March 31, 2019. Any further extension must be approved by the DOE. 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.
As of September 30, 2018, Georgia Power had $2.6 billion of borrowings outstanding under the multi-advance term loan facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB.
Under the Loan Guarantee Agreement, Georgia Power is subject to customary borrower affirmative and negative covenants and events of default. In addition, Georgia Power is subject to project-related reporting requirements and other project-specific covenants and events of default.
In the event certain mandatory prepayment events (including any decision not to continue construction of Plant Vogtle Units 3 and 4) occur, the FFB's commitment to make further advances under the FFB Credit Facility will terminate and Georgia Power will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facility over a period of five years (with level principal amortization). Among other things, these mandatory prepayment events include (i) the termination of the Vogtle Services Agreement or rejection of the Vogtle Services Agreement in bankruptcy if Georgia Power does not maintain access to intellectual property rights under the IP Licenses; (ii) a decision by Georgia Power not to continue construction of Plant Vogtle Units 3 and 4; (iii) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC, or by Georgia Power if authorized by the Georgia PSC; and (iv) cost disallowances by the Georgia PSC that could have a material adverse effect on completion of Plant Vogtle Units 3 and 4 or Georgia Power's ability to repay the outstanding borrowings under the FFB Credit Facility. Under certain circumstances, insurance proceeds and any proceeds from an event of taking must be applied to immediately prepay outstanding borrowings under the FFB Credit Facility. In addition, 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 Facility 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. Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facility. Under the FFB Credit Facility, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Financing Activities
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first nine months of 2018:
|
| | | | | | | | | | | | | | | | | | | |
| Company | Senior Note Issuances | | Senior Note Maturities, Redemptions, and Repurchases | | Revenue Bond
Maturities, Redemptions, and
Repurchases | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(a) |
| | (in millions) |
Southern Company(b) | $ | 750 |
| | $ | 1,000 |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Alabama Power | 500 |
| | — |
| | — |
| | — |
| | — |
|
| Georgia Power | — |
| | 1,000 |
| | 469 |
| | — |
| | 107 |
|
| Mississippi Power | 600 |
| | — |
| | 43 |
| | — |
| | 900 |
|
| Southern Power | — |
| | 350 |
| | — |
| | — |
| | 420 |
|
| Southern Company Gas | — |
| | — |
| | 200 |
| | 100 |
| | — |
|
| Other | — |
| | — |
| | — |
| | — |
| | 10 |
|
Elimination(c) | — |
| | — |
| | — |
| | — |
| | (1 | ) |
| Southern Company Consolidated | $ | 1,850 |
| | $ | 2,350 |
| | $ | 712 |
| | $ | 100 |
| | $ | 1,436 |
|
|
| | | | | | | | | |
| | 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) | Includes reductions in capital lease obligations resulting from cash paymentsRetail 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 capitalASC 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 contracts with customers related to these performance obligations remaining at June 30, 2019 expect the revenues 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 Note 7 to the financial statements in Item 8 of the Form 10-K for additional information on Southern Power's consolidated VIEs.
Southern Power has certain subsidiaries that are determined to be VIEs. Southern Power is considered the primary 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 7 to the financial statements in Item 8 of the Form 10-K for additional information on Southern Company Gas' equity method investments.
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 8 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) | Represents reductions in affiliateSouthern 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 lease obligations at Georgia Power, which are eliminated inneeds of Nicor Gas. Pursuant to this multi-year credit arrangement, the allocations between Southern Company's Consolidated Financial Statements.Company Gas Capital and Nicor Gas may be adjusted. |
Except as otherwise described herein,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 its subsidiaries usedexpect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the proceeds of debt issuances for their redemptions and maturities shown inmaturity dates and/or increase or decrease 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.lending commitments thereunder.
Southern Company
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 entered intoand Mississippi Power and dismissed the allegations related to a $900 million short-term floating rate bank loan bearing interest based on one-month LIBOR, which was repaid in August 2018.
number of the statements that plaintiffs challenged as being false or misleading. In April 2018, Southern Company borrowed $250 million pursuant tothe defendants filed a short-term uncommitted bank credit arrangement, bearing interest at a rate agreed upon by Southern Company andmotion for reconsideration of the bank from time to time and payable on no less than 30 days' demand bycourt's order, seeking dismissal of the bank.
In June 2018, Southern Company repaid at maturity two $100 million short-term floating rate bank term loans.
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, issued $750 million aggregate principal amountcertain of Series 2018A Floating Rate Senior Notes due February 14, 2020 bearing interest basedits 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 three-month LIBOR,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 into a $1.5 billion short-term floating rate bank loan bearing interest based on one-month LIBOR, and repaid $250 million borrowedan order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in August 2017 pursuant to a short-term uncommitted bank credit arrangement.
Alabama Powerthe putative securities class action.
In JuneMay 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, Alabama Power issued $500 million aggregate principal amountthe court entered an
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 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.
Georgia Power
In 2011, plaintiffs filed a putative class action against Georgia Power in the Superior Court of Fulton County, Georgia alleging that Georgia Power's collection in rates of amounts for municipal franchise fees (which fees are paid to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state 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. Georgia Power believes the plaintiffs' claims have no merit. 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. 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
Southern Power indirectly owns a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock facility in Pecos County, Texas. Prior to the facility being placed in service in 2016, certain solar panels were damaged during installation by the construction contractor, McCarthy Building Companies, Inc. (McCarthy), and certain solar panels were damaged by a hail event that also occurred during construction. In connection therewith, Southern Power withheld payment of approximately $26 million to the construction contractor, which placed a lien on the Roserock facility for the same amount. In 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas against XL Insurance America, Inc. and North American Elite Insurance Company seeking recovery from an insurance policy for damages resulting from the hail event and McCarthy's installation practices. In June 2018, the court granted Roserock's motion for partial summary judgment, finding that the insurers were in breach of contract and in violation of the Texas Insurance Code for failing to pay any monies owed for the hail claim. Separate lawsuits were filed between Roserock and McCarthy, as well as other parties, and that litigation was consolidated in the U.S. District Court for the Western District of Texas. On April 18, 2019, Roserock and the parties to the state and federal lawsuits executed a settlement agreement and mutual release that resolved both lawsuits. Following execution of the agreement, the lawsuits were dismissed, Southern Power paid 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 noncontrolling interests and Southern Power recognized a $12 million after-tax gain.
Environmental Remediation
The Southern Company system must comply with environmental laws and regulations governing the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companies and the natural gas distribution utilities in Illinois and Georgia have each received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies.
Georgia Power's environmental remediation liability was $18 million and $23 million as of June 30, 2019 and December 31, 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.
Southern Company Gas' environmental remediation liability was $283 million and $294 million as of June 30, 2019 and December 31, 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 $2 million of the total accrued remediation costs.
The ultimate outcome of these matters cannot be determined at this time; however, as a result of the regulatory treatment for environmental remediation expenses described above, the final disposition of these matters is not expected to have a material impact on the financial statements of Southern Company, Georgia Power, or Southern Company Gas.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Nuclear Fuel Disposal Costs
In 2014, Alabama Power and Georgia Power filed lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plants Farley, Hatch, and Vogtle Units 1 and 2 for the period from January 1, 2011 through December 31, 2013. The damage period was subsequently extended to December 31, 2014. 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 be recognized in the financial statements until the court enters final judgment on the remaining damages. The final outcome of these matters cannot be determined at this 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
Alabama 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 quarterly 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 (K) under "Southern Company" for information regarding the sale of Gulf Power.
Southern Company Gas
The future 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 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 and Southern Company Gas' financial statements.
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 1 to the financial statements under "Recently Adopted Accounting Standards – Revenue" in Item 8 of the Form 10-K for additional information on the adoption of ASC 606 for revenue from contracts with customers and Note 1 to the financial statements under "Revenues" and "Other Taxes" in Item 8 of the Form 10-K for additional 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 repaid itshad 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 $150performance 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 $100$11 million floating rate bank loans due Mayof 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 contracts with customers related to these performance obligations remaining at June 30, 2019 expect the revenues 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 Note 7 to the financial statements in Item 8 of the Form 10-K for additional information on Southern Power's consolidated VIEs.
Southern Power has certain subsidiaries that are determined to be VIEs. Southern Power is considered the primary 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 7 to the financial statements in Item 8 of the Form 10-K for additional information on Southern Company Gas' equity method investments.
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 October 26,related income from those investments for the three- and six-month periods ended June 30, 2019 and 2018 respectively.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 8 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 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.
DOE Loan Guarantee Borrowings
See Note 8 to the financial statements under "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 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 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 an amount 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 April 2018,March 2019, Georgia Power redeemed all $250 millionmade 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 FFB under its Series 2008B 5.40% Senior Notes due June 1, 2018.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 May 2018,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 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 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 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 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 Georgia Power under the Guarantee Settlement Agreement 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 optional) 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 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 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, Georgia PowerSouthern Company repurchased and retired $89approximately $522 million of the $250$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 2007A 5.65%2014B 2.15% Senior Notes due MarchSeptember 1, 2037, $3262019 (Series 2014B Notes), and approximately $504 million of the $500$750 million aggregate principal amount outstanding of its Series 2009A 5.95% Senior2018A Floating Rate Notes due February 1, 2039, and $335 million of the $600 million aggregate principal amount outstanding of its Series 2010B 5.40% Senior Notes due June 1, 2040,14, 2020 (Series 2018A Notes), for an aggregate purchase price, excluding accrued and unpaid interest, of $902 million.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 purchasedredeemed approximately $13 million, $20 million, and held the following pollution control revenue bonds, which may be reoffered to the public at a later date:
$104.6$75 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 20131992, 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 20092009;
$55approximately $105 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), FifthFirst Series 19942013; 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 20082008.
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.
$71.73555 million aggregate principal amount of Development Authority of BartowBurke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant BowenVogtle Project), FirstFourth Series 20131994;
$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 2018,2019, Mississippi Power issued $300 million aggregate principal amount of Series 2018A Floating Rate Senior Notes due March 27, 2020 bearing interest based on three-month LIBOR and $300 million aggregate principal amount of Series 2018B 3.95% Senior Notes due March 30, 2028. In March 2018, Mississippi Power also entered into a $300 million short-term floating rate bank loan bearing interest based on one-month LIBOR, of which $200 million was repaid inreoffered to the second quarter 2018 and $100 million was repaid in the third quarter 2018. Mississippi Power used the proceeds from these financings to repay a $900 million unsecured term loan.
In July 2018, Mississippi Power purchased and held approximatelypublic $43 million aggregate principal amount of Mississippi Business Finance Corporation Pollution Control Revenue Refunding Bonds, Series 2002.2002, which previously had been purchased and held by Mississippi Power may reoffer these bonds to the public at a later date.Power.
Subsequent to September 30, 2018, Mississippi Power completed the redemption of all 8,867 outstanding shares ($886,700 aggregate par value) of its 4.40% Series Preferred Stock, all 8,643 outstanding shares ($864,300 aggregate par value) of its 4.60% Series Preferred Stock, all 16,700 outstanding shares ($1.67 million aggregate par value) of its 4.72% Series Preferred Stock, all 1,200,000 outstanding depositary shares ($30 million aggregate stated value) each representing a 1/4th interest in a share of its 5.25% Series Preferred Stock, all $30 million aggregate principal amount outstanding of its Series G 5.40% Senior Notes due July 1, 2035, and all $125 million aggregate principal amount outstanding of its Series 2009A 5.55% Senior Notes due March 1, 2019.Southern Power
In May 2018,2019, Southern Power entered into two short-term floating rate bank loans, each for anrepaid 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 $100 million, which bear interest basedthe Form 10-K for information on one-month LIBOR.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)
In the second quarter 2018, Southern Power repaid $420 million aggregate principal amount of long-term floating rate bank loans and $350 million aggregate principal amount of Series 2015A 1.50% Senior Notes due June 1, 2018.
During the nine months ended September 30, 2018, Southern Power received approximately $148 million of third-party tax equity related to the Gaskell West 1 and Cactus Flats facilities. See Note (J) under "Southern Power" for additional information.
Southern Company Gas
On January 4, 2018, Southern Company Gas issued a floating rate promissory note to Southern Company in an aggregate principal amount of $100 million bearing interest based on one-month LIBOR. On March 28, 2018, Southern Company Gas repaid this promissory note.
Prior to its sale,There were no stock-based compensation awards that were not included in the second quarter 2018, Pivotal Utility Holdings caused $200 million aggregate principal amount of gas facility revenue bonds to be redeemed.
In May 2018, Southern Company Gas Capital borrowed $95 million pursuant to a short-term uncommitted bank credit arrangement, guaranteed by Southern Company Gas, bearing interest at a rate agreed upon by Southern Company Gas Capital and the bank from time to time and payable on no less than 30 days' demand by the bank. The proceeds of the loandiluted earnings per share calculation because they were used to repay short-term debt. In July 2018, Southern Company Gas Capital repaid this loan.
In July 2018, Nicor Gas agreed to issue $300 million aggregate principal amount of first mortgage bonds in a private placement, $100 million of which was issued in August 2018 and $200 million of which was issued in November 2018.
On January 1, 2018, the qualified defined benefit pension plan of Southern Company Gas was merged into the qualified defined benefit pension plan of Southern Company. Following the plan merger, Southern Company has a qualified defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees at PowerSecure. The Southern Company qualified defined benefit 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 defined benefit pension plan are anticipated for the year ending December 31, 2018.
In addition, the Southern Company Gas non-qualified retirement plans were merged into the Southern Company non-qualified retirement plan (defined benefit and defined contribution). Following the non-qualified retirement plan mergers, Southern Company continues to provide certain non-qualified defined benefits for a select group of management and highly compensated employees, which are funded on a cash basis.
Furthermore, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions. Southern Company Gas also provides certain medical care and life insurance benefits for eligible retired employees through a postretirement benefit plan. 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.
As indicated in Note (A), the registrants adopted ASU 2017-07 as of January 1, 2018. ASU 2017-07 requires that an employer report the service cost component of net periodic benefit costs in the same line item or items as other compensation costs and requires the other components of net periodic benefit costs to be separately presented in the statements of income outside of income from operations. The presentation requirements of ASU 2017-07 have been applied retrospectively with the service cost component of net periodic benefit costs included in operations and maintenance and all other components of net periodic benefit costs included in other income (expense), net in the statements of incomeanti-dilutive for the three and ninesix months ended SeptemberJune 30, 2017.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
With respect to the presentation requirements, the registrants have used the practical expedient provided by ASU 2017-07, which permits2019 and an employer to use the amounts disclosed in its retirement benefits footnote for prior comparative periods as the estimation basis for applying the retrospective presentation requirements to those periods. The amountsimmaterial amount of the other components of net periodic benefit costs reclassifiedsuch awards was not included for the prior period are presentedsix 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 following tables.diluted earnings per share calculation because they were anti-dilutive.
(G) INCOME TAXES
See Note 210 to the financial statements of each registrant in Item 8 of the Form 10-K for additional information.
Components of the net periodic benefit costs for the three and nine months ended September 30, 2018 and 2017 are presented in the following tables.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2018 | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power | | Southern Power | | Southern Company Gas |
| | (in millions) |
| Pension Plans |
| Service cost | $ | 90 |
| | $ | 19 |
| | $ | 22 |
| | $ | 4 |
| | $ | 5 |
| | $ | 3 |
| | $ | 8 |
|
| Interest cost | 116 |
| | 26 |
| | 34 |
| | 5 |
| | 5 |
| | 1 |
| | 10 |
|
| Expected return on plan assets | (236 | ) | | (51 | ) | | (74 | ) | | (10 | ) | | (11 | ) | | (3 | ) | | (18 | ) |
| Amortization: | | | | | | | | | | | | | |
| Prior service costs | 1 |
| | — |
| | 1 |
| | — |
| | — |
| | — |
| | (1 | ) |
| Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 4 |
|
| Net (gain)/loss | 53 |
| | 13 |
| | 18 |
| | 2 |
| | 3 |
| | — |
| | 3 |
|
| Net periodic pension cost (income) | $ | 24 |
| | $ | 7 |
| | $ | 1 |
| | $ | 1 |
| | $ | 2 |
| | $ | 1 |
| | $ | 6 |
|
| Postretirement Benefits |
| Service cost | $ | 6 |
| | $ | 1 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| | $ | — |
|
| Interest cost | 19 |
| | 5 |
| | 7 |
| | 1 |
| | — |
| | — |
| | 2 |
|
| Expected return on plan assets | (17 | ) | | (7 | ) | | (6 | ) | | — |
| | — |
| | — |
| | (1 | ) |
| Amortization: | | | | | | | | | | | | | |
| Prior service costs | 2 |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 2 |
|
| Net (gain)/loss | 3 |
| | — |
| | 2 |
| | — |
| | — |
| | — |
| | — |
|
| Net periodic postretirement benefit cost | $ | 13 |
| | $ | — |
| | $ | 5 |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
| | $ | 3 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2018 | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power | | Southern Power | | Southern Company Gas |
| | (in millions) |
| Pension Plans |
| Service cost | $ | 269 |
| | $ | 58 |
| | $ | 65 |
| | $ | 12 |
| | $ | 13 |
| | $ | 7 |
| | $ | 24 |
|
| Interest cost | 348 |
| | 76 |
| | 104 |
| | 15 |
| | 15 |
| | 4 |
| | 29 |
|
| Expected return on plan assets | (707 | ) | | (155 | ) | | (222 | ) | | (30 | ) | | (31 | ) | | (8 | ) | | (53 | ) |
| Amortization: | | | | | | | | | | | | | |
| Prior service costs | 3 |
| | 1 |
| | 2 |
| | — |
| | — |
| | — |
| | (2 | ) |
| Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 11 |
|
| Net (gain)/loss | 160 |
| | 40 |
| | 52 |
| | 7 |
| | 8 |
| | 1 |
| | 9 |
|
| Net periodic pension cost (income) | $ | 73 |
| | $ | 20 |
| | $ | 1 |
| | $ | 4 |
| | $ | 5 |
| | $ | 4 |
| | $ | 18 |
|
| Postretirement Benefits |
| Service cost | $ | 18 |
| | $ | 4 |
| | $ | 5 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
|
| Interest cost | 56 |
| | 13 |
| | 21 |
| | 2 |
| | 2 |
| | — |
| | 7 |
|
| Expected return on plan assets | (51 | ) | | (20 | ) | | (19 | ) | | (1 | ) | | (1 | ) | | — |
| | (5 | ) |
| Amortization: | | | | | | | | | | | | | |
| Prior service costs | 5 |
| | 3 |
| | 1 |
| | — |
| | — |
| | — |
| | — |
|
| Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 5 |
|
| Net (gain)/loss | 10 |
| | 1 |
| | 6 |
| | — |
| | — |
| | — |
| | — |
|
| Net periodic postretirement benefit cost | $ | 38 |
| | $ | 1 |
| | $ | 14 |
| | $ | 2 |
| | $ | 2 |
| | $ | 1 |
| | $ | 8 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | | | | | |
Three Months Ended September 30, 2017(*) | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power | | Southern Company Gas |
| | (in millions) |
| Pension Plans |
| Service cost | $ | 73 |
|
| $ | 15 |
|
| $ | 19 |
|
| $ | 3 |
|
| $ | 4 |
|
| $ | 6 |
|
| Interest cost | 114 |
|
| 25 |
|
| 34 |
|
| 5 |
|
| 5 |
|
| 10 |
|
| Expected return on plan assets | (224 | ) |
| (49 | ) |
| (71 | ) |
| (10 | ) |
| (9 | ) |
| (18 | ) |
| Amortization: | | | | | | | | | | | |
| Prior service costs | 3 |
|
| 1 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| Net (gain)/loss | 41 |
|
| 10 |
|
| 15 |
|
| 2 |
|
| 1 |
|
| 5 |
|
| Net periodic pension cost (income) | $ | 7 |
|
| $ | 2 |
|
| $ | (3 | ) |
| $ | — |
|
| $ | 1 |
|
| $ | 3 |
|
| Postretirement Benefits |
| Service cost | $ | 6 |
| | $ | 1 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
| Interest cost | 19 |
| | 4 |
| | 6 |
| | 1 |
| | 1 |
| | 3 |
|
| Expected return on plan assets | (16 | ) | | (5 | ) | | (6 | ) | | — |
| | — |
| | (2 | ) |
| Amortization: | | | | | | | | | | | |
| Prior service costs | 2 |
| | 1 |
| | — |
| | — |
| | — |
| | (1 | ) |
| Net (gain)/loss | 3 |
| | — |
| | 3 |
| | — |
| | — |
| | 1 |
|
| Net periodic postretirement benefit cost | $ | 14 |
| | $ | 1 |
| | $ | 5 |
| | $ | 1 |
| | $ | 1 |
| | $ | 2 |
|
| |
(*) | Excludes Southern Power since Southern Power did not participate in the qualified pension and postretirement benefit plans until December 2017. |
|
| | | | | | | | | | | | | | | | | | | | | | | |
Nine Months Ended September 30, 2017(*) | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power | | Southern Company Gas |
| | (in millions) |
| Pension Plans |
| Service cost | $ | 220 |
| | $ | 47 |
| | $ | 56 |
| | $ | 10 |
| | $ | 11 |
| | $ | 17 |
|
| Interest cost | 341 |
| | 73 |
| | 103 |
| | 15 |
| | 15 |
| | 30 |
|
| Expected return on plan assets | (673 | ) | | (147 | ) | | (212 | ) | | (29 | ) | | (29 | ) | | (53 | ) |
| Amortization: | | | | | | | | | | | |
| Prior service costs | 9 |
| | 2 |
| | 2 |
| | — |
| | 1 |
| | (1 | ) |
| Net (gain)/loss | 122 |
| | 31 |
| | 43 |
| | 5 |
| | 5 |
| | 15 |
|
| Net periodic pension cost (income) | $ | 19 |
| | $ | 6 |
| | $ | (8 | ) | | $ | 1 |
| | $ | 3 |
| | $ | 8 |
|
| Postretirement Benefits |
| Service cost | $ | 18 |
| | $ | 4 |
| | $ | 5 |
| | $ | 1 |
| | $ | 1 |
| | $ | 2 |
|
| Interest cost | 59 |
| | 13 |
| | 21 |
| | 2 |
| | 3 |
| | 8 |
|
| Expected return on plan assets | (49 | ) | | (19 | ) | | (18 | ) | | (1 | ) | | (1 | ) | | (5 | ) |
| Amortization: | | | | | | | | | | | |
| Prior service costs | 5 |
| | 3 |
| | 1 |
| | — |
| | — |
| | (2 | ) |
| Net (gain)/loss | 10 |
| | 1 |
| | 6 |
| | — |
| | — |
| | 3 |
|
| Net periodic postretirement benefit cost | $ | 43 |
| | $ | 2 |
| | $ | 15 |
| | $ | 2 |
| | $ | 3 |
| | $ | 6 |
|
| |
(*) | Excludes Southern Power since Southern Power did not participate in the qualified pension and postretirement benefit plans until December 2017. |
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.
Federal Tax Reform Legislation
Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the registrants consider all amounts recorded in the financial statements as a result of the Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. Each of the registrants is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See Note (B) under "Regulatory Matters" for additional information.
Current and Deferred Income Taxes
Tax Credit Carryforwards
Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) totaling $2.4$2.0 billion as of SeptemberJune 30, 20182019 compared to $2.1$2.4 billion as of December 31, 2017.2018.
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 2018 abandonment loss related to certain Kemper County energy facility expenditures as well as the projected taxable gains on the various sale transactions describeddescribe in Note (J)(K) and "Legal Entity Reorganizations" herein. The expected utilization of tax credit carryforwards could be further delayed by numerous factors, including the acquisition of additional renewable projects, increased generation at existing wind facilities, the purchase of rights to additional PTCs during construction of Plant Vogtle Units 3 and 4 pursuant to the MEAG Term Sheet,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 "Nuclear"Georgia Power – Nuclear Construction" for additional information onregarding Plant Vogtle Units 3 and 4. The ultimate outcome of these matters cannot be determined at this time.
Valuation Allowances
|
| | | | | | | | | | | | | | | |
| | Georgia Power | | Mississippi Power | | Southern Company Gas | | Southern Company |
| | (in millions) |
| Federal | $ | 6 |
| | $ | — |
| | $ | 11 |
| | $ | 19 |
|
| State (net of federal benefit) | 33 |
| | 124 |
| | 1 |
| | 171 |
|
| Balance at September 30, 2018 | $ | 39 |
| | $ | 124 |
| | $ | 12 |
| | $ | 190 |
|
Southern Company had valuation allowances, net of related federal benefits, of $190 million at September 30, 2018 compared to $148 million at December 31, 2017. The increase was primarily due to Georgia Power's projected inability to utilize certain state tax credit carryforwards.
Effective Tax Rate
Each registrant'sDetails of significant changes in the effective tax rate for the nine months ended September 30, 2018 varied significantly as compared to the corresponding period in 2017 due to the 14% lower 2018 federal tax rate resulting from the Tax Reform Legislation.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 22.7%33.5% for the ninesix months ended SeptemberJune 30, 20182019 compared to 42.6%an effective tax benefit rate of (3.2)% for the corresponding period in 2017.2018. The effective tax rate decreaseincrease was primarily due to the reductiontax impact from the sale of Gulf Power in the federal corporate income tax rate2019 and the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation, the net state income tax benefits related2018 charge to changes in state apportionment rates arising from the reorganization of Southern Power's legal entities as discussed further herein, and the $3.1 billion pre-tax loss on the Kemper IGCC, net of the non-deductible AFUDC equity portion, recorded in 2017, partially offset by the $1.1 billion pre-tax loss related to Plant Vogtle Units 3 and 4 and the income taxes recordedearnings related to the Southern Company Gas Dispositions in 2018. See Note 3 to the financial statementsconstruction of Southern Company under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) under "Kemper County Energy Facility" for additional information regarding the Kemper IGCC and Note (B) under "Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4. See Note (B) under "Regulatory Matters" for additional information on the flowback of excess deferred income taxes(K) and Note (J) under "Southern Company Gas" for additional information on the Southern Company Gas Dispositions.
Southern Company recognizes PTCs when wind energy is generated and sold (using the prescribed KWH rate in applicable federal and state statutes), which may differ significantly from amounts computed on a quarterly basis using an overall estimated annual effective income tax rate. Southern Company uses this method of recognition since the amount of PTCs can be significantly impacted by wind generation. This method can significantly affect the effective income tax rate for the period depending on the amount of pretax income.
Alabama Power
Alabama Power's effective tax rate was 23.9% for the nine months ended September 30, 2018 compared to 39.9% for the corresponding period in 2017. The effective tax rate decrease was primarily due2 to the reductionfinancial statements in the federal corporate income tax rate and the benefit from the flowback of excess deferred income taxes as a resultItem 8 of the Tax Reform Legislation. See Note (B)Form 10-K under "Regulatory Matters"Georgia Power – Alabama Power"Nuclear Construction" for additional information.
Georgia Power
Georgia Power's effective tax rate was 25.5%21.7% for the ninesix months ended SeptemberJune 30, 20182019 compared to 37.0%a benefit rate of (53.5)% for the corresponding period in 2017.2018. The effective tax rate decreaseincrease was primarily due to the reduction in the federal corporate income tax rate and the $1.1 billion pre-tax loss2018 charge to earnings related to the estimated probable loss onconstruction of Plant Vogtle Units 3 and 4, recorded in 2018, partially offset by the valuation allowance on certainan increase in state tax credit carryforwards.ITCs. See Note (B) under "Nuclear Construction" for additional information.
Gulf Power
Gulf Power's effective tax benefit rate was (0.5)% for the nine months ended September 30, 2018 compared to an effective tax rate of 39.4% for the corresponding period in 2017. The effective tax rate decrease was primarily due2 to the reductionfinancial statements in the federal corporate income tax rate and the benefit from the flowback of excess deferred income taxes as a resultItem 8 of the Tax Reform Legislation. See Note (B)Form 10-K under "Regulatory Matters"Georgia Power – Gulf Power"Nuclear Construction" for additional information.
Mississippi Power
Mississippi Power's effective tax rate was 20.8%14.0% for the ninesix months ended SeptemberJune 30, 20182019 compared to a benefit rate of (30.3)%18.7% for the corresponding period in 2017.2018. The effective tax rate increasedecrease was primarily due to the $3.1 billion pre-tax loss on the Kemper IGCC, net of the non-deductible AFUDC equity portion, recorded in 2017, partially offset by the reductionan increase in the federal corporateflowback of excess deferred income tax ratetaxes as a result of a settlement agreement reached with wholesale customers under the Tax Reform Legislation.MRA tariff. See Note (B) under "Regulatory Matters – Mississippi"Mississippi Power" for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Southern Power
Southern Power's effective tax benefit rate was (220.3)(35.5)% for the ninesix months ended SeptemberJune 30, 20182019 compared to (66.5)(1,386.5)% for the corresponding period in 2017.2018. The effective tax benefit rate decrease was primarily due to lower earnings before income taxes resultingreductions of tax benefits from a $119 million asset impairment chargewind PTCs primarily as a result of the pending2018 sale of Plant Oleanderthe noncontrolling tax equity interest in SPC Wind and Plant Stanton Unit A (together, the Florida Plants) and a $36 million asset impairment charge on wind turbine equipment held for development projects, as well as the reduction in the federal corporate income tax rate and the net state income tax benefits related to certainfrom changes in state apportionment rates arising fromfollowing the reorganization of Southern Power's legal entities as described below.that own and operate certain solar facilities, partially offset by the net tax benefits from the sale of Plant Nacogdoches in 2019. See Note (J)(K) and Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power" for additional information.
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.
Southern Company Gas
Southern Company Gas' effective tax rate was 61.8%18.0% for the ninesix months ended SeptemberJune 30, 20182019 compared to 43.4%39.1% for the corresponding period in 2017.2018. This increasedecrease was primarily related to income taxes recorded related to the Southern Company Gas Dispositions, partially offset by the reductionan increase in the federal corporate income tax rate and the benefit from 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 resultfederal tax valuation allowance in connection with Southern Company Gas' sale of the Tax Reform Legislation,its investment in Triton in 2019, as well as the 2017 increases in deferred tax expense related to the enactmentimpacts of the State of Illinois income tax legislation and new income tax apportionment factorsSouthern Company Gas Dispositions in several states.2018. See Note (B) under "Regulatory Matters – Southern Company Gas" and Note (J)(E) under "Southern Company Gas" for additional information.
Legal Entity Reorganizations
In April 2018, Southern Power completed the final stage of a legal entity reorganization of various direct and indirect subsidiaries that ownNotes 2 and operate substantially all of its solar facilities, including certain subsidiaries owned in partnership with various third parties. The reorganization resulted in net state tax benefits related to certain changes in apportionment rates totaling approximately $54 million, which were recorded in the first half of 2018.
In September 2018, Southern Power also completed a legal reorganization of eight operating wind facilities under a new holding company, SP Wind, which resulted in net state tax benefits totaling approximately $11 million related to certain changes in apportionment rates.
Unrecognized Tax Benefits
See Note 515 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 registrants had no unrecognized tax benefits asSouthern Company system has a qualified defined benefit, trusteed, pension plan covering substantially all employees, with the exception of September 30, 2018. Itemployees at PowerSecure. The qualified pension plan is reasonably possible that the amountfunded in accordance with requirements of the unrecognized taxEmployee 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 could change within 12 months.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 settlement of federal and state audits could impacttraditional electric operating companies fund other postretirement trusts to the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
The IRS has finalized its audits of Southern Company's consolidated income tax returns through 2016, as well as the pre-Mergerextent required by their respective regulatory commissions. Southern Company Gas tax returns. Southern Companyhas 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 a participantincluded 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 Compliance Assurance Processfollowing 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 recurring basis during the period, together with their associated level of the IRS. The audits for Southern Company's state income tax returns have either been concluded, or the statutefair 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 |
|
| |
(I)(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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Southern Company Gas' wholesale gas operations use various contracts in its commercial activities that generally meet the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note (D)(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.
The registrants adopted ASU 2017-12 as of January 1, 2018. See Note (A)1 to the financial statements under "Recently Adopted Accounting Standards – Other""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 approved a moratorium on Gulf Power's fuel-hedging program until January 1, 2021. The moratorium does not have an impact on the recovery of existing hedges entered into under the previously-approved hedging program. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in energy-related commodity prices because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted capacity is used to sell electricity. Southern Company Gas retains exposure to price changes that can, in a volatile energy market, be material and can adversely affect its results of operations.
Southern Company Gas also enters into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in operating revenues.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Energy-related derivative contracts are accounted for under one of three methods:
Regulatory Hedges — Energy-related derivative contracts 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 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.
| |
| • | Regulatory Hedges — Energy-related derivative contracts designated as regulatory hedges relate primarily to the traditional electric operating companies' and the natural gas distribution utilities' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses. |
| |
| • | Cash Flow Hedges — Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in accumulated OCI before being recognized in the statements of income in the same period and in the same income statement line item as the earnings effect of the hedged transactions. |
| |
| • | Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. |
Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric and natural gas industries. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.
At SeptemberJune 30, 2018,2019, 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(*) | 595 | | 2022 | | 2029 | 536 | | 2023 | | 2029 |
| Alabama Power | 82 | | 2022 | | — | 88 | | 2022 | | — |
| Georgia Power | 165 | | 2022 | | — | 200 | | 2022 | | — |
| Gulf Power | 9 | | 2020 | | — | |
| Mississippi Power | 69 | | 2022 | | — | 101 | | 2023 | | — |
| Southern Power | 15 | | 2020 | | — | 8 | | 2020 | | — |
Southern Company Gas(*) | 255 | | 2021 | | 2029 | 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 4.34.0 billion mmBtu and short natural gas positions of 43.9 billion mmBtu as of SeptemberJune 30, 2018,2019, 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 1325 million mmBtu for Southern Company, 2which includes 4 million mmBtu for Alabama Power, 48 million mmBtu for Georgia Power, 1 million mmBtu for Gulf Power, 24 million mmBtu for Mississippi Power, and 49 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, 20192020 are immaterial for all registrants.
Interest Rate Derivatives
Southern Company and certain subsidiaries may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the
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. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
At SeptemberJune 30, 2018,2019, 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, 2018 | 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 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 | | $ | (6 | ) | 300 |
| | 2.75% | 3-month LIBOR+0.92% | June 2020 | | (1 | ) |
Southern Company(*) | 1,500 |
| | 2.35% | 1-month
LIBOR + 0.87% | July 2021 | | (60 | ) | 1,500 |
| | 2.35% | 1-month LIBOR+0.87% | July 2021 | | (14 | ) |
| Georgia Power | 500 |
| | 1.95% | 3-month
LIBOR + 0.76% | December 2018 | | (3 | ) | 200 |
| | 4.25% | 3-month LIBOR+2.46% | December 2019 | | (1 | ) |
| Georgia Power | 200 |
| | 4.25% | 3-month
LIBOR + 2.46% | December 2019 | | (3 | ) | |
| Southern Company Consolidated | $ | 2,500 |
| | $ | (72 | ) | $ | 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, 20192020 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 derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and on the same income statement line as the earnings effect of the hedged transactions, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
At SeptemberJune 30, 2018,2019, 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, 2018 |
| (in millions) | | (in millions) | | | (in millions) |
| Cash Flow Hedges of Existing Debt | | | | | |
| Southern Power | $ | 677 |
| 2.95% | € | 600 |
| 1.00% | June 2022 | $ | 48 |
|
| Southern Power | 564 |
| 3.78% | 500 |
| 1.85% | June 2026 | 51 |
|
| Total | $ | 1,241 |
| | € | 1,100 |
| | | $ | 99 |
|
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, 20192020 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, 2018 | As of December 31, 2017 | 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 | $ | 15 |
| $ | 17 |
| $ | 10 |
| $ | 43 |
| $ | 7 |
| $ | 57 |
| $ | 8 |
| $ | 23 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 5 |
| 26 |
| 7 |
| 24 |
| 9 |
| 34 |
| 9 |
| 26 |
|
| Assets held for sale, current/Liabilities held for sale, current | — |
| 6 |
| — |
| — |
| — |
| — |
| — |
| 6 |
|
| Assets held for sale/Liabilities held for sale | — |
| 2 |
| — |
| — |
| |
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 20 |
| $ | 51 |
| $ | 17 |
| $ | 67 |
| $ | 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 | $ | 3 |
| $ | 6 |
| $ | 3 |
| $ | 14 |
| $ | 1 |
| $ | 7 |
| $ | 3 |
| $ | 7 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 1 |
| 1 |
| — |
| — |
| — |
| 1 |
| 1 |
| 2 |
|
| Interest rate derivatives: | | |
| Other current assets/Other current liabilities | — |
| 22 |
| 1 |
| 4 |
| — |
| 50 |
| — |
| 19 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 50 |
| — |
| 34 |
| — |
| 2 |
| — |
| 30 |
|
| Foreign currency derivatives: | | |
| Other current assets/Other current liabilities | — |
| 23 |
| — |
| 23 |
| — |
| 23 |
| — |
| 23 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 122 |
| — |
| 129 |
| — |
| 60 |
| — |
| 75 |
| — |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 126 |
| $ | 102 |
| $ | 133 |
| $ | 75 |
| $ | 61 |
| $ | 83 |
| $ | 79 |
| $ | 81 |
|
| Derivatives not designated as hedging instruments | | |
| Energy-related derivatives: | | |
| Other current assets/Other current liabilities | $ | 263 |
| $ | 317 |
| $ | 380 |
| $ | 437 |
| $ | 286 |
| $ | 298 |
| $ | 561 |
| $ | 575 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 134 |
| 198 |
| 170 |
| 215 |
| 156 |
| 219 |
| 180 |
| 325 |
|
| Total derivatives not designated as hedging instruments | $ | 397 |
| $ | 515 |
| $ | 550 |
| $ | 652 |
| $ | 442 |
| $ | 517 |
| $ | 741 |
| $ | 900 |
|
| Gross amounts recognized | $ | 543 |
| $ | 668 |
| $ | 700 |
| $ | 794 |
| $ | 519 |
| $ | 691 |
| $ | 837 |
| $ | 1,036 |
|
Gross amounts offset(a) | $ | (303 | ) | $ | (491 | ) | $ | (405 | ) | $ | (598 | ) | $ | (328 | ) | $ | (506 | ) | $ | (524 | ) | $ | (801 | ) |
Net amounts recognized in the Balance Sheets(b) | $ | 240 |
| $ | 177 |
| $ | 295 |
| $ | 196 |
| $ | 191 |
| $ | 185 |
| $ | 313 |
| $ | 235 |
|
| | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| | | | As of September 30, 2018 | As of December 31, 2017 | 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 | $ | 5 |
| $ | 4 |
| $ | 2 |
| $ | 6 |
| $ | 4 |
| $ | 11 |
| $ | 3 |
| $ | 4 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 2 |
| 6 |
| 2 |
| 4 |
| 2 |
| 7 |
| 3 |
| 6 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 7 |
| $ | 10 |
| $ | 4 |
| $ | 10 |
| $ | 6 |
| $ | 18 |
| $ | 6 |
| $ | 10 |
|
| Gross amounts recognized | $ | 7 |
| $ | 10 |
| $ | 4 |
| $ | 10 |
| $ | 6 |
| $ | 18 |
| $ | 6 |
| $ | 10 |
|
| Gross amounts offset | $ | (4 | ) | $ | (4 | ) | $ | (4 | ) | $ | (4 | ) | $ | (3 | ) | $ | (3 | ) | $ | (4 | ) | $ | (4 | ) |
| Net amounts recognized in the Balance Sheets | $ | 3 |
| $ | 6 |
| $ | — |
| $ | 6 |
| $ | 3 |
| $ | 15 |
| $ | 2 |
| $ | 6 |
|
| | | |
| Georgia Power | | |
| Derivatives designated as hedging instruments for regulatory purposes | | |
| Energy-related derivatives: | | |
| Other current assets/Other current liabilities | $ | 5 |
| $ | 9 |
| $ | 2 |
| $ | 9 |
| $ | 1 |
| $ | 26 |
| $ | 2 |
| $ | 8 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 2 |
| 13 |
| 4 |
| 10 |
| 5 |
| 17 |
| 4 |
| 13 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 7 |
| $ | 22 |
| $ | 6 |
| $ | 19 |
| $ | 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 | $ | — |
| $ | 5 |
| $ | — |
| $ | 4 |
| $ | — |
| $ | 37 |
| $ | — |
| $ | 2 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 1 |
| — |
| 1 |
| |
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | — |
| $ | 6 |
| $ | — |
| $ | 5 |
| $ | — |
| $ | 37 |
| $ | — |
| $ | 2 |
|
| Gross amounts recognized | $ | 7 |
| $ | 28 |
| $ | 6 |
| $ | 24 |
| $ | 6 |
| $ | 80 |
| $ | 6 |
| $ | 23 |
|
| Gross amounts offset | $ | (7 | ) | $ | (7 | ) | $ | (6 | ) | $ | (6 | ) | $ | (6 | ) | $ | (6 | ) | $ | (6 | ) | $ | (6 | ) |
| Net amounts recognized in the Balance Sheets | $ | — |
| $ | 21 |
| $ | — |
| $ | 18 |
| $ | — |
| $ | 74 |
| $ | — |
| $ | 17 |
|
| | | |
| Gulf Power | | |
| Derivatives designated as hedging instruments for regulatory purposes | | |
| Energy-related derivatives: | | |
| Other current assets/Other current liabilities | $ | — |
| $ | 6 |
| $ | — |
| $ | 14 |
| |
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 2 |
| — |
| 7 |
| |
| Total derivatives designated as hedging instruments for regulatory purposes | $ | — |
| $ | 8 |
| $ | — |
| $ | 21 |
| |
| Gross amounts recognized | $ | — |
| $ | 8 |
| $ | — |
| $ | 21 |
| |
| Net amounts recognized in the Balance Sheets | $ | — |
| $ | 8 |
| $ | — |
| $ | 21 |
| |
| | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| | | | As of September 30, 2018 | As of December 31, 2017 | 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 | $ | 2 |
| $ | 3 |
| $ | 1 |
| $ | 6 |
| $ | 1 |
| $ | 10 |
| $ | 1 |
| $ | 3 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 1 |
| 6 |
| 1 |
| 3 |
| 2 |
| 9 |
| 2 |
| 6 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 3 |
| $ | 9 |
| $ | 2 |
| $ | 9 |
| $ | 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 | $ | — |
| $ | — |
| $ | 1 |
| $ | — |
| |
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | — |
| $ | — |
| $ | 1 |
| $ | — |
| |
| Gross amounts recognized | $ | 3 |
| $ | 9 |
| $ | 3 |
| $ | 9 |
| $ | 3 |
| $ | 19 |
| $ | 3 |
| $ | 9 |
|
| Gross amounts offset | $ | (3 | ) | $ | (3 | ) | $ | (2 | ) | $ | (2 | ) | $ | (3 | ) | $ | (3 | ) | $ | (2 | ) | $ | (2 | ) |
| Net amounts recognized in the Balance Sheets | $ | — |
| $ | 6 |
| $ | 1 |
| $ | 7 |
| $ | — |
| $ | 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 | $ | 2 |
| $ | 6 |
| $ | 3 |
| $ | 11 |
| $ | 1 |
| $ | 3 |
| $ | 3 |
| $ | 6 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 1 |
| 1 |
| — |
| — |
| — |
| 1 |
| 1 |
| 2 |
|
| Foreign currency derivatives: | | |
| Other current assets/Other current liabilities | — |
| 23 |
| — |
| 23 |
| — |
| 23 |
| — |
| 23 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 122 |
| — |
| 129 |
| — |
| 60 |
| — |
| 75 |
| — |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 125 |
| $ | 30 |
| $ | 132 |
| $ | 34 |
| $ | 61 |
| $ | 27 |
| $ | 79 |
| $ | 31 |
|
| Derivatives not designated as hedging instruments | | |
| Energy-related derivatives: | | |
| Other current assets/Other current liabilities | $ | — |
| $ | — |
| $ | — |
| $ | 2 |
| $ | 1 |
| $ | — |
| $ | — |
| $ | — |
|
| Total derivatives not designated as hedging instruments | | $ | 1 |
| $ | — |
| $ | — |
| $ | — |
|
| Gross amounts recognized | $ | 125 |
| $ | 30 |
| $ | 132 |
| $ | 36 |
| $ | 62 |
| $ | 27 |
| $ | 79 |
| $ | 31 |
|
| Gross amounts offset | $ | (2 | ) | $ | (2 | ) | $ | (3 | ) | $ | (3 | ) | $ | (1 | ) | $ | (1 | ) | $ | (3 | ) | $ | (3 | ) |
| Net amounts recognized in the Balance Sheets | $ | 123 |
| $ | 28 |
| $ | 129 |
| $ | 33 |
| $ | 61 |
| $ | 26 |
| $ | 76 |
| $ | 28 |
|
| | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| | | | As of September 30, 2018 | As of December 31, 2017 | 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 | $ | 3 |
| $ | 1 |
| $ | 5 |
| $ | 8 |
| $ | 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 | $ | 3 |
| $ | 2 |
| $ | 5 |
| $ | 8 |
| $ | 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 | $ | 1 |
| $ | — |
| $ | — |
| $ | 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 | $ | 262 |
| $ | 316 |
| $ | 379 |
| $ | 434 |
| $ | 285 |
| $ | 298 |
| $ | 559 |
| $ | 574 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 134 |
| 198 |
| 170 |
| 215 |
| 156 |
| 219 |
| 180 |
| 325 |
|
| Total derivatives not designated as hedging instruments | $ | 396 |
| $ | 514 |
| $ | 549 |
| $ | 649 |
| $ | 441 |
| $ | 517 |
| $ | 739 |
| $ | 899 |
|
| Gross amounts of recognized | $ | 400 |
| $ | 516 |
| $ | 554 |
| $ | 660 |
| $ | 442 |
| $ | 532 |
| $ | 741 |
| $ | 909 |
|
Gross amounts offset(a) | $ | (287 | ) | $ | (475 | ) | $ | (390 | ) | $ | (583 | ) | $ | (315 | ) | $ | (493 | ) | $ | (508 | ) | $ | (785 | ) |
Net amounts recognized in the Balance Sheets(b) | $ | 113 |
| $ | 41 |
| $ | 164 |
| $ | 77 |
| $ | 127 |
| $ | 39 |
| $ | 233 |
| $ | 124 |
|
| |
| (a) | Gross amounts offset include cash collateral held on deposit in broker margin accounts of $189$178 million and $193$277 million as of SeptemberJune 30, 20182019 and December 31, 2017,2018, respectively. |
| |
| (b) | Net amounts of derivative instruments outstanding exclude premium and intrinsic value associated with weather derivatives of $5 million and $11$8 million as of September 30, 2018 and December 31, 2017, respectively.2018. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
At SeptemberJune 30, 20182019 and December 31, 2017,2018, 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, 2018 |
Derivative Category and Balance Sheet Location | Southern Company(*) | Alabama Power | Georgia Power | Gulf Power | Mississippi Power | Southern Company Gas(*) |
| | (in millions) |
| Energy-related derivatives: | | | | | | |
| Other regulatory assets, current | $ | (9 | ) | $ | (2 | ) | $ | (4 | ) | $ | (6 | ) | $ | (2 | ) | $ | (1 | ) |
| Other regulatory assets, deferred | (20 | ) | (4 | ) | (11 | ) | (2 | ) | (5 | ) | — |
|
| Assets held for sale, current | (6 | ) | — |
| — |
| — |
| — |
| — |
|
| Assets held for sale | (2 | ) | — |
| — |
| — |
| — |
| — |
|
| Other regulatory liabilities, current | 8 |
| 3 |
| — |
| — |
| — |
| 5 |
|
| Total energy-related derivative gains (losses) | $ | (29 | ) | $ | (3 | ) | $ | (15 | ) | $ | (8 | ) | $ | (7 | ) | $ | 4 |
|
| |
| (*) | Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $3$12 million at SeptemberJune 30, 2018.2019. |
|
| | | | | | | | | | | | | | | | | | |
| Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2017 |
Derivative Category and Balance Sheet Location | Southern Company(*) | Alabama Power | Georgia Power | Gulf Power | Mississippi Power | Southern Company Gas(*) |
| | (in millions) |
| Energy-related derivatives: | | | | | | |
| Other regulatory assets, current | $ | (34 | ) | $ | (4 | ) | $ | (7 | ) | $ | (14 | ) | $ | (5 | ) | $ | (4 | ) |
| Other regulatory assets, deferred | (18 | ) | (3 | ) | (6 | ) | (7 | ) | (2 | ) | — |
|
| Other regulatory liabilities, current | 7 |
| — |
| — |
| — |
| — |
| 7 |
|
| Other regulatory liabilities, deferred | 1 |
| 1 |
| — |
| — |
| — |
| — |
|
| Total energy-related derivative gains (losses) | $ | (44 | ) | $ | (6 | ) | $ | (13 | ) | $ | (21 | ) | $ | (7 | ) | $ | 3 |
|
| |
(*) | Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $6 million at December 31, 2017. |
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 ninesix months ended SeptemberJune 30, 20182019 and 2017,2018, 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 September 30, | For the Nine Months
Ended September 30, | For the Three Months
Ended June 30, | For the Six Months
Ended June 30, |
| 2018 | 2017 | 2018 | 2017 | 2019 | 2018 | 2019 | 2018 |
| | (in millions) | (in millions) |
| Southern Company | | |
| Energy-related derivatives | $ | (5 | ) | $ | (6 | ) | $ | 7 |
| $ | (26 | ) | $ | (6 | ) | $ | — |
| $ | (6 | ) | $ | 12 |
|
| Interest rate derivatives | — |
| (1 | ) | (2 | ) | (2 | ) | (37 | ) | — |
| (37 | ) | (2 | ) |
| Foreign currency derivatives | (10 | ) | 46 |
| (31 | ) | 114 |
| (1 | ) | (73 | ) | (39 | ) | (21 | ) |
| Total | $ | (15 | ) | $ | 39 |
| $ | (26 | ) | $ | 86 |
| $ | (44 | ) | $ | (73 | ) | $ | (82 | ) | $ | (11 | ) |
| Georgia Power | | |
| Interest rate derivatives | | $ | (37 | ) | $ | — |
| $ | (37 | ) | $ | — |
|
| Total | | $ | (37 | ) | $ | — |
| $ | (37 | ) | $ | — |
|
| Southern Power | | |
| Energy-related derivatives | $ | (5 | ) | $ | (6 | ) | $ | 5 |
| $ | (21 | ) | $ | (2 | ) | $ | (1 | ) | $ | (2 | ) | $ | 10 |
|
| Foreign currency derivatives | (10 | ) | 46 |
| (31 | ) | 114 |
| (1 | ) | (73 | ) | (39 | ) | (21 | ) |
| Total | $ | (15 | ) | $ | 40 |
| $ | (26 | ) | $ | 93 |
| $ | (3 | ) | $ | (74 | ) | $ | (41 | ) | $ | (11 | ) |
| Southern Company Gas | | |
| Energy-related derivatives | $ | — |
| $ | — |
| $ | 2 |
| $ | (4 | ) | |
For the three and ninesix months ended SeptemberJune 30, 20182019 and 2017,2018, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on accumulated OCI were immaterial for the other registrants.
For the three and nine months ended September 30, 2017, there was no material ineffectiveness recorded in earnings for any registrant. Upon the adoption
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
For the three and ninesix months ended SeptemberJune 30, 20182019 and 2017,2018, the pre-tax effects of cash flow and fair value hedge accounting on income were as follows: |
| | | | | | | | | | | | | |
| | Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships | For the Three Months
Ended September 30, | For the Nine Months
Ended September 30, |
| |
| | 2018 | 2017 | 2018 | 2017 |
| | | (in millions) | (in millions) |
| | Southern Company | | | | |
| | Cost of natural gas | $ | 104 |
| $ | 134 |
| $ | 1,053 |
| $ | 1,085 |
|
| | Gain (loss) on cash flow hedges(a) | | | | |
| | Energy-related derivatives | — |
| — |
| (2 | ) | — |
|
| | Depreciation and amortization | 787 |
| 767 |
| 2,338 |
| 2,236 |
|
| | Gain (loss) on cash flow hedges(a) | | | | |
| | Energy-related derivatives | — |
| (6 | ) | 2 |
| (12 | ) |
| | Interest expense, net of amounts capitalized | (458 | ) | (407 | ) | (1,386 | ) | (1,248 | ) |
| | Gain (loss) on cash flow hedges(a) | | | | |
| | Interest rate derivatives | (5 | ) | (5 | ) | (16 | ) | (15 | ) |
| | Foreign currency derivatives | (6 | ) | (5 | ) | (18 | ) | (17 | ) |
| | Gain (loss) on fair value hedges(b) | | | | |
| | Interest rate derivatives | (4 | ) | (5 | ) | (35 | ) | (6 | ) |
| | Other income (expense), net | 57 |
| 65 |
| 195 |
| 165 |
|
| | Gain (loss) on cash flow hedges(a)(c) | | | | |
| | Foreign currency derivatives | (9 | ) | 43 |
| (46 | ) | 139 |
|
| | Alabama Power | | | | |
| | Interest expense, net of amounts capitalized | $ | (82 | ) | $ | (76 | ) | $ | (240 | ) | $ | (229 | ) |
| | Gain (loss) on cash flow hedges(a) | | | | |
| | Interest rate derivatives | (1 | ) | (2 | ) | (4 | ) | (5 | ) |
| | Georgia Power | | | | |
| | Interest expense, net of amounts capitalized | $ | (95 | ) | $ | (105 | ) | $ | (303 | ) | $ | (310 | ) |
| | Gain (loss) on cash flow hedges(a) | | | | |
| | Interest rate derivatives | (1 | ) | (1 | ) | (4 | ) | (3 | ) |
| | Gain (loss) on fair value hedges(b) | | | | |
| | Interest rate derivatives | — |
| — |
| (1 | ) | (1 | ) |
| | Mississippi Power | | | | |
| | Interest expense, net of amounts capitalized | $ | (19 | ) | $ | 13 |
| $ | (59 | ) | $ | (23 | ) |
| | Gain (loss) on cash flow hedges(a) | | | | |
| | Interest rate derivatives | — |
| — |
| (1 | ) | (1 | ) |
| | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | |
| | Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships | For the Three Months
Ended September 30, | For the Nine Months
Ended September 30, |
| |
| | 2018 | 2017 | 2018 | 2017 |
| | | (in millions) | (in millions) |
| | Southern Power | | | | |
| | Depreciation and amortization | $ | 130 |
| $ | 131 |
| $ | 370 |
| $ | 379 |
|
| | Gain (loss) on cash flow hedges(a) | | | | |
| | Energy-related derivatives | — |
| (6 | ) | 2 |
| (12 | ) |
| | Interest expense, net of amounts capitalized | (45 | ) | (47 | ) | (138 | ) | (144 | ) |
| | Gain (loss) on cash flow hedges(a) | | | | |
| | Foreign currency derivatives | (6 | ) | (5 | ) | (18 | ) | (17 | ) |
| | Other income (expense), net | 17 |
| 3 |
| 22 |
| 3 |
|
| | Gain (loss) on cash flow hedges(a)(c) | | | | |
| | Foreign currency derivatives | (9 | ) | 43 |
| (46 | ) | 139 |
|
| | | | | | |
| | Southern Company Gas | | | | |
| | Cost of natural gas | $ | 104 |
| $ | 134 |
| $ | 1,053 |
| $ | 1,085 |
|
| | Gain (loss) on cash flow hedges(a) | | | | |
| | Energy-related derivatives | — |
| — |
| (2 | ) | — |
|
|
| | | | | | | | | | | | | |
| | 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) | Amounts reflect gains or losses on cash flow hedges that were reclassifiedReclassified from accumulated OCI into income.earnings. |
| |
| (b) | For fair value hedges, presented above, generally changes in the fair value of the derivative contracts are generally equal to changes in the fair value of the underlying debt and have no material impact on income. |
| |
| (c) | The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes. |
For the three and ninesix months ended SeptemberJune 30, 20182019 and 2017,2018, the pre-tax effects of cash flow and fair value hedge accounting on income for energy-related derivatives and interest rate derivatives were immaterial for Gulf Powerthe traditional electric operating companies and Southern Company Gas.
As of SeptemberJune 30, 20182019 and December 31, 2017,2018, the following amounts were recorded on the balance sheets related to cumulative basis adjustments for fair value hedges:
|
| | | | | | | | | | | | | |
| Carrying Amount of the Hedged Item | | Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item |
| Balance Sheet Location of Hedged Items | As of June 30, 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 |
|
|
| | | | | | | | | | | | | |
| 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 September 30, 2018 | As of December 31, 2017 |
| As of September 30, 2018 | As of December 31, 2017 |
| (in millions) | | (in millions) |
| Southern Company | | | | | |
| Securities due within one year | $ | (499 | ) | $ | (746 | ) | | $ | 1 |
| $ | 3 |
|
| Long-term debt | (2,526 | ) | (2,553 | ) | | 65 |
| 35 |
|
| | | | | | |
| Georgia Power | | | | | |
| Securities due within one year | $ | (499 | ) | $ | (746 | ) | | $ | 1 |
| $ | 3 |
|
| Long-term debt | (497 | ) | (498 | ) | | 2 |
| 1 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
For the three and ninesix months ended SeptemberJune 30, 20182019 and 2017,2018, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income of Southern Company and Southern Company Gas were as follows:
| | | | | Gain (Loss) | | 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 | 2018 | 2017 | | 2018 | 2017 | Statements of Income Location | 2019 | 2018 | | 2019 | 2018 |
| | | (in millions) | | (in millions) | | (in millions) | | (in millions) |
| Southern Company | | | | | |
| Energy-related derivatives: | Natural gas revenues(*) | $ | (36 | ) | $ | (17 | ) | | $ | (79 | ) | $ | 48 |
| Natural gas revenues(*) | $ | 50 |
| $ | (28 | ) | | $ | 83 |
| $ | (43 | ) |
| | Cost of natural gas | 2 |
| 2 |
| | 5 |
| (2 | ) | Cost of natural gas | (5 | ) | 2 |
| | 3 |
| 4 |
|
| Total derivatives in non-designated hedging relationships | Total derivatives in non-designated hedging relationships | $ | (34 | ) | $ | (15 | ) | | $ | (74 | ) | $ | 46 |
| 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 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. |
For the three and ninesix months ended SeptemberJune 30, 20182019 and 2017,2018, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments were immaterial forfor the traditional electric operating companies and Southern Power.
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, 2018,2019, the registrants had no collateral posted with derivative counterparties to satisfy these arrangements.
For the registrants with interest rate derivatives at SeptemberJune 30, 2018,2019, 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. At SeptemberJune 30, 2018,2019, 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, 2018,2019, 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, 2018,2019, cash collateral held on deposit in broker margin accounts was $189$178 million.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 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)
| |
(J) | ACQUISITIONS AND DISPOSITIONS |
(K) ACQUISITIONS AND DISPOSITIONS
See Note 15 to the financial statements in Item 8 of the Form 10-K for additional information.
Southern Company's Sale of Gulf PowerCompany
On May 20, 2018,January 1, 2019, Southern Company entered into a stock purchase agreement (Gulf Power SPA) with NextEra Energy and its wholly-owned subsidiary 700 Universe, LLC, which provides forcompleted the sale 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 $5.75approximately $5.8 billion (less the amount$1.3 billion of indebtedness assumed at closing, which is currently estimated at approximately $1.3 billion)assumed), subject to (i) customary adjustments for indebtedness and working capital and (ii) reduction byadjustments. The preliminary gain associated with the amount (if any) by which Gulf Power fails to meet a specified capital expenditure target.
The Gulf Power SPA contains customary representations, warranties, and covenants of Southern Company, 700 Universe, LLC, and NextEra Energy. These covenants include, among others, an obligation of Southern Company to cause Gulf Power to operate its business in the ordinary course until the sale is consummated and an obligation for each of the parties to use reasonable best efforts to obtain the governmental and regulatory approvals described below.
The completion of the sale is subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) approval by the FERC and the Federal Communications Commission, (ii) the entry into certain ancillary agreements, including transmission-related agreements and a transition services agreement, among the parties and their affiliates, and (iii) other customary closing conditions.
The Gulf Power SPA may be terminated by either Southern Company or 700 Universe, LLC under certain circumstances, including if the sale is not consummated by June 28, 2019 (subject to extension to December 31, 2019, if all of the conditions to closing, other than the conditions related to obtaining regulatory approvals, have been satisfied). The Gulf Power SPA further provides that, upon the termination thereof, (i) under certain specified circumstances, 700 Universe, LLC will be required to pay Southern Company a termination fee of $100 million or $200 million (such amount depending on the specific circumstances of such termination) and (ii) upon certain other specified circumstances Southern Company will be required to pay 700 Universe, LLC a termination fee of $100 million.
The sale of Gulf Power is expected to occur in the first quarter 2019.totaled $2.5 billion pre-tax ($1.3 billion after tax). The assets and liabilities of Gulf Power arewere classified as assets held for sale and liabilities held for sale on Southern Company's balance sheet as of SeptemberDecember 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, 2018. 2019. In contemplation of this sale, a goodwill impairment charge of $32 million was recorded in the second quarter 2019.
See "Assets Held for Sale" belowherein for additional information. The ultimate outcome of this matter cannot be determined at this time.
Southern Power
See Note 11 to the financial statements of Southern Power and Note 12 to the financial statements of Southern Company under "Southern Power" in Item 8 of the Form 10-K for additional information.
Acquisitions During the Nine Months Ended September 30, 2018Construction Projects
During the ninesix months ended SeptemberJune 30, 2018, one of2019, Southern Power's wholly-owned subsidiaries acquired andPower completed construction of the Gaskell West 1 solar facility. 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 |
Gaskell West 1 | Solar | Recurrent Energy Development Holdings, LLC January 26, 2018 | 20 | Kern County, CA | 100% of Class B | (*) | March 2018 | 20 years |
| |
(*) | Southern Power owns 100% of the class B membership interests under a tax equity partnership agreement. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
The Gaskell West 1 facility did not have operating revenues or activities prior to completion of construction and the assets being placed in service during March 2018.
Construction Projects in Progress and/or Completed
During the nine months ended September 30, 2018, Southern Power started,385-MW Plant Mankato expansion and continued or completed construction of thetwo other projects set forthas described in the table below. Total aggregate construction costs, excluding the acquisition costs, are expected to be between $575$405 million and $640$450 million for the Mankato, Wild HorseWildhorse Mountain and Reading facilities. At SeptemberJune 30, 2018,2019, total costs of construction costsincurred for these projects were $186 million and are included in CWIP related to these projects totaled $246 million.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 |
Cactus Flats(a)
| Wind | 148 | Concho County, TX | July 2018 | 12-15 yearsProjects Completed During the Six Months Ended June 30, 2019 |
Mankato expansion(a) | Natural Gas | 385 | Mankato, MN | First halfMay 2019 | 20 years |
| Projects Under Construction as of June 30, 2019 |
Wild HorseWildhorse Mountain(b)
| Wind | 100 | Pushmataha County, OK | Fourth quarter 2019 | 20 years |
Reading(c) | Wind | 200 | Osage and Lyon Counties, KS | Second quarter 2020 | 12 years |
| |
| (a) | In July 2017, Southern Power purchased 100% of the Cactus Flats facility and commenced construction. In July 2018, the facility was placed in service and, in AugustNovember 2018, Southern Power closedentered 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 a tax equity partnership agreementJune 1, 2019. See "Sales of Natural Gas and owns 100% of the class B membership interests.Biomass Plants" below. |
| |
| (b) | In May 2018, Southern Power purchased 100% of the Wild HorseWildhorse Mountain facility and commenced construction.facility. Southern Power may enterentered into a tax equity partnership agreement, in which case it would then own 100%June 2019 with funding of the class B membership interests.tax equity amounts expected to occur upon commercial operation. |
| |
| (c) | In August 2018, Southern Power purchased 100% of the membership interests of the Reading facility from the joint development arrangement with Renewable Energy Systems Americas, Inc. and commenced construction. Southern Power may enter into a tax equity partnership, agreement, in which case it would then own 100% of the class B membership interests. |
Development Projects
During 2017, as part of its renewable development strategy, Southern Power purchased wind turbine equipment from Siemens Gamesa Renewable Energy Inc. and Vestas-American Wind Technology, Inc. to be used for various development and construction projects. Any wind projects using this equipment and reaching commercial operation by the end of 2021 are expected to qualify for 80% PTCs.
During 2016, Southern Power entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct wind projects. In addition, in 2016, Southern Power purchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. Any wind projects using this equipment and reaching commercial operation by the end of 2020 are expected to qualify for 100% PTCs.
In response to the previously disclosed decrease of planned expenditures for plant acquisitions and placeholder growth, Southern Power continues to evaluate and refine the deployment of the 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 constructed. During the third quarter 2018, as a result
The ultimate outcome of these matters cannot be determined at this time.
Sale of Solar Facility Interests
In May 2018, Southern Power sold a 33% equity interest in SPSH, a limited partnership indirectly owning substantially all of Southern Power's solar facilities, to Global Atlantic Financial Group Limited (Global Atlantic) for approximately $1.2 billion, subject to customary working capital adjustments. The proceeds were used to repay
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
$770 million of existing indebtedness, to return capital of $250 million to Southern Company, and for other general corporate purposes, including working capital. Since Southern Power retains control ofconstructed. During the limited partnership through its wholly-owned general partner,six months ended June 30, 2019, certain wind turbine equipment was sold, resulting in a gain on the sale was recorded as an equity transaction and Southern Power will continue to consolidate the results of SPSH. approximately $14 million.
On the date of the transaction, the noncontrolling interest was increased by $511 million to reflect 33% of the carrying value of the partnership. This difference, partially offset by the tax impact and other related transaction charges, also resulted in a $410 million decrease to Southern Power's common stockholder's equity.
Sale of Florida Plants
In May 2018,June 14, 2019, Southern Power entered into an equity interest purchase agreement with NextEraBloom Energy to sell allacquire 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 its equity$116 million in exchange for Class B membership interests in DSGP, with the Florida Plants, for an aggregate purchase price of $195 million, subjectremainder expected to customary working capital and timing adjustments.
The sale is subject to certain closing and timing conditions and approvals, including, but not limited to, approvalbe contributed by the FERC. The ultimate purchase price will decrease $110,000 per day for each day after December 31, 2018 through the closingend of 2019. FERC approval of the transaction. Conversely,transfer of the ultimate purchase price will increase $110,000 per day for each day the closing occurs prior to December 31, 2018. The salefacilities is expected to occur in the firstthird quarter 2019. As a result2019; however, the ultimate outcome of this pending transaction,matter cannot be determined at this time.
Sales of Natural Gas and Biomass Plants
On June 13, 2019, Southern Power recordedcompleted the sale of its equity interests in Nacogdoches Power, LLC, the owner of an asset impairment chargeapproximately 115-MW biomass facility located in Nacogdoches County, Texas, to Austin Energy, for an aggregate cash purchase price of approximately $119$461 million, ($89including working capital adjustments. This sale resulted in an $88 million after tax)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 sale of Plant 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 option to terminate the sale, which, if elected, would result in the second quarter 2018.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. The assets and liabilities of the Florida PlantsPlant 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 SeptemberJune 30, 2019 and December 31, 2018. See "Assets Held for Sale" belowherein for additional information. The ultimate outcome of this matter cannot be determined at this time.
Sale of Wind Facility Interests
On October 31, 2018, Southern Power entered into agreements with three financial investors for the sale of a noncontrolling interest for approximately $1.2 billion in tax equity in SP Wind, which owns a portfolio of eight operating wind facilities. The transaction is subject to Public Utility Commission of Texas approval and is expected to close by the end of 2018. Southern Power intends to use the proceeds to return capital of approximately $1.0 billion to Southern Company. The ultimate outcome of this matter cannot be determined at this time.
Sale of Mankato Plant
On November 5, 2018, Southern Power entered into an agreement with Northern States Power to sell all of its equity interests in Plant Mankato (including the 385-MW expansion currently under construction) for an aggregate purchase price of $650 million, subject to customary working capital and timing adjustments. The ultimate purchase price will decrease $66,667 per day for each day after June 1, 2019, if the expansion has not achieved commercial operation, but such decrease will not exceed $15 million. This transaction is subject to the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act and FERC and state commission approvals and is expected to close mid-2019. The ultimate outcome of this matter cannot be determined at this time.
Assets Subject to Lien
Under the terms of the PPA and the expansion PPAPPAs for thePlant Mankato, project, approximately $500$545 million of assets, primarily related to property, plant, and equipment, are subject to lien at SeptemberJune 30, 2018.
Southern Company Gas
Sale of Pivotal Home Solutions
On June 4, 2018, Southern Company Gas completed the stock sale of Pivotal Home Solutions to American Water Enterprises LLC for a total cash purchase price of $365 million, which includes the final working capital adjustment. This disposition resulted in an estimated net loss of $73 million, which includes $39 million of income tax expense, the calculation of which is expected to be finalized in the fourth quarter 2018. In contemplation of the transaction, a goodwill impairment charge of $42 million was recorded during the first quarter 2018. The after-tax
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
loss included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. Southern Company Gas and American Water Enterprises LLC entered into a transition services agreement whereby Southern Company Gas provided certain administrative and operational services through November 4, 2018.
Sale of Elizabethtown Gas and Elkton Gas
On July 1, 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. for a total cash purchase price of $1.7 billion and an additional $40 million for working capital, subject to a final working capital adjustment expected in the fourth quarter 2018. This disposition resulted in an estimated pre-tax gain of approximately $230 million and an after-tax gain of approximately $18 million, the calculations of which are expected to be finalized in the fourth quarter 2018. The after-tax gain included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. Southern Company Gas and South Jersey Industries, Inc. entered into transition services agreements whereby Southern Company Gas will provide certain administrative and operational services through no later than January 31, 2020.
Sale of Florida City Gas
On July 29, 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI Corporation, completed the stock sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energy for a total cash purchase price of $530 million (less $3 million of indebtedness assumed at closing for customer deposits) and an additional $60 million for cash and other working capital, which includes the final working capital adjustment. This disposition resulted in an estimated pre-tax gain of approximately $121 million and an after-tax gain of approximately $20 million, the calculations of which are expected to be finalized in the fourth quarter 2018. The after-tax gain included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. Southern Company Gas and NextEra Energy entered into a transition services agreement whereby Southern Company Gas will provide certain administrative and operational services through no later than July 29, 2020.2019.
Assets Held for Sale
As discussed above, Southern Company and Southern Power each have assets and liabilities held for sale on their balance sheets at SeptemberJune 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.
Upon classification as held for sale in MayNovember 2018 and April 2019 for Plant Mankato and Plant Nacogdoches, respectively, Southern Power ceased recognizing depreciation and amortization on the Florida Plants' property, plant, and equipmentlong-lived assets to be sold. Since the depreciation
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
The following table provides Southern Company's and Southern Power's major classes of assets and liabilities classified as held for sale at SeptemberJune 30, 2019 and December 31, 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 |
|
|
| | | | | | |
| | Southern Company | Southern Power |
| | (in millions) |
| Assets Held for Sale: | | |
| Current assets | $ | 407 |
| $ | 18 |
|
| Total property, plant, and equipment | 4,093 |
| 168 |
|
| Other non-current assets | 574 |
| 17 |
|
| Total Assets Held for Sale | $ | 5,074 |
| $ | 203 |
|
| | | |
| Liabilities Held for Sale: | | |
| Current liabilities | $ | 355 |
| $ | 4 |
|
| Long-term debt | 1,285 |
| — |
|
| Accumulated deferred income taxes | 542 |
| — |
|
| Other non-current liabilities | 1,008 |
| — |
|
| Total Liabilities Held for Sale | $ | 3,190 |
| $ | 4 |
|
Southern Company Southern Power, and Southern Company GasPower each concluded that the sale of their assets, both individually and combined, did not represent a strategic shift in operations that has, or is expected to have, a major effect on its operations and financial results; therefore, none of the assets related to the sales have been classified as discontinued operations for any of the periods presented.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Gulf Power and Southern Power's equity interests in Plant Oleander and Plant Stanton Unit A (together, the Florida Plants representPlants) 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 ninesix months ended SeptemberJune 30, 20182019 and 20172018 is presented below:
|
| | | | | | | | | | | | | |
| | For the Three Months
Ended September 30, | | For the Nine Months
Ended September 30, |
| 2018 | 2017 | | 2018 | 2017 |
| | (in millions) | | (in millions) |
| Earnings before income taxes: | | | | | |
| Gulf Power | $ | 59 |
| $ | 103 |
| | $ | 146 |
| $ | 199 |
|
| Southern Power's Florida Plants | $ | 18 |
| $ | 11 |
| | $ | 40 |
| $ | 28 |
|
|
| | | | | | | | | | | | |
| | 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 |
|
| |
(K)(*) | VARIABLE INTEREST ENTITY AND EQUITY METHOD INVESTMENTSEarnings 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). |
Southern Power(L) LEASES
In May 2018, Southern Power soldOn 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 33% limited partnership interest in SPSH to Global Atlantic. See Note (J) under "Southern Power" for additional information. A wholly-owned subsidiaryterm of Southern Power isgreater than 12 months on the general partner and holdsbalance 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 1% ownership interest in SPSH and another wholly-owned subsidiaryprospective basis as of Southern Power owns the remaining 66% ownership in SPSH. SPSH is a variable interest entity (VIE) becauseadoption date of January 1, 2019, without restating prior periods. The registrants also elected the arrangement is structured as a limited partnershippackage of practical expedients provided by ASC 842 that allows prior determinations of whether existing contracts are, or contain, leases and the 33% limited partner does not have substantive kick-out rights againstclassification of existing leases to continue without reassessment. Additionally, the general partner. Southern Power previously consolidated SPSH and will continue to do soregistrants applied the use-of-hindsight practical expedient in determining lease terms as the primary beneficiary of the VIE because it controlsdate of adoption and elected the most significant activitiespractical 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 the partnership, including operatinglease 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 maintaining its assets.Southern Company Gas and various land leases primarily associated with renewable energy facilities at Southern
At September 30, 2018, SPSH had total assets
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 33% to Global Atlanticapproved 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 accordance with their membership interestsrailcar leases at Alabama Power and Georgia Power and the limited partnership agreement.
Transfers and salesamounts probable of the assetsbeing paid under those guarantees are included in the VIElease payments. All such amounts are subject to limited partner consentimmaterial 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 liabilities do not have recourse to the general creditright-of-use asset.
Southern Company Gas
See Note 4 to the financial statements of Southern Company Gas in Item 8 of the Form 10-K for additional information on Southern Company Gas' equity method investments.
Equity Method Investments
The carrying amounts of Southern Company Gas' equity method investments as of September 30, 2018 and December 31, 2017 and related income from those investments for the three and nine-month periods ended September 30, 2018 and September 30, 2017 were as follows:
|
| | | | | | |
| Investment Balance | September 30, 2018 | December 31, 2017 |
| | (in millions) |
| SNG | $ | 1,260 |
| $ | 1,262 |
|
| Atlantic Coast Pipeline | 73 |
| 41 |
|
| PennEast Pipeline | 70 |
| 57 |
|
| Other | 126 |
| 117 |
|
| Total | $ | 1,529 |
| $ | 1,477 |
|
|
| | | | | | | | | | | | |
Earnings from Equity Method Investments | Three Months Ended
September 30, 2018 | Three Months Ended
September 30, 2017 | Nine Months Ended
September 30, 2018 | Nine Months
Ended
September 30, 2017 |
| | (in millions) |
| SNG | $ | 29 |
| $ | 28 |
| $ | 95 |
| $ | 86 |
|
| PennEast Pipeline | 2 |
| 1 |
| 4 |
| 5 |
|
| Atlantic Coast Pipeline | 1 |
| 1 |
| 4 |
| 4 |
|
| Other | 2 |
| 2 |
| 5 |
| 5 |
|
| Total | $ | 34 |
| $ | 32 |
| $ | 108 |
| $ | 100 |
|
Southern Natural Gas
Selected financial information of SNG for the three and nine months ended September 30, 2018 and September 30, 2017 is as follows:
|
| | | | | | | | | | | | |
Income Statement Information | Three Months Ended September 30, 2018 | Three Months Ended September 30, 2017 | Nine Months Ended September 30, 2018 | Nine Months Ended September 30, 2017 |
| | (in millions) |
| Revenues | $ | 145 |
| $ | 146 |
| $ | 451 |
| $ | 445 |
|
| Operating income | $ | 71 |
| $ | 71 |
| $ | 230 |
| $ | 218 |
|
| Net income | $ | 58 |
| $ | 57 |
| $ | 190 |
| $ | 172 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
(L)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 its natural gas distribution utilities and is involved in several other complementary businesses including gas marketing services,pipeline investments, wholesale gas services, and gas midstream operations. In July 2018, Southern Company Gas completed sales of three of its natural gas distribution utilities. See Note (J) under "Southern Company Gas" for additional information.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 $134$117 million and $326$204 million for the three and ninesix months ended SeptemberJune 30, 2018,2019, respectively, and $105$109 million and $295$192 million for the three and ninesix months ended SeptemberJune 30, 2017,2018, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies were $14 million and $22 millionimmaterial for both the three and ninesix months ended SeptemberJune 30, 2018, respectively,2019 and $9 million and $19 million for the three and nine months ended September 30, 2017, respectively.2018. Revenues from sales of natural gas from Southern Company Gas to Southern Power were $38$16 million and $96$33 million for the three and ninesix months ended SeptemberJune 30, 2018,2019, respectively, and $38$22 million and $94$58 million for the three and ninesix months ended SeptemberJune 30, 2017,2018, 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, 20182019 and 20172018 was as follows:
| | | | Electric Utilities | | Electric Utilities | |
| | Traditional Electric Operating Companies | Southern Power | Eliminations | Total | Southern Company Gas | All Other | Eliminations | Consolidated | Traditional Electric Operating Companies | Southern Power | Eliminations | Total | Southern Company Gas | All Other | Eliminations | Consolidated |
| | (in millions) | (in millions) |
| Three Months Ended September 30, 2018: | | |
| Three Months Ended June 30, 2019 | | Three Months Ended June 30, 2019 | |
| Operating revenues | $ | 5,014 |
| $ | 635 |
| $ | (140 | ) | $ | 5,509 |
| $ | 492 |
| $ | 202 |
| $ | (44 | ) | $ | 6,159 |
| $ | 3,899 |
| $ | 510 |
| $ | (119 | ) | $ | 4,290 |
| $ | 689 |
| $ | 186 |
| $ | (67 | ) | $ | 5,098 |
|
Segment net income (loss)(a)(b)(c)(d) | 1,148 |
| 92 |
| — |
| 1,240 |
| 46 |
| (119 | ) | (3 | ) | 1,164 |
| 782 |
| 174 |
| — |
| 956 |
| 106 |
| (154 | ) | (9 | ) | 899 |
|
| Nine Months Ended September 30, 2018: | |
|
| | |
| Six Months Ended June 30, 2019 | | Six Months Ended June 30, 2019 | |
|
| |
| Operating revenues | $ | 13,117 |
| $ | 1,699 |
| $ | (360 | ) | $ | 14,456 |
| $ | 2,861 |
| $ | 984 |
| $ | (143 | ) | $ | 18,158 |
| $ | 7,343 |
| $ | 953 |
| $ | (211 | ) | $ | 8,085 |
| $ | 2,163 |
| $ | 368 |
| $ | (106 | ) | $ | 10,510 |
|
Segment net income (loss)(a)(b)(c)(d) | 1,711 |
| 235 |
| — |
| 1,946 |
| 294 |
| (292 | ) | — |
| 1,948 |
| 1,346 |
| 230 |
| — |
| 1,576 |
| 376 |
| 1,041 |
| (11 | ) | 2,982 |
|
| At September 30, 2018: | | |
| At June 30, 2019 | | |
| Goodwill | $ | — |
| $ | 2 |
| $ | — |
| $ | 2 |
| $ | 5,015 |
| $ | 298 |
| $ | — |
| $ | 5,315 |
| $ | — |
| $ | 2 |
| $ | — |
| $ | 2 |
| $ | 5,015 |
| $ | 265 |
| $ | — |
| $ | 5,282 |
|
| Total assets | 75,069 |
| 15,355 |
| (322 | ) | 90,102 |
| 20,398 |
| 3,086 |
| (1,869 | ) | 111,717 |
| 78,314 |
| 14,518 |
| (783 | ) | 92,049 |
| 20,761 |
| 3,343 |
| (1,286 | ) | 114,867 |
|
| Three Months Ended September 30, 2017: | | |
| Three Months Ended June 30, 2018 | | Three Months Ended June 30, 2018 | |
| Operating revenues | $ | 5,017 |
| $ | 618 |
| $ | (112 | ) | $ | 5,523 |
| $ | 565 |
| $ | 153 |
| $ | (40 | ) | $ | 6,201 |
| $ | 4,124 |
| $ | 555 |
| $ | (114 | ) | $ | 4,565 |
| $ | 730 |
| $ | 381 |
| $ | (49 | ) | $ | 5,627 |
|
Segment net income (loss)(b)(d) | 1,008 |
| 124 |
| — |
| 1,132 |
| 15 |
| (80 | ) | 2 |
| 1,069 |
| (48 | ) | 22 |
| — |
| (26 | ) | (31 | ) | (100 | ) | 3 |
| (154 | ) |
| Nine Months Ended September 30, 2017: | | |
| Six Months Ended June 30, 2018 | | Six Months Ended June 30, 2018 | |
| Operating revenues | $ | 12,960 |
| $ | 1,597 |
| $ | (318 | ) | $ | 14,239 |
| $ | 2,841 |
| $ | 442 |
| $ | (119 | ) | $ | 17,403 |
| $ | 8,104 |
| $ | 1,064 |
| $ | (220 | ) | $ | 8,948 |
| $ | 2,369 |
| $ | 782 |
| $ | (100 | ) | $ | 11,999 |
|
Segment net income (loss)(a)(b)(e) | — |
| 276 |
| — |
| 276 |
| 303 |
| (232 | ) | — |
| 347 |
| |
| At December 31, 2017: | | |
Segment net income (loss)(a)(b)(d)(e) | | 563 |
| 143 |
| — |
| 706 |
| 248 |
| (174 | ) | 4 |
| 784 |
|
| At December 31, 2018 | | |
| Goodwill | $ | — |
| $ | 2 |
| $ | — |
| $ | 2 |
| $ | 5,967 |
| $ | 299 |
| $ | — |
| $ | 6,268 |
| $ | — |
| $ | 2 |
| $ | — |
| $ | 2 |
| $ | 5,015 |
| $ | 298 |
| $ | — |
| $ | 5,315 |
|
| Total assets | 72,204 |
| 15,206 |
| (325 | ) | 87,085 |
| 22,987 |
| 2,552 |
| (1,619 | ) | 111,005 |
| 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 losses on plants under construction of $1$4 million ($13 million after tax) and $34 million$1.1 billion ($21 million0.8 billion after tax) for the three months ended SeptemberJune 30, 2019 and 2018, respectively, and 2017, respectively,$6 million ($5 million after tax) and $1.1 billion ($0.8 billion after tax) and $3.2 billion ($2.2 billion after tax) for the ninesix months ended SeptemberJune 30, 20182019 and 2017,2018, respectively. See Note 32 to the financial statements of Southern Company under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) under ""Georgia Power – Nuclear Construction"Construction" and "Mississippi Power – Kemper County Energy Facility" for additional information. |
| |
| (c) | Segment net income (loss) for Southernthe "All Other" column includes the preliminary pre-tax gain associated with the sale of Gulf Power includes pre-tax impairment charges of $36 million$2.5 billion ($27 million after tax) and $155 million ($116 million1.3 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 ninesix months ended SeptemberJune 30, 2018, respectively.2019 in contemplation of the sale of one of PowerSecure's business units. See Note (J)(K) under "Southern Power – Development Projects" and " – Sale of Florida PlantsSouthern Company" for additional information. |
| |
| (d) | Segment net income (loss) for Southern Company GasPower includes a net$23 million pre-tax gain on dispositions of $353 million ($4088 million gain after tax) on the sale of Plant Nacogdoches for the three and $317six months ended June 30, 2019 and a pre-tax impairment charge of $119 million ($3589 million loss after tax) for the three and ninesix months ended September 30, 2018, respectively, related to the Southern Company Gas Dispositions and a goodwill impairment charge of $42 million for the nine months ended SeptemberJune 30, 2018 related to the sale of Pivotal Home Solutions.Southern Power's Florida Plants. See Note (J)(K) under "Southern CompanyPower" and 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. |
| |
| (e) | Segment net income (loss) for the traditional electric operating companiesSouthern Company Gas includes a pre-taxgoodwill impairment charge of $42 million for the write-down of Gulf Power's ownership of Plant Scherer Unit 3 of $33 million ($20 million after tax) for the ninesix months ended SeptemberJune 30, 2017.2018 related to the sale of Pivotal Home Solutions. See Note 315 to the financial statements of Southern Company under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" 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, 2018 | $ | 4,605 |
| $ | 693 |
| $ | 211 |
| $ | 5,509 |
|
| Three Months Ended September 30, 2017 | 4,615 |
| 718 |
| 190 |
| 5,523 |
|
| | | | | |
| Nine Months Ended September 30, 2018 | $ | 11,913 |
| $ | 1,923 |
| $ | 620 |
| $ | 14,456 |
|
| Nine Months Ended September 30, 2017 | 11,786 |
| 1,867 |
| 586 |
| 14,239 |
|
|
| | | | | | | | | | | | |
| | 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, 2018 | $ | 438 |
| $ | 44 |
| $ | 10 |
| $ | 492 |
|
| Three Months Ended September 30, 2017 | 430 |
| 143 |
| (8 | ) | 565 |
|
| Nine Months Ended September 30, 2018 | $ | 2,276 |
| $ | 403 |
| $ | 182 |
| $ | 2,861 |
|
| Nine Months Ended September 30, 2017 | 2,119 |
| 597 |
| 125 |
| 2,841 |
|
|
| | | | | | | | | | | | |
| | 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. In July 2018,
Gas pipeline investments consists of joint ventures in natural gas pipeline 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 the customers of Southern Company Gas sold three of its natural gas distribution utilities, Elizabethtown Gas, Elkton Gas, and Florida City Gas. See Note (J) under "Southern Company Gas" for additional information.
Gas marketing services includes natural gas marketing to end-use customers primarily in Georgia and Illinois. On June 4, 2018, Southern Company Gas sold Pivotal Home Solutions. See Note (J) under "Southern Company Gas" for additional information.
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. See Note (E) under "Southern Company Gas" for additional information and related disclosures.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Business segment financial data for the three and ninesix months ended SeptemberJune 30, 20182019 and 20172018 was as follows:
| | | | Gas Distribution Operations(a)(c) | Gas Marketing Services(b)(c) | Wholesale Gas Services(d) | Gas Midstream Operations | Total | All Other | Eliminations | Consolidated | Gas Distribution Operations(a) | Gas Pipeline Investments | Wholesale Gas Services(b) | Gas Marketing Services(c)(d) | Total | All Other | Eliminations | Consolidated |
| | (in millions) | (in millions) |
| Three Months Ended September 30, 2018: | | |
| Three Months Ended June 30, 2019 | | Three Months Ended June 30, 2019 | |
| Operating revenues | $ | 441 |
| $ | 44 |
| $ | (8 | ) | $ | 20 |
| $ | 497 |
| $ | 1 |
| $ | (6 | ) | $ | 492 |
| $ | 568 |
| $ | 8 |
| $ | 48 |
| $ | 58 |
| $ | 682 |
| $ | 13 |
| $ | (6 | ) | $ | 689 |
|
| Segment net income (loss) | 74 |
| (8 | ) | (18 | ) | 16 |
| 64 |
| (18 | ) | — |
| 46 |
| 58 |
| 25 |
| 23 |
| (3 | ) | 103 |
| 3 |
| — |
| 106 |
|
| Nine Months Ended September 30, 2018: | | |
| Six Months Ended June 30, 2019 | | Six Months Ended June 30, 2019 | |
| Operating revenues | 2,297 |
| 403 |
| 142 |
| 60 |
| 2,902 |
| 3 |
| (44 | ) | 2,861 |
| $ | 1,740 |
| $ | 16 |
| $ | 134 |
| $ | 287 |
| $ | 2,177 |
| $ | 24 |
| $ | (38 | ) | $ | 2,163 |
|
| Segment net income (loss) | 290 |
| (71 | ) | 65 |
| 54 |
| 338 |
| (44 | ) | — |
| 294 |
| 191 |
| 57 |
| 70 |
| 58 |
| 376 |
| — |
| — |
| 376 |
|
| Total assets at September 30, 2018: | 16,850 |
| 1,522 |
| 855 |
| 2,297 |
| 21,524 |
| 10,146 |
| (11,272 | ) | 20,398 |
| |
| Three Months Ended September 30, 2017: | | |
| 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 | | Three Months Ended June 30, 2018 | |
| Operating revenues | $ | 472 |
| $ | 143 |
| $ | (24 | ) | $ | 16 |
| $ | 607 |
| $ | 2 |
| $ | (44 | ) | $ | 565 |
| $ | 643 |
| $ | 8 |
| $ | (16 | ) | $ | 89 |
| $ | 724 |
| $ | 11 |
| $ | (5 | ) | $ | 730 |
|
| Segment net income (loss) | 52 |
| 1 |
| (23 | ) | 14 |
| 44 |
| (29 | ) | — |
| 15 |
| 68 |
| 21 |
| (21 | ) | (76 | ) | (8 | ) | (23 | ) | — |
| (31 | ) |
| Nine Months Ended September 30, 2017: | | |
| Six Months Ended June 30, 2018 | | Six Months Ended June 30, 2018 | |
| Operating revenues | 2,255 |
| 597 |
| 95 |
| 53 |
| 3,000 |
| 7 |
| (166 | ) | 2,841 |
| $ | 1,856 |
| $ | 16 |
| $ | 150 |
| $ | 359 |
| $ | 2,381 |
| $ | 26 |
| $ | (38 | ) | $ | 2,369 |
|
| Segment net income (loss) | 223 |
| 36 |
| 28 |
| 38 |
| 325 |
| (22 | ) | — |
| 303 |
| 216 |
| 48 |
| 83 |
| (63 | ) | 284 |
| (36 | ) | — |
| 248 |
|
| Total assets at December 31, 2017: | 19,358 |
| 2,147 |
| 1,096 |
| 2,241 |
| 24,842 |
| 12,184 |
| (14,039 | ) | 22,987 |
| |
| 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 $8$70 million and $50$237 million for the three and six months ended SeptemberJune 30, 2018, and 2017, respectively, and $245 million and $274 million for the nine months ended September 30, 2018 and 2017, respectively. See Note (J)15 to the financial statements in Item 8 of the Form 10-K under "Southern"Southern Company Gas"Gas" for additional information. |
| |
| (b) | Operating revenues for the gas marketing services disposition were $32 million for the three months ended September 30, 2017 and $55 million and $95 million for the nine months ended September 30, 2018 and 2017, respectively. See Note (J) under "Southern Company Gas" for additional information.
|
| |
(c) | Segment net income for gas distribution operations includes a gain on dispositions of $351 million ($38 million after tax) for the three and nine months ended September 30, 2018. Segment net income for gas marketing services includes a gain on disposition of $2 million ($2 million after tax) for the three months ended September 30, 2018 and a loss on disposition of $34 million ($73 million loss after tax) and a goodwill impairment charge of $42 million for the nine months ended September 30, 2018 recorded in contemplation of the sale of Pivotal Home Solutions. See Note (J) under "Southern Company Gas" for additional information.
|
| |
(d) | The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table. |
|
| | | | | | | | | | | | | | | |
| | Third Party Gross Revenues | Intercompany Revenues | Total Gross Revenues | Less Gross Gas Costs | Operating Revenues |
| | (in millions) |
| Three Months Ended September 30, 2018 | $ | 1,573 |
| $ | 82 |
| $ | 1,655 |
| $ | 1,663 |
| $ | (8 | ) |
| Three Months Ended September 30, 2017 | 1,411 |
| 103 |
| 1,514 |
| 1,538 |
| (24 | ) |
| Nine Months Ended September 30, 2018 | $ | 4,847 |
| $ | 352 |
| $ | 5,199 |
| $ | 5,057 |
| $ | 142 |
|
| Nine Months Ended September 30, 2017 | 4,781 |
| 362 |
| 5,143 |
| 5,048 |
| 95 |
|
|
| | | | | | | | | | | | | | | |
| | 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.
Georgia Power may incur additional costs or delays in the construction of Plant Vogtle Units 3 or 4 and may not be able to recover its investments, which could have a material impact on the financial statements of Southern Company and Georgia Power.
Background
In 2009, the Georgia PSC certified construction of 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 Vogtle Owners, entered into the Interim Assessment Agreement with the EPC Contractor to allow construction to continue. The Interim Assessment Agreement expired in July 2017 when Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Vogtle Services Agreement. Under the Vogtle Services Agreement, Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis.
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.
In December 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor.
Cost and Schedule
In preparation for its nineteenth VCM filing, Georgia Power requested Southern Nuclear to perform a full cost reforecast for the project. 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 September 30, 2018(b) | (4.3 | ) |
Remaining estimate to complete(a) | $ | 4.1 |
|
| |
(a) | Excludes financing costs expected to be capitalized through AFUDC of approximately $350 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 $3.2 billion, of which $1.8 billion had been incurred through September 30, 2018.
The table above reflects the $0.7 billion increase to the base capital cost forecast reported in the second quarter 2018 and is based on the cost reforecast performed prior to the nineteenth VCM filing, which primarily resulted from changed assumptions related to the finalization of contract scopes and management responsibilities for Bechtel and over 60 subcontractors, labor productivity rates, and craft labor incentives, as well as the related levels of project management, oversight, and support, including field supervision and engineering support.
Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC's order in the seventeenth VCM proceeding specifically states that the construction of Plant Vogtle Units 3 and 4 is not subject to a cost cap, Georgia Power did not seek rate recovery for these cost increases included in the current base capital cost forecast (or any related financing costs) in the nineteenth VCM report that was filed with the Georgia PSC on August 31, 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs currently included in the construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018, which includes the total increase in the base capital cost forecast and construction contingency estimate.
As construction continues, challenges with management of contractors, subcontractors, and vendors; labor productivity, availability, and/or cost escalation; procurement, fabrication, delivery, assembly, and/or installation, including any required engineering changes, of plant systems, structures, and components (some of which are based on new technology that only recently began initial operation in the global nuclear industry at this scale); or other issues could arise and change the projected schedule and estimated cost. Monthly construction production targets required to maintain the current project schedule continue to increase significantly through the remainder of 2018 and into 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers 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 resolution of Inspections, Tests, Analyses, and Acceptance Criteria (ITAAC) and the related approvals by the NRC, 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 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 August 31, 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).
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 as described above, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. On September 26, 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, and (ii) a term sheet (MEAG Term Sheet and, together with the Vogtle Owner Term Sheet, Term Sheets) with MEAG and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 (Project J) under certain circumstances. Pursuant to the Vogtle Owner Term Sheet, the Vogtle Joint Ownership Agreements will be modified as follows: (i) each Vogtle Owner will pay its proportionate share of qualifying construction costs for Plant Vogtle Units 3 and 4 based on its ownership percentage up to the estimated cost at completion (EAC) for Plant Vogtle Units 3 and 4 which forms the basis of Georgia Power's forecast of $8.4 billion in the nineteenth VCM plus $800 million of additional construction costs; (ii) Georgia Power will be responsible for 55.7% of actual qualifying construction costs between $800 million and $1.6 billion over the EAC in the nineteenth VCM (resulting in $80 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests; and (iii) Georgia Power will be responsible for 65.7% of qualifying construction costs between $1.6 billion and $2.1 billion over the EAC in the nineteenth VCM (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests.
If the EAC is revised and exceeds the EAC in the nineteenth VCM by more than $2.1 billion, each of the other Vogtle Owners will have a one-time option to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100% of such Vogtle Owner's remaining share of total construction
costs in excess of the EAC in the nineteenth VCM plus $2.1 billion. In this event, Georgia Power will have the option of cancelling the project in lieu of purchasing a portion of the ownership interest of any other Vogtle Owner. If Georgia Power accepts the offer to purchase a portion of another Vogtle Owner's ownership interest in Plant Vogtle Units 3 and 4, the ownership interest(s) to be conveyed from the tendering Vogtle Owner(s) to Georgia Power would be calculated based on the proportion of the cumulative amount of construction costs paid by each such tendering Vogtle Owner(s) and by Georgia Power as of the commercial operation date of Plant Vogtle Unit 4. For purposes of this calculation, payments made by Georgia Power on behalf of another Vogtle Owner in accordance with the second and third items described in the paragraph above would be treated as payments made by the applicable Vogtle Owner.
In the event the actual costs at completion are less than the EAC reflected in the nineteenth VCM report and Plant Vogtle Unit 3 is placed in service by the currently scheduled date of November 2021 or Plant Vogtle Unit 4 is placed in service by the currently scheduled date of November 2022, Georgia Power would be entitled to 60.7% of the cost savings with respect to the relevant unit and the remaining Vogtle Owners would be entitled to 39.3% of such savings on a pro rata basis in accordance with their respective ownership interests.
For purposes of the foregoing provisions, qualifying construction costs would not include costs (i) resulting from force majeure events, including governmental actions or inactions (or significant delays associated with issuance of such actions) that affect the licensing, completion, startup, operations, or financing of Plant Vogtle Units 3 and 4, administrative proceedings or litigation regarding ITAAC or other regulatory challenges to commencement of operation of Plant Vogtle Units 3 and 4, and changes in laws or regulations governing Plant Vogtle Units 3 and 4, (ii) legal fees and legal expenses incurred due to litigation with contractors or subcontractors that are not subsidiaries or affiliates of Southern Company, and (iii) additional costs caused by Vogtle Owner requests other than Georgia Power, except for the exercise of a right to vote granted under the Vogtle Joint Ownership Agreements, that increase costs by $100,000 or more.
Georgia Power is working with the other Vogtle Owners to clarify any interpretive issues related to the operation of certain of the above provisions of the Vogtle Owner Term Sheet.
Under the Vogtle Owner Term Sheet, the provisions of the Vogtle Joint Ownership Agreements requiring that Vogtle Owners holding 90% of the ownership interests in Plant Vogtle Units 3 and 4 vote to continue construction following certain adverse events (Project Adverse Events) will be modified. Pursuant to the Vogtle Joint Ownership Agreements and the Vogtle Owner 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 Project Adverse Events occur, including: (i) the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power publicly announces its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 or the Georgia PSC determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Vogtle Owners pursuant to the Vogtle Owner Term Sheet provisions described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Georgia PSC for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates; and (iv) an incremental extension of one year or more over the most recently approved schedule. Under the Vogtle Owner Term Sheet, Georgia Power may cancel the project at any time in its sole discretion.
In addition, pursuant to the Vogtle Joint Ownership Agreements, 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 Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement.
The Vogtle Owner Term Sheet provides that if the holders of at least 90% of the ownership interests fail to vote in favor of continuing the project following any future Project Adverse Event, work on Plant Vogtle Units 3 and 4 would continue for a period of 30 days if the holders of more than 50% of the ownership interests vote in favor of continuing construction (Majority Voting Owners). In such a case, the Vogtle Owners (i) would agree to negotiate in
good faith towards the resumption of the project, (ii) if no agreement was reached during such 30-day period, the project would be cancelled, and (iii) in the event of such a cancellation, the Majority Voting Owners would be obligated to reimburse any other Vogtle Owner for the costs it incurred during such 30-day negotiation period.
Purchase of PTCs During Commercial Operation
In addition, under the terms of the Vogtle Owner Term Sheet, Georgia Power agreed to purchase additional PTCs from OPC, Dalton, MEAG SPVM, MEAG SPVP, and MEAG SPVJ (to the extent any MEAG SPVJ PTC rights remain after any purchases required under the MEAG Term Sheet as described below) at varying purchase prices dependent upon the actual cost to complete construction of Plant Vogtle Units 3 and 4 as compared to the EAC included in the nineteenth VCM report. The purchases will be at the option of the applicable Vogtle Owner and will occur during the month after such PTCs are earned.
Potential Funding to MEAG Project J
Pursuant to the MEAG Term Sheet, if MEAG SPVJ is unable to make its payments due under the Vogtle Joint Ownership Agreements solely because (i) the conduct of JEA, such as JEA's legal challenges of its obligations under a PPA with MEAG (PPA-J), materially impedes access to capital markets for MEAG for Project J, or (ii) PPA-J is declared void by a court of competent jurisdiction or rejected by JEA under the applicable provisions of the U.S. Bankruptcy Code (each of (i) and (ii), a JEA Default), Georgia Power would purchase from MEAG SPVJ the rights to PTCs attributable to MEAG SPVJ's share of Plant Vogtle Units 3 and 4 (approximately 206 MWs) at varying prices dependent upon the stage of construction of Plant Vogtle Units 3 and 4. The aggregate purchase price of the PTCs, together with any advances made as described in the next paragraph, shall not exceed $300 million.
At the option of MEAG, as an alternative or supplement to Georgia Power's purchase of PTCs as described above, Georgia Power has agreed to provide up to $250 million in funding to MEAG for Project J in the form of advances (either advances under the Vogtle Joint Ownership Agreements or the purchase of MEAG Project J bonds, at the discretion of Georgia Power), subject to any required approvals of the Georgia PSC and the DOE.
In the event MEAG SPVJ certifies to Georgia Power that it is unable to fund its obligations under the Vogtle Joint Ownership Agreements as a result of a JEA Default and Georgia Power becomes obligated to provide funding as described above, MEAG is required to (i) assign to Georgia Power its right to vote on any future Project Adverse Event and (ii) diligently pursue JEA for its breach of PPA-J. In addition, Georgia Power agreed that it will not sue MEAG for any amounts due from MEAG SPVJ under MEAG's guarantee of MEAG SPVJ's obligations so long as MEAG SPVJ complies with the terms of the MEAG Term Sheet as to its payment obligations and the other provisions of the Vogtle Joint Ownership Agreements.
Under the terms of the MEAG Term Sheet, Georgia Power may decline to provide any funding in the form of advances, including in the event of a failure to receive any required Georgia PSC or DOE approvals, and cancel the project in lieu of providing such funding.
The ultimate outcome of these matters cannot be determined at this time.
Regulatory Matters
In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) Georgia Power's recommendation to continue construction and 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 $25 million in 2017 and are estimated to have negative earnings impacts of approximately $100 million in 2018 and an aggregate of $680 million from 2019 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.
On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. On March 8, 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's final decision and denial of Georgia Watch's motion for reconsideration. Georgia Power believes the two appeals have no merit; however, an adverse outcome in either 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.
The ultimate outcome of these matters cannot be determined at this time.
See Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
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.
|
| | | | |
| | | (4) Instruments Describing Rights(2) Plan of Security Holders, Including Indenturesacquisition, reorganization, arrangement, liquidation or succession |
| | | | | |
| | | Southern CompanyPower |
| | | | |
| | (e)1 | - | |
| | | | |
| | (e)2 | - | |
| | | | |
| | (3) Articles of Incorporation and By-Laws |
| | | | |
| | Mississippi Power |
| | | | | |
| | * | (a)1(d) | - | |
| | | | | |
| | | Southern Company Gas |
| | | | | |
| | * | (g)1(e) | - | |
| | | | |
|
| | | | |
| | (10) Material Contracts |
| | |
| | Georgia Power |
| | | | |
| | (c)1 | - | First Amendment to Agreement Regarding Additional Participating Party Rights and Amendment No. 3 to Plant Alvin W. Vogtle Additional Units Ownership Participation Agreement, dated as of August 31, 2018, among Georgia Power, Oglethorpe Power Corporation, MEAG, MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, MEAG Power SPVP, LLC, and The City of Dalton, Georgia. (Designated in Form 8-K dated August 31, 2018, File No. 1-6468 as Exhibit 10.1.)amended. |
| | | | | |
| | | (24) Power of Attorney and Resolutions |
| | | | | |
| | | Southern Company |
| | | | | |
| | | (a)1 | - | |
| | | | |
| | (a)2 | - | |
| | | | | |
| | | Alabama Power |
| | | | | |
| | | (b) | - | |
| | | | | |
| | | Georgia Power |
| | | | | |
| | | (c)1 | - | |
| | | | |
| | Gulf Power |
| | | | |
| | (d)1 | - | |
| | | | | |
| | | Mississippi Power |
| | | | | |
| | | (e)(d) | - | |
| | | | | |
|
| | | | |
| | | Southern Power |
| | | | | |
| | | (f)(e)1 | - | |
| | | | |
| | (f)2 | - | |
| | | | | |
| | | Southern Company Gas |
| | | | | |
| | | (g)(f)1 | - | |
| | | | | |
| | | (g)(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) | - | |
| | | | |
| | (99) Additional Exhibits |
| | | | |
| | Georgia Power |
| | | | |
| | (c) | - | Co-Owner Term Sheet, dated September 26, 2018, among Georgia Power, Oglethorpe Power Corporation, MEAG, MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, MEAG Power SPVP, LLC, and the City of Dalton, Georgia. (Designated in Form 8-K dated September 26, 2018, File No. 000-53908 as Exhibit 10.1.) |
| | | | | |
| | | (101) Interactive Data Files |
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| | * | 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 |
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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.
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| | | THE SOUTHERN COMPANY |
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| By | | Thomas A. Fanning |
| | | Chairman, President, and Chief Executive Officer |
| | | (Principal Executive Officer) |
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| By | | Andrew W. Evans |
| | | Executive Vice President and Chief Financial Officer |
| | | (Principal Financial Officer) |
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| By | | /s/ Melissa K. Caen | |
| | | (Melissa K. Caen, Attorney-in-fact) | |
Date: November 6, 2018July 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.
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| | | ALABAMA POWER COMPANY |
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| By | | Mark A. Crosswhite | |
| | | Chairman, President, and Chief Executive Officer |
| | | (Principal Executive Officer) |
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| By | | Philip C. Raymond |
| | | Executive Vice President, Chief Financial Officer, and Treasurer |
| | | (Principal Financial Officer) |
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| By | | /s/ Melissa K. Caen | |
| | | (Melissa K. Caen, Attorney-in-fact) | |
Date: November 6, 2018July 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.
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| | | GEORGIA POWER COMPANY |
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| By | | W. Paul Bowers |
| | | Chairman, President, and Chief Executive Officer |
| | | (Principal Executive Officer) |
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| By | | Xia LiuDavid P. Poroch |
| | | Executive Vice President, Chief Financial Officer, Treasurer, and TreasurerComptroller |
| | | (Principal Financial Officer) |
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| By | | /s/ Melissa K. Caen | |
| | | (Melissa K. Caen, Attorney-in-fact) | |
Date: November 6, 2018July 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.
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| | GULF POWER COMPANY |
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By | | S. W. Connally, Jr. |
| | Chairman, President and Chief Executive Officer |
| | (Principal Executive Officer) |
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By | | Robin B. Boren |
| | Vice President, Chief Financial Officer, and Treasurer |
| | (Principal Financial Officer) |
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By | | /s/ Melissa K. Caen | |
| | (Melissa K. Caen, Attorney-in-fact) | |
Date: November 6, 2018
MISSISSIPPI POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
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| | | MISSISSIPPI POWER COMPANY |
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| By | | Anthony L. Wilson |
| | | Chairman, President, and Chief Executive Officer |
| | | (Principal Executive Officer) |
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| By | | Moses H. Feagin |
| | | Vice President, Chief Financial Officer, and Treasurer |
| | | (Principal Financial Officer) |
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| By | | /s/ Melissa K. Caen | |
| | | (Melissa K. Caen, Attorney-in-fact) | |
Date: November 6, 2018July 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.
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| | | SOUTHERN POWER COMPANY |
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| By | | Mark S. Lantrip |
| | | Chairman President, and Chief Executive Officer |
| | | (Principal Executive Officer) |
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| By | | William C. GranthamElliott L. Spencer |
| | | Senior Vice President, Chief Financial Officer, and Treasurer |
| | | (Principal Financial Officer) |
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| By | | /s/ Melissa K. Caen | |
| | | (Melissa K. Caen, Attorney-in-fact) | |
Date: November 6, 2018July 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.
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| | | SOUTHERN COMPANY GAS |
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| By | | Kimberly S. Greene |
| | | Chairman, President, and Chief Executive Officer |
| | | (Principal Executive Officer) |
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| 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: November 6, 2018July 30, 2019