0000092122so:WholesaleElectricRevenuesMember2022-01-012022-09-30
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
þ☑QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 20172022
OR
¨☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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| Commission
File Number
| | Registrant,
State of Incorporation,
Address and Telephone Number
| | I.R.S. Employer
Identification No.
| |
| | | | | | | | | | | | | | | | | | | | |
1-3526 | 1-3526 | | The Southern Company | | 58-0690070 | |
(A Delaware Corporation)
30 Ivan Allen Jr. Boulevard, N.W.
Atlanta, Georgia 30308
(404) 506-5000
(A Delaware Corporation)
30 Ivan Allen Jr. Boulevard, N.W.
Atlanta, Georgia 30308
(404) 506-5000
| | 58-0690070 | | | | | | | | | | | | | | | | | | |
| 1-3164 | | | |
1-3164 | | Alabama Power Company | | 63-0004250 | |
(An Alabama Corporation)
600 North 18th Street
Birmingham, Alabama 35203
(205) 257-1000
(An Alabama Corporation)
600 North 18th Street
Birmingham, Alabama 35203
(205) 257-1000
| | 63-0004250 | | | | | | | | | | | | | | | | | | |
| 1-6468 | | | |
1-6468 | | Georgia Power Company | | 58-0257110 | |
(A Georgia Corporation)
241 Ralph McGill Boulevard, N.E.
Atlanta, Georgia 30308
(404) 506-6526
(A Georgia Corporation)
241 Ralph McGill Boulevard, N.E.
Atlanta, Georgia 30308
(404) 506-6526
| | 58-0257110 | | | | | | | | | | | | | | | | | | |
| 001-11229 | | | |
001-31737 | | Gulf Power Company
(A Florida Corporation)
One Energy Place
Pensacola, Florida 32520
(850) 444-6111
| | 59-0276810 |
| | | | |
001-11229 | | Mississippi Power Company | | 64-0205820 | |
(A Mississippi Corporation)
2992 West Beach Boulevard
Gulfport, Mississippi 39501
(228) 864-1211
(A Mississippi Corporation)
2992 West Beach Boulevard
Gulfport, Mississippi 39501
(228) 864-1211
| | 64-0205820 | | | | | | | | | | | | | | | | | | |
| 001-37803 | | | |
001-37803 | | Southern Power Company | | 58-2598670 | |
(A Delaware Corporation)
30 Ivan Allen Jr. Boulevard, N.W.
Atlanta, Georgia 30308
(404) 506-5000
(A Delaware Corporation)
30 Ivan Allen Jr. Boulevard, N.W.
Atlanta, Georgia 30308
(404) 506-5000
| | 58-2598670 | | | | | | | | | | | | | | | | | | |
| 1-14174 | | | |
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, Georgia 30309
(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 2017B 5.25% Junior Subordinated Notes due 2077 | SOJC | NYSE |
| The Southern Company | 2019 Series A Corporate Units | SOLN | NYSE |
| The Southern Company | Series 2020A 4.95% Junior Subordinated Notes due 2080 | SOJD | NYSE |
| The Southern Company | Series 2020C 4.20% Junior Subordinated Notes due 2060 | SOJE | NYSE |
| The Southern Company | Series 2021B 1.875% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2081 | SO 81 | 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 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. Yes þ No ¨
Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files). Yes þ No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
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| Registrant | Large Accelerated Filer | Large
Accelerated
Filer
| Non-accelerated Filer | Accelerated
Filer
Smaller
Reporting
Company | | Non-
accelerated
Filer
| | Smaller
Reporting
Emerging
Growth
Company | | Emerging
Growth
Company
|
| The Southern Company | X | X | | | | | | | | |
| Alabama Power Company | | | X | | | X | | | | |
| Georgia Power Company | | | X | | | X | | | | |
Gulf Power Company | | | | | | X | | | | |
| Mississippi Power Company | | | X | | | X | | | | |
| Southern Power Company | | | X | | | X | | | | |
| Southern Company Gas | | | X | | | 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 | Description of
Common Stock
| | Shares Outstanding at September 30, 2017 |
2022 |
| The Southern Company | | Par Value $5 Per Share | 1,088,672,828 | 1,003,627,691 |
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| Alabama Power Company | | Par Value $40 Per Share | 30,537,500 | 30,537,500 |
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| Georgia Power Company | | Without Par Value | 9,261,500 | 9,261,500 |
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GulfMississippi Power Company | | Without Par Value | 1,121,000 | 7,392,717 |
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Mississippi Power Company | | Without Par Value | | 1,121,000 |
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| Southern Power Company | | Par Value $0.01 Per Share | 1,000 | 1,000 |
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| Southern Company Gas | | Par Value $0.01 Per Share | 100 | 100 |
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This combined Form 10-Q is separately filed by The Southern Company, Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, Southern Power Company, and Southern Company Gas. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.
INDEX TO QUARTERLY REPORT ON FORM 10-Q
September 30, 2017
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| PART I—FINANCIAL INFORMATION | |
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| Item 1. | | |
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| Item 2. | |
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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
September 30, 2017
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| PART I—FINANCIAL INFORMATION (CONTINUED) | |
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Item 3. | | |
| Item 4. | | |
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| PART II—OTHER INFORMATION | |
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| Item 1. | | |
| Item 1A. | | |
| Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds | Inapplicable |
| Item 3. | Defaults Upon Senior Securities | Inapplicable |
| Item 4. | Mine Safety Disclosures | Inapplicable |
| Item 5. | Other Information | Inapplicable |
| Item 6. | | |
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| Term | Meaning |
| 2019 ARP | |
2012 MPSC CPCN Order | A detailed order issued by the Mississippi PSC in April 2012 confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC |
2013 ARP | AlternativeAlternate Rate Plan approved by the Georgia PSC in 20132019 for Georgia Power for the years 20142020 through 2016 and subsequently extended through 20192022 |
| AFUDC | Allowance for funds used during construction |
| Alabama Power | Alabama Power Company |
ASC | Accounting Standards Codification |
ASU | Accounting Standards Update |
Atlanta Gas Light | Atlanta Gas Light Company, a wholly-owned subsidiary of Southern Company Gas |
Atlantic Coast Pipeline | Atlantic Coast Pipeline, LLC, a joint venture to constructAmended and operate a natural gas pipeline in which Southern Company Gas has a 5% ownership interest |
Baseload Act | State of Mississippi legislation designed to enhance the Mississippi PSC's authority to facilitate development and construction of baseload generation in the State of Mississippi |
CCR | Coal combustion residuals |
Clean Power Plan | Final action published by the EPA in 2015 that established guidelines for states to develop plans to meet EPA-mandated CO2 emission rates or emission reduction goals for existing electric generating units
|
CO2
| Carbon dioxide |
COD | Commercial operation date |
Contractor Settlement Agreement | The December 31, 2015 agreement between Westinghouse and the Vogtle Owners resolving disputes between the Vogtle Owners and the EPC Contractor under the Vogtle 3 and 4 Agreement |
Cooperative Energy | Electric cooperative in Mississippi formerly known as South Mississippi Electric Power Association (SMEPA) |
CPCN | Certificate of public convenience and necessity |
CWIP | Construction work in progress |
Dalton Pipeline | A 50% undivided ownership interest of Southern Company Gas in a pipeline facility in Georgia |
DOE | U.S. Department of Energy |
ECO Plan | Mississippi Power's Environmental Compliance Overview Plan |
Eligible Project Costs | Certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Title XVII Loan Guarantee Program |
EPA | U.S. Environmental Protection Agency |
EPC Contractor | Westinghouse and its affiliate, WECTEC (formerly known as CB&I Stone & Webster, Inc.), formerly a subsidiary of The Shaw Group Inc. and Chicago Bridge & Iron Company N.V.; the former engineering, procurement, and construction contractor for Plant Vogtle Units 3 and 4 |
FASB | Financial Accounting Standards Board |
FERC | Federal Energy Regulatory Commission |
FFB | Federal Financing Bank |
Fitch | Fitch Ratings, Inc. |
Form 10-K | Annual Report on Form 10-K of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas for the year ended December 31, 2016, as applicable |
GAAP | U.S. generally accepted accounting principles |
Georgia Power | Georgia Power Company |
Gulf Power | Gulf Power Company |
Heating Degree Days | A measure of weather, calculated when the average daily temperatures are less than 65 degrees Fahrenheit |
Horizon Pipeline | Horizon Pipeline Company, LLC |
DEFINITIONS
(continued)
|
| |
Term | Meaning |
| |
IGCC | Integrated coal gasification combined cycle |
IIC | Intercompany interchange contract |
Illinois Commission | Illinois Commerce Commission, the state regulatory agency for Nicor Gas |
IRC | Internal Revenue Code of 1986, as amended |
IRS | Internal Revenue Service |
ITC | Investment tax credit |
Kemper IGCC | Mississippi Power's IGCC project in Kemper County, Mississippi |
KWH | Kilowatt-hour |
LIBOR | London Interbank Offered Rate |
LIFO | Last-in, first-out |
LNG | Liquefied natural gas |
| Restated Loan Guarantee Agreement | Loan guarantee agreement entered into by Georgia Power with the DOE in 2014, as amended and restated in March 2019, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4 |
LOCOMARO | Asset retirement obligation |
| Atlanta Gas Light | Atlanta Gas Light Company, a wholly-owned subsidiary of Southern Company Gas |
| Bechtel | Bechtel Power Corporation, the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4 |
| Bechtel Agreement | The 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 Air Act | Clean Air Act Amendments of 1990 |
| 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 |
| COVID-19 | The novel coronavirus disease declared a pandemic by the World Health Organization and the Centers for Disease Control and Prevention in March 2020 |
| CWIP | Construction work in progress |
| Dalton | City of Dalton, Georgia, an incorporated municipality in the State of Georgia, acting by and through its Board of Water, Light, and Sinking Fund Commissioners |
| Dalton Pipeline | A pipeline facility in Georgia in which Southern Company Gas has a 50% undivided ownership interest |
| DOE | U.S. Department of Energy |
| ECCR | Georgia Power's Environmental Compliance Cost Recovery tariff |
| 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 |
| FERC | Federal Energy Regulatory Commission |
| FFB | Federal Financing Bank |
| Fitch | Fitch Ratings, Inc. |
| Form 10-K | Annual Report on Form 10-K of Southern Company, Alabama Power, Georgia Power, Mississippi Power, Southern Power, and Southern Company Gas for the year ended December 31, 2021, as applicable |
| GAAP | U.S. generally accepted accounting principles |
| Georgia Power | Georgia Power Company |
| GRAM | Atlanta Gas Light's Georgia Rate Adjustment Mechanism |
| Guarantee Settlement Agreement | The June 9, 2017 settlement agreement between the Vogtle Owners and Toshiba related to certain payment obligations of the EPC Contractor guaranteed by Toshiba |
| Gulf Power | Gulf Power Company, until January 1, 2019 a wholly-owned subsidiary of Southern Company; effective January 1, 2021, Gulf Power Company merged with and into Florida Power and Light Company, with Florida Power and Light Company remaining as the surviving company |
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| Term | Meaning |
| Heating Degree Days | A measure of weather, calculated when the average daily temperatures are less than 65 degrees Fahrenheit |
| Heating Season | The period from November through March when Southern Company Gas' 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 |
| IIC | Intercompany Interchange Contract |
| IRP | Integrated resource plan |
| ITAAC | Inspections, Tests, Analyses, and Acceptance Criteria, standards established by the NRC |
| ITC | Investment tax credit |
| JEA | Jacksonville Electric Authority |
| KWH | Kilowatt-hour |
| LIBOR | London Interbank Offered Rate |
| LIFO | Last-in, first-out |
| LOCOM | Lower of weighted average cost or current market price |
| LTSA | Long-term service agreement |
MATS ruleMEAG Power | Mercury and Air Toxics Standards ruleMunicipal 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 |
Mirror CWIP | A regulatory liability used by Mississippi Power to record customer refunds resulting from a 2015 Mississippi PSC order |
Mississippi Power | Mississippi Power Company |
| mmBtu | Million British thermal units |
| Moody's | Moody's Investors Service, Inc. |
| MRA | Municipal and Rural Associations |
| MW | Megawatt |
| natural gas distribution utilities | Southern Company Gas' seven natural gas distribution utilities (Nicor Gas, Atlanta Gas Light, Virginia Natural Gas, Elizabethtown Gas, Florida City Gas,and Chattanooga Gas Company, and Elkton Gas) |
| NCCR | Georgia Power's Nuclear Construction Cost Recovery tariff |
New Jersey BPUNDR | New Jersey Board of Public Utilities, the state regulatory agency for Elizabethtown GasAlabama Power's Natural Disaster Reserve |
| Nicor Gas | Northern Illinois Gas Company, a wholly-owned subsidiary of Southern Company Gas |
NRCN/M | Not meaningful |
| NRC | U.S. Nuclear Regulatory Commission |
| NYMEX | New York Mercantile Exchange, Inc. |
| OCI | Other comprehensive income |
| OPC | Oglethorpe Power Corporation (an electric membership corporation) |
| 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 |
PiedmontPowerSecure | Piedmont Natural Gas Company, Inc. |
Pivotal Utility Holdings | Pivotal Utility Holdings,PowerSecure, Inc., a wholly-owned subsidiary of Southern Company |
| PPA | Power purchase agreements, as well as, for Southern Power, contracts for differences that provide the owner of a renewable facility a certain fixed price for the electricity sold to the grid |
| PSC | Public Service Commission |
| PTC | Production tax credit |
| Rate CNP | Alabama Power's Rate Certificated New Plant, consisting of Rate CNP New Plant, Rate CNP Compliance, and Rate CNP PPA |
| 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 |
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| Term | Meaning |
| Registrants | Southern Company, Alabama Power, Georgia Power, Mississippi Power, Southern Power Company, and Southern Company Gas doing business as Elizabethtown |
| ROE | Return on equity |
| S&P | S&P Global Ratings, a division of S&P Global Inc. |
| SAVE | Steps to Advance Virginia's Energy, an infrastructure replacement program at Virginia Natural Gas Elkton |
| SCS | Southern Company Services, Inc., the Southern Company system service company and a wholly-owned subsidiary of Southern Company |
| SEC | U.S. Securities and Exchange Commission |
| SEGCO | Southern Electric Generating Company, 50% owned by each of Alabama Power and Georgia Power |
| Sequent | Sequent Energy Management, L.P. and Sequent Energy Canada Corp., wholly-owned subsidiaries of Southern Company Gas through June 30, 2021 |
| SNG | Southern Natural Gas Company, L.L.C., a pipeline system in which Southern Company Gas has a 50% ownership interest |
| SOFR | Secured Overnight Financing Rate |
| Southern Company | The Southern Company |
| Southern Company Gas | Southern Company Gas and Florida City Gasits subsidiaries |
Plant Vogtle Units 3 and 4Southern Company Gas Capital | Two new nuclear generating units under construction at Georgia Power's Plant VogtleSouthern Company Gas Capital Corporation, a 100%-owned subsidiary of Southern Company Gas |
PowerSecure | PowerSecure, Inc. |
| Southern Company power pool | The operating arrangement whereby the integrated generating resources of the traditional electric operating companies and Southern Power (excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations |
DEFINITIONS
(continued)
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Term | Meaning |
| |
PPA | Power purchase agreements, as well as, for Southern Power, contracts for differences that provide the owner of a renewable facility a certain fixed price for the electricity sold to the grid |
PSC | Public Service Commission |
PTC | Production tax credit |
Rate CNP | Alabama Power's Rate Certificated New Plant |
Rate CNP Compliance | Alabama Power's Rate Certificated New Plant Compliance |
Rate CNP PPA | Alabama Power's Rate Certificated New Plant Power Purchase Agreement |
Rate ECR | Alabama Power's Rate Energy Cost Recovery |
Rate NDR | Alabama Power's Rate Natural Disaster Reserve |
Rate RSE | Alabama Power's Rate Stabilization and Equalization plan |
registrants | Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power Company, and Southern Company Gas |
ROE | Return on equity |
S&P | S&P Global Ratings, a division of S&P Global Inc. |
scrubber | Flue gas desulfurization system |
SCS | Southern Company Services, Inc. (the Southern Company system service company) |
SEC | U.S. Securities and Exchange Commission |
SNG | Southern Natural Gas Company, L.L.C. |
Southern Company | The Southern Company |
Southern Company Gas | Southern Company Gas and its subsidiaries |
Southern Company Gas Capital | Southern Company Gas Capital Corporation, a 100%-owned subsidiary of Southern Company Gas |
Southern Company system | Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas, (as of July 1, 2016), Southern Electric Generating Company,SEGCO, Southern Nuclear, SCS, Southern Communications Services, Inc., PowerSecure, (as of May 9, 2016), and other subsidiaries |
| Southern Holdings | Southern Company Holdings, Inc., a wholly-owned subsidiary of Southern Company |
| Southern Nuclear | Southern Nuclear Operating Company, Inc., a wholly-owned subsidiary of Southern Company |
| Southern Power | Southern Power Company and its subsidiaries |
| SouthStar | SouthStar Energy Services, LLC (a Marketer), a wholly-owned subsidiary of Southern Company Gas |
STRIDESP Solar | Atlanta Gas Light's Strategic Infrastructure DevelopmentSP Solar Holdings I, LP, a limited partnership indirectly owning substantially all of Southern Power's solar and Enhancement programbattery energy storage facilities, in which Southern Power has a 67% ownership interest |
ToshibaSP Wind | Toshiba Corporation, parentSP Wind Holdings II, LLC, a holding company owning a portfolio of Westinghouseeight operating wind facilities, in which Southern Power is the controlling partner in a tax equity arrangement |
Toshiba GuaranteeSubsidiary Registrants | Certain payment obligations of the EPC Contractor guaranteed by Toshiba |
traditional electric operating companies | Alabama Power, Georgia Power, GulfMississippi Power, Southern Power, and Southern Company Gas |
| Toshiba | Toshiba Corporation, the parent company of Westinghouse |
| traditional electric operating companies | Alabama Power, Georgia Power, and Mississippi Power |
TritonVCM | Triton Container Investments, LLCVogtle Construction Monitoring |
| VIE | Variable interest entity |
| Virginia Commission | Virginia State Corporation Commission the state regulatory agency for |
| Virginia Natural Gas |
Virginia Natural Gas | Virginia Natural Gas, Inc., a wholly-owned subsidiary of Southern Company Gas |
| 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, OglethorpeOPC, MEAG Power, Corporation,and Dalton |
| | | | | |
| Term | Meaning |
| Vogtle Services Agreement | The June 2017 services agreement between the Municipal Electric Authority of Georgia,Vogtle Owners and the CityEPC Contractor, as amended and restated in July 2017, for the EPC Contractor to transition construction management of Dalton, Georgia, an incorporated municipality in the State of Georgia acting byPlant Vogtle Units 3 and through its Board of Water, Light,4 to Southern Nuclear and Sinking Fund Commissionersto provide ongoing design, engineering, and procurement services to Southern Nuclear |
| WACOG | Weighted average cost of gas |
WECTECWestinghouse | WECTEC Global Project Services Inc. |
Westinghouse | Westinghouse Electric Company LLC |
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This Quarterly Report on Form 10-Q contains forward-looking statements. Forward-looking statements include, among other things, statements concerning regulated rates, the strategic goals for the wholesale business, customer and sales growth, economic conditions, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, accessTable of ContentsIndex to sources of capital, financing activities, completion dates of construction projects, completion of announced acquisitions or dispositions, filings with state and federal regulatory authorities, federal income tax benefits, estimated sales and purchases under power sale and purchase agreements, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:Financial Statements
the impact of recent and future federal and state regulatory changes, including environmental laws regulating emissions, discharges, and disposal to air, water, and land, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, including potential tax reform legislation, as well as changes in application of existing laws and regulations;
current and future litigation, regulatory investigations, proceedings, or inquiries;
the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company's subsidiaries operate;
variations in demand for electricity and natural gas, including those relating to weather, the general economy and recovery from the last recession, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;
available sources and costs of natural gas and other fuels;
limits on pipeline capacity;
effects of inflation;
the ability to control costs and avoid cost overruns during the development, construction, and operation of facilities, which include the development and construction of generating facilities with designs that have not been finalized or previously constructed, including changes in labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by any PSC);
the impact of any inability or other failure of Toshiba to perform its obligations under the Toshiba Guarantee, including any effect on the construction of Plant Vogtle Units 3 and 4;
the ability to construct facilities in accordance with the requirements of permits and licenses, to satisfy any environmental performance standards and the requirements of tax credits and other incentives, and to integrate facilities into the Southern Company system upon completion of construction;
investment performance of the Southern Company system's employee and retiree benefit plans and nuclear decommissioning trust funds;
advances in technology;
ongoing renewable energy partnerships and development agreements;
state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;
legal proceedings and regulatory approvals and actions related to Plant Vogtle Units 3 and 4, including Georgia PSC approvals and NRC actions;
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This Quarterly Report on Form 10-Q contains forward-looking statements. Forward-looking statements include, among other things, statements concerning the potential and expected effects of the continued COVID-19 pandemic, regulated rates, the strategic goals for the business, customer and sales growth, economic conditions, cost recovery and other rate actions, projected equity ratios, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, financing activities, completion dates and costs of construction projects, matters related to the abandonment of the Kemper IGCC, completion of announced 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, environmental, and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;
•the potential effects of the continued COVID-19 pandemic, including, but not limited to, those described in Item 1A "Risk Factors" of the Form 10-K;
•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 and Plant Vogtle Units 3 and 4;
•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 and commodities;
•the ability to complete necessary or desirable pipeline expansion or infrastructure projects, limits on pipeline capacity, and operational interruptions to natural gas distribution and transmission activities;
•transmission constraints;
•effects of inflation;
•the ability to control costs and avoid cost and schedule overruns during the development, construction, and operation of facilities or other projects, including Plant Vogtle Units 3 and 4 (which includes components based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale) and Plant Barry Unit 8, due to current and/or future challenges which include, but are not limited to, changes in labor costs, availability, and productivity; challenges with management of contractors or vendors; subcontractor performance; adverse weather conditions; shortages, delays, increased costs, or inconsistent quality of equipment, materials, and labor; contractor or supplier delay; delays due to judicial or regulatory action; nonperformance under construction, operating, or other agreements; operational readiness, including specialized operator training and required site safety programs; engineering or design problems or any remediation related thereto; design and other licensing-based compliance matters, including, for Plant Vogtle Unit 4, inspections and the timely submittal by Southern Nuclear of the ITAAC documentation and the related investigations, reviews, and approvals by the NRC necessary to support NRC authorization to load fuel; challenges with start-up activities, including major equipment failure, or system integration; and/or operational performance; and challenges related to the COVID-19 pandemic;
•the ability to overcome or mitigate the current challenges at Plant Vogtle Units 3 and 4, as described in Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" in Item 1 herein, that could further impact the cost and schedule for the project;
•legal proceedings and regulatory approvals and actions related to construction projects, such as Plant Vogtle Units 3 and 4 and Plant Barry Unit 8, including PSC approvals and FERC and NRC actions;
•under certain specified circumstances, a decision by holders of more than 10% of the ownership interests of Plant Vogtle Units 3 and 4 not to proceed with construction;
•the ability of certain other Vogtle Owners to tender a portion of their ownership interests to Georgia Power following certain construction cost increases, including the purported exercises by OPC and Dalton of their tender options and related litigation;
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
(continued)
•in the event Georgia Power becomes obligated to provide funding to MEAG Power with respect to the portion of MEAG Power's ownership interest in Plant Vogtle Units 3 and 4 involving JEA, any inability of Georgia Power to receive repayment of such funding;
•the ability to construct facilities in accordance with the requirements of permits and licenses (including satisfaction of NRC requirements), to satisfy any environmental performance standards and the requirements of tax credits and other incentives, and to integrate facilities into the Southern Company system upon completion of construction;
•investment performance of the employee and retiree benefit plans and nuclear decommissioning trust funds;
•advances in technology, including the pace and extent of development of low- to no-carbon energy and battery energy storage technologies and negative carbon concepts;
•performance of counterparties under ongoing renewable energy partnerships and development agreements;
•state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relatedrelating to ROE, equity ratios, additional generating capacity, and fuel and other cost recovery for the Kemper IGCC, including ongoing settlement discussions, Mississippi PSC review of the prudence of Kemper IGCC costs and approval of further permanent rate recovery plans, and related legal or regulatory proceedings;mechanisms;
•the ability to successfully operate the traditional electric utilities' generating,operating companies' and SEGCO's generation, transmission, and distribution facilities, Southern Power's generation facilities, and Southern Company Gas' natural gas distribution and storage facilities and the successful performance of necessary corporate functions;
•the inherent risks involved in operating and constructing nuclear generating facilities, including environmental, health, regulatory, natural disaster, terrorism, and financial risks;facilities;
•the inherent risks involved in transporting and storing natural gas;
•the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities;
•internal restructuring or other restructuring options that may be pursued;
•potential business strategies, including acquisitions or dispositions of assets or businesses, including the proposed disposition by a wholly-owned subsidiary of Southern Company Gas of Elizabethtown Gas and Elkton Gas, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries;
the possibility that the anticipated benefits from the Merger cannot be fully realized or may take longer to realize than expected, the possibility that costs related to the integration of Southern Company and Southern Company Gas will be greater than expected, the ability to retain and hire key personnel and maintain relationships with customers, suppliers, or other business partners, and the diversion of management time on integration-related issues;
•the ability of counterparties of Southern Company and its subsidiaries to make payments as and when due and to perform as required;
•the ability to obtain new short- and long-term contracts with wholesale customers;
•the direct or indirect effect on the Southern Company system's business resulting from cyber intrusion or terrorist incidentsphysical attack and the threat of terrorist incidents;physical attacks;
•interest rate fluctuations and financial market conditions and the results of financing efforts;
•access to capital markets and other financing sources;
•changes in Southern Company's and any of its subsidiaries' credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;ratings;
•the impactsreplacement 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;LIBOR with an alternative reference rate;
•the ability of Southern Company'sthe traditional electric utilitiesoperating companies 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,political unrest, wars, or other similar occurrences;
•the direct or indirect effects on the Southern Company system's business resulting from incidents affecting the U.S. electric grid, natural gas pipeline infrastructure, or operation of generating or storage resources;
•impairments of goodwill or long-lived assets;
•the effect of accounting pronouncements issued periodically by standard-setting bodies; and
•other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the registrantsRegistrants from time to time with the SEC.
The registrantsRegistrants expressly disclaim any obligation to update any forward-looking statements.
THE SOUTHERN COMPANYPART I
AND SUBSIDIARY COMPANIES
Item 1. Financial Statements (Unaudited).
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
| | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) | | (in millions) | | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | | Operating Revenues: | |
| Retail electric revenues | $ | 4,615 |
| | $ | 4,808 |
| | $ | 11,786 |
| | $ | 11,932 |
| Retail electric revenues | $ | 5,961 | | | $ | 4,551 | | | $ | 14,363 | | | $ | 11,492 | |
| Wholesale electric revenues | 718 |
| | 613 |
| | 1,867 |
| | 1,455 |
| Wholesale electric revenues | 1,197 | | | 731 | | | 2,798 | | | 1,822 | |
| Other electric revenues | 168 |
| | 181 |
| | 510 |
| | 529 |
| Other electric revenues | 185 | | | 179 | | | 554 | | | 525 | |
| Natural gas revenues | 532 |
| | 518 |
| | 2,746 |
| | 518 |
| |
Natural gas revenues (includes alternative revenue programs of $(1), $(1), $—, and $3, respectively) | | Natural gas revenues (includes alternative revenue programs of $(1), $(1), $—, and $3, respectively) | 857 | | | 623 | | | 3,998 | | | 2,994 | |
| Other revenues | 168 |
| | 144 |
| | 494 |
| | 281 |
| Other revenues | 178 | | | 154 | | | 519 | | | 513 | |
| Total operating revenues | 6,201 |
| | 6,264 |
| | 17,403 |
| | 14,715 |
| Total operating revenues | 8,378 | | | 6,238 | | | 22,232 | | | 17,346 | |
| Operating Expenses: | | | | | | | | Operating Expenses: | | | | | | | |
| Fuel | 1,285 |
| | 1,400 |
| | 3,372 |
| | 3,334 |
| Fuel | 2,423 | | | 1,234 | | | 5,249 | | | 2,930 | |
| Purchased power | 256 |
| | 227 |
| | 646 |
| | 581 |
| Purchased power | 645 | | | 288 | | | 1,285 | | | 712 | |
| Cost of natural gas | 134 |
| | 133 |
| | 1,085 |
| | 133 |
| Cost of natural gas | 294 | | | 129 | | | 1,840 | | | 943 | |
| Cost of other sales | 90 |
| | 84 |
| | 293 |
| | 161 |
| Cost of other sales | 92 | | | 71 | | | 275 | | | 255 | |
| Other operations and maintenance | 1,287 |
| | 1,411 |
| | 3,918 |
| | 3,616 |
| Other operations and maintenance | 1,547 | | | 1,446 | | | 4,621 | | | 4,257 | |
| Depreciation and amortization | 767 |
| | 695 |
| | 2,236 |
| | 1,805 |
| Depreciation and amortization | 922 | | | 896 | | | 2,728 | | | 2,658 | |
| Taxes other than income taxes | 303 |
| | 309 |
| | 941 |
| | 821 |
| Taxes other than income taxes | 352 | | | 312 | | | 1,073 | | | 969 | |
| Estimated loss on Kemper IGCC | 34 |
| | 88 |
| | 3,155 |
| | 222 |
| |
| Estimated loss on Plant Vogtle Units 3 and 4 | | Estimated loss on Plant Vogtle Units 3 and 4 | (70) | | | 264 | | | (18) | | | 772 | |
| | Gain on dispositions, net | | Gain on dispositions, net | (20) | | | (125) | | | (53) | | | (179) | |
| Total operating expenses | 4,156 |
| | 4,347 |
| | 15,646 |
| | 10,673 |
| Total operating expenses | 6,185 | | | 4,515 | | | 17,000 | | | 13,317 | |
| Operating Income | 2,045 |
| | 1,917 |
| | 1,757 |
| | 4,042 |
| Operating Income | 2,193 | | | 1,723 | | | 5,232 | | | 4,029 | |
| Other Income and (Expense): | | | | | | | | Other Income and (Expense): | |
| Allowance for equity funds used during construction | 18 |
| | 52 |
| | 133 |
| | 150 |
| Allowance for equity funds used during construction | 59 | | | 49 | | | 163 | | | 140 | |
| Earnings from equity method investments | 32 |
| | 29 |
| | 100 |
| | 28 |
| Earnings from equity method investments | 28 | | | 30 | | | 109 | | | 35 | |
| Interest expense, net of amounts capitalized | (407 | ) | | (374 | ) | | (1,248 | ) | | (913 | ) | Interest expense, net of amounts capitalized | (511) | | | (451) | | | (1,461) | | | (1,352) | |
| | Other income (expense), net | 11 |
| | (8 | ) | | 2 |
| | (66 | ) | Other income (expense), net | 132 | | | 131 | | | 414 | | | 290 | |
| Total other income and (expense) | (346 | ) | | (301 | ) | | (1,013 | ) | | (801 | ) | Total other income and (expense) | (292) | | | (241) | | | (775) | | | (887) | |
| Earnings Before Income Taxes | 1,699 |
| | 1,616 |
| | 744 |
| | 3,241 |
| Earnings Before Income Taxes | 1,901 | | | 1,482 | | | 4,457 | | | 3,142 | |
| Income taxes | 590 |
| | 439 |
| | 317 |
| | 917 |
| Income taxes | 414 | | | 372 | | | 891 | | | 550 | |
| Consolidated Net Income | 1,109 |
| | 1,177 |
| | 427 |
| | 2,324 |
| Consolidated Net Income | 1,487 | | | 1,110 | | | 3,566 | | | 2,592 | |
| Less: | | | | | | | | |
| Dividends on preferred and preference stock of subsidiaries | 10 |
| | 11 |
| | 32 |
| | 34 |
| |
| Net income attributable to noncontrolling interests | 30 |
| | 27 |
| | 48 |
| | 39 |
| |
| | Dividends on preferred stock of subsidiaries | | Dividends on preferred stock of subsidiaries | 3 | | | 4 | | | 10 | | | 11 | |
| Net income (loss) attributable to noncontrolling interests | | Net income (loss) attributable to noncontrolling interests | 12 | | | 5 | | | (55) | | | (27) | |
Consolidated Net Income Attributable to Southern Company | $ | 1,069 |
| | $ | 1,139 |
| | $ | 347 |
| | $ | 2,251 |
| Consolidated Net Income Attributable to
Southern Company | $ | 1,472 | | | $ | 1,101 | | | $ | 3,611 | | | $ | 2,608 | |
| Common Stock Data: | | | | | | | | Common Stock Data: | | | | | | | |
| Earnings per share — | | | | | | | | |
| Earnings per share - | | Earnings per share - | |
| Basic | $ | 1.07 |
| | $ | 1.18 |
| | $ | 0.35 |
| | $ | 2.40 |
| Basic | $ | 1.36 | | | $ | 1.04 | | | $ | 3.38 | | | $ | 2.46 | |
| Diluted | $ | 1.06 |
| | $ | 1.17 |
| | $ | 0.35 |
| | $ | 2.38 |
| Diluted | $ | 1.35 | | | $ | 1.03 | | | $ | 3.36 | | | $ | 2.44 | |
| Average number of shares of common stock outstanding (in millions) | | | | | | | | Average number of shares of common stock outstanding (in millions) | |
| Basic | 1,003 |
| | 968 |
| | 998 |
| | 940 |
| Basic | 1,082 | | | 1,061 | | | 1,070 | | | 1,060 | |
| Diluted | 1,010 |
| | 975 |
| | 1,005 |
| | 945 |
| Diluted | 1,088 | | | 1,068 | | | 1,076 | | | 1,067 | |
| Cash dividends paid per share of common stock | $ | 0.5800 |
| | $ | 0.5600 |
| | $ | 1.7200 |
| | $ | 1.6625 |
| |
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) |
| Consolidated Net Income | $ | 1,109 |
| | $ | 1,177 |
| | $ | 427 |
| | $ | 2,324 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
Changes in fair value, net of tax of $15, $12, $32, and $(74),
respectively | 25 |
| | 19 |
| | 54 |
| | (118 | ) |
Reclassification adjustment for amounts included in net income,
net of tax of $(10), $2, $(36), and $13, respectively | (17 | ) | | 2 |
| | (59 | ) | | 20 |
|
| Pension and other postretirement benefit plans: | | | | | | | |
Reclassification adjustment for amounts included in net income,
net of tax of $1, $1, $2, and $2, respectively | 1 |
| | 1 |
| | 3 |
| | 3 |
|
| Total other comprehensive income (loss) | 9 |
| | 22 |
| | (2 | ) | | (95 | ) |
| Comprehensive Income | 1,118 |
| | 1,199 |
| | 425 |
| | 2,229 |
|
| Less: | | | | | | | |
| Dividends on preferred and preference stock of subsidiaries | 10 |
| | 11 |
| | 32 |
| | 34 |
|
| Comprehensive income attributable to noncontrolling interests | 30 |
| | 27 |
| | 48 |
| | 39 |
|
Consolidated Comprehensive Income Attributable to Southern Company | $ | 1,078 |
| | $ | 1,161 |
| | $ | 345 |
| | $ | 2,156 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
| Consolidated Net Income | $ | 1,487 | | | $ | 1,110 | | | $ | 3,566 | | | $ | 2,592 | |
| Other comprehensive income: | | | | | | | |
| Qualifying hedges: | | | | | | | |
Changes in fair value, net of tax of $2, $1, $(5), and $(4), respectively | — | | | 1 | | | (27) | | | (15) | |
Reclassification adjustment for amounts included in net income, net of tax of $8, $10, $32, and $27, respectively | 26 | | | 31 | | | 100 | | | 81 | |
| Pension and other postretirement benefit plans: | | | | | | | |
| | | | | | | |
Reclassification adjustment for amounts included in net income, net of tax of $1, $1, $3, and $4, respectively | 2 | | | 4 | | | 8 | | | 10 | |
| Total other comprehensive income | 28 | | | 36 | | | 81 | | | 76 | |
| Comprehensive Income | 1,515 | | | 1,146 | | | 3,647 | | | 2,668 | |
| | | | | | | |
| Dividends on preferred stock of subsidiaries | 3 | | | 4 | | | 10 | | | 11 | |
| Comprehensive income (loss) attributable to noncontrolling interests | 12 | | | 5 | | | (55) | | | (27) | |
Consolidated Comprehensive Income Attributable to
Southern Company | $ | 1,500 | | | $ | 1,137 | | | $ | 3,692 | | | $ | 2,684 | |
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
| | | | For the Nine Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
| Operating Activities: | | | | Operating Activities: | |
| Consolidated net income | $ | 427 |
| | $ | 2,324 |
| Consolidated net income | $ | 3,566 | | | $ | 2,592 | |
| Adjustments to reconcile consolidated net income to net cash provided from operating activities — | | | | Adjustments to reconcile consolidated net income to net cash provided from operating activities — | |
| Depreciation and amortization, total | 2,564 |
| | 2,109 |
| Depreciation and amortization, total | 3,084 | | | 2,944 | |
| Deferred income taxes | 15 |
| | (22 | ) | Deferred income taxes | 608 | | | 89 | |
| Utilization of federal investment tax credits | | Utilization of federal investment tax credits | 266 | | | 256 | |
| Allowance for equity funds used during construction | (133 | ) | | (150 | ) | Allowance for equity funds used during construction | (163) | | | (140) | |
| Mark-to-market adjustments | | Mark-to-market adjustments | (33) | | | 147 | |
| Pension, postretirement, and other employee benefits | (64 | ) | | (158 | ) | Pension, postretirement, and other employee benefits | (322) | | | (218) | |
| Settlement of asset retirement obligations | (137 | ) | | (117 | ) | Settlement of asset retirement obligations | (314) | | | (341) | |
| Hedge settlements | — |
| | (236 | ) | |
| Estimated loss on Kemper IGCC | 3,148 |
| | 222 |
| |
| Stock based compensation expense | | Stock based compensation expense | 116 | | | 134 | |
| | Estimated loss on Plant Vogtle Units 3 and 4 | | Estimated loss on Plant Vogtle Units 3 and 4 | (18) | | | 772 | |
| | Storm damage accruals | | Storm damage accruals | 160 | | | 166 | |
| | Gain on dispositions, net | | Gain on dispositions, net | (41) | | | (171) | |
| Natural gas cost under recovery – long-term | | Natural gas cost under recovery – long-term | 207 | | | (79) | |
| Retail fuel cost under recovery – long-term | | Retail fuel cost under recovery – long-term | (1,701) | | | (209) | |
| Other, net | (8 | ) | | (1 | ) | Other, net | (45) | | | 156 | |
| Changes in certain current assets and liabilities — | | | | Changes in certain current assets and liabilities — | |
| -Receivables | 426 |
| | (458 | ) | -Receivables | (327) | | | 2 | |
| -Fossil fuel for generation | 59 |
| | 204 |
| |
| | -Materials and supplies | | -Materials and supplies | (138) | | | (91) | |
| -Natural gas for sale, net of temporary LIFO liquidation | — |
| | (222 | ) | -Natural gas for sale, net of temporary LIFO liquidation | (136) | | | 20 | |
| -Natural gas cost under recovery | | -Natural gas cost under recovery | (124) | | | (432) | |
| -Other current assets | (164 | ) | | (112 | ) | -Other current assets | (343) | | | (180) | |
| -Accounts payable | (467 | ) | | (9 | ) | -Accounts payable | 805 | | | (45) | |
| -Accrued taxes | 157 |
| | 1,062 |
| -Accrued taxes | 167 | | | 288 | |
| -Accrued compensation | (230 | ) | | (122 | ) | -Accrued compensation | (123) | | | (93) | |
| -Accrued interest | | -Accrued interest | (101) | | | (110) | |
| -Retail fuel cost over recovery | (211 | ) | | (106 | ) | -Retail fuel cost over recovery | (1) | | | (150) | |
| | -Other current liabilities | (129 | ) | | 88 |
| -Other current liabilities | (32) | | | (226) | |
| Net cash provided from operating activities | 5,253 |
| | 4,296 |
| Net cash provided from operating activities | 5,017 | | | 5,081 | |
| Investing Activities: | | | | Investing Activities: | | | |
| Business acquisitions, net of cash acquired | (1,032 | ) | | (9,513 | ) | Business acquisitions, net of cash acquired | — | | | (345) | |
| | Property additions | (5,242 | ) | | (5,252 | ) | Property additions | (5,502) | | | (5,222) | |
| Investment in restricted cash | (16 | ) | | (750 | ) | |
| Distribution of restricted cash | 33 |
| | 746 |
| |
| | Nuclear decommissioning trust fund purchases | (585 | ) | | (838 | ) | Nuclear decommissioning trust fund purchases | (858) | | | (1,301) | |
| Nuclear decommissioning trust fund sales | 580 |
| | 832 |
| Nuclear decommissioning trust fund sales | 854 | | | 1,297 | |
| Proceeds from dispositions | | Proceeds from dispositions | 120 | | | 160 | |
| Cost of removal, net of salvage | (208 | ) | | (155 | ) | Cost of removal, net of salvage | (518) | | | (282) | |
| Change in construction payables, net | 120 |
| | (259 | ) | |
| Investment in unconsolidated subsidiaries | (134 | ) | | (1,421 | ) | |
| | Payments pursuant to LTSAs | (189 | ) | | (125 | ) | Payments pursuant to LTSAs | (121) | | | (145) | |
| Other investing activities | (14 | ) | | 95 |
| Other investing activities | 73 | | | (12) | |
| Net cash used for investing activities | (6,687 | ) | | (16,640 | ) | Net cash used for investing activities | (5,952) | | | (5,850) | |
| Financing Activities: | | | | Financing Activities: | | | |
| Increase (decrease) in notes payable, net | (515 | ) | | 655 |
| |
| Decrease in notes payable, net | | Decrease in notes payable, net | (349) | | | (203) | |
| Proceeds — | | | | Proceeds — | |
| Long-term debt | 4,068 |
| | 14,091 |
| Long-term debt | 3,800 | | | 6,793 | |
| | Short-term borrowings | | Short-term borrowings | 1,200 | | | 325 | |
| Common stock | 613 |
| | 3,265 |
| Common stock | 1,803 | | | 62 | |
| Preferred stock | 250 |
| | — |
| |
| Short-term borrowings | 1,263 |
| | — |
| |
| | Redemptions and repurchases — | | | | Redemptions and repurchases — | |
| Long-term debt | (1,981 | ) | | (2,405 | ) | Long-term debt | (1,932) | | | (3,060) | |
| Preferred and preference stock | (150 | ) | | — |
| |
| | Short-term borrowings | (409 | ) | | (475 | ) | Short-term borrowings | (900) | | | (25) | |
| Capital contributions from noncontrolling interests | | Capital contributions from noncontrolling interests | 73 | | | 415 | |
| Distributions to noncontrolling interests | (89 | ) | | (22 | ) | Distributions to noncontrolling interests | (175) | | | (204) | |
| Capital contributions from noncontrolling interests | 79 |
| | 367 |
| |
| Purchase of membership interests from noncontrolling interests | — |
| | (129 | ) | |
| | Payment of common stock dividends | (1,716 | ) | | (1,553 | ) | Payment of common stock dividends | (2,166) | | | (2,077) | |
| | Other financing activities | (113 | ) | | (185 | ) | Other financing activities | (235) | | | (224) | |
| Net cash provided from financing activities | 1,300 |
| | 13,609 |
| Net cash provided from financing activities | 1,119 | | | 1,802 | |
| Net Change in Cash and Cash Equivalents | (134 | ) | | 1,265 |
| |
| Cash and Cash Equivalents at Beginning of Period | 1,975 |
| | 1,404 |
| |
| Cash and Cash Equivalents at End of Period | $ | 1,841 |
| | $ | 2,669 |
| |
| Net Change in Cash, Cash Equivalents, and Restricted Cash | | Net Change in Cash, Cash Equivalents, and Restricted Cash | 184 | | | 1,033 | |
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | | Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 1,829 | | | 1,068 | |
| Cash, Cash Equivalents, and Restricted Cash at End of Period | | Cash, Cash Equivalents, and Restricted Cash at End of Period | $ | 2,013 | | | $ | 2,101 | |
| Supplemental Cash Flow Information: | | | | Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | | |
| Interest (net of $72 and $94 capitalized for 2017 and 2016, respectively) | $ | 1,286 |
| | $ | 766 |
| |
| Cash paid during the period for — | | Cash paid during the period for — | |
| Interest (net of $74 and $68 capitalized for 2022 and 2021, respectively) | | Interest (net of $74 and $68 capitalized for 2022 and 2021, respectively) | $ | 1,425 | | | $ | 1,417 | |
| Income taxes, net | (187 | ) | | (151 | ) | Income taxes, net | 160 | | | 92 | |
| Noncash transactions — Accrued property additions at end of period | 805 |
| | 578 |
| |
| Noncash transactions — | | Noncash transactions — | |
| Accrued property additions at end of period | | Accrued property additions at end of period | 872 | | | 915 | |
| Contributions from noncontrolling interests | | Contributions from noncontrolling interests | — | | | 89 | |
| Contributions of wind turbine equipment | | Contributions of wind turbine equipment | — | | | 82 | |
| Right-of-use assets obtained under leases | | Right-of-use assets obtained under leases | 141 | | | 92 | |
| Reassessment of right-of-use assets under operating leases | | Reassessment of right-of-use assets under operating leases | 40 | | | — | |
|
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
| | | Assets | | At September 30, 2017 | | At December 31, 2016 | Assets | | At September 30, 2022 | | At December 31, 2021 |
| | | (in millions) | | | (in millions) |
| Current Assets: | | | | | Current Assets: | |
| Cash and cash equivalents | | $ | 1,841 |
| | $ | 1,975 |
| Cash and cash equivalents | | $ | 2,009 | | | $ | 1,798 | |
| | Receivables — | | | | | Receivables — | |
| Customer accounts receivable | | 1,744 |
| | 1,583 |
| |
| Energy marketing receivables | | 427 |
| | 623 |
| |
| Customer accounts | | Customer accounts | | 2,223 | | | 1,806 | |
| | Unbilled revenues | | 595 |
| | 706 |
| Unbilled revenues | | 593 | | | 711 | |
| Under recovered fuel clause revenues | | 62 |
| | — |
| |
| Income taxes receivable, current | | 138 |
| | 544 |
| |
| Other accounts and notes receivable | | 578 |
| | 377 |
| |
| | Other accounts and notes | | Other accounts and notes | | 533 | | | 523 | |
| Accumulated provision for uncollectible accounts | | (43 | ) | | (43 | ) | Accumulated provision for uncollectible accounts | | (80) | | | (78) | |
| Materials and supplies | | 1,499 |
| | 1,462 |
| Materials and supplies | | 1,657 | | | 1,543 | |
| Fossil fuel for generation | | 571 |
| | 689 |
| Fossil fuel for generation | | 526 | | | 450 | |
| Natural gas for sale | | 631 |
| | 631 |
| Natural gas for sale | | 498 | | | 362 | |
| | Prepaid expenses | | 365 |
| | 364 |
| Prepaid expenses | | 373 | | | 330 | |
| Other regulatory assets, current | | 585 |
| | 581 |
| |
| | Assets from risk management activities, net of collateral | | Assets from risk management activities, net of collateral | | 289 | | | 151 | |
| Regulatory assets – asset retirement obligations | | Regulatory assets – asset retirement obligations | | 284 | | | 219 | |
| Natural gas cost under recovery | | Natural gas cost under recovery | | 390 | | | 266 | |
| | Other regulatory assets | | Other regulatory assets | | 746 | | | 653 | |
| Other current assets | | 209 |
| | 230 |
| Other current assets | | 322 | | | 231 | |
| Total current assets | | 9,202 |
| | 9,722 |
| Total current assets | | 10,363 | | | 8,965 | |
| Property, Plant, and Equipment: | | | | | Property, Plant, and Equipment: | | | | |
| In service | | 102,014 |
| | 98,416 |
| In service | | 116,236 | | | 115,592 | |
| Less: Accumulated depreciation | | 31,164 |
| | 29,852 |
| Less: Accumulated depreciation | | 34,922 | | | 34,079 | |
| Plant in service, net of depreciation | | 70,850 |
| | 68,564 |
| Plant in service, net of depreciation | | 81,314 | | | 81,513 | |
| Other utility plant, net | | Other utility plant, net | | 602 | | | — | |
| Nuclear fuel, at amortized cost | | 865 |
| | 905 |
| Nuclear fuel, at amortized cost | | 840 | | | 824 | |
| Construction work in progress | | 8,026 |
| | 8,977 |
| Construction work in progress | | 10,773 | | | 8,771 | |
| Total property, plant, and equipment | | 79,741 |
| | 78,446 |
| Total property, plant, and equipment | | 93,529 | | | 91,108 | |
| Other Property and Investments: | | | | | Other Property and Investments: | | | | |
| Goodwill | | 6,267 |
| | 6,251 |
| Goodwill | | 5,280 | | | 5,280 | |
| Nuclear decommissioning trusts, at fair value | | Nuclear decommissioning trusts, at fair value | | 2,031 | | | 2,542 | |
| Equity investments in unconsolidated subsidiaries | | 1,637 |
| | 1,549 |
| Equity investments in unconsolidated subsidiaries | | 1,292 | | | 1,282 | |
Other intangible assets, net of amortization of $156 and $62
at September 30, 2017 and December 31, 2016, respectively | | 902 |
| | 970 |
| |
| Nuclear decommissioning trusts, at fair value | | 1,783 |
| | 1,606 |
| |
| Leveraged leases | | 788 |
| | 774 |
| |
| Other intangible assets, net of amortization of $331 and $307, respectively | | Other intangible assets, net of amortization of $331 and $307, respectively | | 415 | | | 445 | |
| | Miscellaneous property and investments | | 236 |
| | 270 |
| Miscellaneous property and investments | | 590 | | | 653 | |
| Total other property and investments | | 11,613 |
| | 11,420 |
| Total other property and investments | | 9,608 | | | 10,202 | |
| Deferred Charges and Other Assets: | | | | | Deferred Charges and Other Assets: | | | | |
| Operating lease right-of-use assets, net of amortization | | Operating lease right-of-use assets, net of amortization | | 1,560 | | | 1,701 | |
| Deferred charges related to income taxes | | 1,318 |
| | 1,629 |
| Deferred charges related to income taxes | | 854 | | | 824 | |
| Prepaid pension costs | | Prepaid pension costs | | 2,019 | | | 1,657 | |
| | Unamortized loss on reacquired debt | | 210 |
| | 223 |
| Unamortized loss on reacquired debt | | 243 | | | 258 | |
| Deferred under recovered fuel clause revenues | | Deferred under recovered fuel clause revenues | | 1,697 | | | 410 | |
| Regulatory assets – asset retirement obligations, deferred | | Regulatory assets – asset retirement obligations, deferred | | 6,519 | | | 5,466 | |
| Other regulatory assets, deferred | | 6,718 |
| | 6,851 |
| Other regulatory assets, deferred | | 6,121 | | | 5,577 | |
| | Other deferred charges and assets | | 1,513 |
| | 1,406 |
| Other deferred charges and assets | | 1,492 | | | 1,366 | |
| Total deferred charges and other assets | | 9,759 |
| | 10,109 |
| Total deferred charges and other assets | | 20,505 | | | 17,259 | |
| Total Assets | | $ | 110,315 |
| | $ | 109,697 |
| Total Assets | | $ | 134,005 | | | $ | 127,534 | |
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
| | | Liabilities and Stockholders' Equity | | At September 30, 2017 | | At December 31, 2016 | Liabilities and Stockholders' Equity | | At September 30, 2022 | | At December 31, 2021 |
| | | (in millions) | | | (in millions) |
| Current Liabilities: | | | | | Current Liabilities: | |
| Securities due within one year | | $ | 3,505 |
| | $ | 2,587 |
| Securities due within one year | | $ | 3,241 | | | $ | 2,157 | |
| | Notes payable | | 2,579 |
| | 2,241 |
| Notes payable | | 1,398 | | | 1,440 | |
| Energy marketing trade payables | | 451 |
| | 597 |
| |
| | Accounts payable | | 2,353 |
| | 2,228 |
| Accounts payable | | 3,079 | | | 2,169 | |
| Customer deposits | | 550 |
| | 558 |
| Customer deposits | | 516 | | | 479 | |
| Accrued taxes — | | | | | Accrued taxes — | |
| Accrued income taxes | | 176 |
| | 193 |
| Accrued income taxes | | 129 | | | 50 | |
| Unrecognized tax benefits | | 17 |
| | 385 |
| |
| | Other accrued taxes | | 690 |
| | 667 |
| Other accrued taxes | | 882 | | | 641 | |
| Accrued interest | | 443 |
| | 518 |
| Accrued interest | | 431 | | | 533 | |
| | Accrued compensation | | 703 |
| | 915 |
| Accrued compensation | | 961 | | | 1,070 | |
| Asset retirement obligations, current | | 245 |
| | 378 |
| |
| Acquisitions payable | | — |
| | 489 |
| |
| Other regulatory liabilities, current | | 139 |
| | 236 |
| |
| Asset retirement obligations | | Asset retirement obligations | | 689 | | | 697 | |
| | Operating lease obligations | | Operating lease obligations | | 191 | | | 250 | |
| Other regulatory liabilities | | Other regulatory liabilities | | 440 | | | 563 | |
| Other current liabilities | | 752 |
| | 925 |
| Other current liabilities | | 844 | | | 872 | |
| Total current liabilities | | 12,603 |
| | 12,917 |
| Total current liabilities | | 12,801 | | | 10,921 | |
| Long-term Debt | | 44,042 |
| | 42,629 |
| Long-term Debt | | 50,427 | | | 50,120 | |
| Deferred Credits and Other Liabilities: | | | | | Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 14,321 |
| | 14,092 |
| Accumulated deferred income taxes | | 9,916 | | | 8,862 | |
| Deferred credits related to income taxes | | Deferred credits related to income taxes | | 5,271 | | | 5,401 | |
| Accumulated deferred ITCs | | 2,290 |
| | 2,228 |
| Accumulated deferred ITCs | | 2,154 | | | 2,216 | |
| Employee benefit obligations | | 2,139 |
| | 2,299 |
| Employee benefit obligations | | 1,466 | | | 1,550 | |
| Operating lease obligations, deferred | | Operating lease obligations, deferred | | 1,393 | | | 1,503 | |
| Asset retirement obligations, deferred | | 4,356 |
| | 4,136 |
| Asset retirement obligations, deferred | | 11,007 | | | 10,990 | |
| | Other cost of removal obligations | | 2,708 |
| | 2,748 |
| Other cost of removal obligations | | 1,950 | | | 2,103 | |
| Other regulatory liabilities, deferred | | 449 |
| | 476 |
| Other regulatory liabilities, deferred | | 536 | | | 485 | |
| | Other deferred credits and liabilities | | 1,048 |
| | 1,278 |
| Other deferred credits and liabilities | | 1,366 | | | 816 | |
| Total deferred credits and other liabilities | | 27,311 |
| | 27,257 |
| Total deferred credits and other liabilities | | 35,059 | | | 33,926 | |
| Total Liabilities | | 83,956 |
| | 82,803 |
| Total Liabilities | | 98,287 | | | 94,967 | |
| Redeemable Preferred Stock of Subsidiaries | | 361 |
| | 118 |
| Redeemable Preferred Stock of Subsidiaries | | 242 | | | 291 | |
| Redeemable Noncontrolling Interests | | 59 |
| | 164 |
| |
| Stockholders' Equity: | | | | | |
| Common Stockholders' Equity: | | | | | |
| Common stock, par value $5 per share — | | | | | |
| Authorized — 1.5 billion shares | | | | | |
| Issued — September 30, 2017: 1.0 billion shares | | | | | |
| — December 31, 2016: 991 million shares | | | | | |
| Treasury — September 30, 2017: 0.9 million shares | | | | | |
| — December 31, 2016: 0.8 million shares | | | | | |
| Par value | | 5,018 |
| | 4,952 |
| |
| Paid-in capital | | 10,300 |
| | 9,661 |
| |
| Treasury, at cost | | (35 | ) | | (31 | ) | |
| Retained earnings | | 8,981 |
| | 10,356 |
| |
| Accumulated other comprehensive loss | | (182 | ) | | (180 | ) | |
| Total Common Stockholders' Equity | | 24,082 |
| | 24,758 |
| |
| Preferred and Preference Stock of Subsidiaries | | 462 |
| | 609 |
| |
| Noncontrolling Interests | | 1,395 |
| | 1,245 |
| |
| Total Stockholders' Equity | | 25,939 |
| | 26,612 |
| |
| Total Stockholders' Equity (See accompanying statements) | | Total Stockholders' Equity (See accompanying statements) | | 35,476 | | | 32,276 | |
| Total Liabilities and Stockholders' Equity | | $ | 110,315 |
| | $ | 109,697 |
| Total Liabilities and Stockholders' Equity | | $ | 134,005 | | | $ | 127,534 | |
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSISCONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED)
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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, 2020 | 1,058 | | | (1) | | | $ | 5,268 | | | $ | 11,834 | | | $ | (46) | | | $ | 11,311 | | | $ | (395) | | | | $ | 4,262 | | | $ | 32,234 | |
| Consolidated net income (loss) | — | | | — | | | — | | | — | | | — | | | 1,135 | | | — | | | | (32) | | | 1,103 | |
| Other comprehensive income | — | | | — | | | — | | | — | | | — | | | — | | | 28 | | | | — | | | 28 | |
| Stock issued | 2 | | | — | | | 5 | | | 9 | | | — | | | — | | | — | | | | — | | | 14 | |
| Stock-based compensation | — | | | — | | | — | | | 9 | | | — | | | — | | | — | | | | — | | | 9 | |
| | | | | | | | | | | | | | | | | | |
| Cash dividends of $0.64 per share | — | | | — | | | — | | | — | | | — | | | (678) | | | — | | | | — | | | (678) | |
| | | | | | | | | | | | | | | | | | |
Capital contributions from
noncontrolling interests | — | | | — | | | — | | | — | | | — | | | — | | | — | | | | 403 | | | 403 | |
| Distributions to noncontrolling interests | — | | | — | | | — | | | — | | | — | | | — | | | — | | | | (46) | | | (46) | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| Other | — | | | — | | | — | | | 2 | | | — | | | — | | | — | | | | (1) | | | 1 | |
| Balance at March 31, 2021 | 1,060 | | | (1) | | | 5,273 | | | 11,854 | | | (46) | | | 11,768 | | | (367) | | | | 4,586 | | | 33,068 | |
| Consolidated net income | — | | | — | | | — | | | — | | | — | | | 372 | | | — | | | | — | | | 372 | |
| Other comprehensive income | — | | | — | | | — | | | — | | | — | | | — | | | 12 | | | | — | | | 12 | |
| Stock issued | — | | | — | | | 1 | | | 9 | | | — | | | — | | | — | | | | — | | | 10 | |
| Stock-based compensation | — | | | — | | | — | | | 22 | | | — | | | — | | | — | | | | — | | | 22 | |
| | | | | | | | | | | | | | | | | | |
| Cash dividends of $0.66 per share | — | | | — | | | — | | | — | | | — | | | (699) | | | — | | | | — | | | (699) | |
| | | | | | | | | | | | | | | | | | |
Capital contributions from
noncontrolling interests | — | | | — | | | — | | | — | | | — | | | — | | | — | | | | 29 | | | 29 | |
| Distributions to noncontrolling interests | — | | | — | | | — | | | — | | | — | | | — | | | — | | | | (68) | | | (68) | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| Other | — | | | — | | | — | | | 1 | | | (2) | | | 1 | | | — | | | | — | | | — | |
| Balance at June 30, 2021 | 1,060 | | | (1) | | | 5,274 | | | 11,886 | | | (48) | | | 11,442 | | | (355) | | | | 4,547 | | | 32,746 | |
| Consolidated net income | — | | | — | | | — | | | — | | | — | | | 1,101 | | | — | | | | 5 | | | 1,106 | |
| Other comprehensive income | — | | | — | | | — | | | — | | | — | | | — | | | 36 | | | | — | | | 36 | |
| | | | | | | | | | | | | | | | | | |
| Stock issued | 1 | | | — | | | 4 | | | 34 | | | — | | | — | | | — | | | | — | | | 38 | |
| Stock-based compensation | — | | | — | | | — | | | 22 | | | — | | | — | | | — | | | | — | | | 22 | |
| | | | | | | | | | | | | | | | | | |
| Cash dividends of $0.66 per share | — | | | — | | | — | | | — | | | — | | | (700) | | | — | | | | — | | | (700) | |
| | | | | | | | | | | | | | | | | | |
Capital contributions from
noncontrolling interests | — | | | — | | | — | | | — | | | — | | | — | | | — | | | | 72 | | | 72 | |
| Distributions to noncontrolling interests | — | | | — | | | — | | | — | | | — | | | — | | | — | | | | (94) | | | (94) | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| Other | — | | | — | | | — | | | (10) | | | 2 | | | 1 | | | — | | | | — | | | (7) | |
| Balance at September 30, 2021 | 1,061 | | | (1) | | | $ | 5,278 | | | $ | 11,932 | | | $ | (46) | | | $ | 11,844 | | | $ | (319) | | | | $ | 4,530 | | | $ | 33,219 | |
| | | | | | | | | | | | | | | | | | |
THIRD QUARTER 2017 vs. THIRD QUARTER 2016
AND
YEAR-TO-DATE 2017 vs. YEAR-TO-DATE 2016
OVERVIEW
Southern Company is a holding company that owns all of the common stock of the traditional electric operating companies and the parent entities of Southern Power and Southern Company Gas and owns other direct and indirect subsidiaries. Discussion of the results of operations is focused on the Southern Company system's primary businesses of electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas by Southern Company Gas. The four traditional electric operating companies are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. Southern Company's other business activities include providing energy technologies and services to electric utilities and large industrial, commercial, institutional, and municipal customers. Customer solutions include distributed generation systems, utility infrastructure solutions, and energy efficiency products and services. Other business activities also include investments in telecommunications, leveraged lease projects, and gas storage facilities. For additional information, see BUSINESS – "The Southern Company System – Traditional Electric Operating Companies," " – Southern Power," " – Southern Company Gas," and " – Other Businesses" in Item 1 of the Form 10-K. See FUTURE EARNINGS POTENTIAL herein for information regarding agreements entered into by a wholly-owned subsidiary of Southern Company Gas to sell two of its natural gas distribution utilities.
Southern Company continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, electric and natural gas system reliability, execution of major construction projects, and earnings per share.
Construction Program
See RESULTS OF OPERATIONS – "Estimated Loss on Kemper IGCC," FUTURE EARNINGS POTENTIAL – "Construction Program," and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the construction program. For information about Southern Power's acquisitions and construction of renewable energy facilities, see Note (I) to the Condensed Financial Statements under "Southern Power" herein.
Kemper IGCC
On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC (Kemper Settlement Order). The Kemper Settlement Order established a new docket for the purposes of pursuing a global settlement of costs of the Kemper IGCC (Kemper IGCC Settlement Docket). The Mississippi PSC requested any such proposed settlement agreement reflect: (i) at a minimum, no rate increase to Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and related assets; and (iii) modification or amendment of the CPCN for the Kemper IGCC to allow only for ownership and operation of a natural gas facility.
On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSISCONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED)
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Southern Company Common Stockholders' Equity | | | | | |
| | Number of
Common Shares | | Common Stock | | | | Accumulated
Other
Comprehensive Income
(Loss) | | | | | |
| | Issued | | Treasury | | Par Value | | Paid-In Capital | | Treasury | | Retained Earnings | | | Noncontrolling Interests | | Total |
| | (in millions) |
| Balance at December 31, 2021 | 1,061 | | | (1) | | | $ | 5,279 | | | $ | 11,950 | | | $ | (47) | | | $ | 10,929 | | | $ | (237) | | | | $ | 4,402 | | | $ | 32,276 | |
| Consolidated net income (loss) | — | | | — | | | — | | | — | | | — | | | 1,032 | | | — | | | | (45) | | | 987 | |
| Other comprehensive income | — | | | — | | | — | | | — | | | — | | | — | | | 42 | | | | — | | | 42 | |
| Stock issued | 3 | | | — | | | 7 | | | 31 | | | — | | | — | | | — | | | | — | | | 38 | |
| Stock-based compensation | — | | | — | | | — | | | 6 | | | — | | | — | | | — | | | | — | | | 6 | |
| | | | | | | | | | | | | | | | | | |
| Cash dividends of $0.66 per share | — | | | — | | | — | | | — | | | — | | | (702) | | | — | | | | — | | | (702) | |
| | | | | | | | | | | | | | | | | | |
Capital contributions from
noncontrolling interests | — | | | — | | | — | | | — | | | — | | | — | | | — | | | | 73 | | | 73 | |
| Distributions to noncontrolling interests | — | | | — | | | — | | | — | | | — | | | — | | | — | | | | (98) | | | (98) | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| Other | — | | | — | | | — | | | 7 | | | (2) | | | 2 | | | — | | | | — | | | 7 | |
| Balance at March 31, 2022 | 1,064 | | | (1) | | | 5,286 | | | 11,994 | | | (49) | | | 11,261 | | | (195) | | | | 4,332 | | | 32,629 | |
| Consolidated net income (loss) | — | | | — | | | — | | | — | | | — | | | 1,107 | | | — | | | | (22) | | | 1,085 | |
| Other comprehensive income | — | | | — | | | — | | | — | | | — | | | — | | | 11 | | | | — | | | 11 | |
| Stock issued | — | | | — | | | 2 | | | 21 | | | — | | | — | | | — | | | | — | | | 23 | |
| Stock-based compensation | — | | | — | | | — | | | 14 | | | — | | | — | | | — | | | | — | | | 14 | |
| | | | | | | | | | | | | | | | | | |
| Cash dividends of $0.68 per share | — | | | — | | | — | | | — | | | — | | | (723) | | | — | | | | — | | | (723) | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| Distributions to noncontrolling interests | — | | | — | | | — | | | — | | | — | | | — | | | — | | | | (28) | | | (28) | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| Other | — | | | — | | | — | | | 4 | | | (2) | | | — | | | — | | | | — | | | 2 | |
| Balance at June 30, 2022 | 1,064 | | | (1) | | | 5,288 | | | 12,033 | | | (51) | | | 11,645 | | | (184) | | | | 4,282 | | | 33,013 | |
| Consolidated net income | — | | | — | | | — | | | — | | | — | | | 1,472 | | | — | | | | 12 | | | 1,484 | |
| Other comprehensive income | — | | | — | | | — | | | — | | | — | | | — | | | 28 | | | | — | | | 28 | |
| | | | | | | | | | | | | | | | | | |
| Stock issued | 26 | | | — | | | 129 | | | 1,613 | | | — | | | — | | | — | | | | — | | | 1,742 | |
| Stock-based compensation | — | | | — | | | — | | | 15 | | | — | | | — | | | — | | | | — | | | 15 | |
| | | | | | | | | | | | | | | | | | |
| Cash dividends of $0.68 per share | — | | | — | | | — | | | — | | | — | | | (741) | | | — | | | | — | | | (741) | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| Distributions to noncontrolling interests | — | | | — | | | — | | | — | | | — | | | — | | | — | | | | (57) | | | (57) | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| Other | — | | | — | | | — | | | (4) | | | (1) | | | (2) | | | (1) | | | | — | | | (8) | |
| Balance at September 30, 2022 | 1,090 | | | (1) | | | $ | 5,417 | | | $ | 13,657 | | | $ | (52) | | | $ | 12,374 | | | $ | (157) | | | | $ | 4,237 | | | $ | 35,476 | |
of the gasifier portion of the Kemper IGCC. Mississippi Power expectsThe accompanying notes as they relate to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014. At the time of project suspension, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in additional grants from the DOE received on April 8, 2016 (Additional DOE Grants).
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred.
Total pre-tax charges to income for the estimated probable losses on the Kemper IGCC were $34 million ($21 million after tax) for the third quarter 2017 and $3.2 billion ($2.2 billion after tax) for the nine months ended September 30, 2017. In the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $6.0 billion ($4.0 billion after tax) through September 30, 2017.
Mississippi Power reached and filed a settlement agreement on August 21, 2017 with certain parties (not including the Mississippi Public Utilities Staff (MPUS)), which it believes met the conditions of the Kemper Settlement Order. The settlement agreement provides for an annual revenue requirement of $126 million for Kemper IGCC-related costs, which would (i) be effective January 1, 2018, (ii) represent no rate increase for customers, and (iii) include no recovery for the costs associated with the gasifier portion of the Kemper IGCC in 2018 or at any future date. In addition, under the settlement agreement, the CPCN for the Kemper IGCC would be modified to limit the Kemper County energy facility to natural gas combined cycle operation and Mississippi Power would, in the future, file a reserve margin plan with the Mississippi PSC. The Mississippi PSC issued a scheduling order, as amended on October 5, 2017, noting Mississippi Power and the MPUS had failed to reach a joint stipulation and ordering a full hearing. The Mississippi PSC is expected to rule on an order resolving this matter in January 2018.
As of September 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which $0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility, as well as the 15% that was previously contracted to Cooperative Energy. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.
For additional information on the Kemper IGCC, including information on the project economic viability analysis, pending lawsuits, and an ongoing SEC investigation, see Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8are an integral part of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and "Other Matters" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein.these condensed consolidated financial statements.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
Nuclear Construction
On March 29, 2017, the EPC Contractor for Plant Vogtle Units 3 and 4 filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. To provide for a continuation of work, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an interim assessment agreement with the EPC Contractor (Interim Assessment Agreement), which the bankruptcy court approved on March 30, 2017. On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion (Guarantee Obligations), of which Georgia Power's proportionate share is approximately $1.7 billion, and that the Guarantee Obligations exist regardless of whether Plant Vogtle Units 3 and 4 are completed. On October 2, 2017, Georgia Power received the first installment of the Guarantee Obligations of $300 million from Toshiba, of which Georgia Power's proportionate share was $137 million.
Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into a services agreement (Services Agreement), which was amended and restated on July 20, 2017, for the EPC Contractor to transition construction management of Plant Vogtle Units 3 and 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear. On July 27, 2017, the Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE and the Interim Assessment Agreement expired pursuant to its terms. The Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice. Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement (Bechtel Agreement) with Bechtel Power Corporation (Bechtel), whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4.
In the seventeenth Vogtle Construction Monitoring (VCM) report filed on August 31, 2017, Georgia Power recommended that construction of Plant Vogtle Units 3 and 4 be continued, with Southern Nuclear serving as project manager. Georgia Power believes that the most reasonable schedule for completing Plant Vogtle Units 3 and 4 is by November 2021 for Unit 3 and by November 2022 for Unit 4, at an additional cost of approximately $1.41 billion, net of the Guarantee Settlement Agreement. The Georgia PSC is expected to make a decision on these matters by February 6, 2018.
On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to the financial statements of Southern Company under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Southern Company's financial statements. The ultimate outcome of these matters cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Construction Program – Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4, including Georgia Power's cost-to-complete and cancellation cost assessments for Plant Vogtle Units 3 and 4.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
Net Income
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(70) | | (6.1) | | $(1,904) | | (84.6) |
Consolidated net income attributable to Southern Company was $1.07 billion ($1.07 per share) for the third quarter 2017 compared to $1.14 billion ($1.18 per share) for the corresponding period in 2016. The decrease was primarily due to a decrease in retail electric revenues due to milder weather and lower customer usage, a decrease in tax benefits at Southern Power, and an increase in depreciation and amortization. These changes were partially offset by higher retail electric revenues resulting from increases in base rates and a decrease in operations and maintenance expenses.
Consolidated net income attributable to Southern Company was $347 million ($0.35 per share) for year-to-date 2017 compared to $2.3 billion ($2.40 per share) for the corresponding period in 2016. The decrease was primarily due to charges of $3.2 billion and $222 million for year-to-date 2017 and 2016, respectively, related to the Kemper IGCC at Mississippi Power. Also contributing to the change was an increase of $299 million in net income from Southern Company Gas reflecting the nine-month period in 2017 compared to the three-month period following the Merger closing on July 1, 2016, higher retail electric revenues resulting from increases in base rates, and increases in renewable energy sales at Southern Power, partially offset by a decrease in retail electric revenues due to milder weather and lower customer usage, higher interest expense, and an increase in depreciation and amortization.
See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the Kemper IGCC and Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information on the Merger.
Retail Electric Revenues
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(193) | | (4.0) | | $(146) | | (1.2) |
In the third quarter 2017, retail electric revenues were $4.6 billion compared to $4.8 billion for the corresponding period in 2016. For year-to-date 2017, retail electric revenues were $11.8 billion compared to $11.9 billion for the corresponding period in 2016.
Details of the changes in retail electric revenues were as follows:
|
| | | | | | | | | | | | | | |
| | | Third Quarter 2017 | | Year-to-Date 2017 |
| | | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail electric – prior year | | $ | 4,808 |
| | | | $ | 11,932 |
| | |
| Estimated change resulting from – | | | | | | | | |
| Rates and pricing | | 138 |
| | 2.9 |
| | 338 |
| | 2.8 |
|
| Sales decline | | (52 | ) | | (1.1 | ) | | (74 | ) | | (0.6 | ) |
| Weather | | (162 | ) | | (3.4 | ) | | (351 | ) | | (2.9 | ) |
| Fuel and other cost recovery | | (117 | ) | | (2.4 | ) | | (59 | ) | | (0.5 | ) |
| Retail electric – current year | | $ | 4,615 |
| | (4.0 | )% | | $ | 11,786 |
| | (1.2 | )% |
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016 primarily due to a Rate RSE increase at Alabama Power effective
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
January 1, 2017, the recovery of Plant Vogtle Units 3 and 4 construction financing costs under the NCCR tariff at Georgia Power, and an increase in retail base revenues effective July 2017 and in environmental cost recovery effective November 2016 at Gulf Power.
See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Alabama Power," " – Georgia Power – Rate Plans," and " – Gulf Power – Retail Base Rate Cases" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.
Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016. Weather-adjusted residential KWH sales decreased 2.0% and 0.6% in the third quarter and year-to-date 2017, respectively, primarily due to decreased customer usage resulting from an increase in penetration of energy efficient residential appliances, partially offset by customer growth. Weather-adjusted commercial KWH sales decreased 1.4% and 1.1% in the third quarter and year-to-date 2017, respectively, primarily due to decreased customer usage resulting from customer initiatives in energy savings and an ongoing migration to the electronic commerce business model, partially offset by customer growth. Industrial KWH sales decreased 0.5% and 1.1% in the third quarter and year-to-date 2017, respectively, primarily in the paper sector, partially offset by increased sales in the primary metals and textile sectors. Despite a more stable dollar and improving global economy, the industrial sector remains constrained by economic policy uncertainty. Additionally, Hurricane Irma negatively impacted customer usage for all customer classes.
Fuel and other cost recovery revenues decreased $117 million and $59 million in the third quarter and year-to-date 2017, respectively, when compared to the corresponding periods in 2016 primarily due to lower energy sales resulting from milder weather and lower coal prices. Electric rates for the traditional electric operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of PPA costs, and do not affect net income. The traditional electric operating companies each have one or more regulatory mechanisms to recover other costs such as environmental and other compliance costs, storm damage, new plants, and PPA capacity costs.
Wholesale Electric Revenues
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $105 | | 17.1 | | $412 | | 28.3 |
Wholesale electric revenues consist of PPAs primarily with investor-owned utilities and electric cooperatives and short-term opportunity sales. Wholesale electric revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues generally represent the greatest contribution to net income and are designed to provide recovery of fixed costs plus a return on investment. Energy revenues will vary depending on fuel prices, the market prices of wholesale energy compared to the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Energy sales from solar and wind PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or through a fixed price related to the energy. As a result, Southern Company's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, and other factors. Wholesale electric revenues at Mississippi Power include FERC-regulated municipal and rural association sales as well as market-based sales. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system's variable cost to produce the energy.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In the third quarter 2017, wholesale electric revenues were $718 million compared to $613 million for the corresponding period in 2016. This increase was primarily related to a $78 million increase in energy revenues and a $27 million increase in capacity revenues. For year-to-date 2017, wholesale electric revenues were $1.9 billion compared to $1.5 billion for the corresponding period in 2016. This increase was primarily related to a $354 million increase in energy revenues and a $58 million increase in capacity revenues. The increases in energy revenues primarily relate to Southern Power increases in renewable energy sales arising from new solar and wind facilities and non-PPA revenues from short-term sales. The increases in capacity revenues primarily resulted from PPAs related to new natural gas facilities and additional customer capacity requirements at Southern Power.
Other Electric Revenues
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(13) | | (7.2) | | $(19) | | (3.6) |
In the third quarter 2017, other electric revenues were $168 million compared to $181 million for the corresponding period in 2016. The decrease was primarily related to lower open access transmission tariff revenues, primarily as a result of the expiration of long-term transmission services contracts at Georgia Power and rate adjustments at Alabama Power, and a decrease in solar application fee revenues at Georgia Power.
For year-to-date 2017, other electric revenues were $510 million compared to $529 million for the corresponding period in 2016. The decrease was primarily due to a $14 million adjustment in 2016 for customer temporary facilities services revenues and a $12 million decrease in open access transmission tariff revenues, primarily as a result of the expiration of long-term transmission services contracts at Georgia Power, partially offset by a $10 million increase in outdoor lighting sales revenues primarily attributable to LED conversions at Georgia Power.
Natural Gas Revenues
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $14 | | 2.7 | | $2,228 | | N/M |
N/M - Not meaningful
Natural gas revenues represent sales from the natural gas distribution utilities and certain non-regulated operations of Southern Company Gas. In the third quarter 2017, natural gas revenues were $532 million compared to $518 million for the corresponding period in 2016. This increase is primarily due to infrastructure replacement programs and increases in base rate revenues at Southern Company Gas.
For year-to-date 2017, natural gas revenues were $2.7 billion compared to $518 million for the corresponding period in 2016. The increase reflects the inclusion of Southern Company Gas results for the nine-month period in 2017 compared to the three-month period subsequent to the Merger closing on July 1, 2016.
See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
Other Revenues
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $24 | | 16.7 | | $213 | | 75.8 |
In the third quarter 2017, other revenues were $168 million compared to $144 million for the corresponding period in 2016. For year-to-date 2017, other revenues were $494 million compared to $281 million for the corresponding
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
period in 2016. These increases were primarily due to increases of $5 million and $135 million for the third quarter and year-to-date 2017, respectively, from products and services at PowerSecure, which was acquired on May 9, 2016, and $8 million and $70 million for the third quarter and year-to-date 2017, respectively, of revenues from gas marketing products and services at Southern Company Gas following the Merger. Additionally, revenues from certain non-regulated sales of products and services at the traditional electric operating companies increased $5 million and $13 million for the third quarter and year-to-date 2017, respectively, primarily due to additional third-party infrastructure services.
See Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information on the Merger and the acquisition of PowerSecure.
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | |
| | Third Quarter 2017
vs.
Third Quarter 2016 | | Year-to-Date 2017
vs.
Year-to-Date 2016 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | (115 | ) | | (8.2) | | $ | 38 |
| | 1.1 |
| Purchased power | 29 |
| | 12.8 | | 65 |
| | 11.2 |
| Total fuel and purchased power expenses | $ | (86 | ) | | | | $ | 103 |
| | |
In the third quarter 2017, total fuel and purchased power expenses were $1.5 billion compared to $1.6 billion for the corresponding period in 2016. The decrease was primarily the result of a $104 million net decrease in the volume of KWHs generated and purchased, partially offset by an $18 million net increase in the average cost of fuel and purchased power primarily due to higher natural gas prices.
For year-to-date 2017, total fuel and purchased power expenses were $4.0 billion compared to $3.9 billion for the corresponding period in 2016. The increase was primarily the result of a $277 million increase in the average cost of fuel and purchased power primarily due to higher natural gas prices, partially offset by a $174 million decrease in the volume of KWHs generated and purchased.
Fuel and purchased power energy transactions at the traditional electric operating companies are generally offset by fuel revenues and do not have a significant impact on net income. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Fuel Cost Recovery" herein for additional information. Fuel expenses incurred under Southern Power's PPAs are generally the responsibility of the counterparties and do not significantly impact net income.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of the Southern Company system's generation and purchased power were as follows:
|
| | | | | | | |
| | Third Quarter 2017 | | Third Quarter 2016 | | Year-to-Date 2017 | | Year-to-Date 2016 |
Total generation (in billions of KWHs) | 54 | | 56 | | 147 | | 145 |
Total purchased power (in billions of KWHs) | 6 | | 6 | | 14 | | 15 |
Sources of generation (percent) — | | | | | | | |
| Coal | 31 | | 38 | | 30 | | 33 |
| Nuclear | 15 | | 15 | | 16 | | 16 |
| Gas | 47 | | 44 | | 46 | | 46 |
| Hydro | 2 | | 1 | | 2 | | 3 |
| Other | 5 | | 2 | | 6 | | 2 |
Cost of fuel, generated (in cents per net KWH) — | | | | | | | |
| Coal | 2.82 | | 2.97 | | 2.82 | | 3.10 |
| Nuclear | 0.80 | | 0.81 | | 0.80 | | 0.82 |
| Gas | 2.92 | | 2.74 | | 2.93 | | 2.40 |
Average cost of fuel, generated (in cents per net KWH) | 2.54 | | 2.54 | | 2.51 | | 2.38 |
Average cost of purchased power (in cents per net KWH)(*) | 4.96 | | 4.98 | | 5.32 | | 4.75 |
| |
(*) | Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider. |
Fuel
In the third quarter 2017, fuel expense was $1.3 billion compared to $1.4 billion for the corresponding period in 2016. The decrease was primarily due to a 21.4% decrease in the volume of KWHs generated by coal and a 5.1% decrease in the average cost of coal per KWH generated, partially offset by a 6.6% increase in the average cost of natural gas per KWH generated and a 1.2% increase in the volume of KWHs generated by natural gas.
For year-to-date 2017, fuel expense was $3.4 billion compared to $3.3 billion for the corresponding period in 2016. The increase was primarily due to a 22.1% increase in the average cost of natural gas per KWH generated, partially offset by a 9.0% decrease in the average cost of coal per KWH generated, a 7.4% decrease in the volume of KWHs generated by coal, and a 3.7% decrease in the volume of KWHs generated by natural gas.
Purchased Power
In the third quarter 2017, purchased power expense was $256 million compared to $227 million for the corresponding period in 2016. The increase was primarily due to a 10.1% increase in the volume of KWHs purchased, partially offset by a 0.4% decrease in the average cost per KWH purchased.
For year-to-date 2017, purchased power expense was $646 million compared to $581 million for the corresponding period in 2016. The increase was primarily due to a 12.0% increase in the average cost per KWH purchased, primarily as a result of higher natural gas prices, partially offset by a 1.3% decrease in the volume of KWHs purchased.
Energy purchases will vary depending on demand for energy within the Southern Company system's electric service territory, the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, and the availability of the Southern Company system's generation.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Cost of Natural Gas
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1 | | 0.8 | | $952 | | N/M |
N/M - Not meaningful
Cost of natural gas represents the cost of natural gas sold by the natural gas distribution utilities and certain non-regulated operations of Southern Company Gas. In the third quarter 2017, cost of natural gas was $134 million compared to $133 million for the corresponding period in 2016. For year-to-date 2017, cost of natural gas was $1.1 billion compared to $133 million for the corresponding period in 2016. The year-to-date increase reflects the inclusion of Southern Company Gas results for the nine-month period in 2017 compared to the three-month period subsequent to the Merger closing on July 1, 2016.
See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
Cost of Other Sales
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $6 | | 7.1 | | $132 | | 82.0 |
In the third quarter 2017, cost of other sales was $90 million compared to $84 million for the corresponding period in 2016. For year-to-date 2017, cost of other sales was $293 million compared to $161 million for the corresponding period in 2016. The year-to-date increase primarily reflects costs related to sales of products and services by PowerSecure, which was acquired on May 9, 2016, and costs related to gas marketing products and services at Southern Company Gas following the Merger closing on July 1, 2016. See Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(124) | | (8.8) | | $302 | | 8.4 |
In the third quarter 2017, other operations and maintenance expenses were $1.3 billion compared to $1.4 billion for the corresponding period in 2016. The decrease was primarily due to cost containment and modernization activities implemented at Georgia Power in the third quarter 2016 that contributed to decreases of $37 million in maintenance costs, $9 million in customer accounts, service, and sales costs, and $8 million in other employee compensation and benefits. Other factors include a $40 million decrease in acquisition-related expenses and a $31 million decrease in employee compensation and benefits including pension costs.
For year-to-date 2017, other operations and maintenance expenses were $3.9 billion compared to $3.6 billion for the corresponding period in 2016. The increase was primarily due to increases of $420 million and $32 million in operations and maintenance expenses as a result of the inclusion of Southern Company Gas and PowerSecure results for the nine-month period in 2017, respectively, a $48 million increase associated with new solar, wind, and gas facilities at Southern Power, and $32.5 million resulting from the write-down of Gulf Power's ownership of Plant Scherer Unit 3 in accordance with a settlement agreement approved by the Florida PSC on April 4, 2017 (2017 Rate Case Settlement Agreement). These increases were partially offset due to cost containment and modernization activities implemented at Georgia Power in the third quarter 2016 that contributed to decreases of $79 million in maintenance costs and $34 million in other employee compensation and benefits. Other factors
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
include a $32 million decrease in acquisition-related expenses, a $25 million decrease in customer accounts, service, and sales costs primarily at Georgia Power, a $19 million increase in gains from sales of integrated transmission system assets at Georgia Power, and a $16 million decrease in scheduled outage and maintenance costs at generation facilities.
See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information regarding the 2017 Rate Case Settlement Agreement and Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information related to the Merger and the acquisition of PowerSecure.
Depreciation and Amortization
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $72 | | 10.4 | | $431 | | 23.9 |
In the third quarter 2017, depreciation and amortization was $767 million compared to $695 million for the corresponding period in 2016. The increase is primarily related to additional plant in service at the traditional electric operating companies, Southern Power, and Southern Company Gas.
For year-to-date 2017, depreciation and amortization was $2.2 billion compared to $1.8 billion for the corresponding period in 2016. The increase reflects $254 million as a result of the inclusion of Southern Company Gas for the nine-month period in 2017 compared to the three-month period subsequent to the Merger closing on July 1, 2016. Additionally, the increase reflects $170 million related to additional plant in service at the traditional electric operating companies and Southern Power. The increase was partially offset by a $34 million increase in the reductions in depreciation authorized in Gulf Power's 2013 rate case settlement approved by the Florida PSC as compared to the corresponding period in 2016.
See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" in Item 8 of the Form 10-K and Notes (B) and (I) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" and "Southern Company – Merger with Southern Company Gas," respectively, herein for additional information.
Taxes Other Than Income Taxes
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(6) | | (1.9) | | $120 | | 14.6 |
For year-to-date 2017, taxes other than income taxes were $941 million compared to $821 million for the corresponding period in 2016. The increase primarily reflects the inclusion of Southern Company Gas taxes for the nine-month period in 2017 compared to the three-month period subsequent to the Merger closing on July 1, 2016.
See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Estimated Loss on Kemper IGCC
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(54) | | (61.4) | | $2,933 | | N/M |
N/M - Not meaningful
Estimated probable losses on the Kemper IGCC of $34 million and $3.2 billion were recorded at Mississippi Power in the third quarter and year-to-date 2017, respectively, compared to $88 million and $222 million in the third quarter and year-to-date 2016, respectively. While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable. As a result, Mississippi Power suspended the project on June 28, 2017, and recorded $34 million and $2.9 billion of additional charges to income in the third quarter and year-to-date 2017, respectively, for the estimated costs associated with the gasification portions of the plant and lignite mine.
Prior to the project's suspension, Mississippi Power recorded losses for revisions of estimated costs expected to be incurred on construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (Initial DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (construction cost increase demonstrated to produce efficiencies that result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions).
See FUTURE EARNINGS POTENTIAL – "Construction Program – Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Allowance for Equity Funds Used During Construction
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(34) | | (65.4) | | $(17) | | (11.3) |
In the third quarter 2017, AFUDC equity was $18 million compared to $52 million in the corresponding period in 2016. For year-to-date 2017, AFUDC equity was $133 million compared to $150 million in the corresponding period in 2016. These decreases primarily resulted from Mississippi Power's suspension of the Kemper IGCC project in June 2017.
See FUTURE EARNINGS POTENTIAL – "Construction Program – Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Earnings from Equity Method Investments
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $3 | | 10.3 | | $72 | | N/M |
N/M - Not meaningful
In the third quarter 2017, earnings from equity method investments were $32 million compared to $29 million in the corresponding period in 2016. For year-to-date 2017, earnings from equity method investments were $100 million
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
compared to $28 million in the corresponding period in 2016. These increases were primarily related to Southern Company Gas' equity method investment in SNG in September 2016.
See Note 12 to the financial statements of Southern Company under "Southern Company – Investment in Southern Natural Gas" in Item 8 of the Form 10-K for additional information.
Interest Expense, Net of Amounts Capitalized
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $33 | | 8.8 | | $335 | | 36.7 |
In the third quarter 2017, interest expense, net of amounts capitalized was $407 million compared to $374 million in the corresponding period in 2016. The increase was primarily due to an increase in average outstanding long-term debt and a $16 million decrease in interest capitalized, partially offset by a net reduction of $33 million following Mississippi Power's settlement with the IRS related to research and experimental (R&E) deductions.
For year-to-date 2017, interest expense, net of amounts capitalized was $1.2 billion compared to $913 million in the corresponding period in 2016. The increase was primarily due to an increase in average outstanding long-term debt and a $31 million decrease in interest capitalized, partially offset by a net reduction of $33 million following Mississippi Power's settlement with the IRS related to R&E deductions. In addition, year-to-date 2017 includes an additional $106 million reflecting the nine-month period of interest expense for Southern Company Gas compared to the three-month period subsequent to the Merger closing on July 1, 2016.
See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Section 174 Research and Experimental Deduction" and Notes (E) and (G) to the Condensed Financial Statements herein for additional information.
Other Income (Expense), Net
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $19 | | N/M | | $68 | | N/M |
N/M - Not meaningful
In the third quarter 2017, other income (expense), net was $11 million compared to $(8) million for the corresponding period in 2016. For year-to-date 2017, other income (expense), net was $2 million compared to $(66) million for the corresponding period in 2016. These changes were primarily due to $14 million and $16 million from settlement of contractor litigation claims at Southern Company Gas in the third quarter and year-to-date 2017, respectively, and increases of $6 million and $10 million in customer contributions in aid of construction and contract service revenue at Georgia Power in the third quarter and year-to-date 2017, respectively. Additionally, the year-to-date change reflects $30 million of expenses incurred in 2016 associated with bridge financing for the Merger. These changes also include increases of $36 million and $152 million in currency losses arising from a translation of euro-denominated fixed-rate notes into U.S. dollars for the third quarter and year-to-date 2017, respectively, fully offset by an equal change in gains on the foreign currency hedges that were reclassified from accumulated OCI into earnings at Southern Power.
See Note (H) to the Condensed Financial Statements under "Foreign Currency Derivatives" herein for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Income Taxes
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $151 | | 34.4 | | $(600) | | (65.4) |
In the third quarter 2017, income taxes were $590 million compared to $439 million for the corresponding period in 2016. The increase was primarily due to a $61 million decrease in income tax benefits from solar ITCs at Southern Power, a $23 million increase in deferred income tax expenses associated with new State of Illinois tax legislation and new tax apportionment factors at Southern Company Gas, and a $21 million decrease in tax benefits related to estimated losses on the Kemper IGCC at Mississippi Power.
For year-to-date 2017, income taxes were $317 million compared to $917 million for the corresponding period in 2016. The decrease was primarily due to $866 million in tax benefits related to estimated losses on the Kemper IGCC at Mississippi Power, partially offset by a $226 million increase reflecting the nine-month period of income taxes at Southern Company Gas in 2017 compared to the three-month period subsequent to the Merger closing on July 1, 2016 and a $44 million net decrease in tax benefits from renewable tax credits at Southern Power.
See Notes (B), (G), and (I) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle," "Effective Tax Rate," and "Southern Company – Merger with Southern Company Gas," respectively, herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern Company's future earnings potential. The level of Southern Company's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Southern Company system's primary businesses of selling electricity and distributing natural gas. These factors include the traditional electric operating companies' and the natural gas distribution utilities' ability to maintain a constructive regulatory environment that allows for the timely recovery of prudently-incurred costs during a time of increasing costs and limited projected demand growth over the next several years. Matters related to Plant Vogtle Units 3 and 4 construction and rate recovery and the ability to recover costs for the remainder of the Kemper County energy facility not included in current rates are also major factors. In addition, the profitability of Southern Power's competitive wholesale business and successful additional investments in renewable and other energy projects are also major factors.
Current proposals related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals, including any potential changes to the availability or realizability of ITCs and PTCs, is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Southern Company's financial statements.
Future earnings for the electricity and natural gas businesses will be driven primarily by customer growth. Earnings in the electricity business will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies, increasing volumes of electronic commerce transactions, and higher multi-family home construction. Earnings for both the electricity and natural gas businesses are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the prices of electricity and natural gas, the price elasticity of demand, and the rate of economic growth or decline in the service territory. In addition, the level of future earnings for the wholesale electric business also depends on numerous factors including regulatory matters, creditworthiness of customers, total electric generating capacity available and related costs, future acquisitions and construction of electric generating facilities, the impact of tax credits from renewable energy projects, and the successful remarketing of capacity as current contracts expire. Demand for electricity and natural gas is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
impact future earnings. In addition, the volatility of natural gas prices has a significant impact on the natural gas distribution utilities' customer rates, long-term competitive position against other energy sources, and the ability of Southern Company Gas' gas marketing services and wholesale gas services businesses to capture value from locational and seasonal spreads. Additionally, changes in commodity prices subject a significant portion of Southern Company Gas' operations to earnings variability.
As part of its ongoing effort to adapt to changing market conditions, Southern Company continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, partnerships, and acquisitions involving other utility or non-utility businesses or properties, disposition of certain assets or businesses, internal restructuring, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations, risks, and financial condition of Southern Company.
Southern Power is considering the sale of up to a one-third equity interest in its solar asset portfolio. The ultimate outcome of this matter cannot be determined at this time.
On October 15, 2017, a wholly-owned subsidiary of Southern Company Gas entered into agreements for the sale of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion. As of September 30, 2017, the net book value of the assets to be disposed of in the sale was approximately $1.5 billion, which includes approximately $0.5 billion of goodwill. The goodwill is not deductible for tax purposes and as a result, a deferred tax liability has not yet been provided for goodwill. Through the completion of the sale, Southern Company Gas intends to invest approximately $0.1 billion in capital expenditures which are required for ordinary business operations. The completion of each sale is subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act; (ii) the receipt of required regulatory approvals, including the FERC, the Federal Communications Commission, the New Jersey BPU, and, with respect to the sale of Elkton Gas, the Maryland PSC; and (iii) other customary closing conditions. The sales are expected to be completed by the end of the third quarter 2018. The ultimate outcome of these matters cannot be determined at this time.
For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Company in Item 7 of the Form 10-K and RISK FACTORS in Item 1A herein.
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis for the traditional electric operating companies and the natural gas distribution utilities or through long-term wholesale agreements for the traditional electric operating companies and Southern Power. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity and natural gas, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Environmental Statutes and Regulations
Air Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Southern Company in Item 7 of the Form 10-K for additional information regarding the EPA's eight-hour ozone National Ambient Air Quality Standard (NAAQS).
On June 2, 2017, the EPA published a final rule redesignating a 15-county area within metropolitan Atlanta to attainment for the 2008 eight-hour ozone NAAQS.
On June 18, 2017, the EPA published a notice delaying attainment designations for the 2015 eight-hour ozone NAAQS by one year, setting a revised deadline of October 1, 2018. However, on August 2, 2017, the EPA issued a withdrawal notice of the one-year extension and reinstated the original October 1, 2017 designation deadline. The ultimate outcome of this matter cannot be determined at this time.
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Southern Company in Item 7 of the Form 10-K for additional information regarding the final effluent guidelines rule and the final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs.
On April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. On September 18, 2017, the EPA published a final rule establishing a stay of the compliance deadlines for certain effluent limitations and pretreatment standards under the rule.
On June 27, 2017, the EPA and the U.S. Army Corps of Engineers proposed to rescind the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.
The ultimate outcome of these matters cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Southern Company in Item 7 of the Form 10-K for additional information.
On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules. On October 16, 2017, the EPA published a proposed rule to repeal the Clean Power Plan. The EPA has not determined whether or when it will promulgate a replacement rule.
On June 1, 2017, the U.S. President announced that the United States will withdraw from the non-binding Paris Agreement and begin renegotiation of its terms.
The ultimate outcome of these matters cannot be determined at this time.
Natural Gas Storage
A wholly-owned subsidiary of Southern Company Gas owns and operates a natural gas storage facility consisting of two salt dome caverns in Louisiana. Periodic integrity tests are required in accordance with rules of the Louisiana Department of Natural Resources (LDNR). In August 2017, in connection with an ongoing integrity project, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. At September 30, 2017, the facility's property, plant, and equipment had a net book value of $111 million, of which the cavern itself
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including the results of ongoing third-party technical engineering reviews, testing, and compliance with an order from the LDNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining a core sample to determine the composition of the sheath surrounding the edge of the salt dome. Early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. The ultimate outcome of this matter cannot be determined at this time, but could have a significant impact on Southern Company's financial statements.
FERC Matters
Market-Based Rate Authority
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters – Market-Based Rate Authority" of Southern Company in Item 7 of the Form 10-K for additional information regarding the traditional electric operating companies' and Southern Power's market power proceeding and amendment to their market-rate tariff.
On May 17, 2017, the FERC accepted the traditional electric operating companies' and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' and Southern Power's market power proceeding related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' and Southern Power's June 30, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order, or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and Southern Power expect to make a filing within the specified 60 days responding to the FERC's order.
The ultimate outcome of these matters cannot be determined at this time.
Southern Company Gas
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters – Southern Company Gas" of Southern Company in Item 7 and Note 4 to the financial statements of Southern Company in Item 8 of the Form 10-K for additional information regarding Southern Company Gas' pipeline projects.
On August 1, 2017, the Dalton Pipeline was placed in service as authorized by the FERC and transportation service for customers commenced.
On October 13, 2017, the Atlantic Coast Pipeline project received FERC approval.
Regulatory Matters
Fuel Cost Recovery
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Fuel Cost Recovery" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Regulatory Matters – Alabama Power – Rate ECR" and "Regulatory Matters – Georgia Power – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding fuel cost recovery for the traditional electric operating companies.
The traditional electric operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
on Southern Company's revenues or net income, but will affect cash flow. The traditional electric operating companies continuously monitor their under or over recovered fuel cost balances and make appropriate filings with their state PSCs to adjust fuel cost recovery rates as necessary.
Renewables
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Renewables" of Southern Company in Item 7 of the Form 10-K for additional information regarding the Southern Company system's renewables activity.
On May 16, 2017, the Georgia PSC approved Georgia Power's request to build, own, and operate a 139-MW solar generation facility at a U.S. Air Force base that is expected to be placed in service by the end of 2019.
During the nine months ended September 30, 2017, Georgia Power continued construction of a 31-MW solar generation facility at a U.S. Marine Corps base that is expected to be placed in service in the fourth quarter 2017.
In 2015, the Florida PSC approved Gulf Power's three energy purchase agreements totaling 120 MWs of utility-scale solar generation located at three military installations in northwest Florida. Purchases under these agreements began in the summer of 2017.
Mississippi Power placed in service three solar projects in January, June, and October 2017. Mississippi Power may retire the renewable energy credits (REC) generated on behalf of its customers or sell the RECs, separately or bundled with energy, to third parties.
On August 17, 2017, the Mississippi PSC approved Mississippi Power's CPCN for the construction, operation, and maintenance of a 52.5-MW solar energy generating facility, which is expected to be placed in service by January 2020.
The ultimate outcome of these matters cannot be determined at this time.
Alabama Power
Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Alabama Power" in Item 8 of the Form 10-K for additional information regarding Alabama Power's rate mechanisms and accounting orders. The recovery balance of each regulatory clause for Alabama Power is reported in Note (B) to the Condensed Financial Statements herein.
Georgia Power
Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, Environmental Compliance Cost Recovery tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to the construction of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a separate fuel cost recovery tariff. See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein and Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding Georgia Power's NCCR tariff. Also see Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Fuel Cost Recovery" herein for additional information regarding Georgia Power's fuel cost recovery.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Integrated Resource Plan
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Georgia Power – Integrated Resource Plan" of Southern Company in Item 7 of the Form 10-K for additional information regarding Georgia Power's triennial Integrated Resource Plan.
On March 7, 2017, the Georgia PSC approved Georgia Power's decision to suspend work at a future generation site in Stewart County, Georgia, due to changing economics, including load forecasts and lower fuel costs. The timing of recovery for costs incurred of approximately $50 million will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time.
Storm Damage Recovery
Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, for incremental operating and maintenance costs of damage from major storms to its transmission and distribution facilities. During September 2017, Hurricane Irma caused significant damage to Georgia Power's transmission and distribution facilities. The total amount of incremental restoration costs related to this hurricane is estimated to be approximately $150 million. As of September 30, 2017, Georgia Power had deferred approximately $145 million in a regulatory asset related to storm damage. As of September 30, 2017, the total balance in Georgia Power's regulatory asset related to storm damage was $360 million. The rate of storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case required to be filed by July 1, 2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's financial statements. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Storm Damage Recovery" in Item 8 of the Form 10-K for additional information regarding Georgia Power's storm damage reserve.
Gulf Power
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Gulf Power" of Southern Company in Item 7 of the Form 10-K for additional information regarding Gulf Power's October 2016 request to the Florida PSC to increase retail base rates and Gulf Power's ownership of Plant Scherer Unit 3.
On April 4, 2017, the Florida PSC approved the 2017 Rate Case Settlement Agreement among Gulf Power and three intervenors with respect to Gulf Power's request to increase retail base rates. Among the terms of the 2017 Rate Case Settlement Agreement, Gulf Power increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consisted of a $62.0 million increase in annual base revenues less an annual equivalent credit of approximately $7.7 million for 2017 for certain wholesale revenues to be provided through December 2019 through the purchased power capacity cost recovery clause. In addition, Gulf Power continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%) and is deemed to have an equity ratio of 52.5% for all retail regulatory purposes. Gulf Power will also begin amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 (357 MWs) over 15 years effective January 1, 2018 and will implement new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs), which was recorded in the first quarter 2017. The remaining issues related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause rate approved by the Florida PSC in November 2016.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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Southern Company Gas
Natural Gas Cost Recovery
Southern Company Gas has established natural gas cost recovery rates approved by the relevant state regulatory agencies in the states in which it serves. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flows.
Base Rate Cases
On March 10, 2017, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $208 million increase in annual base rate revenues. The requested increase is based on a 2018 projected test year and a ROE of 10.7%. The Illinois Commission is expected to rule on the requested increase in December 2017, after which rate adjustments will be effective. The ultimate outcome of this matter cannot be determined at this time.
Construction Program
Overview
The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue its strategy of developing and constructing new electric generating facilities, adding environmental modifications to certain existing units, expanding the electric transmission and distribution systems, and updating and expanding the natural gas distribution systems. For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. Following Mississippi Power's suspension of the Kemper IGCC construction, the largest construction project currently underway in the Southern Company system is Plant Vogtle Units 3 and 4 (45.7% ownership interest by Georgia Power in the two units, each with approximately 1,100 MWs). In August 2017, Georgia Power filed its seventeenth VCM report with the Georgia PSC, in which it recommended that construction of Plant Vogtle Units 3 and 4 be continued, with Southern Nuclear serving as project manager. Georgia Power believes that the most reasonable schedule for completing Plant Vogtle Units 3 and 4 is by November 2021 for Unit 3 and by November 2022 for Unit 4, at an additional cost of approximately $1.41 billion, net of the Guarantee Settlement Agreement. The Georgia PSC is expected to make a decision on these and other related matters by February 6, 2018. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. Southern Company Gas is engaged in various infrastructure improvement programs designed to update or expand the natural gas distribution systems of the natural gas distribution utilities to improve reliability and meet operational flexibility and growth. The natural gas distribution utilities recover their investment and a return associated with these infrastructure programs through their regulated rates.
For additional information, see Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Nuclear Construction" and " – Southern Company Gas – Regulatory Infrastructure Programs" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters– Georgia Power – Nuclear Construction" and " – Southern Company Gas–Regulatory Infrastructure Programs" and "Integrated Coal Gasification Combined Cycle" herein. Also see Note 12 to the financial statements of Southern Company under "Southern Power – Construction Projects" in Item 8 of the Form 10-K and Note (I) to the Condensed Financial Statements under "Southern Power" herein.
Also see FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information regarding Southern Company's capital requirements for its subsidiaries' construction programs.
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Integrated Coal Gasification Combined Cycle
The Kemper IGCC was approved by the Mississippi PSC in the 2010 CPCN proceedings, subject to a construction cost cap of $2.88 billion, net of $245 million of Initial DOE Grants and excluding the Cost Cap Exceptions. The combined cycle and associated common facilities portion of the Kemper IGCC were placed in service in August 2014.
In December 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order), based on a stipulation between Mississippi Power and the MPUS, authorizing rates that provide for the recovery of approximately $126 million annually related to the combined cycle and associated common facilities portion of Kemper IGCC assets previously placed in service. As required by the In-Service Asset Rate Order, on June 5, 2017, Mississippi Power made a rate filing requesting to adjust the amortization schedules of the regulatory assets reviewed and determined prudent in a manner that would not change customer rates or annual revenues. On June 28, 2017, the Mississippi PSC suspended this filing. On July 6, 2017, the Mississippi PSC issued an order requiring Mississippi Power to establish a regulatory liability account to maintain current rates related to the Kemper IGCC following the July 2017 completion of the amortization period for certain regulatory assets approved in the In-Service Asset Rate Order that would allow for subsequent refund if the Mississippi PSC deems the rates unjust and unreasonable. At September 30, 2017, the related regulatory liability totaled $7 million.
The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO2, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast has decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations has increased significantly since certification.
On June 21, 2017, the Mississippi PSC stated its intent to issue the Kemper Settlement Order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC. The Kemper Settlement Order established the Kemper IGCC Settlement Docket for the purposes of pursuing a global settlement of costs of the Kemper IGCC. The Mississippi PSC requested any such proposed settlement agreement reflect: (i) at a minimum, no rate increase to Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and related assets; and (iii) modification or amendment of the CPCN for the Kemper IGCC to allow only for ownership and operation of a natural gas facility.
On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014. At the time of project suspension, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants.
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension,
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which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred.
Total pre-tax charges to income for the estimated probable losses on the Kemper IGCC were $34 million ($21 million after tax) for the third quarter 2017 and $3.2 billion ($2.2 billion after tax) for the nine months ended September 30, 2017. In the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $6.0 billion ($4.0 billion after tax) through September 30, 2017.
Mississippi Power reached and filed a settlement agreement on August 21, 2017 with certain parties (not including the MPUS), which it believes met the conditions of the Kemper Settlement Order. The settlement agreement provides for an annual revenue requirement of $126 million for Kemper IGCC-related costs, which would (i) be effective January 1, 2018, (ii) represent no rate increase for customers, and (iii) include no recovery for the costs associated with the gasifier portion of the Kemper IGCC in 2018 or at any future date. In addition, under the settlement agreement, the CPCN for the Kemper IGCC would be modified to limit the Kemper County energy facility to natural gas combined cycle operation and Mississippi Power would, in the future, file a reserve margin plan with the Mississippi PSC. The Mississippi PSC issued a scheduling order, as amended on October 5, 2017, noting Mississippi Power and the MPUS had failed to reach a joint stipulation and ordering a full hearing. The Mississippi PSC is expected to rule on an order resolving this matter in January 2018.
As of September 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which $0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility, as well as the 15% that was previously contracted to Cooperative Energy. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.
For additional information on the Kemper IGCC, including information on the project economic viability analysis, pending lawsuits, and an ongoing SEC investigation, see Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and "Other Matters" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein. Also see "Litigation" herein.
Litigation
On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff alleges that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper IGCC and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper IGCC; ask the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper IGCC in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper IGCC costs from being charged to customers through electric rates. On June 23, 2017, the Circuit
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Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the plaintiffs filed notice of an appeal.
On June 9, 2016, Treetop Midstream Services, LLC (Treetop) and other related parties filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint relates to the cancelled CO2 contract with Treetop and alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and seeks compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS moved to compel arbitration pursuant to the terms of the CO2 contract, which the court granted on May 4, 2017. On June 28, 2017, Treetop and other related parties filed a claim for arbitration requesting $500 million in damages.
Southern Company believes these legal challenges have no merit; however, an adverse outcome in these proceedings could have a material impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, and the ultimate outcome of these matters cannot be determined at this time.
Nuclear Construction
See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the construction of Plant Vogtle Units 3 and 4, VCM reports, the NCCR tariff, and the Contractor Settlement Agreement.
Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcy
In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Vogtle 3 and 4 Agreement, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4. Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. Georgia Power's proportionate share of Plant Vogtle Units 3 and 4 is 45.7%.
The Vogtle 3 and 4 Agreement also provided for liquidated damages upon the EPC Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to an aggregate cap of 10% of the contract price, or approximately $920 million (approximately $420 million based on Georgia Power's ownership interest). Under the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. In January 2016, Westinghouse delivered to the Vogtle Owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020 and require 60 days' written notice to Georgia Power in the event the Westinghouse Letters of Credit will not be renewed.
Under the terms of the Vogtle 3 and 4 Agreement, the EPC Contractor did not have the right to terminate the Vogtle 3 and 4 Agreement for convenience. In the event of an abandonment of work by the EPC Contractor, the maximum liability of the EPC Contractor under the Vogtle 3 and 4 Agreement was 40% of the contract price (approximately $1.7 billion based on Georgia Power's ownership interest).
On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. To provide for a continuation of work at Plant Vogtle Units 3 and 4, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Interim Assessment Agreement, which the bankruptcy court approved on March 30, 2017.
The Interim Assessment Agreement provided, among other items, that during the term of the Interim Assessment Agreement Georgia Power was obligated to pay, on behalf of the Vogtle Owners, all costs accrued by the EPC Contractor for subcontractors and vendors for services performed or goods provided. The Interim Assessment Agreement, as amended, expired on July 27, 2017.
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Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor, including Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken, and continues to take, actions to remove liens filed by these subcontractors through the posting of surety bonds. Georgia Power estimates the aggregate liability, through September 30, 2017, of the Vogtle Owners for the removal of subcontractor liens and payment of other EPC Contractor pre-petition accounts payable to total approximately $386 million, of which $340 million had been paid or accrued as of September 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $176 million.
On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into the Guarantee Settlement Agreement. Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion, of which Georgia Power's proportionate share is approximately $1.7 billion, and that the Guarantee Obligations exist regardless of whether Plant Vogtle Units 3 and 4 are completed. The Guarantee Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations, which will reduce CWIP, beginning in October 2017 and continuing through January 2021. In the event Toshiba receives certain payments, including sale proceeds, from or related to Westinghouse (or its subsidiaries) or Toshiba Nuclear Energy Holdings (UK) Limited (or its subsidiaries), it will hold a portion of such payments in trust for the Vogtle Owners and promptly pay them as offsets against any remaining Guarantee Obligations. Under the Guarantee Settlement Agreement, the Vogtle Owners will forbear from exercising certain remedies, including drawing on the Westinghouse Letters of Credit, until June 30, 2020, unless certain events of nonpayment, insolvency, or other material breach of the Guarantee Settlement Agreement by Toshiba occur. If such an event occurs, the balance of the Guarantee Obligations will become immediately due and payable, and the Vogtle Owners may exercise any and all rights and remedies, including drawing on the Westinghouse Letters of Credit without restriction. In addition, the Guarantee Settlement Agreement does not restrict the Vogtle Owners from fully drawing on the Westinghouse Letters of Credit in the event they are not renewed or replaced prior to the expiration date. On October 2, 2017, Georgia Power received the first installment of the Guarantee Obligations of $300 million from Toshiba, of which Georgia Power's proportionate share was $137 million. Georgia Power is considering potential options with respect to its right to future payments under the Guarantee Settlement Agreement and its claims against the EPC Contractor in the EPC Contractor's bankruptcy proceeding, including a potential sale of those payment rights and bankruptcy claims. Any such transaction cannot be assured and would be subject to DOE consents and related approvals under the Loan Guarantee Agreement and related agreements.
On August 10, 2017, Toshiba released its financial results for the quarter ended June 30, 2017, which reflected a negative shareholders' equity balance of approximately $4.5 billion as of June 30, 2017. Toshiba previously announced the existence of material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern. As a result, substantial risk regarding the Vogtle Owners' ability to fully collect the Guarantee Obligations continues to exist. An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Southern Company's financial statements.
Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Services Agreement, which was amended and restated on July 20, 2017, for the EPC Contractor to transition construction management of Plant Vogtle Units 3 and 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Services Agreement, (ii) assume and assign to the Vogtle Owners certain project-related contracts, (iii) join the Vogtle Owners as counterparties to certain assumed project-related contracts, and (iv) reject the Vogtle 3 and 4 Agreement. The Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE on July 27, 2017. The Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.
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Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into the Bechtel Agreement, whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4. Facility design and engineering remains the responsibility of the EPC Contractor under the Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. Pursuant to the Loan Guarantee Agreement, Georgia Power is required to obtain the DOE's approval of the Bechtel Agreement prior to obtaining any further advances under the Loan Guarantee Agreement.
In connection with the recommendation to continue with construction of Plant Vogtle Units 3 and 4 (described below), the Vogtle Owners agreed on a term sheet to amend the existing joint ownership agreements to provide for additional Vogtle Owner approval requirements. Under the term sheet, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including (i) the bankruptcy of Toshiba or a material breach by Toshiba of the Guarantee Settlement Agreement; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report by more than $1 billion or extension of the project schedule contained in the seventeenth VCM report by more than one year. In addition, under the term sheet, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Services Agreement or agreements with the primary construction contractor or Southern Nuclear.
The term sheet also confirms that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.
The ultimate outcome of these matters cannot be determined at this time.
Regulatory Matters
In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by including the related CWIP accounts in rate base during the construction period. As of September 30, 2017, Georgia Power had recovered approximately $1.5 billion of financing costs. Georgia Power expects to file on November 1, 2017 to increase the NCCR tariff by approximately $90 million, effective January 1, 2018, pending Georgia PSC approval.
On December 20, 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving the following prudence matters: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report will be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement is reasonable and prudent and none of the amounts paid or to be paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) financing costs on verified and approved capital costs will be deemed prudent provided they are
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incurred prior to December 31, 2019 and December 31, 2020 for Plant Vogtle Units 3 and 4, respectively; and (iv) (a) the in-service capital cost forecast will be adjusted to $5.680 billion (Revised Forecast), which includes a contingency of $240 million above Georgia Power's then current forecast of $5.440 billion, (b) capital costs incurred up to the Revised Forecast will be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, and (c) Georgia Power would have the burden to show that any capital costs above the Revised Forecast are reasonable and prudent. Under the terms of the Vogtle Cost Settlement Agreement, the certified in-service capital cost for purposes of calculating the NCCR tariff will remain at $4.418 billion. Construction capital costs above $4.418 billion will accrue AFUDC through the date each unit is placed in service. The ROE used to calculate the NCCR tariff was reduced from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016. For purposes of the AFUDC calculation, the ROE on costs between $4.418 billion and $5.440 billion will also be 10.00% and the ROE on any amounts above $5.440 billion would be Georgia Power's average cost of long-term debt. If the Georgia PSC adjusts Georgia Power's ROE rate setting point in a rate case prior to Plant Vogtle Units 3 and 4 being placed into retail rate base, then the ROE for purposes of calculating both the NCCR tariff and AFUDC will likewise be 95 basis points lower than the revised ROE rate setting point. If Plant Vogtle Units 3 and 4 are not placed in service by December 31, 2020, then (i) the ROE for purposes of calculating the NCCR tariff will be reduced an additional 300 basis points, or $8 million per month, and may, at the Georgia PSC's discretion, be accrued to be used for the benefit of customers, until such time as the units are placed in service and (ii) the ROE used to calculate AFUDC will be Georgia Power's average cost of long-term debt.
The Georgia PSC has approved sixteen VCM reports covering the periods through December 31, 2016, including construction capital costs incurred, which through that date totaled $3.9 billion. Georgia Power filed its seventeenth VCM report, covering the period from January 1 through June 30, 2017, requesting approval of $542 million of construction capital costs incurred during that period, with the Georgia PSC on August 31, 2017.
In the seventeenth VCM report, Georgia Power recommended that construction of Plant Vogtle Units 3 and 4 be continued, with Southern Nuclear serving as project manager. Georgia Power believes that the most reasonable schedule for completing Plant Vogtle Units 3 and 4 is by November 2021 for Unit 3 and by November 2022 for Unit 4. Georgia Power's recommendation to go forward with completion of Vogtle Units 3 and 4 is based on the following assumptions about the regulatory treatment of this recommendation, if the recommendation to go forward is adopted by the Georgia PSC: (i) that pursuant to Georgia law, the Georgia PSC in the seventeenth VCM proceeding approves the new cost and schedule forecast and finds that it is a reasonable basis for going forward, and that if the Georgia PSC disapproves all or part of the proposed cost and schedule revisions, Georgia Power may cancel Plant Vogtle Units 3 and 4 and recover its actual investment in Plant Vogtle Units 3 and 4; (ii) that the Vogtle Cost Settlement Agreement remains in full force and effect, including Georgia Power retaining the burden of proving all capital costs above $5.680 billion were prudent; (iii) that while the Georgia PSC will make no prudence finding in the seventeenth VCM proceeding, nor will the certified amount be amended consistent with the Vogtle Cost Settlement Agreement, the Georgia PSC recognizes that the certified amount is not a cap, and all costs that are approved and presumed or shown to be prudently incurred will be recoverable by Georgia Power; (iv) that Georgia Power is not a guarantor of the Toshiba Guarantee, and the failure of Toshiba to pay the Toshiba Guarantee, the failure of the U.S. Congress to extend the PTCs for Plant Vogtle Units 3 and 4, or the failure of the DOE to extend the Loan Guarantee Agreement with Georgia Power to reflect the increased capital amounts, will not reduce the amount of investment Georgia Power is otherwise allowed to collect; and (v) that as conditions change and assumptions are either proven or disproven, Georgia Power and the Georgia PSC may reconsider the decision to go forward. The Georgia PSC is expected to make a decision on these matters by February 6, 2018.
The ultimate outcome of these matters cannot be determined at this time.
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Revised Cost and Schedule
Georgia Power's approximate proportionate share of the remaining estimated cost to complete Plant Vogtle Units 3 and 4 is as follows:
|
| | | |
| | (in billions) |
| Estimated cost to complete | $ | 4.2 |
|
| CWIP as of September 30, 2017 | 4.6 |
|
| Guarantee Obligations | (1.7 | ) |
| Estimated capital costs | $ | 7.1 |
|
| Vogtle Cost Settlement Agreement Revised Forecast | (5.7 | ) |
| Estimated net additional capital costs | $ | 1.4 |
|
Georgia Power's estimated financing costs during the construction period total approximately $3.4 billion, of which approximately $1.5 billion had been incurred through September 30, 2017.
Georgia Power's cancellation cost estimate results indicate that its proportionate share of the estimated costs to cancel both units is approximately $350 million. As a result, as of September 30, 2017, total estimated costs subject to evaluation by Georgia Power and the Georgia PSC in the event of a cancellation decision are as follows:
|
| | | |
| | Cancellation Cost Estimate |
| | (in billions) |
| CWIP as of September 30, 2017 | $ | 4.6 |
|
| Financing costs collected, net of tax | 1.5 |
|
Cancellation costs(*) | 0.4 |
|
| Guarantee Obligations | (1.7 | ) |
| Estimated net cancellation cost | $ | 4.8 |
|
| |
(*) | The estimate for cancellation costs includes, but is not limited to, costs to terminate contracts for construction and other services, as well as costs to secure the Plant Vogtle Units 3 and 4 construction site. |
The Guarantee Obligations continue to exist in the event of cancellation. In addition, under Georgia law, prudently incurred costs related to certificated projects cancelled by the Georgia PSC are allowed recovery, including carrying costs, in future retail rates. Georgia Power will continue working with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4, including, but not limited to, the status of construction and rate recovery.
The ultimate outcome of these matters cannot be determined at this time.
Other Matters
As of September 30, 2017, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through the Loan Guarantee Agreement and a multi-advance credit facility among Georgia Power, the DOE, and the FFB, which provides for borrowings of up to $3.46 billion, subject to the satisfaction of certain conditions. On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to the financial statements of Southern Company under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
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The IRS has allocated PTCs to Plant Vogtle Units 3 and 4 which require that the applicable unit be placed in service prior to 2021. The net present value of Georgia Power's PTCs is estimated at approximately $400 million per unit.
There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise while construction proceeds. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise while construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.
While construction continues, the risk remains that challenges with management of contractors, subcontractors, and vendors, labor productivity, fabrication, delivery, assembly, and installation of plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost.
The ultimate outcome of these matters cannot be determined at this time.
See RISK FACTORS of Southern Company in Item 1A of the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world. See additional risks in Item 1A herein regarding the EPC Contractor's bankruptcy.
Income Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Southern Company in Item 7 of the Form 10-K and Note (G) to the Condensed Financial Statements herein for additional information.
Bonus Depreciation
Excluding the Kemper IGCC, approximately $830 million of positive cash flows is expected to result from bonus depreciation for the 2017 tax year. All projected tax benefits previously received for bonus depreciation related to the Kemper IGCC were repaid in connection with third quarter 2017 estimated tax payments. If the suspension of the Kemper IGCC start-up activities ultimately results in an abandonment for income tax purposes, the related deduction would be claimed in the year of the abandonment. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein and Note (G) to the Condensed Financial Statements herein for additional information. The ultimate outcome of this matter cannot be determined at this time.
Section 174 Research and Experimental Deduction
Southern Company has reflected deductions for R&E expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation (JCT), resolving a methodology for these deductions. As a result of the JCT approval, Southern Company recognized $176 million of previously unrecognized tax benefits and reversed $36 million of associated accrued interest. See Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Section 174 Research and Experimental Deduction," respectively, herein for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Power
During the third quarter 2017, Southern Power began a legal entity reorganization of various direct and indirect subsidiaries that own and operate solar facilities, including certain subsidiaries owned in partnership with various third parties. Southern Power's ownership interests in the various solar entities and facilities will not be affected by the reorganization. The reorganization is expected to result in estimated tax benefits totaling approximately $40 million that will be recorded in the fourth quarter 2017 related to certain changes in state apportionment rates and net operating loss carryforward utilization. The ultimate outcome of this matter cannot be determined at this time.
Other Matters
Southern Company and its subsidiaries are involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. The business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
On January 20, 2017, a purported securities class action complaint was filed against Southern Company, certain of its officers, and certain former Mississippi Power officers in the U.S. District Court for the Northern District of Georgia, Atlanta Division, by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint alleges that Southern Company, certain of its officers, and certain former Mississippi Power officers made materially false and misleading statements regarding the Kemper IGCC in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. On June 12, 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. On July 27, 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition on September 11, 2017.
On February 27, 2017, Jean Vineyard filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the defendants caused Southern Company to make false or misleading statements regarding the Kemper IGCC cost and schedule. Further, the complaint alleges that the defendants were unjustly enriched and caused the waste of corporate assets. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on her own behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. On March 27, 2017, the court deferred this lawsuit until 30 days after certain further action in the purported securities class action complaint discussed above.
On May 15, 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia and, on May 31, 2017, Judy Mesirov filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. Each
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper IGCC. Each complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper IGCC schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. On August 15, 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia and the court deferred the consolidated case until 30 days after certain further action in the purported securities class action complaint discussed above.
Southern Company believes these legal challenges have no merit; however, an adverse outcome in any of these proceedings could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, the ultimate outcome of which cannot be determined at this time.
The SEC is conducting a formal investigation of Southern Company and Mississippi Power concerning the estimated costs and expected in-service date of the Kemper IGCC. Southern Company believes the investigation is focused primarily on periods subsequent to 2010 and on accounting matters, disclosure controls and procedures, and internal controls over financial reporting associated with the Kemper IGCC. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" herein for additional information on the Kemper IGCC. The ultimate outcome of this matter cannot be determined at this time; however, it is not expected to have a material impact on the financial statements of Southern Company.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Company in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Company in Item 7 of the Form 10-K for a complete discussion of Southern Company's critical accounting policies and estimates related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, Goodwill and Other Intangible Assets, Derivatives and Hedging Activities, and Contingent Obligations.
Kemper IGCC Rate Recovery
For periods prior to the second quarter 2017, significant accounting estimates included Kemper IGCC estimated construction costs, project completion date, and rate recovery. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Kemper IGCC Estimated Construction Costs, Project Completion Date, and Rate Recovery" of Southern Company in Item 7 of the Form 10-K for additional information. Mississippi Power recorded total pre-tax charges to income related to the Kemper IGCC of $428 million ($264 million after tax) in 2016, $365 million ($226 million after tax) in 2015, $868 million ($536 million after tax) in 2014, and $1.2 billion ($729 million after tax) in prior years.
As a result of the Mississippi PSC's June 21, 2017 stated intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant rather than an IGCC plant, as well as Mississippi Power's June 28, 2017 suspension of the operation and start-up of the gasifier portion of the Kemper IGCC, the estimated construction costs and project completion date are no longer considered significant accounting estimates. Significant accounting estimates
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
for the September 30, 2017 financial statements presented herein include the overall assessment of rate recovery for the Kemper County energy facility and the estimated costs for the potential cancellation of the Kemper IGCC.
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred.
As of September 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which $0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility, as well as the 15% that was previously contracted to Cooperative Energy. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.
In the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $6.00 billion ($3.96 billion after tax) through September 30, 2017. Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $34 million ($21 million after tax) and $88 million ($54 million after tax) in the third quarter 2017 and the third quarter 2016, respectively, and total pre-tax charges of $3.2 billion ($2.2 billion after tax) and $222 million ($137 million after tax) year-to-date in 2017 and 2016, respectively.
Given the significant judgment involved in estimating the costs to cancel the gasifier portion of the Kemper IGCC, the ultimate rate recovery for the Kemper IGCC, including the $0.5 billion of combined cycle-related costs not yet in rates, and the impact on Southern Company's results of operations, Southern Company considers these items to be critical accounting estimates. See Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Recently Issued Accounting Standards
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Southern Company in Item 7 of the Form 10-K for additional information.
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
While Southern Company expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Southern Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity or natural gas without a defined
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
contractual term, as well as longer-term contractual commitments, including PPAs and non-derivative natural gas asset management and optimization arrangements. Southern Company expects the adoption of ASC 606 will not result in a significant shift from the current timing of revenue recognition for such transactions.
Southern Company's ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements, such as certain PPAs, energy-related derivatives, and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Southern Company's financial statements. In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Southern Company expects CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Southern Company intends to use the modified retrospective method of adoption effective January 1, 2018. Southern Company has also elected to utilize practical expedients which allow it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Southern Company's financial statements, Southern Company will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.
On January 26, 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for annual and interim periods beginning on or after December 15, 2019, and early adoption is permitted on testing dates after January 1, 2017. Southern Company is evaluating the standard and expects to early adopt ASU 2017-04 effective January 1, 2018.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Southern Company's financial statements.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with early adoption permitted. Southern Company is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on Southern Company's financial statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company in Item 7 of the Form 10-K for additional information. Southern Company's financial condition remained stable at September 30, 2017. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $5.3 billion for the first nine months of 2017, an increase of $1.0 billion from the corresponding period in 2016. The increase in net cash provided from operating activities was primarily due to an increase of $1.5 billion in net cash provided from operating activities of Southern Company Gas, which was acquired on July 1, 2016, partially offset by the timing of vendor payments. Net cash used for investing activities totaled $6.7 billion for the first nine months of 2017 primarily due to the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities, capital expenditures for Southern Company Gas' infrastructure replacement programs, and Southern Power's renewable acquisitions. Net cash provided from financing activities totaled $1.3 billion for the first nine months of 2017 primarily due to net issuances of long-term and short-term debt, partially offset by common stock dividend payments. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first nine months of 2017 include an increase of $1.3 billion in total property, plant, and equipment primarily related to the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities, Southern Company Gas' infrastructure replacement programs, and Southern Power's renewable acquisitions, largely offset by the $2.9 billion write-down of the gasification portions of the Kemper IGCC; a decrease of $0.4 billion in income taxes receivable, current and unrecognized tax benefits primarily related to income tax refunds associated with deductible R&E expenditures; a decrease of $0.5 billion in acquisitions payable related to Southern Power; an increase of $2.3 billion in long-term debt (including amounts due within one year) primarily to fund the Southern Company system's continuous construction programs and for general corporate purposes; and a decrease of $0.7 billion in total common stockholder's equity primarily related to the estimated probable losses on the Kemper IGCC, partially offset by the issuance of additional shares of common stock.
At the end of the third quarter 2017, the market price of Southern Company's common stock was $49.14 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $23.99 per share, representing a market-to-book ratio of 205%, compared to $49.19, $25.00, and 197%, respectively, at the end of 2016. Southern Company's common stock dividend for the third quarter 2017 was $0.58 per share compared to $0.56 per share in the third quarter 2016.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company in Item 7 of the Form 10-K for a description of Southern Company's capital requirements for the construction programs of the Southern Company system, including estimated capital expenditures for new electric generating facilities and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, derivative
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
obligations, preferred and preference stock dividends, leases, purchase commitments, pipeline charges, storage capacity, and gas supply, asset management agreements, standby letters of credit and performance/surety bonds, trust funding requirements, and unrecognized tax benefits. Subsequent to September 30, 2017, Alabama Power repaid at maturity $325 million aggregate principal amount of its Series Q 5.50% Senior Notes due October 15, 2017. An additional $3.2 billion will be required through September 30, 2018 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.
The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; state regulatory agency approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Additionally, planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power's ability to execute its growth strategy. See Note 12 to the financial statements of Southern Company under "Southern Power" in Item 8 of the Form 10-K and Note (I) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding Southern Power's plant acquisitions. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein for information regarding additional factors that may impact construction expenditures, including Georgia Power's cost-to-complete and cancellation cost assessments for Plant Vogtle Units 3 and 4.
Sources of Capital
Southern Company intends to meet its future capital needs through operating cash flows, short-term debt, term loans, and external security issuances. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings. The amount and timing of additional equity capital and debt issuances in 2017, as well as in subsequent years, will be contingent on Southern Company's investment opportunities and the Southern Company system's capital requirements and will depend upon prevailing market conditions and other factors. See "Capital Requirements and Contractual Obligations" herein for additional information.
Except as described herein, the traditional electric operating companies, Southern Power, and Southern Company Gas plan to obtain the funds required for construction and other purposes from operating cash flows, external security issuances, term loans, short-term borrowings, and equity contributions or loans from Southern Company. In addition, Southern Power plans to utilize tax equity partnership contributions. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Company in Item 7 of the Form 10-K for additional information.
In addition, in 2014, Georgia Power entered into the Loan Guarantee Agreement with the DOE, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4. Under the Loan Guarantee Agreement, the DOE agreed to guarantee borrowings of up to $3.46 billion (not to exceed 70% of (i) Eligible Project Costs, less (ii) amounts received from Toshiba under the Guarantee Settlement Agreement and amounts received from the Westinghouse bankruptcy proceeding) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. As of September 30, 2017, Georgia Power had borrowed $2.6 billion under the FFB Credit Facility. On July 27, 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement, which provides that further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement and satisfaction of certain other conditions.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion of additional guaranteed loans under the Loan Guarantee Agreement. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to the financial statements of Southern Company under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information regarding the Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and additional conditions to borrowing. Also see Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
As of September 30, 2017, Southern Company's current liabilities exceeded current assets by $3.4 billion due to long-term debt that is due within one year of $3.5 billion (comprised of approximately $1.0 billion at the parent company, $0.3 billion at Alabama Power, $0.3 billion at Georgia Power, $1.0 billion at Mississippi Power, and $0.9 billion at Southern Power) and notes payable of $2.6 billion (comprised of approximately $1.1 billion at the parent company, $0.4 billion at Georgia Power, $0.1 billion at Southern Power, and $0.9 billion at Southern Company Gas). To meet short-term cash needs and contingencies, the Southern Company system has substantial cash flow from operating activities and access to capital markets and financial institutions. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas intend to utilize operating cash flows, as well as commercial paper, lines of credit, bank notes, and securities issuances, as market conditions permit, as well as, under certain circumstances for the traditional electric operating companies, Southern Power, and Southern Company Gas, equity contributions and/or loans from Southern Company to meet their short-term capital needs.
At September 30, 2017, Southern Company and its subsidiaries had approximately $1.8 billion of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2017 were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Expires | | | | Executable Term Loans | | Expires Within One Year |
| Company | 2017 | 2018 | 2019 | 2020 | 2022 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out |
| | (in millions) |
Southern Company(a) | $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 2,000 |
| | $ | 2,000 |
| | $ | 2,000 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Alabama Power | — |
| 35 |
| — |
| 500 |
| 800 |
| | 1,335 |
| | 1,335 |
| | — |
| | — |
| | — |
| | 35 |
|
| Georgia Power | — |
| — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,732 |
| | — |
| | — |
| | — |
| | — |
|
| Gulf Power | 30 |
| 195 |
| 25 |
| 30 |
| — |
| | 280 |
| | 280 |
| | 45 |
| | — |
| | — |
| | 40 |
|
| Mississippi Power | 100 |
| — |
| — |
| — |
| — |
| | 100 |
| | 100 |
| | — |
| | — |
| | — |
| | 100 |
|
Southern Power Company(b) | — |
| — |
| — |
| — |
| 750 |
| | 750 |
| | 728 |
| | — |
| | — |
| | — |
| | — |
|
Southern Company Gas(c) | — |
| — |
| — |
| — |
| 1,900 |
| | 1,900 |
| | 1,861 |
| | — |
| | — |
| | — |
| | — |
|
| Other | — |
| 30 |
| — |
| — |
| — |
| | 30 |
| | 30 |
| | 20 |
| | — |
| | 20 |
| | 10 |
|
| Southern Company Consolidated | $ | 130 |
| $ | 260 |
| $ | 25 |
| $ | 530 |
| $ | 7,200 |
| | $ | 8,145 |
| | $ | 8,066 |
| | $ | 65 |
| | $ | — |
| | $ | 20 |
| | $ | 185 |
|
| |
(a) | Represents the Southern Company parent entity. |
| |
(b) | Does not include Southern Power's $120 million continuing letter of credit facility for standby letters of credit expiring in 2019, of which $111 million has been used for letters of credit and $9 million remains unused at September 30, 2017.
|
| |
(c) | Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.2 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $700 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas.
|
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
See Note 6 to the financial statements of Southern Company under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
As reflected in the table above, in May 2017, Southern Company, Alabama Power, Georgia Power, and Southern Power Company each amended certain of their multi-year credit arrangements, which, among other things, extended the maturity dates from 2020 to 2022. Southern Company and Southern Power Company increased their borrowing ability under these arrangements to $2.0 billion from $1.25 billion and to $750 million from $600 million, respectively. Southern Company also terminated its $1.0 billion facility maturing in 2018. Also in May 2017, Southern Company Gas Capital and Nicor Gas terminated their existing credit arrangements for $1.3 billion and $700 million, respectively, which were to mature in 2017 and 2018, and entered into a new multi-year credit arrangement currently allocated for $1.2 billion and $700 million, respectively, with a maturity date of 2022. Pursuant to the new multi-year credit arrangement, the allocations may be adjusted. In September 2017, Alabama Power amended its $500 million multi-year credit arrangement, which, among other things, extended the maturity date from 2018 to 2020.
Most of these bank credit arrangements, as well as the term loan arrangements of Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Power Company, contain covenants that limit debt levels and contain cross-acceleration or cross-default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of the individual company. Such cross-default provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness or guarantee obligations over a specified threshold. Such cross-acceleration provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2017, Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas were in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the unused credit with banks is allocated to provide liquidity support to the pollution control revenue bonds of the traditional electric operating companies and the commercial paper programs of Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas. The amount of variable rate pollution control revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of September 30, 2017 was approximately $1.5 billion as compared to $1.9 billion at December 31, 2016. In June 2017, Georgia Power remarketed $318 million of variable rate pollution control bonds in index rate modes, reducing the liquidity support utilized under Georgia Power's bank credit arrangement. In addition, at September 30, 2017, the traditional electric operating companies had approximately $699 million of pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to September 30, 2017, $40 million of these pollution control revenue bonds of Georgia Power which were in an index rate mode were remarketed to the public in a long-term fixed rate mode.
Southern Company, the traditional electric operating companies (other than Mississippi Power), Southern Power Company, Southern Company Gas, and Nicor Gas make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Short-term borrowings are included in notes payable in the balance sheets.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of short-term borrowings were as follows:
|
| | | | | | | | | | | | | | | | | | |
| | | Short-term Debt at September 30, 2017 | | Short-term Debt During the Period(*) |
| | | Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) | | | | (in millions) |
| Commercial paper | | $ | 1,725 |
| | 1.5 | % | | $ | 1,895 |
| | 1.5 | % | | $ | 2,284 |
|
| Short-term bank debt | | 854 |
| | 2.0 | % | | 938 |
| | 2.1 | % | | 1,017 |
|
| Total | | $ | 2,579 |
| | 1.7 | % | | $ | 2,833 |
| | 1.7 | % | | |
| |
(*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2017. |
Southern Company believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, bank term loans, and operating cash flows.
Credit Rating Risk
At September 30, 2017, Southern Company and its subsidiaries did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain subsidiaries to BBB and/or Baa2 or below. These contracts are for physical electricity and natural gas purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, and interest rate management.
The maximum potential collateral requirements under these contracts at September 30, 2017 were as follows:
|
| | | |
| Credit Ratings | Maximum Potential
Collateral
Requirements |
| | (in millions) |
| At BBB and/or Baa2 | $ | 38 |
|
| At BBB- and/or Baa3 | $ | 647 |
|
At BB+ and/or Ba1(*) | $ | 2,352 |
|
| |
(*) | Any additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $38 million. |
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Company and its subsidiaries to access capital markets, and would be likely to impact the cost at which they do so.
On March 1, 2017, Moody's downgraded the senior unsecured debt rating of Mississippi Power to Ba1 from Baa3.
On March 20, 2017, Moody's revised its rating outlook for Georgia Power from stable to negative.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including the traditional electric operating companies, Southern Power, Southern Company Gas, Southern Company Gas Capital, and Nicor Gas) from stable to negative.
On March 30, 2017, Fitch placed the ratings of Southern Company, Georgia Power, and Mississippi Power on rating watch negative.
On June 22, 2017, Moody's placed the ratings of Mississippi Power on review for downgrade. On September 21, 2017, Moody's revised its rating outlook for Mississippi Power from under review to stable.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Financing Activities
During the first nine months of 2017, Southern Company issued approximately 10.6 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $479 million.
In addition, during the second and third quarters of 2017, Southern Company issued a total of approximately 2.7 million shares of common stock through at-the-market issuances pursuant to sales agency agreements related to Southern Company's continuous equity offering program and received cash proceeds of approximately $134 million, net of $1.1 million in fees and commissions.
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first nine months of 2017:
|
| | | | | | | | | | | | | | | | | | | |
| Company | Senior Note Issuances | | Senior Note Maturities and Redemptions | | Revenue Bond Maturities, Redemptions, and Repurchases | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(a) |
| | (in millions) |
Southern Company(b) | $ | 300 |
| | $ | 400 |
| | $ | — |
| | $ | 500 |
| | $ | 400 |
|
| Alabama Power | 550 |
| | 200 |
| | 36 |
| | — |
| | — |
|
| Georgia Power | 1,350 |
| | 450 |
| | 65 |
| | 370 |
| | 13 |
|
| Gulf Power | 300 |
| | 85 |
| | — |
| | 6 |
| | — |
|
| Mississippi Power | — |
| | — |
| | — |
| | 40 |
| | 893 |
|
| Southern Power | — |
| | — |
| | — |
| | 43 |
| | 4 |
|
Southern Company Gas(c) | 450 |
| | — |
| | — |
| | 200 |
| | 22 |
|
| Other | — |
| | — |
| | — |
| | — |
| | 12 |
|
Elimination(d) | — |
| | — |
| | — |
| | (40 | ) | | (599 | ) |
| Southern Company Consolidated | $ | 2,950 |
| | $ | 1,135 |
| | $ | 101 |
| | $ | 1,119 |
| | $ | 745 |
|
| |
(a) | Includes reductions in capital lease obligations resulting from cash payments under capital leases. |
| |
(b) | Represents the Southern Company parent entity. |
| |
(c) | The senior notes were issued by Southern Company Gas Capital and guaranteed by the Southern Company Gas parent entity. Other long-term debt issued represents first mortgage bonds issued by Nicor Gas.
|
| |
(d) | Includes intercompany loans from Southern Company to Mississippi Power and reductions in affiliate capital lease obligations at Georgia Power. These transactions are eliminated in Southern Company's Consolidated Financial Statements. |
In March 2017, Southern Company repaid at maturity a $400 million 18-month floating rate bank loan.
In June 2017, Southern Company issued $500 million aggregate principal amount of Series 2017A 5.325% Junior Subordinated Notes due June 21, 2057 and $300 million aggregate principal amount of Series 2017A Floating Rate Senior Notes due September 30, 2020, which bear interest at a floating rate based on three-month LIBOR. The proceeds were used to repay short-term indebtedness and for other general corporate purposes.
Also in June 2017, Southern Company entered into two $100 million aggregate principal amount floating rate bank term loan agreements, which mature on June 21, 2018 and June 29, 2018 and bear interest based on one-month LIBOR. The proceeds were used for working capital and other general corporate purposes.
In August 2017, Southern Company borrowed $250 million pursuant to an uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Southern Company and the bank from time to time and is payable on no less than 30 days' demand by the bank. The proceeds were used for working capital and other general corporate purposes.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Also in August 2017, Southern Company repaid at maturity $400 million aggregate principal amount of Series 2014A 1.30% Senior Notes.
Except as described herein, Southern Company's subsidiaries used the proceeds of the debt issuances shown in the table above for their redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including their continuous construction programs.
In September 2017, Alabama Power issued 10 million shares ($250 million aggregate stated capital) of 5.00% Class A Preferred Stock, Cumulative, Par Value $1 Per Share (Stated Capital $25 Per Share). The proceeds were used in October 2017 to redeem all 2 million shares ($50 million aggregate stated capital) of Alabama Power's 6.50% Series Preference Stock, 6 million shares ($150 million aggregate stated capital) of Alabama Power's 6.45% Series Preference Stock, and 1.52 million shares ($38 million aggregate stated capital) of Alabama Power's 5.83% Class A Preferred Stock and for other general corporate purposes, including Alabama Power's continuous construction program.
Subsequent to September 30, 2017, Alabama Power repaid at maturity $325 million aggregate principal amount of Series Q 5.50% Senior Notes due October 15, 2017.
In June 2017, Georgia Power entered into three floating rate bank loans in aggregate principal amounts of $50 million, $150 million, and $100 million, with maturity dates of December 1, 2017, May 31, 2018, and June 28, 2018, respectively, which bear interest based on one-month LIBOR. Also in June 2017, Georgia Power borrowed $500 million pursuant to an uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Georgia Power and the bank from time to time and is payable on no less than 30 days' demand by the bank. The proceeds from these bank loans were used to repay a portion of Georgia Power's existing indebtedness and for working capital and other general corporate purposes, including Georgia Power's continuous construction program.
In August 2017, Georgia Power repaid its $50 million floating rate bank loan due December 1, 2017 and $250 million of the $500 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement. Also in August 2017, Georgia Power amended its $100 million floating rate bank loan to extend the maturity date from June 28, 2018 to October 26, 2018.
As reflected in the table above under other long-term debt issuances, in September 2017, Georgia Power issued $270 million aggregate principal amount of Series 2017A 5.00% Junior Subordinated Notes due October 1, 2077. The proceeds were used in October 2017 to redeem all 1.8 million shares ($45 million aggregate liquidation amount) of Georgia Power's 6.125% Series Class A Preferred Stock and 2.25 million shares ($225 million aggregate liquidation amount) of Georgia Power's 6.50% Series 2007A Preference Stock.
In March 2017, Gulf Power extended the maturity of a $100 million short-term floating rate bank loan bearing interest based on one-month LIBOR from April 2017 to October 2017 and subsequently repaid the loan in May 2017.
A portion of the proceeds of Gulf Power's senior note issuances was used in June 2017 to redeem 550,000 shares ($55 million aggregate liquidation amount) of Gulf Power's 6.00% Series Preference Stock, 450,000 shares ($45 million aggregate liquidation amount) of Gulf Power's Series 2007A 6.45% Preference Stock, and 500,000 shares ($50 million aggregate liquidation amount) of Gulf Power's Series 2013A 5.60% Preference Stock.
In June 2017, Mississippi Power prepaid $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018.
In September 2017, Southern Power amended its $60 million aggregate principal amount floating rate bank loan to, among other things, increase the aggregate principal amount to $100 million and extend the maturity date from September 2017 to October 2018. The additional $40 million of proceeds were used to repay existing indebtedness and for other general corporate purposes.
In July 2017, Nicor Gas agreed to issue $400 million aggregate principal amount of first mortgage bonds in a private placement. On August 10, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.03% Series due August 10, 2027 and $100 million aggregate principal amount of First Mortgage
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Bonds 3.62% Series due August 10, 2037. The proceeds were used to repay short-term indebtedness incurred under the Nicor Gas commercial paper program and for other working capital needs. The remaining $200 million is expected to be issued in November 2017.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company and its subsidiaries plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
PART I
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
During the nine months ended September 30, 2017, there were no material changes to Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, and Southern Power's disclosures about market risk. For additional market risk disclosures relating to Gulf Power and Southern Company Gas, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Gulf Power and Southern Company Gas, respectively, herein. For an in-depth discussion of each registrant's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of each registrant in Item 7 of the Form 10-K and Note 1 to the financial statements of each registrant under "Financial Instruments," Note 11 to the financial statements of Southern Company, Alabama Power, and Georgia Power, Note 10 to the financial statements of Gulf Power, Mississippi Power, and Southern Company Gas, and Note 9 to the financial statements of Southern Power in Item 8 of the Form 10-K. Also see Note (C) and Note (H) to the Condensed Financial Statements herein for information relating to derivative instruments.
Item 4. Controls and Procedures.
| |
(a) | Evaluation of disclosure controls and procedures. |
As of the end of the period covered by this Quarterly Report on Form 10-Q, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas conducted separate evaluations under the supervision and with the participation of each company's management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Sections 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended). Based upon these evaluations, the Chief Executive Officer and the Chief Financial Officer, in each case, concluded that the disclosure controls and procedures are effective.
| |
(b) | Changes in internal controls over financial reporting. |
There have been no changes in Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended) during the third quarter 2017 that have materially affected or are reasonably likely to materially affect Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting.
ALABAMA POWER COMPANY
ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | |
| Retail revenues | $ | 2,008 | | | $ | 1,651 | | | $ | 5,015 | | | $ | 4,357 | |
| Wholesale revenues, non-affiliates | 250 | | | 107 | | | 522 | | | 285 | |
| Wholesale revenues, affiliates | 70 | | | 53 | | | 170 | | | 109 | |
| Other revenues | 116 | | | 93 | | | 316 | | | 268 | |
| Total operating revenues | 2,444 | | | 1,904 | | | 6,023 | | | 5,019 | |
| Operating Expenses: | | | | | | | |
| Fuel | 666 | | | 373 | | | 1,399 | | | 927 | |
| Purchased power, non-affiliates | 185 | | | 76 | | | 347 | | | 173 | |
| Purchased power, affiliates | 113 | | | 45 | | | 260 | | | 114 | |
| Other operations and maintenance | 418 | | | 401 | | | 1,270 | | | 1,175 | |
| Depreciation and amortization | 220 | | | 214 | | | 652 | | | 640 | |
| Taxes other than income taxes | 106 | | | 99 | | | 309 | | | 303 | |
| Total operating expenses | 1,708 | | | 1,208 | | | 4,237 | | | 3,332 | |
| Operating Income | 736 | | | 696 | | | 1,786 | | | 1,687 | |
| Other Income and (Expense): | | | | | | | |
| Allowance for equity funds used during construction | 18 | | | 14 | | | 51 | | | 38 | |
| Interest expense, net of amounts capitalized | (98) | | | (84) | | | (278) | | | (252) | |
| Other income (expense), net | 38 | | | 29 | | | 101 | | | 93 | |
| Total other income and (expense) | (42) | | | (41) | | | (126) | | | (121) | |
| Earnings Before Income Taxes | 694 | | | 655 | | | 1,660 | | | 1,566 | |
| Income taxes | 166 | | | 152 | | | 394 | | | 366 | |
| Net Income | 528 | | | 503 | | | 1,266 | | | 1,200 | |
| Dividends on Preferred Stock | 3 | | | 4 | | | 10 | | | 11 | |
| Net Income After Dividends on Preferred Stock | $ | 525 | | | $ | 499 | | | $ | 1,256 | | | $ | 1,189 | |
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | |
| Retail revenues | $ | 1,595 |
| | $ | 1,629 |
| | $ | 4,155 |
| | $ | 4,139 |
|
| Wholesale revenues, non-affiliates | 77 |
| | 82 |
| | 210 |
| | 211 |
|
| Wholesale revenues, affiliates | 18 |
| | 18 |
| | 83 |
| | 49 |
|
| Other revenues | 50 |
| | 56 |
| | 158 |
| | 162 |
|
| Total operating revenues | 1,740 |
| | 1,785 |
| | 4,606 |
| | 4,561 |
|
| Operating Expenses: | | | | | | | |
| Fuel | 343 |
| | 410 |
| | 944 |
| | 973 |
|
| Purchased power, non-affiliates | 57 |
| | 63 |
| | 132 |
| | 139 |
|
| Purchased power, affiliates | 55 |
| | 41 |
| | 117 |
| | 129 |
|
| Other operations and maintenance | 391 |
| | 348 |
| | 1,134 |
| | 1,097 |
|
| Depreciation and amortization | 185 |
| | 177 |
| | 549 |
| | 524 |
|
| Taxes other than income taxes | 93 |
| | 96 |
| | 284 |
| | 286 |
|
| Total operating expenses | 1,124 |
| | 1,135 |
| | 3,160 |
| | 3,148 |
|
| Operating Income | 616 |
| | 650 |
| | 1,446 |
| | 1,413 |
|
| Other Income and (Expense): | | | | | | | |
| Allowance for equity funds used during construction | 11 |
| | 7 |
| | 27 |
| | 23 |
|
| Interest expense, net of amounts capitalized | (76 | ) | | (77 | ) | | (229 | ) | | (224 | ) |
| Other income (expense), net | (5 | ) | | (5 | ) | | (8 | ) | | (16 | ) |
| Total other income and (expense) | (70 | ) | | (75 | ) | | (210 | ) | | (217 | ) |
| Earnings Before Income Taxes | 546 |
| | 575 |
| | 1,236 |
| | 1,196 |
|
| Income taxes | 216 |
| | 219 |
| | 493 |
| | 462 |
|
| Net Income | 330 |
| | 356 |
| | 743 |
| | 734 |
|
| Dividends on Preferred and Preference Stock | 5 |
| | 4 |
| | 14 |
| | 13 |
|
| Net Income After Dividends on Preferred and Preference Stock | $ | 325 |
| | $ | 352 |
| | $ | 729 |
| | $ | 721 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) |
| Net Income | $ | 330 |
| | $ | 356 |
| | $ | 743 |
| | $ | 734 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
| Changes in fair value, net of tax of $-, $-, $-, and $(1), respectively | — |
| | — |
| | — |
| | (2 | ) |
Reclassification adjustment for amounts included in net income,
net of tax of $1, $1, $2, and $2, respectively | 1 |
| | 1 |
| | 3 |
| | 3 |
|
| Total other comprehensive income (loss) | 1 |
| | 1 |
| | 3 |
| | 1 |
|
| Comprehensive Income | $ | 331 |
| | $ | 357 |
| | $ | 746 |
| | $ | 735 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
| Net Income | $ | 528 | | | $ | 503 | | | $ | 1,266 | | | $ | 1,200 | |
| Other comprehensive income: | | | | | | | |
| Qualifying hedges: | | | | | | | |
Changes in fair value, net of tax of $—, $1, $—, and $1, respectively | 1 | | | 4 | | | (1) | | | 3 | |
Reclassification adjustment for amounts included in net income, net of tax of $—, $—, $1, and $1, respectively | 1 | | | 1 | | | 3 | | | 3 | |
| Total other comprehensive income | 2 | | | 5 | | | 2 | | | 6 | |
| Comprehensive Income | $ | 530 | | | $ | 508 | | | $ | 1,268 | | | $ | 1,206 | |
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
| | | | For the Nine Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
| Operating Activities: | | | | Operating Activities: | |
| Net income | $ | 743 |
| | $ | 734 |
| Net income | $ | 1,266 | | | $ | 1,200 | |
| Adjustments to reconcile net income to net cash provided from operating activities — | | | | Adjustments to reconcile net income to net cash provided from operating activities — | |
| Depreciation and amortization, total | 666 |
| | 634 |
| Depreciation and amortization, total | 817 | | | 748 | |
| Deferred income taxes | 260 |
| | 267 |
| Deferred income taxes | 210 | | | 104 | |
| Allowance for equity funds used during construction | (27 | ) | | (23 | ) | |
| | Pension, postretirement, and other employee benefits | (4 | ) | | (14 | ) | Pension, postretirement, and other employee benefits | (85) | | | (74) | |
| Settlement of asset retirement obligations | | Settlement of asset retirement obligations | (139) | | | (152) | |
| | Retail fuel cost under recovery – long-term | | Retail fuel cost under recovery – long-term | (413) | | | — | |
| | Other, net | 43 |
| | (12 | ) | Other, net | (98) | | | (51) | |
| Changes in certain current assets and liabilities — | | | | Changes in certain current assets and liabilities — | |
| -Receivables | (163 | ) | | (4 | ) | -Receivables | (296) | | | (128) | |
| -Fossil fuel stock | 34 |
| | 18 |
| -Fossil fuel stock | (40) | | | 91 | |
| -Prepayments | | -Prepayments | (34) | | | (24) | |
| | -Retail fuel cost under recovery | | -Retail fuel cost under recovery | (93) | | | (79) | |
| -Other current assets | (58 | ) | | (46 | ) | -Other current assets | (41) | | | (32) | |
| -Accounts payable | (125 | ) | | (113 | ) | -Accounts payable | (22) | | | (230) | |
| -Accrued taxes | 159 |
| | 207 |
| -Accrued taxes | 110 | | | 178 | |
| -Accrued compensation | (48 | ) | | (22 | ) | |
| -Retail fuel cost over recovery | (76 | ) | | (104 | ) | |
| | -Other current liabilities | 7 |
| | 19 |
| -Other current liabilities | (70) | | | (132) | |
| Net cash provided from operating activities | 1,411 |
| | 1,541 |
| Net cash provided from operating activities | 1,072 | | | 1,419 | |
| Investing Activities: | | | | Investing Activities: | | | |
| Property additions | (1,211 | ) | | (947 | ) | Property additions | (1,483) | | | (1,235) | |
| Nuclear decommissioning trust fund purchases | (174 | ) | | (275 | ) | Nuclear decommissioning trust fund purchases | (273) | | | (536) | |
| Nuclear decommissioning trust fund sales | 174 |
| | 275 |
| Nuclear decommissioning trust fund sales | 273 | | | 536 | |
| Cost of removal, net of salvage | (82 | ) | | (70 | ) | Cost of removal, net of salvage | (163) | | | (93) | |
| Change in construction payables | 105 |
| | (37 | ) | |
| | Other investing activities | (29 | ) | | (28 | ) | Other investing activities | 5 | | | (7) | |
| Net cash used for investing activities | (1,217 | ) | | (1,082 | ) | Net cash used for investing activities | (1,641) | | | (1,335) | |
| Financing Activities: | | | | Financing Activities: | | | |
| Proceeds — | | | | |
| | Proceeds — Senior notes | | Proceeds — Senior notes | 1,700 | | | 600 | |
| | Redemptions — | | Redemptions — | |
| | Senior notes | 550 |
| | 400 |
| Senior notes | (550) | | | (200) | |
| | Other long-term debt | | Other long-term debt | — | | | (206) | |
| | Capital contributions from parent company | 337 |
| | 253 |
| Capital contributions from parent company | 660 | | | 630 | |
| Preferred stock | 250 |
| | — |
| |
| Other long-term debt | — |
| | 45 |
| |
| Redemptions — |
|
| |
| |
| Pollution control revenue bonds | (36 | ) | | — |
| |
| Senior notes | (200 | ) | | (200 | ) | |
| Payment of common stock dividends | (536 | ) | | (574 | ) | Payment of common stock dividends | (762) | | | (738) | |
| Other financing activities | (26 | ) | | (21 | ) | Other financing activities | (81) | | | (30) | |
| Net cash provided from (used for) financing activities | 339 |
| | (97 | ) | |
| Net Change in Cash and Cash Equivalents | 533 |
| | 362 |
| |
| Cash and Cash Equivalents at Beginning of Period | 420 |
| | 194 |
| |
| Cash and Cash Equivalents at End of Period | $ | 953 |
| | $ | 556 |
| |
| Net cash provided from financing activities | | Net cash provided from financing activities | 967 | | | 56 | |
| Net Change in Cash, Cash Equivalents, and Restricted Cash | | Net Change in Cash, Cash Equivalents, and Restricted Cash | 398 | | | 140 | |
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | | Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 1,060 | | | 530 | |
| Cash, Cash Equivalents, and Restricted Cash at End of Period | | Cash, Cash Equivalents, and Restricted Cash at End of Period | $ | 1,458 | | | $ | 670 | |
| Supplemental Cash Flow Information: | | | | Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | | |
| Interest (net of $10 and $8 capitalized for 2017 and 2016, respectively) | $ | 217 |
| | $ | 215 |
| |
| Cash paid during the period for — | | Cash paid during the period for — | |
| Interest (net of $14 and $11 capitalized for 2022 and 2021, respectively) | | Interest (net of $14 and $11 capitalized for 2022 and 2021, respectively) | $ | 278 | | | $ | 246 | |
| Income taxes, net | 146 |
| | (70 | ) | Income taxes, net | 178 | | | 183 | |
| Noncash transactions — Accrued property additions at end of period | 189 |
| | 84 |
| |
| Noncash transactions — | | Noncash transactions — | |
| Accrued property additions at end of period | | Accrued property additions at end of period | 186 | | | 178 | |
| Right-of-use assets obtained under leases | | Right-of-use assets obtained under leases | 9 | | | 2 | |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
| | | Assets | | At September 30, 2017 | | At December 31, 2016 | Assets | | At September 30, 2022 | | At December 31, 2021 |
| | | (in millions) | | | (in millions) |
| Current Assets: | | | | | Current Assets: | |
| Cash and cash equivalents | | $ | 953 |
| | $ | 420 |
| Cash and cash equivalents | | $ | 1,458 | | | $ | 1,060 | |
| Receivables — | | | | | Receivables — | |
| Customer accounts receivable | | 428 |
| | 348 |
| |
| Customer accounts | | Customer accounts | | 573 | | | 410 | |
| Unbilled revenues | | 149 |
| | 146 |
| Unbilled revenues | | 146 | | | 138 | |
| Other accounts and notes receivable | | 47 |
| | 27 |
| |
| | Affiliated | | 45 |
| | 40 |
| Affiliated | | 84 | | | 37 | |
| Other accounts and notes | | Other accounts and notes | | 131 | | | 55 | |
| Accumulated provision for uncollectible accounts | | (8 | ) | | (10 | ) | Accumulated provision for uncollectible accounts | | (13) | | | (14) | |
| Fossil fuel stock | | 171 |
| | 205 |
| Fossil fuel stock | | 199 | | | 159 | |
| Materials and supplies | | 455 |
| | 435 |
| Materials and supplies | | 568 | | | 548 | |
| | Prepaid expenses | | 58 |
| | 34 |
| Prepaid expenses | | 67 | | | 41 | |
| Other regulatory assets, current | | 122 |
| | 149 |
| |
| Other regulatory assets | | Other regulatory assets | | 298 | | | 208 | |
| Other current assets | | 5 |
| | 11 |
| Other current assets | | 129 | | | 67 | |
| Total current assets | | 2,425 |
| | 1,805 |
| Total current assets | | 3,640 | | | 2,709 | |
| Property, Plant, and Equipment: | | | | | Property, Plant, and Equipment: | | | | |
| In service | | 26,619 |
| | 26,031 |
| In service | | 33,042 | | | 33,135 | |
| Less: Accumulated provision for depreciation | | 9,463 |
| | 9,112 |
| Less: Accumulated provision for depreciation | | 10,393 | | | 10,313 | |
| Plant in service, net of depreciation | | 17,156 |
| | 16,919 |
| Plant in service, net of depreciation | | 22,649 | | | 22,822 | |
| Other utility plant, net | | Other utility plant, net | | 602 | | | — | |
| Nuclear fuel, at amortized cost | | 314 |
| | 336 |
| Nuclear fuel, at amortized cost | | 242 | | | 247 | |
| Construction work in progress | | 928 |
| | 491 |
| Construction work in progress | | 1,524 | | | 1,147 | |
| Total property, plant, and equipment | | 18,398 |
| | 17,746 |
| Total property, plant, and equipment | | 25,017 | | | 24,216 | |
| Other Property and Investments: | | | | | Other Property and Investments: | | | | |
| Nuclear decommissioning trusts, at fair value | | Nuclear decommissioning trusts, at fair value | | 1,067 | | | 1,325 | |
| Equity investments in unconsolidated subsidiaries | | 65 |
| | 66 |
| Equity investments in unconsolidated subsidiaries | | 58 | | | 57 | |
| Nuclear decommissioning trusts, at fair value | | 869 |
| | 792 |
| |
| Miscellaneous property and investments | | 121 |
| | 112 |
| Miscellaneous property and investments | | 128 | | | 126 | |
| Total other property and investments | | 1,055 |
| | 970 |
| Total other property and investments | | 1,253 | | | 1,508 | |
| Deferred Charges and Other Assets: | | | | | Deferred Charges and Other Assets: | | | | |
| Operating lease right-of-use assets, net of amortization | | Operating lease right-of-use assets, net of amortization | | 70 | | | 108 | |
| Deferred charges related to income taxes | | 525 |
| | 525 |
| Deferred charges related to income taxes | | 248 | | | 240 | |
| Deferred under recovered regulatory clause revenues | | 17 |
| | 150 |
| |
| Prepaid pension and other postretirement benefit costs | | Prepaid pension and other postretirement benefit costs | | 605 | | | 513 | |
| | Regulatory assets – asset retirement obligations | | Regulatory assets – asset retirement obligations | | 1,952 | | | 1,547 | |
| Other regulatory assets, deferred | | 1,191 |
| | 1,157 |
| Other regulatory assets, deferred | | 2,048 | | | 1,807 | |
| Other deferred charges and assets | | 178 |
| | 163 |
| Other deferred charges and assets | | 413 | | | 334 | |
| Total deferred charges and other assets | | 1,911 |
| | 1,995 |
| Total deferred charges and other assets | | 5,336 | | | 4,549 | |
| Total Assets | | $ | 23,789 |
| | $ | 22,516 |
| Total Assets | | $ | 35,246 | | | $ | 32,982 | |
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
| | | Liabilities and Stockholder's Equity | | At September 30, 2017 | | At December 31, 2016 | Liabilities and Stockholder's Equity | | At September 30, 2022 | | At December 31, 2021 |
| | | (in millions) | | | (in millions) |
| Current Liabilities: | | | | | Current Liabilities: | |
| Securities due within one year | | $ | 325 |
| | $ | 561 |
| Securities due within one year | | $ | 202 | | | $ | 751 | |
| | Accounts payable — | | | | | Accounts payable — | |
| Affiliated | | 275 |
| | 297 |
| Affiliated | | 401 | | | 309 | |
| Other | | 376 |
| | 433 |
| Other | | 376 | | | 459 | |
| Customer deposits | | 92 |
| | 88 |
| Customer deposits | | 106 | | | 106 | |
| Accrued taxes — | | | | | |
| Accrued income taxes | | 115 |
| | 45 |
| |
| Other accrued taxes | | 128 |
| | 42 |
| |
| | Accrued taxes | | Accrued taxes | | 209 | | | 98 | |
| Accrued interest | | 75 |
| | 78 |
| Accrued interest | | 86 | | | 100 | |
| | Accrued compensation | | 151 |
| | 193 |
| Accrued compensation | | 200 | | | 219 | |
| Other regulatory liabilities, current | | 4 |
| | 85 |
| |
| | Asset retirement obligations | | Asset retirement obligations | | 327 | | | 320 | |
| Other regulatory liabilities | | Other regulatory liabilities | | 89 | | | 215 | |
| Other current liabilities | | 50 |
| | 76 |
| Other current liabilities | | 97 | | | 125 | |
| Total current liabilities | | 1,591 |
| | 1,898 |
| Total current liabilities | | 2,093 | | | 2,702 | |
| Long-term Debt | | 7,083 |
| | 6,535 |
| Long-term Debt | | 10,628 | | | 8,936 | |
| Deferred Credits and Other Liabilities: | | | | | Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 4,919 |
| | 4,654 |
| Accumulated deferred income taxes | | 3,829 | | | 3,573 | |
| Deferred credits related to income taxes | | 60 |
| | 65 |
| Deferred credits related to income taxes | | 1,930 | | | 1,968 | |
| Accumulated deferred ITCs | | 118 |
| | 110 |
| Accumulated deferred ITCs | | 82 | | | 88 | |
| Employee benefit obligations | | 289 |
| | 300 |
| Employee benefit obligations | | 171 | | | 171 | |
| Asset retirement obligations | | 1,564 |
| | 1,503 |
| |
| Operating lease obligations | | Operating lease obligations | | 65 | | | 66 | |
| Asset retirement obligations, deferred | | Asset retirement obligations, deferred | | 3,987 | | | 4,014 | |
| Other cost of removal obligations | | 630 |
| | 684 |
| Other cost of removal obligations | | 57 | | | 192 | |
| Other regulatory liabilities, deferred | | 93 |
| | 100 |
| Other regulatory liabilities, deferred | | 226 | | | 210 | |
| | Other deferred credits and liabilities | | 51 |
| | 63 |
| Other deferred credits and liabilities | | 62 | | | 58 | |
| Total deferred credits and other liabilities | | 7,724 |
| | 7,479 |
| Total deferred credits and other liabilities | | 10,409 | | | 10,340 | |
| Total Liabilities | | 16,398 |
| | 15,912 |
| Total Liabilities | | 23,130 | | | 21,978 | |
| Redeemable Preferred Stock | | 329 |
| | 85 |
| Redeemable Preferred Stock | | 242 | | | 291 | |
| Preference Stock | | 196 |
| | 196 |
| |
| Common Stockholder's Equity: | | | | | |
| Common stock, par value $40 per share — | | | | | |
| Authorized — 40,000,000 shares | | | | | |
| Outstanding — 30,537,500 shares | | 1,222 |
| | 1,222 |
| |
| Paid-in capital | | 2,961 |
| | 2,613 |
| |
| Retained earnings | | 2,711 |
| | 2,518 |
| |
| Accumulated other comprehensive loss | | (28 | ) | | (30 | ) | |
| Total common stockholder's equity | | 6,866 |
| | 6,323 |
| |
| Common Stockholder's Equity (See accompanying statements) | | Common Stockholder's Equity (See accompanying statements) | | 11,874 | | | 10,713 | |
| Total Liabilities and Stockholder's Equity | | $ | 23,789 |
| | $ | 22,516 |
| Total Liabilities and Stockholder's Equity | | $ | 35,246 | | | $ | 32,982 | |
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSISCONDENSED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY (UNAUDITED)
FINANCIAL CONDITION AND RESULTS OF OPERATIONS | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Number of
Common
Shares
Issued | | Common
Stock | | Paid-In
Capital | | Retained
Earnings | | Accumulated
Other
Comprehensive
Income (Loss) | | Total |
| (in millions) |
| Balance at December 31, 2020 | 31 | | | $ | 1,222 | | | $ | 5,413 | | | $ | 3,194 | | | $ | (19) | | | $ | 9,810 | |
Net income after dividends on
preferred stock | — | | | — | | | — | | | 359 | | | — | | | 359 | |
| | | | | | | | | | | |
| Capital contributions from parent company | — | | | — | | | 602 | | | — | | | — | | | 602 | |
| Other comprehensive income | — | | | — | | | — | | | — | | | 1 | | | 1 | |
| Cash dividends on common stock | — | | | — | | | — | | | (246) | | | — | | | (246) | |
| | | | | | | | | | | |
| Balance at March 31, 2021 | 31 | | | 1,222 | | | 6,015 | | | 3,307 | | | (18) | | | 10,526 | |
Net income after dividends on
preferred stock | — | | | — | | | — | | | 331 | | | — | | | 331 | |
| | | | | | | | | | | |
| Capital contributions from parent company | — | | | — | | | 26 | | | — | | | — | | | 26 | |
| Other comprehensive income | — | | | — | | | — | | | — | | | 1 | | | 1 | |
| Cash dividends on common stock | — | | | — | | | — | | | (246) | | | — | | | (246) | |
| Other | — | | | — | | | — | | | (1) | | | — | | | (1) | |
| Balance at June 30, 2021 | 31 | | | 1,222 | | | 6,041 | | | 3,391 | | | (17) | | | 10,637 | |
Net income after dividends on
preferred stock | — | | | — | | | — | | | 499 | | | — | | | 499 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Capital contributions from parent company | — | | | — | | | 9 | | | — | | | — | | | 9 | |
| Other comprehensive income | — | | | — | | | — | | | — | | | 5 | | | 5 | |
| Cash dividends on common stock | — | | | — | | | — | | | (246) | | | — | | | (246) | |
| Other | — | | | — | | | — | | | — | | | (1) | | | (1) | |
| Balance at September 30, 2021 | 31 | | | $ | 1,222 | | | $ | 6,050 | | | $ | 3,644 | | | $ | (13) | | | $ | 10,903 | |
| | | | | | | | | | | |
| Balance at December 31, 2021 | 31 | | | $ | 1,222 | | | $ | 6,056 | | | $ | 3,448 | | | $ | (13) | | | $ | 10,713 | |
Net income after dividends on
preferred stock | — | | | — | | | — | | | 347 | | | — | | | 347 | |
| | | | | | | | | | | |
| Capital contributions from parent company | — | | | — | | | 626 | | | — | | | — | | | 626 | |
| | | | | | | | | | | |
| Cash dividends on common stock | — | | | — | | | — | | | (254) | | | — | | | (254) | |
| | | | | | | | | | | |
| Balance at March 31, 2022 | 31 | | | 1,222 | | | 6,682 | | | 3,541 | | | (13) | | | 11,432 | |
Net income after dividends on
preferred stock | — | | | — | | | — | | | 383 | | | — | | | 383 | |
| | | | | | | | | | | |
| Capital contributions from parent company | — | | | — | | | 32 | | | — | | | — | | | 32 | |
| Other comprehensive income | — | | | — | | | — | | | — | | | 1 | | | 1 | |
| Cash dividends on common stock | — | | | — | | | — | | | (254) | | | — | | | (254) | |
| | | | | | | | | | | |
| Balance at June 30, 2022 | 31 | | | 1,222 | | | 6,714 | | | 3,670 | | | (12) | | | 11,594 | |
Net income after dividends on
preferred stock | — | | | — | | | — | | | 525 | | | — | | | 525 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Capital contributions from parent company | — | | | — | | | 7 | | | — | | | — | | | 7 | |
| Other comprehensive income | — | | | — | | | — | | | — | | | 2 | | | 2 | |
| Cash dividends on common stock | — | | | — | | | — | | | (254) | | | — | | | (254) | |
| | | | | | | | | | | |
| Balance at September 30, 2022 | 31 | | | $ | 1,222 | | | $ | 6,721 | | | $ | 3,941 | | | $ | (10) | | | $ | 11,874 | |
THIRD QUARTER 2017 vs. THIRD QUARTER 2016
AND
YEAR-TO-DATE 2017 vs. YEAR-TO-DATE 2016
OVERVIEW
The accompanying notes as they relate to Alabama Power operates as a vertically integrated utility providing electric service to retail and wholesale customers within its traditional service territory located in the Stateare an integral part of Alabama in addition to wholesale customers in the Southeast.these condensed financial statements.
Many factors affect the opportunities, challenges, and risks of Alabama Power's business of providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, reliability, fuel, capital expenditures, and restoration following major storms. Alabama Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Alabama Power for the foreseeable future.
Alabama Power continues to focus on several key performance indicators including, but not limited to, customer satisfaction, plant availability, system reliability, and net income after dividends on preferred and preference stock.
RESULTS OF OPERATIONS
Net Income
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) |
| (% change) |
| (change in millions) |
| (% change) |
| $(27) | | (7.7) | | $8 | | 1.1 |
Alabama Power's net income after dividends on preferred and preference stock for the third quarter 2017 was $325 million compared to $352 million for the corresponding period in 2016. The decrease was primarily related to a decrease in retail revenues associated with milder weather and lower customer usage in the third quarter 2017 compared to the corresponding period in 2016 and an increase in non-fuel operations and maintenance expenses. The decrease was partially offset by an increase in rates under Rate RSE effective January 1, 2017.
Alabama Power's net income after dividends on preferred and preference stock for year-to-date 2017 was $729 million compared to $721 million for the corresponding period in 2016. The increase was primarily related to an increase in rates under Rate RSE effective January 1, 2017, partially offset by a decrease in retail revenues associated with milder weather and lower customer usage for year-to-date 2017 compared to the corresponding period in 2016, and an increase in non-fuel operations and maintenance expenses.
Retail Revenues
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(34) | | (2.1) | | $16 | | 0.4 |
In the third quarter 2017, retail revenues were $1.60 billion compared to $1.63 billion for the corresponding period in 2016. For year-to-date 2017, retail revenues were $4.16 billion compared to $4.14 billion for the corresponding period in 2016.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of the changes in retail revenues were as follows:
|
| | | | | | | | | | | | | |
| | Third Quarter 2017 |
| Year-to-Date 2017 |
| | (in millions) |
| (% change) |
| (in millions) |
| (% change) |
| Retail – prior year | $ | 1,629 |
| | | | $ | 4,139 |
| | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 85 |
| | 5.2 |
| | 240 |
| | 5.8 |
|
| Sales decline | (18 | ) | | (1.1 | ) | | (31 | ) | | (0.7 | ) |
| Weather | (50 | ) | | (3.1 | ) | | (116 | ) | | (2.8 | ) |
| Fuel and other cost recovery | (51 | ) | | (3.1 | ) | | (77 | ) | | (1.9 | ) |
| Retail – current year | $ | 1,595 |
| | (2.1 | )% | | $ | 4,155 |
| �� | 0.4 | % |
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016 primarily due to an increase in rates under Rate RSE effective January 1, 2017. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016. Weather-adjusted residential KWH sales decreased 2.4% and 1.1% for the third quarter and year-to-date 2017, respectively, primarily due to lower customer usage resulting from an increase in penetration of energy efficient residential appliances, partially offset by customer growth. Weather-adjusted commercial KWH sales decreased 2.3% and 1.4% for the third quarter and year-to-date 2017, respectively, primarily due to lower customer usage resulting from customer initiatives in energy savings and an ongoing migration to the electronic commerce business model, partially offset by customer growth. Industrial KWH sales increased 1.8% and 0.6% for the third quarter and year-to-date 2017, respectively, as a result of an increase in demand resulting from changes in production levels primarily in the primary metals, chemicals, and mining sectors, partially offset by a decrease in demand from the pipeline sector.
Revenues resulting from changes in weather decreased in the third quarter and year-to-date 2017 due to milder weather experienced in Alabama Power's service territory compared to the corresponding periods in 2016. For the third quarter 2017, the resulting decreases were 5.1% and 2.4% for residential and commercial sales revenues, respectively. For year-to-date 2017, the resulting decreases were 5.2% and 1.8% for residential and commercial sales revenues, respectively.
Fuel and other cost recovery revenues decreased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016 primarily due to a decrease in KWH generation and a decrease in the average cost of fuel. Electric rates include provisions to recognize the full recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the natural disaster reserve. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.
Wholesale Revenues – Affiliates
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $— | | — | | $34 | | 69.4 |
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
marginal cost and energy purchases are generally offset by energy revenues through Alabama Power's energy cost recovery clauses.
For year-to-date 2017, wholesale revenues from sales to affiliates were $83 million compared to $49 million for the corresponding period in 2016. The increase was primarily due to a 52% increase in KWH sales as a result of supporting Southern Company system transmission reliability and an 11% increase in the price of energy due to an increase in natural gas prices.
Other Revenues
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(6) | | (10.7) | | $(4) | | (2.5) |
In the third quarter 2017, other revenues were $50 million compared to $56 million for the corresponding period in 2016. The decrease was primarily due to lower open access transmission tariff revenues as a result of rate adjustments.
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | | |
| | Third Quarter 2017
vs.
Third Quarter 2016 | | Year-to-Date 2017
vs.
Year-to-Date 2016 |
| | (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| Fuel | $ | (67 | ) | | (16.3) | | $ | (29 | ) | | (3.0 | ) |
| Purchased power – non-affiliates | (6 | ) | | (9.5) | | (7 | ) | | (5.0 | ) |
| Purchased power – affiliates | 14 |
| | 34.1 | | (12 | ) | | (9.3 | ) |
| Total fuel and purchased power expenses | $ | (59 | ) | | | | $ | (48 | ) | | |
In the third quarter 2017, fuel and purchased power expenses were $455 million compared to $514 million for the corresponding period in 2016. The decrease was primarily due to a $43 million net decrease related to the volume of KWHs generated and purchased and a $16 million decrease related to the average cost of fuel.
For year-to-date 2017, fuel and purchased power expenses were $1.19 billion compared to $1.24 billion for the corresponding period in 2016. The decrease was primarily due to a $53 million decrease in the volume of KWHs purchased and a $34 million decrease related to the average cost of fuel. This decrease was partially offset by a $35 million increase in the average cost of purchased power.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Alabama Power's energy cost recovery clause. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate ECR" in Item 8 of the Form 10-K for additional information.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of Alabama Power's generation and purchased power were as follows:
|
| | | | | | | |
| | Third Quarter 2017 | | Third Quarter 2016 | | Year-to-Date 2017 |
| Year-to-Date 2016 |
Total generation (in billions of KWHs) | 16 | | 18 | | 46 | | 46 |
Total purchased power (in billions of KWHs) | 2 | | 2 | | 5 | | 6 |
Sources of generation (percent) — | | | | | | | |
| Coal | 52 | | 59 | | 49 | | 51 |
| Nuclear | 24 | | 22 | | 25 | | 24 |
| Gas | 19 | | 18 | | 20 | | 19 |
| Hydro | 5 | | 1 | | 6 | | 6 |
Cost of fuel, generated (in cents per net KWH) — | | | | | | | |
| Coal | 2.61 | | 2.73 | | 2.61 | | 2.80 |
| Nuclear | 0.75 | | 0.77 | | 0.75 | | 0.78 |
| Gas | 2.72 | | 2.85 | | 2.74 | | 2.62 |
Average cost of fuel, generated (in cents per net KWH)(a) | 2.17 | | 2.32 | | 2.15 | | 2.25 |
Average cost of purchased power (in cents per net KWH)(b) | 5.65 | | 5.70 | | 5.57 | | 4.81 |
| |
(a)
| KWHs generated by hydro are excluded from the average cost of fuel, generated. |
| |
(b)
| Average cost of purchased power includes fuel, energy, and transmission purchased by Alabama Power for tolling agreements where power is generated by the provider. |
Fuel
In the third quarter 2017, fuel expense was $343 million compared to $410 million for the corresponding period in 2016. The decrease was primarily due to an 18.4% decrease in the volume of KWHs generated by coal, a 4.6% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, and a 4.4% decrease in average cost of coal per KWH generated. In addition, there was a 194.0% increase in the volume of KWHs generated by hydro facilities as a result of significantly more rainfall in 2017.
For year-to-date 2017, fuel expense was $944 million compared to $973 million for the corresponding period in 2016. The decrease was primarily due to a 6.8% decrease in the average cost of coal per KWH generated and a 2.0% decrease in the volume of KWHs generated by coal. The decrease was partially offset by a 4.8% increase in the volume of KWHs generated by natural gas and a 4.6% increase in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements.
Purchased Power – Affiliates
In the third quarter 2017, purchased power expense from affiliates was $55 million compared to $41 million for the corresponding period in 2016. The increase was primarily related to a 55.2% increase in the amount of energy purchased due to an increase in plant outages and increased purchases from Southern Electric Generating Company (SEGCO). The increase was partially offset by a 14.5% decrease in the average cost per KWH of capacity and energy at SEGCO. See Note 4 to the financial statements of Alabama Power in Item 8 of the Form 10-K for additional information.
For year-to-date 2017, purchased power expense from affiliates was $117 million compared to $129 million for the corresponding period in 2016. The decrease was primarily related to a 26.6% decrease in the amount of energy purchased due to a decrease in demand as a result of milder weather in 2017, partially offset by a 22.9% increase in the average cost of purchased power per KWH as a result of higher natural gas prices.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $43 | | 12.4 | | $37 | | 3.4 |
In the third quarter 2017, other operations and maintenance expenses were $391 million compared to $348 million for the corresponding period in 2016. The increase was primarily due to increases of $26 million in scheduled generation outage costs, $11 million in vegetation management costs, and $3 million in employee compensation and benefit costs, including pension costs.
For year-to-date 2017, other operations and maintenance expenses were $1.13 billion compared to $1.10 billion for the corresponding period in 2016. The increase was primarily due to increases of $31 million in vegetation management costs, $10 million in nuclear generation plant improvement costs, and $7 million in employee compensation and benefit costs, including pension costs, partially offset by an $11 million decrease in contract services.
Depreciation and Amortization
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $8 | | 4.5 | | $25 | | 4.8 |
In the third quarter 2017, depreciation and amortization was $185 million compared to $177 million for the corresponding period in 2016. For year-to-date 2017, depreciation and amortization was $549 million compared to $524 million for the corresponding period in 2016. These increases were primarily due to additional plant in service and an increase in depreciation rates, effective January 1, 2017, associated with compliance-related steam projects and asset retirement obligation recovery, partially offset by a decrease in distribution-related depreciation rates. See Note 1 to the financial statements of Alabama Power under "Depreciation and Amortization" in Item 8 of the Form 10-K for additional information.
Income Taxes
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(3) | | (1.4) | | $31 | | 6.7 |
For year-to-date 2017, income taxes were $493 million compared to $462 million for the corresponding period in 2016. The increase was primarily due to higher pre-tax earnings, unrecognized tax benefits related to certain state deductions for federal income taxes, and prior year tax return actualization.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Alabama Power's future earnings potential. The level of Alabama Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Alabama Power's primary business of providing electric service. These factors include Alabama Power's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs during a time of increasing costs and limited projected demand growth over the next several years. Future earnings will be driven primarily by customer growth. Earnings will also depend upon
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions. Earnings are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Alabama Power's service territory. Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings. Current proposals related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Alabama Power's financial statements. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Alabama Power in Item 7 of the Form 10-K.
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Environmental compliance costs are recovered through Rate CNP Compliance. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate CNP Compliance" in Item 8 of the Form 10-K for additional information. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Statutes and Regulations
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the final effluent guidelines rule and the final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs.
On April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. On September 18, 2017, the EPA published a final rule establishing a stay of the compliance deadlines for certain effluent limitations and pretreatment standards under the rule.
On June 27, 2017, the EPA and the U.S. Army Corps of Engineers proposed to rescind the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.
The ultimate outcome of these matters cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Alabama Power in Item 7 of the Form 10-K for additional information.
On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
specifically directs the EPA to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules. On October 16, 2017, the EPA published a proposed rule to repeal the Clean Power Plan. The EPA has not determined whether or when it will promulgate a replacement rule.
On June 1, 2017, the U.S. President announced that the United States will withdraw from the non-binding Paris Agreement and begin renegotiation of its terms.
The ultimate outcome of these matters cannot be determined at this time.
FERC Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the traditional electric operating companies' and Southern Power's market power proceeding and amendment to their market-rate tariff.
On May 17, 2017, the FERC accepted the traditional electric operating companies' (including Alabama Power's) and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies (including Alabama Power) and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' (including Alabama Power's) and Southern Power's market power proceeding related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including Alabama Power's) and Southern Power's June 30, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including Alabama Power) and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order, or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including Alabama Power) and Southern Power expect to make a filing within the specified 60 days responding to the FERC's order.
The ultimate outcome of these matters cannot be determined at this time.
Retail Regulatory Matters
Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See Notes 1 and 3 to the financial statements of Alabama Power under "Nuclear Outage Accounting Order" and "Retail Regulatory Matters," respectively, in Item 8 of the Form 10-K for additional information regarding Alabama Power's rate mechanisms and accounting orders. The recovery balance of each regulatory clause for Alabama Power is reported in Note (B) to the Condensed Financial Statements herein.
Other Matters
Alabama Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Alabama Power is subject to certain claims and legal actions arising in the ordinary course of business. Alabama Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Alabama Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Alabama Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Alabama Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Alabama Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Alabama Power in Item 7 of the Form 10-K for a complete discussion of Alabama Power's critical accounting policies and estimates related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, and Contingent Obligations.
Recently Issued Accounting Standards
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Alabama Power in Item 7 of the Form 10-K for additional information.
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
While Alabama Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Alabama Power's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs. Alabama Power expects that the revenue from contracts with these customers will not result in a significant shift in the timing of revenue recognition for such sales.
Alabama Power's ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements, such as alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Alabama Power's financial statements, if material. In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Alabama Power expects CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Alabama Power intends to use the modified retrospective method of adoption effective January 1, 2018. Alabama Power has also elected to utilize practical expedients which allow it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Alabama Power's financial statements, Alabama Power will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Alabama Power's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Alabama Power's financial statements.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with early adoption permitted. Alabama Power is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on Alabama Power's financial statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Alabama Power in Item 7 of the Form 10-K for additional information. Alabama Power's financial condition remained stable at September 30, 2017. Alabama Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $1.4 billion for the first nine months of 2017, a decrease of $130 million as compared to the first nine months of 2016. The decrease in net cash provided from operating activities was primarily due to the receipt of income tax refunds in 2016 as a result of bonus depreciation. Net cash used for investing activities totaled $1.2 billion for the first nine months of 2017 primarily due to gross property additions related to distribution, environmental, transmission, and steam generation. Net cash provided from financing activities totaled $339 million for the first nine months of 2017 primarily due to an issuance of long-term debt and preferred stock and additional capital contributions from Southern Company, partially offset by common stock dividend payments and a redemption of long-term debt. Fluctuations in cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first nine months of 2017 include increases of $652 million in property, plant, and equipment primarily due to additions to distribution, transmission, and steam generation, $548 million in long-term debt primarily due to the issuance of additional senior notes, $533 million in cash and cash equivalents, $348 million in additional paid-in capital due to capital contributions from Southern Company, $265 million in
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
accumulated deferred income taxes primarily due to bonus depreciation, and $244 million in redeemable preferred stock primarily due to the September 2017 issuance, as well as a decrease of $236 million in securities due within one year.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Alabama Power in Item 7 of the Form 10-K for a description of Alabama Power's capital requirements for its construction program, including estimated capital expenditures to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. Subsequent to September 30, 2017, Alabama Power repaid at maturity $325 million aggregate principal amount of Series Q 5.50% Senior Notes due October 15, 2017. No additional funds will be required through September 30, 2018 to fund maturities of long-term debt.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – General" and " – Global Climate Issues" of Alabama Power in Item 7 of the Form 10-K for additional information on Alabama Power's environmental compliance strategy.
Alabama Power's Board of Directors approved its construction program that is currently estimated to total $2.2 billion for 2018, $1.6 billion for 2019, $1.6 billion for 2020, $1.7 billion for 2021, and $1.4 billion for 2022. The construction program includes capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under LTSAs. Estimated capital expenditures to comply with environmental statutes and regulations included in these amounts are $0.6 billion for 2018, $0.1 billion for 2019, $0.2 billion for 2020, $0.3 billion for 2021, and $0.3 billion for 2022. These estimated expenditures do not include any potential compliance costs that may arise from the EPA's final rules and guidelines or future state plans that would limit CO2 emissions from new, existing, modified, or reconstructed fossil-fuel-fired electric generating units.
Alabama Power also anticipates costs associated with closure in place and monitoring of ash ponds in accordance with the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule), which are reflected in Alabama Power's asset retirement obligation liabilities. These costs, which could change as Alabama Power continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities, are estimated to be $27 million for 2018, $101 million for 2019, $105 million for 2020, $107 million for 2021, and $109 million for 2022. See Note 1 to the financial statements of Alabama Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information. Costs associated with the CCR Rule are expected to be recovered through Rate CNP Compliance.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating units, to meet regulatory requirements; changes in the expected environmental compliance program; changes in FERC rules and regulations; Alabama PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Sources of Capital
Alabama Power plans to obtain the funds to meet its future capital needs from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, term loans, external security issuances, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Alabama Power in Item 7 of the Form 10-K for additional information.
Alabama Power's current liabilities sometimes exceed current assets because of long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs.
At September 30, 2017, Alabama Power had approximately $953 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2017 were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Expires | | | | | | Expires Within One Year |
| 2018 | | 2020 | | 2022 | | Total | | Unused | | Term Out | | No Term Out |
| (in millions) |
| $ | 35 |
| | $ | 500 |
| | $ | 800 |
| | $ | 1,335 |
| | $ | 1,335 |
| | $ | — |
| | $ | 35 |
|
See Note 6 to the financial statements of Alabama Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
In May 2017 and September 2017, Alabama Power amended its $800 million and $500 million multi-year credit arrangements, which, among other things, extended the maturity dates from 2020 to 2022 and 2018 to 2020, respectively, as reflected in the table above.
Most of these bank credit arrangements, as well as Alabama Power's term loan arrangements, contain covenants that limit debt levels and contain cross-acceleration provisions to other indebtedness (including guarantee obligations) of Alabama Power. Such cross-acceleration provisions to other indebtedness would trigger an event of default if Alabama Power defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2017, Alabama Power was in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, Alabama Power expects to renew or replace its bank credit arrangements as needed, prior to expiration. In connection therewith, Alabama Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the unused credit with banks is allocated to provide liquidity support to Alabama Power's pollution control revenue bonds and commercial paper programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support was approximately $854 million as of September 30, 2017. At September 30, 2017, Alabama Power had no fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.
Alabama Power also has substantial cash flow from operating activities and access to capital markets, including a commercial paper program, to meet liquidity needs. Alabama Power may meet short-term cash needs through its commercial paper program. Alabama Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Alabama Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Alabama Power are loaned directly to Alabama Power. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of commercial paper borrowings were as follows:
|
| | | | | | | | | | | |
| | | Short-term Debt During the Period(*) |
| | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) |
| Commercial paper | | $ | 30 |
| | 1.3 | % | | $ | 220 |
|
| |
(*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2017. No short-term debt was outstanding at September 30, 2017. |
Alabama Power believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and operating cash flows.
Credit Rating Risk
At September 30, 2017, Alabama Power did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2 or below. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, energy price risk management, and transmission.
The maximum potential collateral requirements under these contracts at September 30, 2017 were as follows:
|
| | | |
| Credit Ratings | Maximum Potential Collateral Requirements |
| | (in millions) |
| At BBB and/or Baa2 | $ | 1 |
|
| At BBB- and/or Baa3 | $ | 2 |
|
| Below BBB- and/or Baa3 | $ | 338 |
|
Included in these amounts are certain agreements that could require collateral in the event that either Alabama Power or Georgia Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Alabama Power to access capital markets and would be likely to impact the cost at which it does so.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including Alabama Power) from stable to negative.
Financing Activities
In February 2017, Alabama Power repaid at maturity $200 million aggregate principal amount of Series 2007A 5.55% Senior Notes.
In March 2017, Alabama Power issued $550 million aggregate principal amount of Series 2017A 2.45% Senior Notes due March 30, 2022. The proceeds were used to repay Alabama Power's short-term indebtedness and for general corporate purposes, including Alabama Power's continuous construction program.
In July 2017, Alabama Power repaid at maturity $36.1 million aggregate principal amount of Series 1993-A, 1993-B, and 1993-C Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Refunding Bonds (Alabama Power Company Project).
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In September 2017, Alabama Power issued 10 million shares ($250 million aggregate stated capital) of 5.00% Class A Preferred Stock, Cumulative, Par Value $1 Per Share (Stated Capital $25 Per Share). The proceeds were used in October 2017 to redeem all 2 million shares ($50 million aggregate stated capital) of 6.50% Series Preference Stock, 6 million shares ($150 million aggregate stated capital) of 6.45% Series Preference Stock, and 1.52 million shares ($38 million aggregate stated capital) of 5.83% Class A Preferred Stock and for other general corporate purposes, including Alabama Power's continuous construction program.
Subsequent to September 30, 2017, Alabama Power repaid at maturity $325 million aggregate principal amount of Series Q 5.50% Senior Notes due October 15, 2017.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Alabama Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
GEORGIA POWER COMPANY
GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | |
| Retail revenues | $ | 3,703 | | | $ | 2,652 | | | $ | 8,629 | | | $ | 6,465 | |
| Wholesale revenues | 56 | | | 63 | | | 186 | | | 143 | |
| | | | | | | |
| Other revenues | 130 | | | 141 | | | 403 | | | 442 | |
| Total operating revenues | 3,889 | | | 2,856 | | | 9,218 | | | 7,050 | |
| Operating Expenses: | | | | | | | |
| Fuel | 841 | | | 432 | | | 1,887 | | | 1,088 | |
| Purchased power, non-affiliates | 304 | | | 173 | | | 700 | | | 461 | |
| Purchased power, affiliates | 571 | | | 288 | | | 1,100 | | | 573 | |
| Other operations and maintenance | 595 | | | 544 | | | 1,686 | | | 1,558 | |
| Depreciation and amortization | 359 | | | 345 | | | 1,066 | | | 1,025 | |
| Taxes other than income taxes | 155 | | | 130 | | | 420 | | | 365 | |
| Estimated loss on Plant Vogtle Units 3 and 4 | (70) | | | 264 | | | (18) | | | 772 | |
| Total operating expenses | 2,755 | | | 2,176 | | | 6,841 | | | 5,842 | |
| Operating Income | 1,134 | | | 680 | | | 2,377 | | | 1,208 | |
| Other Income and (Expense): | | | | | | | |
| Allowance for equity funds used during construction | 37 | | | 33 | | | 102 | | | 94 | |
| Interest expense, net of amounts capitalized | (123) | | | (106) | | | (347) | | | (315) | |
| Other income (expense), net | 36 | | | 42 | | | 140 | | | 124 | |
| Total other income and (expense) | (50) | | | (31) | | | (105) | | | (97) | |
| Earnings Before Income Taxes | 1,084 | | | 649 | | | 2,272 | | | 1,111 | |
| Income taxes | 226 | | | 113 | | | 421 | | | 81 | |
| Net Income | $ | 858 | | | $ | 536 | | | $ | 1,851 | | | $ | 1,030 | |
| | | | | | | |
| | | | | | | |
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | |
| Retail revenues | $ | 2,402 |
| | $ | 2,540 |
| | $ | 5,995 |
| | $ | 6,164 |
|
| Wholesale revenues, non-affiliates | 45 |
| | 49 |
| | 124 |
| | 131 |
|
| Wholesale revenues, affiliates | 6 |
| | 9 |
| | 23 |
| | 24 |
|
| Other revenues | 93 |
| | 100 |
| | 284 |
| | 302 |
|
| Total operating revenues | 2,546 |
| | 2,698 |
| | 6,426 |
| | 6,621 |
|
| Operating Expenses: | | | | | | | |
| Fuel | 482 |
| | 575 |
| | 1,297 |
| | 1,390 |
|
| Purchased power, non-affiliates | 119 |
| | 102 |
| | 310 |
| | 277 |
|
| Purchased power, affiliates | 161 |
| | 142 |
| | 470 |
| | 392 |
|
| Other operations and maintenance | 413 |
| | 496 |
| | 1,194 |
| | 1,393 |
|
| Depreciation and amortization | 225 |
| | 215 |
| | 669 |
| | 639 |
|
| Taxes other than income taxes | 112 |
| | 114 |
| | 311 |
| | 311 |
|
| Total operating expenses | 1,512 |
| | 1,644 |
| | 4,251 |
| | 4,402 |
|
| Operating Income | 1,034 |
| | 1,054 |
| | 2,175 |
| | 2,219 |
|
| Other Income and (Expense): | | | | | | | |
| Interest expense, net of amounts capitalized | (105 | ) | | (98 | ) | | (310 | ) | | (290 | ) |
| Other income (expense), net | 5 |
| | 11 |
| | 41 |
| | 35 |
|
| Total other income and (expense) | (100 | ) | | (87 | ) | | (269 | ) | | (255 | ) |
| Earnings Before Income Taxes | 934 |
| | 967 |
| | 1,906 |
| | 1,964 |
|
| Income taxes | 350 |
| | 363 |
| | 705 |
| | 734 |
|
| Net Income | 584 |
| | 604 |
| | 1,201 |
| | 1,230 |
|
| Dividends on Preferred and Preference Stock | 4 |
| | 4 |
| | 13 |
| | 13 |
|
| Net Income After Dividends on Preferred and Preference Stock | $ | 580 |
| | $ | 600 |
| | $ | 1,188 |
| | $ | 1,217 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
| | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) | | (in millions) | | (in millions) | | (in millions) |
| Net Income | $ | 584 |
| | $ | 604 |
| | $ | 1,201 |
| | $ | 1,230 |
| Net Income | $ | 858 | | | $ | 536 | | | $ | 1,851 | | | $ | 1,030 | |
| Other comprehensive income (loss): | | | | | | | | |
| Other comprehensive income: | | Other comprehensive income: | |
| Qualifying hedges: | | | | | | | | 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 |
| |
Changes in fair value, net of tax of $—, $—, $8, and $—, respectively | | Changes in fair value, net of tax of $—, $—, $8, and $—, respectively | — | | | — | | | 23 | | | — | |
Reclassification adjustment for amounts included in net income, net of tax of $—, $1, $1, and $2, respectively | | Reclassification adjustment for amounts included in net income, net of tax of $—, $1, $1, and $2, respectively | 1 | | | 2 | | | 4 | | | 5 | |
| Total other comprehensive income | | Total other comprehensive income | 1 | | | 2 | | | 27 | | | 5 | |
| Comprehensive Income | $ | 585 |
| | $ | 605 |
| | $ | 1,203 |
| | $ | 1,232 |
| Comprehensive Income | $ | 859 | | | $ | 538 | | | $ | 1,878 | | | $ | 1,035 | |
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED) | | | | For the Nine Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
| Operating Activities: | | | | Operating Activities: | |
| Net income | $ | 1,201 |
| | $ | 1,230 |
| Net income | $ | 1,851 | | | $ | 1,030 | |
| Adjustments to reconcile net income to net cash provided from operating activities -- | | | | |
| Adjustments to reconcile net income to net cash provided from operating activities — | | Adjustments to reconcile net income to net cash provided from operating activities — | |
| Depreciation and amortization, total | 821 |
| | 794 |
| Depreciation and amortization, total | 1,211 | | | 1,164 | |
| Deferred income taxes | 328 |
| | 346 |
| Deferred income taxes | 266 | | | (299) | |
| Utilization of federal investment tax credits | | Utilization of federal investment tax credits | 49 | | | 19 | |
| Allowance for equity funds used during construction | (29 | ) | | (36 | ) | Allowance for equity funds used during construction | (102) | | | (94) | |
| Deferred expenses | (30 | ) | | (40 | ) | |
| | Pension, postretirement, and other employee benefits | (42 | ) | | (14 | ) | Pension, postretirement, and other employee benefits | (178) | | | (112) | |
| | Settlement of asset retirement obligations | (95 | ) | | (93 | ) | Settlement of asset retirement obligations | (149) | | | (154) | |
| Storm damage accruals | | Storm damage accruals | 160 | | | 160 | |
| Retail fuel cost under recovery – long-term | | Retail fuel cost under recovery – long-term | (1,287) | | | (203) | |
| | Estimated loss on Plant Vogtle Units 3 and 4 | | Estimated loss on Plant Vogtle Units 3 and 4 | (18) | | | 772 | |
| Other, net | (21 | ) | | 7 |
| Other, net | (71) | | | 70 | |
| Changes in certain current assets and liabilities — | | | | Changes in certain current assets and liabilities — | |
| -Receivables | (254 | ) | | (162 | ) | -Receivables | (321) | | | (85) | |
| -Fossil fuel stock | (2 | ) | | 128 |
| -Fossil fuel stock | (23) | | | 77 | |
| | -Materials and supplies | | -Materials and supplies | (67) | | | (60) | |
| -Contract assets | | -Contract assets | (51) | | | (32) | |
| -Other current assets | (29 | ) | | 62 |
| -Other current assets | (72) | | | (20) | |
| -Accounts payable | (161 | ) | | 39 |
| -Accounts payable | 211 | | | 164 | |
| -Accrued taxes | (52 | ) | | (22 | ) | -Accrued taxes | 151 | | | 154 | |
| -Accrued compensation | (60 | ) | | (26 | ) | |
| | -Retail fuel cost over recovery | (84 | ) | | 9 |
| -Retail fuel cost over recovery | — | | | (113) | |
| | -Other current liabilities | (11 | ) | | 44 |
| -Other current liabilities | (78) | | | (88) | |
| Net cash provided from operating activities | 1,480 |
| | 2,266 |
| Net cash provided from operating activities | 1,482 | | | 2,350 | |
| Investing Activities: | | | | Investing Activities: | | | |
| Property additions | (1,907 | ) | | (1,566 | ) | Property additions | (2,658) | | | (2,411) | |
| Nuclear decommissioning trust fund purchases | (411 | ) | | (563 | ) | Nuclear decommissioning trust fund purchases | (585) | | | (766) | |
| Nuclear decommissioning trust fund sales | 406 |
| | 558 |
| Nuclear decommissioning trust fund sales | 581 | | | 761 | |
| Cost of removal, net of salvage | (54 | ) | | (45 | ) | Cost of removal, net of salvage | (250) | | | (99) | |
| Change in construction payables, net of joint owner portion | 180 |
| | (139 | ) | Change in construction payables, net of joint owner portion | 148 | | | (68) | |
| Payments pursuant to LTSAs | (59 | ) | | (27 | ) | |
| Sale of property | 63 |
| | 10 |
| |
| | Contributions in aid of construction | | Contributions in aid of construction | 102 | | | 71 | |
| Proceeds from dispositions | | Proceeds from dispositions | 56 | | | 4 | |
| | Other investing activities | (52 | ) | | 14 |
| Other investing activities | (47) | | | (64) | |
| Net cash used for investing activities | (1,834 | ) | | (1,758 | ) | Net cash used for investing activities | (2,653) | | | (2,572) | |
| Financing Activities: | | | | Financing Activities: | | | |
| Decrease in notes payable, net | (391 | ) | | (63 | ) | |
| Increase (decrease) in notes payable, net | | Increase (decrease) in notes payable, net | 415 | | | (60) | |
| Proceeds — | | | | Proceeds — | |
| Capital contributions from parent company | 412 |
| | 294 |
| |
| Senior notes | 1,350 |
| | 650 |
| Senior notes | 1,500 | | | 750 | |
| Pollution control revenue bonds | | Pollution control revenue bonds | — | | | 122 | |
| FFB loan | | FFB loan | — | | | 371 | |
| Short-term borrowings | | Short-term borrowings | 650 | | | — | |
| | Redemptions and repurchases — | | Redemptions and repurchases — | |
| | Senior notes | | Senior notes | (400) | | | (325) | |
| Pollution control revenue bonds | | Pollution control revenue bonds | (53) | | | (69) | |
| FFB loan | — |
| | 300 |
| FFB loan | (66) | | | (75) | |
| Short-term borrowings | 700 |
| | — |
| Short-term borrowings | (250) | | | — | |
| Other long-term debt | 370 |
| | — |
| Other long-term debt | (125) | | | — | |
| Redemptions and repurchases — | | | | |
| Pollution control revenue bonds | (65 | ) | | (4 | ) | |
| Senior notes | (450 | ) | | (700 | ) | |
| Short-term borrowings | (300 | ) | | — |
| |
| | Capital contributions from parent company | | Capital contributions from parent company | 813 | | | 1,054 | |
| Payment of common stock dividends | (961 | ) | | (979 | ) | Payment of common stock dividends | (1,268) | | | (1,237) | |
| | Other financing activities | (48 | ) | | (26 | ) | Other financing activities | (45) | | | (26) | |
| Net cash provided from (used for) financing activities | 617 |
| | (528 | ) | |
| Net Change in Cash and Cash Equivalents | 263 |
| | (20 | ) | |
| Cash and Cash Equivalents at Beginning of Period | 3 |
| | 67 |
| |
| Cash and Cash Equivalents at End of Period | $ | 266 |
| | $ | 47 |
| |
| Net cash provided from financing activities | | Net cash provided from financing activities | 1,171 | | | 505 | |
| Net Change in Cash, Cash Equivalents, and Restricted Cash | | Net Change in Cash, Cash Equivalents, and Restricted Cash | — | | | 283 | |
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | | Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 33 | | | 9 | |
| Cash, Cash Equivalents, and Restricted Cash at End of Period | | Cash, Cash Equivalents, and Restricted Cash at End of Period | $ | 33 | | | $ | 292 | |
| Supplemental Cash Flow Information: | | | | Supplemental Cash Flow Information: | | | |
| Cash paid during the period for — | | | | Cash paid during the period for — | |
| Interest (net of $17 and $15 capitalized for 2017 and 2016, respectively) | $ | 284 |
| | $ | 277 |
| |
| Interest (net of $52 and $47 capitalized for 2022 and 2021, respectively) | | Interest (net of $52 and $47 capitalized for 2022 and 2021, respectively) | $ | 332 | | | $ | 325 | |
| Income taxes, net | 369 |
| | 188 |
| Income taxes, net | 151 | | | 237 | |
| Noncash transactions — Accrued property additions at end of period | 470 |
| | 226 |
| |
| Noncash transactions — | | Noncash transactions — | |
| Accrued property additions at end of period | | Accrued property additions at end of period | 609 | | | 477 | |
| Right-of-use assets obtained under operating leases | | Right-of-use assets obtained under operating leases | 7 | | | (3) | |
| Right-of-use assets obtained under finance leases | | Right-of-use assets obtained under finance leases | 112 | | | — | |
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
| | | Assets | | At September 30, 2017 | | At December 31, 2016 | Assets | | At September 30, 2022 | | At December 31, 2021 |
| | | (in millions) | | | (in millions) |
| Current Assets: | | | | | Current Assets: | |
| Cash and cash equivalents | | $ | 266 |
| | $ | 3 |
| Cash and cash equivalents | | $ | 33 | | | $ | 33 | |
| | Receivables — | | | | | Receivables — | |
| Customer accounts receivable | | 670 |
| | 523 |
| |
| Customer accounts, net | | Customer accounts, net | | 866 | | | 547 | |
| Unbilled revenues | | 276 |
| | 224 |
| Unbilled revenues | | 267 | | | 231 | |
| Under recovered fuel clause revenues | | 62 |
| | — |
| |
| Joint owner accounts receivable | | 222 |
| | 57 |
| |
| Other accounts and notes receivable | | 82 |
| | 81 |
| |
| | Joint owner accounts | | Joint owner accounts | | 64 | | | 116 | |
| | Affiliated | | 21 |
| | 18 |
| Affiliated | | 66 | | | 25 | |
| Accumulated provision for uncollectible accounts | | (3 | ) | | (3 | ) | |
| Other accounts and notes | | Other accounts and notes | | 30 | | | 44 | |
| | Fossil fuel stock | | 300 |
| | 298 |
| Fossil fuel stock | | 272 | | | 248 | |
| Materials and supplies | | 480 |
| | 479 |
| Materials and supplies | | 713 | | | 670 | |
| Prepaid expenses | | 82 |
| | 105 |
| |
| Other regulatory assets, current | | 200 |
| | 193 |
| |
| | Regulatory assets – asset retirement obligations | | Regulatory assets – asset retirement obligations | | 244 | | | 178 | |
| Assets from risk management activities | | Assets from risk management activities | | 88 | | | 48 | |
| Other regulatory assets | | Other regulatory assets | | 299 | | | 289 | |
| Other current assets | | 27 |
| | 38 |
| Other current assets | | 212 | | | 130 | |
| Total current assets | | 2,685 |
| | 2,016 |
| Total current assets | | 3,154 | | | 2,559 | |
| Property, Plant, and Equipment: | | | | | Property, Plant, and Equipment: | | | | |
| In service | | 34,589 |
| | 33,841 |
| In service | | 41,159 | | | 41,332 | |
| Less: Accumulated provision for depreciation | | 11,655 |
| | 11,317 |
| Less: Accumulated provision for depreciation | | 12,942 | | | 12,854 | |
| Plant in service, net of depreciation | | 22,934 |
| | 22,524 |
| Plant in service, net of depreciation | | 28,217 | | | 28,478 | |
| | Nuclear fuel, at amortized cost | | 551 |
| | 569 |
| Nuclear fuel, at amortized cost | | 598 | | | 577 | |
| Construction work in progress | | 5,751 |
| | 4,939 |
| Construction work in progress | | 8,053 | | | 6,688 | |
| Total property, plant, and equipment | | 29,236 |
| | 28,032 |
| Total property, plant, and equipment | | 36,868 | | | 35,743 | |
| Other Property and Investments: | | | | | Other Property and Investments: | | | | |
| Nuclear decommissioning trusts, at fair value | | Nuclear decommissioning trusts, at fair value | | 964 | | | 1,217 | |
| Equity investments in unconsolidated subsidiaries | | 53 |
| | 60 |
| Equity investments in unconsolidated subsidiaries | | 51 | | | 50 | |
| Nuclear decommissioning trusts, at fair value | | 914 |
| | 814 |
| |
| Miscellaneous property and investments | | 51 |
| | 46 |
| Miscellaneous property and investments | | 87 | | | 69 | |
| Total other property and investments | | 1,018 |
| | 920 |
| Total other property and investments | | 1,102 | | | 1,336 | |
| Deferred Charges and Other Assets: | | | | | Deferred Charges and Other Assets: | | | | |
| Operating lease right-of-use assets, net of amortization | | Operating lease right-of-use assets, net of amortization | | 1,034 | | | 1,157 | |
| Deferred charges related to income taxes | | 669 |
| | 676 |
| Deferred charges related to income taxes | | 573 | | | 550 | |
| Prepaid pension costs | | Prepaid pension costs | | 697 | | | 563 | |
| Deferred under recovered fuel clause revenues | | Deferred under recovered fuel clause revenues | | 1,697 | | | 410 | |
| Regulatory assets – asset retirement obligations, deferred | | Regulatory assets – asset retirement obligations, deferred | | 4,323 | | | 3,688 | |
| Other regulatory assets, deferred | | 2,890 |
| | 2,774 |
| Other regulatory assets, deferred | | 2,579 | | | 1,964 | |
| Other deferred charges and assets | | 608 |
| | 417 |
| Other deferred charges and assets | | 519 | | | 491 | |
| Total deferred charges and other assets | | 4,167 |
| | 3,867 |
| Total deferred charges and other assets | | 11,422 | | | 8,823 | |
| Total Assets | | $ | 37,106 |
| | $ | 34,835 |
| Total Assets | | $ | 52,546 | | | $ | 48,461 | |
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
| | | Liabilities and Stockholder's Equity | | At September 30, 2017 | | At December 31, 2016 | Liabilities and Stockholder's Equity | | At September 30, 2022 | | At December 31, 2021 |
| | | (in millions) | | | (in millions) |
| Current Liabilities: | | | | | Current Liabilities: | |
| Securities due within one year | | $ | 261 |
| | $ | 460 |
| Securities due within one year | | $ | 900 | | | $ | 675 | |
| Notes payable | | 400 |
| | 391 |
| Notes payable | | 814 | | | — | |
| Accounts payable — | | | | | Accounts payable — | |
| Affiliated | | 396 |
| | 438 |
| Affiliated | | 880 | | | 757 | |
| Other | | 1,012 |
| | 589 |
| Other | | 1,025 | | | 702 | |
| Customer deposits | | 270 |
| | 265 |
| Customer deposits | | 254 | | | 259 | |
| | Accrued taxes | | 353 |
| | 407 |
| Accrued taxes | | 486 | | | 335 | |
| Accrued interest | | 121 |
| | 106 |
| Accrued interest | | 127 | | | 136 | |
| | Accrued compensation | | 164 |
| | 224 |
| Accrued compensation | | 213 | | | 232 | |
| Asset retirement obligations, current | | 214 |
| | 299 |
| |
| Operating lease obligations | | Operating lease obligations | | 148 | | | 156 | |
| Asset retirement obligations | | Asset retirement obligations | | 309 | | | 317 | |
| | Other regulatory liabilities | | Other regulatory liabilities | | 197 | | | 280 | |
| | Other current liabilities | | 192 |
| | 297 |
| Other current liabilities | | 243 | | | 254 | |
| Total current liabilities | | 3,383 |
| | 3,476 |
| Total current liabilities | | 5,596 | | | 4,103 | |
| Long-term Debt | | 11,610 |
| | 10,225 |
| Long-term Debt | | 13,831 | | | 13,109 | |
| Deferred Credits and Other Liabilities: | | | | | Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 6,328 |
| | 6,000 |
| Accumulated deferred income taxes | | 3,588 | | | 3,019 | |
| Deferred credits related to income taxes | | Deferred credits related to income taxes | | 2,264 | | | 2,321 | |
| Accumulated deferred ITCs | | 248 |
| | 256 |
| Accumulated deferred ITCs | | 321 | | | 328 | |
| Employee benefit obligations | | 665 |
| | 703 |
| Employee benefit obligations | | 370 | | | 402 | |
| Operating lease obligations, deferred | | Operating lease obligations, deferred | | 854 | | | 999 | |
| Asset retirement obligations, deferred | | 2,367 |
| | 2,233 |
| Asset retirement obligations, deferred | | 6,547 | | | 6,507 | |
| | Other deferred credits and liabilities | | 232 |
| | 320 |
| Other deferred credits and liabilities | | 518 | | | 439 | |
| Total deferred credits and other liabilities | | 9,840 |
| | 9,512 |
| Total deferred credits and other liabilities | | 14,462 | | | 14,015 | |
| Total Liabilities | | 24,833 |
| | 23,213 |
| Total Liabilities | | 33,889 | | | 31,227 | |
| Preferred Stock | | 45 |
| | 45 |
| |
| Preference Stock | | 221 |
| | 221 |
| |
| Common Stockholder's Equity: | | | | | |
| Common stock, without par value — | | | | | |
| Authorized — 20,000,000 shares | | | | | |
| Outstanding — 9,261,500 shares | | 398 |
| | 398 |
| |
| Paid-in capital | | 7,308 |
| | 6,885 |
| |
| Retained earnings | | 4,311 |
| | 4,086 |
| |
| Accumulated other comprehensive loss | | (10 | ) | | (13 | ) | |
| Total common stockholder's equity | | 12,007 |
| | 11,356 |
| |
| Common Stockholder's Equity (See accompanying statements) | | Common Stockholder's Equity (See accompanying statements) | | 18,657 | | | 17,234 | |
| Total Liabilities and Stockholder's Equity | | $ | 37,106 |
| | $ | 34,835 |
| Total Liabilities and Stockholder's Equity | | $ | 52,546 | | | $ | 48,461 | |
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSIONCONDENSED 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, 2020 | 9 | | | $ | 398 | | | $ | 12,361 | | | $ | 3,789 | | | $ | (47) | | | $ | 16,501 | |
| Net income | — | | | — | | | — | | | 351 | | | — | | | 351 | |
| | | | | | | | | | | |
| Capital contributions from parent company | — | | | — | | | 332 | | | — | | | — | | | 332 | |
| Other comprehensive income | — | | | — | | | — | | | — | | | 2 | | | 2 | |
| Cash dividends on common stock | — | | | — | | | — | | | (412) | | | — | | | (412) | |
| | | | | | | | | | | |
| Balance at March 31, 2021 | 9 | | | 398 | | | 12,693 | | | 3,728 | | | (45) | | | 16,774 | |
| Net income | — | | | — | | | — | | | 143 | | | — | | | 143 | |
| | | | | | | | | | | |
| Capital contributions from parent company | — | | | — | | | 40 | | | — | | | — | | | 40 | |
| Other comprehensive income | — | | | — | | | — | | | — | | | 1 | | | 1 | |
| Cash dividends on common stock | — | | | — | | | — | | | (412) | | | — | | | (412) | |
| | | | | | | | | | | |
| Balance at June 30, 2021 | 9 | | | 398 | | | 12,733 | | | 3,459 | | | (44) | | | 16,546 | |
| Net income | — | | | — | | | — | | | 536 | | | — | | | 536 | |
| | | | | | | | | | | |
| Capital contributions from parent company | — | | | — | | | 690 | | | — | | | — | | | 690 | |
| Other comprehensive income | — | | | — | | | — | | | — | | | 2 | | | 2 | |
| Cash dividends on common stock | — | | | — | | | — | | | (413) | | | — | | | (413) | |
| | | | | | | | | | | |
| Balance at September 30, 2021 | 9 | | | $ | 398 | | | $ | 13,423 | | | $ | 3,582 | | | $ | (42) | | | $ | 17,361 | |
| | | | | | | | | | | |
| Balance at December 31, 2021 | 9 | | | $ | 398 | | | $ | 14,153 | | | $ | 2,724 | | | $ | (41) | | | $ | 17,234 | |
| Net income | — | | | — | | | — | | | 385 | | | — | | | 385 | |
| | | | | | | | | | | |
| Capital contributions from parent company | — | | | — | | | 443 | | | — | | | — | | | 443 | |
| Other comprehensive income | — | | | — | | | — | | | — | | | 10 | | | 10 | |
| Cash dividends on common stock | — | | | — | | | — | | | (423) | | | — | | | (423) | |
| | | | | | | | | | | |
| Balance at March 31, 2022 | 9 | | | 398 | | | 14,596 | | | 2,686 | | | (31) | | | 17,649 | |
| Net income | — | | | — | | | — | | | 608 | | | — | | | 608 | |
| | | | | | | | | | | |
| Capital contributions from parent company | — | | | — | | | 46 | | | — | | | — | | | 46 | |
| Other comprehensive income | — | | | — | | | — | | | — | | | 16 | | | 16 | |
| Cash dividends on common stock | — | | | — | | | — | | | (422) | | | — | | | (422) | |
| | | | | | | | | | | |
| Balance at June 30, 2022 | 9 | | | 398 | | | 14,642 | | | 2,872 | | | (15) | | | 17,897 | |
| Net income | — | | | — | | | — | | | 858 | | | — | | | 858 | |
| | | | | | | | | | | |
| Capital contributions from parent company | — | | | — | | | 324 | | | — | | | — | | | 324 | |
| Other comprehensive income | — | | | — | | | — | | | — | | | 1 | | | 1 | |
| Cash dividends on common stock | — | | | — | | | — | | | (423) | | | — | | | (423) | |
| | | | | | | | | | | |
| Balance at September 30, 2022 | 9 | | | $ | 398 | | | $ | 14,966 | | | $ | 3,307 | | | $ | (14) | | | $ | 18,657 | |
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | |
| Retail revenues | $ | 250 | | | $ | 248 | | | $ | 718 | | | $ | 670 | |
| Wholesale revenues, non-affiliates | 60 | | | 60 | | | 191 | | | 178 | |
| Wholesale revenues, affiliates | 187 | | | 62 | | | 336 | | | 120 | |
| Other revenues | 13 | | | 8 | | | 34 | | | 20 | |
| Total operating revenues | 510 | | | 378 | | | 1,279 | | | 988 | |
| Operating Expenses: | | | | | | | |
| Fuel and purchased power | 262 | | | 145 | | | 601 | | | 351 | |
| | | | | | | |
| | | | | | | |
| Other operations and maintenance | 86 | | | 85 | | | 252 | | | 230 | |
| Depreciation and amortization | 45 | | | 46 | | | 135 | | | 138 | |
| Taxes other than income taxes | 32 | | | 33 | | | 93 | | | 96 | |
| | | | | | | |
| Total operating expenses | 425 | | | 309 | | | 1,081 | | | 815 | |
| Operating Income | 85 | | | 69 | | | 198 | | | 173 | |
| Other Income and (Expense): | | | | | | | |
| | | | | | | |
| Interest expense, net of amounts capitalized | (15) | | | (16) | | | (42) | | | (45) | |
| Other income (expense), net | 9 | | | 7 | | | 32 | | | 27 | |
| Total other income and (expense) | (6) | | | (9) | | | (10) | | | (18) | |
| Earnings Before Income Taxes | 79 | | | 60 | | | 188 | | | 155 | |
| Income taxes | 17 | | | 10 | | | 38 | | | 22 | |
| Net Income | $ | 62 | | | $ | 50 | | | $ | 150 | | | $ | 133 | |
| | | | | | | |
| | | | | | | |
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
| Net Income | $ | 62 | | | $ | 50 | | | $ | 150 | | | $ | 133 | |
| Other comprehensive income: | | | | | | | |
| Qualifying hedges: | | | | | | | |
| | | | | | | |
Reclassification adjustment for amounts included in net income, net of tax of $—, $—, $—, and $—, respectively | — | | | — | | | — | | | 1 | |
| Total other comprehensive income | — | | | — | | | — | | | 1 | |
| Comprehensive Income | $ | 62 | | | $ | 50 | | | $ | 150 | | | $ | 134 | |
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, |
| | 2022 | | 2021 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 150 | | | $ | 133 | |
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 164 | | | 161 | |
| | | |
| | | |
| | | |
| | | |
| Settlement of asset retirement obligations | (15) | | | (18) | |
| | | |
| | | |
| Other, net | 20 | | | (20) | |
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (58) | | | (19) | |
| | | |
| | | |
| | | |
| -Other current assets | (17) | | | (9) | |
| -Accounts payable | 41 | | | (12) | |
| -Accrued taxes | (3) | | | (20) | |
| | | |
| | | |
| -Retail fuel cost over recovery | — | | | (19) | |
| | | |
| | | |
| | | |
| -Other current liabilities | (3) | | | (18) | |
| Net cash provided from operating activities | 279 | | | 159 | |
| Investing Activities: | | | |
| Property additions | (165) | | | (135) | |
| Construction payables | (9) | | | (11) | |
| | | |
| | | |
| | | |
| Payments pursuant to LTSAs | (23) | | | (21) | |
| Other investing activities | (22) | | | (15) | |
| Net cash used for investing activities | (219) | | | (182) | |
| Financing Activities: | | | |
| Decrease in notes payable, net | — | | | (25) | |
| | | |
| Proceeds — Senior notes | — | | | 525 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| Redemptions — | | | |
| | | |
| | | |
| | | |
| Other revenue bonds | — | | | (270) | |
| Other long-term debt | — | | | (75) | |
| | | |
| | | |
| | | |
| Capital contributions from parent company | 55 | | | 103 | |
| | | |
| Payment of common stock dividends | (128) | | | (118) | |
| Other financing activities | 1 | | | (10) | |
| Net cash provided from (used for) financing activities | (72) | | | 130 | |
| Net Change in Cash, Cash Equivalents, and Restricted Cash | (12) | | | 107 | |
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 61 | | | 39 | |
| Cash, Cash Equivalents, and Restricted Cash at End of Period | $ | 49 | | | $ | 146 | |
| Supplemental Cash Flow Information: | | | |
| Cash paid during the period for — | | | |
| Interest | $ | 49 | | | $ | 53 | |
| Income taxes, net | 18 | | | 11 | |
| | | |
| Noncash transactions — Accrued property additions at end of period | 16 | | | 23 | |
| | | |
| | | |
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
| | | | | | | | | | | | | | |
| Assets | | At September 30, 2022 | | At December 31, 2021 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 49 | | | $ | 61 | |
| Receivables — | | | | |
| Customer accounts, net | | 71 | | | 37 | |
| Unbilled revenues | | 43 | | | 34 | |
| | | | |
| Affiliated | | 39 | | | 29 | |
| Other accounts and notes | | 34 | | | 28 | |
| | | | |
| Fossil fuel stock | | 37 | | | 28 | |
| Materials and supplies | | 80 | | | 70 | |
| Assets from risk management activities | | 69 | | | 28 | |
| Other regulatory assets | | 60 | | | 54 | |
| | | | |
| Other current assets | | 16 | | | 13 | |
| Total current assets | | 498 | | | 382 | |
| Property, Plant, and Equipment: | | | | |
| In service | | 5,209 | | | 5,106 | |
| Less: Accumulated provision for depreciation | | 1,669 | | | 1,591 | |
| Plant in service, net of depreciation | | 3,540 | | | 3,515 | |
| | | | |
| Construction work in progress | | 168 | | | 127 | |
| Total property, plant, and equipment | | 3,708 | | | 3,642 | |
| Other Property and Investments | | 171 | | | 179 | |
| Deferred Charges and Other Assets: | | | | |
| | | | |
| Deferred charges related to income taxes | | 30 | | | 31 | |
| Prepaid pension costs | | 97 | | | 79 | |
| Regulatory assets – asset retirement obligations | | 238 | | | 232 | |
| Other regulatory assets, deferred | | 271 | | | 317 | |
| Accumulated deferred income taxes | | 108 | | | 118 | |
| | | | |
| Other deferred charges and assets | | 130 | | | 100 | |
| Total deferred charges and other assets | | 874 | | | 877 | |
| Total Assets | | $ | 5,251 | | | $ | 5,080 | |
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
| | | | | | | | | | | | | | |
| Liabilities and Stockholder's Equity | | At September 30, 2022 | | At December 31, 2021 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 1 | | | $ | 1 | |
| | | | |
| | | | |
| | | | |
| | | | |
| Accounts payable — | | | | |
| Affiliated | | 96 | | | 81 | |
| Other | | 68 | | | 47 | |
| | | | |
| | | | |
| | | | |
| Accrued taxes | | 116 | | | 120 | |
| | | | |
| | | | |
| Accrued compensation | | 33 | | | 36 | |
| | | | |
| Asset retirement obligations | | 20 | | | 30 | |
| | | | |
| Other regulatory liabilities | | 102 | | | 59 | |
| | | | |
| | | | |
| Other current liabilities | | 80 | | | 65 | |
| Total current liabilities | | 516 | | | 439 | |
| | | | |
| | | | |
| | | | |
| Long-term Debt | | 1,509 | | | 1,510 | |
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 465 | | | 464 | |
| Deferred credits related to income taxes | | 258 | | | 269 | |
| | | | |
| Employee benefit obligations | | 86 | | | 88 | |
| | | | |
| Asset retirement obligations, deferred | | 162 | | | 160 | |
| | | | |
| Other cost of removal obligations | | 197 | | | 195 | |
| Other regulatory liabilities, deferred | | 87 | | | 64 | |
| Other deferred credits and liabilities | | 25 | | | 24 | |
| Total deferred credits and other liabilities | | 1,280 | | | 1,264 | |
| Total Liabilities | | 3,305 | | | 3,213 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
Common Stockholder's Equity (See accompanying statements) | | 1,946 | | | 1,867 | |
| Total Liabilities and Stockholder's Equity | | $ | 5,251 | | | $ | 5,080 | |
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 Deficit) | | Accumulated
Other
Comprehensive
Income (Loss) | | Total |
| | (in millions) |
| Balance at December 31, 2020 | 1 | | | $ | 38 | | | $ | 4,460 | | | $ | (2,754) | | | $ | (2) | | | $ | 1,742 | |
| Net income | — | | | — | | | — | | | 45 | | | — | | | 45 | |
| | | | | | | | | | | |
| Capital contributions from parent company | — | | | — | | | 100 | | | — | | | — | | | 100 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Cash dividends on common stock | — | | | — | | | — | | | (39) | | | — | | | (39) | |
| | | | | | | | | | | |
| Balance at March 31, 2021 | 1 | | | 38 | | | 4,560 | | | (2,748) | | | (2) | | | 1,848 | |
| Net income | — | | | — | | | — | | | 38 | | | — | | | 38 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Capital contributions from parent company | — | | | — | | | 2 | | | — | | | — | | | 2 | |
| | | | | | | | | | | |
| Cash dividends on common stock | — | | | — | | | — | | | (39) | | | — | | | (39) | |
| Other | — | | | — | | | — | | | (1) | | | 1 | | | — | |
| Balance at June 30, 2021 | 1 | | | 38 | | | 4,562 | | | (2,750) | | | (1) | | | 1,849 | |
| Net income | — | | | — | | | — | | | 50 | | | — | | | 50 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Capital contributions from parent company | — | | | — | | | 3 | | | — | | | — | | | 3 | |
| | | | | | | | | | | |
| Cash dividends on common stock | — | | | — | | | — | | | (39) | | | — | | | (39) | |
| | | | | | | | | | | |
| Balance at September 30, 2021 | 1 | | | $ | 38 | | | $ | 4,565 | | | $ | (2,739) | | | $ | (1) | | | $ | 1,863 | |
| | | | | | | | | | | |
| Balance at December 31, 2021 | 1 | | | $ | 38 | | | $ | 4,582 | | | $ | (2,753) | | | $ | — | | | $ | 1,867 | |
| Net income | — | | | — | | | — | | | 42 | | | — | | | 42 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Capital contributions from parent company | — | | | — | | | 51 | | | — | | | — | | | 51 | |
| | | | | | | | | | | |
| Cash dividends on common stock | — | | | — | | | — | | | (43) | | | — | | | (43) | |
| | | | | | | | | | | |
| Balance at March 31, 2022 | 1 | | | 38 | | | 4,633 | | | (2,754) | | | — | | | 1,917 | |
| Net income | — | | | — | | | — | | | 45 | | | — | | | 45 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Capital contributions from parent company | — | | | — | | | 1 | | | — | | | — | | | 1 | |
| | | | | | | | | | | |
| Cash dividends on common stock | — | | | — | | | — | | | (42) | | | — | | | (42) | |
| | | | | | | | | | | |
| Balance at June 30, 2022 | 1 | | | 38 | | | 4,634 | | | (2,751) | | | — | | | 1,921 | |
| Net income | — | | | — | | | — | | | 62 | | | — | | | 62 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Capital contributions from parent company | — | | | — | | | 5 | | | — | | | — | | | 5 | |
| | | | | | | | | | | |
| Cash dividends on common stock | — | | | — | | | — | | | (42) | | | — | | | (42) | |
| | | | | | | | | | | |
| Balance at September 30, 2022 | 1 | | | $ | 38 | | | $ | 4,639 | | | $ | (2,731) | | | $ | — | | | $ | 1,946 | |
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
SOUTHERN POWER COMPANY AND ANALYSISSUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
FINANCIAL CONDITION AND RESULTS
| | | | | | | | | | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | |
| Wholesale revenues, non-affiliates | $ | 835 | | | $ | 503 | | | $ | 1,918 | | | $ | 1,231 | |
| Wholesale revenues, affiliates | 336 | | | 167 | | | 673 | | | 361 | |
| Other revenues | 9 | | | 9 | | | 27 | | | 18 | |
| Total operating revenues | 1,180 | | | 679 | | | 2,618 | | | 1,610 | |
| Operating Expenses: | | | | | | | |
| Fuel | 605 | | | 259 | | | 1,274 | | | 540 | |
| Purchased power | 144 | | | 41 | | | 233 | | | 86 | |
| | | | | | | |
| Other operations and maintenance | 113 | | | 94 | | | 331 | | | 308 | |
| Depreciation and amortization | 133 | | | 132 | | | 384 | | | 383 | |
| Taxes other than income taxes | 13 | | | 12 | | | 38 | | | 35 | |
| | | | | | | |
| Loss on sales-type leases | — | | | 15 | | | 1 | | | 15 | |
| Gain on dispositions, net | — | | | — | | | (2) | | | (39) | |
| Total operating expenses | 1,008 | | | 553 | | | 2,259 | | | 1,328 | |
| Operating Income | 172 | | | 126 | | | 359 | | | 282 | |
| Other Income and (Expense): | | | | | | | |
| Interest expense, net of amounts capitalized | (32) | | | (36) | | | (105) | | | (111) | |
| Other income (expense), net | 3 | | | 2 | | | 5 | | | 10 | |
| Total other income and (expense) | (29) | | | (34) | | | (100) | | | (101) | |
| Earnings Before Income Taxes | 143 | | | 92 | | | 259 | | | 181 | |
| Income taxes (benefit) | 36 | | | 9 | | | 49 | | | (3) | |
| Net Income | 107 | | | 83 | | | 210 | | | 184 | |
| Net income (loss) attributable to noncontrolling interests | 12 | | | 5 | | | (55) | | | (27) | |
| Net Income Attributable to Southern Power | $ | 95 | | | $ | 78 | | | $ | 265 | | | $ | 211 | |
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONSCOMPREHENSIVE INCOME (UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
| Net Income | $ | 107 | | | $ | 83 | | | $ | 210 | | | $ | 184 | |
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
Changes in fair value, net of tax of $(11), $(7), $(35), and $(16), respectively | (35) | | | (21) | | | (106) | | | (48) | |
Reclassification adjustment for amounts included in net income, net of tax of $9, $9, $35, and $22, respectively | 28 | | | 27 | | | 106 | | | 66 | |
| Pension and other postretirement benefit plans: | | | | | | | |
| | | | | | | |
| | | | | | | |
Reclassification adjustment for amounts included in net income, net of tax of $—, $—, $—, and $1, respectively | — | | | 1 | | | 1 | | | 2 | |
| Total other comprehensive income (loss) | (7) | | | 7 | | | 1 | | | 20 | |
| Comprehensive Income | 100 | | | 90 | | | 211 | | | 204 | |
| Comprehensive income (loss) attributable to noncontrolling interests | 12 | | | 5 | | | (55) | | | (27) | |
| Comprehensive Income Attributable to Southern Power | $ | 88 | | | $ | 85 | | | $ | 266 | | | $ | 231 | |
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
THIRD QUARTER 2017 vs. THIRD QUARTER 2016SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
ANDCONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
YEAR-TO-DATE 2017 vs. YEAR-TO-DATE 2016
| | | | | | | | | | | |
| | For the Nine Months Ended September 30, |
| | 2022 | | 2021 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 210 | | | $ | 184 | |
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 404 | | | 402 | |
| Deferred income taxes | 21 | | | (16) | |
| Utilization of federal investment tax credits | 218 | | | 237 | |
| Amortization of investment tax credits | (44) | | | (44) | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| Gain on dispositions, net | (2) | | | (39) | |
| Other, net | 1 | | | 14 | |
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (124) | | | (117) | |
| | | |
| -Prepaid income taxes | 22 | | | 63 | |
| -Other current assets | (15) | | | (5) | |
| -Accounts payable | 95 | | | 55 | |
| -Accrued taxes | 55 | | | 15 | |
| | | |
| | | |
| -Other current liabilities | (14) | | | 1 | |
| Net cash provided from operating activities | 827 | | | 750 | |
| Investing Activities: | | | |
| Business acquisitions, net of cash acquired | — | | | (345) | |
| Property additions | (64) | | | (355) | |
| Proceeds from dispositions | 48 | | | 22 | |
| | | |
| Change in construction payables | (60) | | | (22) | |
| | | |
| Payments pursuant to LTSAs | (52) | | | (61) | |
| | | |
| | | |
| Other investing activities | — | | | 8 | |
| Net cash used for investing activities | (128) | | | (753) | |
| Financing Activities: | | | |
| Decrease in notes payable, net | (5) | | | (148) | |
| | | |
| Proceeds — Senior notes | — | | | 400 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| Redemptions — Senior notes | (677) | | | — | |
| | | |
| Capital contributions from parent company | 330 | | | 4 | |
| Return of capital to parent company | — | | | (271) | |
| Capital contributions from noncontrolling interests | 73 | | | 415 | |
| Distributions to noncontrolling interests | (175) | | | (204) | |
| | | |
| Payment of common stock dividends | (148) | | | (153) | |
| Other financing activities | (1) | | | (10) | |
| Net cash provided from (used for) financing activities | (603) | | | 33 | |
| Net Change in Cash, Cash Equivalents, and Restricted Cash | 96 | | | 30 | |
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 135 | | | 183 | |
| Cash, Cash Equivalents, and Restricted Cash at End of Period | $ | 231 | | | $ | 213 | |
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
| Interest (net of $— and $5 capitalized for 2022 and 2021, respectively) | $ | 120 | | | $ | 118 | |
| Income taxes, net | (202) | | | (235) | |
| Noncash transactions — | | | |
| Contributions from noncontrolling interests | — | | | 89 | |
| Contributions of wind turbine equipment | — | | | 82 | |
| Accrued property additions at end of period | 30 | | | 53 | |
| Right-of-use assets obtained under operating leases | — | | | 66 | |
| Reassessment of right-of-use assets under operating leases | 40 | | | — | |
| | | |
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, 2022 | | At December 31, 2021 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 229 | | | $ | 107 | |
| Receivables — | | | | |
| Customer accounts, net | | 232 | | | 139 | |
| Affiliated | | 95 | | | 51 | |
| Other | | 24 | | | 29 | |
| | | | |
| Materials and supplies | | 112 | | | 106 | |
| | | | |
| Prepaid income taxes | | 5 | | | 27 | |
| | | | |
| | | | |
| | | | |
| | | | |
| Other current assets | | 51 | | | 46 | |
| Total current assets | | 748 | | | 505 | |
| Property, Plant, and Equipment: | | | | |
| In service | | 14,641 | | | 14,585 | |
| Less: Accumulated provision for depreciation | | 3,589 | | | 3,241 | |
| Plant in service, net of depreciation | | 11,052 | | | 11,344 | |
| Construction work in progress | | 48 | | | 45 | |
| | | | |
| Total property, plant, and equipment | | 11,100 | | | 11,389 | |
| Other Property and Investments: | | | | |
| | | | |
| Intangible assets, net of amortization of $124 and $109, respectively | | 268 | | | 282 | |
| Equity investments in unconsolidated subsidiaries | | 49 | | | 86 | |
| Net investment in sales-type leases | | 155 | | | 161 | |
| Total other property and investments | | 472 | | | 529 | |
| Deferred Charges and Other Assets: | | | | |
| Operating lease right-of-use assets, net of amortization | | 491 | | | 479 | |
| Prepaid LTSAs | | 210 | | | 210 | |
| | | | |
| | | | |
| | | | |
| | | | |
| Other deferred charges and assets | | 262 | | | 278 | |
| Total deferred charges and other assets | | 963 | | | 967 | |
| Total Assets | | $ | 13,283 | | | $ | 13,390 | |
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
| | | | | | | | | | | | | | |
| Liabilities and Stockholders' Equity | | At September 30, 2022 | | At December 31, 2021 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 290 | | | $ | 679 | |
| Notes payable | | 208 | | | 211 | |
| Accounts payable — | | | | |
| Affiliated | | 179 | | | 92 | |
| Other | | 70 | | | 85 | |
| | | | |
| Accrued taxes | | 208 | | | 14 | |
| | | | |
| Accrued interest | | 22 | | | 32 | |
| | | | |
| | | | |
| | | | |
| Other current liabilities | | 96 | | | 140 | |
| Total current liabilities | | 1,073 | | | 1,253 | |
| Long-term Debt | | 2,642 | | | 3,009 | |
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 315 | | | 215 | |
| Accumulated deferred ITCs | | 1,571 | | | 1,614 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| Operating lease obligations | | 515 | | | 497 | |
| Other deferred credits and liabilities | | 287 | | | 204 | |
| Total deferred credits and other liabilities | | 2,688 | | | 2,530 | |
| Total Liabilities | | 6,403 | | | 6,792 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
Total Stockholders' Equity (See accompanying statements) | | 6,880 | | | 6,598 | |
| Total Liabilities and Stockholders' Equity | | $ | 13,283 | | | $ | 13,390 | |
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, 2020 | | | | | $ | 914 | | | $ | 1,522 | | | $ | (67) | | | $ | 2,369 | | | $ | 4,262 | | | $ | 6,631 | |
| Net income (loss) | | | | | — | | | 97 | | | — | | | 97 | | | (32) | | | 65 | |
| Return of capital to parent company | | | | | (271) | | | — | | | — | | | (271) | | | — | | | (271) | |
| | | | | | | | | | | | | | | |
| Other comprehensive income | | | | | — | | | — | | | 16 | | | 16 | | | — | | | 16 | |
| Cash dividends on common stock | | | | | — | | | (51) | | | — | | | (51) | | | — | | | (51) | |
| | | | | | | | | | | | | | | |
Capital contributions from
noncontrolling interests | | | | | — | | | — | | | — | | | — | | | 403 | | | 403 | |
| Distributions to noncontrolling interests | | | | | — | | | — | | | — | | | — | | | (46) | | | (46) | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Other | | | | | (2) | | | 1 | | | (1) | | | (2) | | | (1) | | | (3) | |
| Balance at March 31, 2021 | | | | | 641 | | | 1,569 | | | (52) | | | 2,158 | | | 4,586 | | | 6,744 | |
| Net income | | | | | — | | | 36 | | | — | | | 36 | | | — | | | 36 | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Other comprehensive income (loss) | | | | | — | | | — | | | (3) | | | (3) | | | — | | | (3) | |
| Cash dividends on common stock | | | | | — | | | (51) | | | — | | | (51) | | | — | | | (51) | |
| | | | | | | | | | | | | | | |
Capital contributions from
noncontrolling interests | | | | | — | | | — | | | — | | | — | | | 29 | | | 29 | |
| Distributions to noncontrolling interests | | | | | — | | | — | | | — | | | — | | | (68) | | | (68) | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Other | | | | | 2 | | | — | | | 1 | | | 3 | | | — | | | 3 | |
| Balance at June 30, 2021 | | | | | 643 | | | 1,554 | | | (54) | | | 2,143 | | | 4,547 | | | 6,690 | |
| Net income | | | | | — | | | 78 | | | — | | | 78 | | | 5 | | | 83 | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Other comprehensive income | | | | | — | | | — | | | 7 | | | 7 | | | — | | | 7 | |
| Cash dividends on common stock | | | | | — | | | (51) | | | — | | | (51) | | | — | | | (51) | |
| | | | | | | | | | | | | | | |
Capital contributions from
noncontrolling interests | | | | | — | | | — | | | — | | | — | | | 73 | | | 73 | |
| Distributions to noncontrolling interests | | | | | — | | | — | | | — | | | — | | | (95) | | | (95) | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Balance at September 30, 2021 | | | | | $ | 643 | | | $ | 1,581 | | | $ | (47) | | | $ | 2,177 | | | $ | 4,530 | | | $ | 6,707 | |
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, 2021 | | | | | $ | 638 | | | $ | 1,585 | | | $ | (27) | | | $ | 2,196 | | | $ | 4,402 | | | $ | 6,598 | |
| Net income (loss) | | | | | — | | | 72 | | | — | | | 72 | | | (45) | | | 27 | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Other comprehensive income | | | | | — | | | — | | | 5 | | | 5 | | | — | | | 5 | |
| Cash dividends on common stock | | | | | — | | | (49) | | | — | | | (49) | | | — | | | (49) | |
| | | | | | | | | | | | | | | |
Capital contributions from
noncontrolling interests | | | | | — | | | — | | | — | | | — | | | 73 | | | 73 | |
| Distributions to noncontrolling interests | | | | | — | | | — | | | — | | | — | | | (98) | | | (98) | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Balance at March 31, 2022 | | | | | 638 | | | 1,608 | | | (22) | | | 2,224 | | | 4,332 | | | 6,556 | |
| Net income (loss) | | | | | — | | | 98 | | | — | | | 98 | | | (22) | | | 76 | |
| | | | | | | | | | | | | | | |
| Capital contributions from parent company | | | | | 322 | | | — | | | — | | | 322 | | | — | | | 322 | |
| Other comprehensive income | | | | | — | | | — | | | 3 | | | 3 | | | — | | | 3 | |
| Cash dividends on common stock | | | | | — | | | (50) | | | — | | | (50) | | | — | | | (50) | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Distributions to noncontrolling interests | | | | | — | | | — | | | — | | | — | | | (28) | | | (28) | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Balance at June 30, 2022 | | | | | 960 | | | 1,656 | | | (19) | | | 2,597 | | | 4,282 | | | 6,879 | |
| Net income | | | | | — | | | 95 | | | — | | | 95 | | | 12 | | | 107 | |
| | | | | | | | | | | | | | | |
| Capital contributions from parent company | | | | | 9 | | | — | | | — | | | 9 | | | — | | | 9 | |
| Other comprehensive income (loss) | | | | | — | | | — | | | (7) | | | (7) | | | — | | | (7) | |
| Cash dividends on common stock | | | | | — | | | (49) | | | — | | | (49) | | | — | | | (49) | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Distributions to noncontrolling interests | | | | | — | | | — | | | — | | | — | | | (57) | | | (57) | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Other | | | | | — | | | (1) | | | (1) | | | (2) | | | — | | | (2) | |
| Balance at September 30, 2022 | | | | | $ | 969 | | | $ | 1,701 | | | $ | (27) | | | $ | 2,643 | | | $ | 4,237 | | | $ | 6,880 | |
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | |
Natural gas revenues (includes revenue taxes of $15, $12, $118, and $89, respectively) | $ | 858 | | | $ | 624 | | | $ | 3,998 | | | $ | 2,991 | |
| Alternative revenue programs | (1) | | | (1) | | | — | | | 3 | |
| | | | | | | |
| Total operating revenues | 857 | | | 623 | | | 3,998 | | | 2,994 | |
| Operating Expenses: | | | | | | | |
| Cost of natural gas | 294 | | | 129 | | | 1,840 | | | 943 | |
| | | | | | | |
| Other operations and maintenance | 252 | | | 238 | | | 829 | | | 776 | |
| Depreciation and amortization | 140 | | | 133 | | | 414 | | | 396 | |
| Taxes other than income taxes | 45 | | | 36 | | | 208 | | | 166 | |
| | | | | | | |
Gain on dispositions, net
| — | | | (121) | | | (5) | | | (127) | |
| | | | | | | |
| Total operating expenses | 731 | | | 415 | | | 3,286 | | | 2,154 | |
| Operating Income | 126 | | | 208 | | | 712 | | | 840 | |
| Other Income and (Expense): | | | | | | | |
| Earnings from equity method investments | 34 | | | 25 | | | 105 | | | 14 | |
| Interest expense, net of amounts capitalized | (65) | | | (57) | | | (187) | | | (175) | |
| Other income (expense), net | 15 | | | 13 | | | 47 | | | (66) | |
| Total other income and (expense) | (16) | | | (19) | | | (35) | | | (227) | |
| Earnings Before Income Taxes | 110 | | | 189 | | | 677 | | | 613 | |
| Income taxes | 27 | | | 133 | | | 161 | | | 224 | |
| Net Income | $ | 83 | | | $ | 56 | | | $ | 516 | | | $ | 389 | |
| | | | | | | |
| | | | | | | |
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
| Net Income | $ | 83 | | | $ | 56 | | | $ | 516 | | | $ | 389 | |
| Other comprehensive income: | | | | | | | |
| Qualifying hedges: | | | | | | | |
Changes in fair value, net of tax of $8, $8, $16, and $11, respectively | 19 | | | 23 | | | 39 | | | 32 | |
Reclassification adjustment for amounts included in net income, net of tax of $(2), $—, $(7), and $1, respectively | (5) | | | (2) | | | (17) | | | 1 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Total other comprehensive income | 14 | | | 21 | | | 22 | | | 33 | |
| Comprehensive Income | $ | 97 | | | $ | 77 | | | $ | 538 | | | $ | 422 | |
| | | | | | | |
| | | | | | | |
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, |
| | 2022 | | 2021 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 516 | | | $ | 389 | |
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 414 | | | 396 | |
| Deferred income taxes | 109 | | | 289 | |
| | | |
| | | |
| | | |
| | | |
| Mark-to-market adjustments | (34) | | | 147 | |
| Impairment of PennEast Pipeline investment | — | | | 84 | |
| Gain on dispositions, net | (5) | | | (127) | |
| Natural gas cost under recovery – long-term | 207 | | | (79) | |
| Other, net | 27 | | | 32 | |
| Changes in certain current assets and liabilities — | | | |
| -Receivables | 301 | | | 311 | |
| -Natural gas for sale, net of temporary LIFO liquidation | (136) | | | 20 | |
| -Prepaid income taxes | (77) | | | (148) | |
| -Natural gas cost under recovery | (124) | | | (432) | |
| -Other current assets | 7 | | | (98) | |
| -Accounts payable | 342 | | | 30 | |
| | | |
| | | |
| -Other current liabilities | (15) | | | (57) | |
| Net cash provided from operating activities | 1,532 | | | 757 | |
| Investing Activities: | | | |
| Property additions | (1,063) | | | (1,045) | |
| Cost of removal, net of salvage | (84) | | | (74) | |
| Change in construction payables, net | (103) | | | 4 | |
| | | |
| | | |
| Proceeds from dispositions | — | | | 126 | |
| Other investing activities | 11 | | | 23 | |
| Net cash used for investing activities | (1,239) | | | (966) | |
| Financing Activities: | | | |
| Increase (decrease) in notes payable, net | (749) | | | 38 | |
| Proceeds — | | | |
| Short-term borrowings | 50 | | | 300 | |
| First mortgage bonds | 100 | | | 100 | |
| Senior notes | 500 | | | 450 | |
| Redemptions — | | | |
| | | |
| | | |
| Short-term borrowings | (150) | | | — | |
| Senior notes | — | | | (300) | |
| | | |
| | | |
| Medium-term notes | (46) | | | (30) | |
| Capital contributions from parent company | 357 | | | 63 | |
| Payment of common stock dividends | (389) | | | (397) | |
| Other financing activities | 14 | | | (2) | |
| Net cash provided from (used for) financing activities | (313) | | | 222 | |
| Net Change in Cash, Cash Equivalents, and Restricted Cash | (20) | | | 13 | |
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 48 | | | 19 | |
| Cash, Cash Equivalents, and Restricted Cash at End of Period | $ | 28 | | | $ | 32 | |
| Supplemental Cash Flow Information: | | | |
| Cash paid during the period for — | | | |
| Interest (net of $7 and $6 capitalized for 2022 and 2021, respectively) | $ | 186 | | | $ | 173 | |
| Income taxes, net | 193 | | | 85 | |
| Noncash transactions — Accrued property additions at end of period | 10 | | | 146 | |
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, 2022 | | At December 31, 2021 |
| | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 26 | | | $ | 45 | |
| Receivables — | | | | |
| | | | |
| Customer accounts | | 296 | | | 462 | |
| Unbilled revenues | | 122 | | | 278 | |
| | | | |
| | | | |
| | | | |
| Other accounts and notes | | 58 | | | 49 | |
| Accumulated provision for uncollectible accounts | | (41) | | | (39) | |
| | | | |
| Natural gas for sale | | 498 | | | 362 | |
| | | | |
| | | | |
| Prepaid expenses | | 192 | | | 114 | |
| | | | |
| Natural gas cost under recovery | | 390 | | | 266 | |
| | | | |
| | | | |
| Other regulatory assets | | 121 | | | 136 | |
| Other current assets | | 118 | | | 82 | |
| Total current assets | | 1,780 | | | 1,755 | |
| Property, Plant, and Equipment: | | | | |
| In service | | 19,656 | | | 18,880 | |
| Less: Accumulated depreciation | | 5,270 | | | 5,067 | |
| Plant in service, net of depreciation | | 14,386 | | | 13,813 | |
| Construction work in progress | | 871 | | | 684 | |
| Total property, plant, and equipment | | 15,257 | | | 14,497 | |
| Other Property and Investments: | | | | |
| Goodwill | | 5,015 | | | 5,015 | |
| Equity investments in unconsolidated subsidiaries | | 1,125 | | | 1,173 | |
| Other intangible assets, net of amortization of $154 and $145, respectively | | 28 | | | 37 | |
| Miscellaneous property and investments | | 27 | | | 19 | |
| Total other property and investments | | 6,195 | | | 6,244 | |
| Deferred Charges and Other Assets: | | | | |
| Operating lease right-of-use assets, net of amortization | | 61 | | | 70 | |
| Prepaid pension costs | | 200 | | | 175 | |
| | | | |
| | | | |
| Other regulatory assets, deferred | | 468 | | | 689 | |
| | | | |
| | | | |
| Other deferred charges and assets | | 136 | | | 130 | |
| Total deferred charges and other assets | | 865 | | | 1,064 | |
| Total Assets | | $ | 24,097 | | | $ | 23,560 | |
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
| | | | | | | | | | | | | | |
| Liabilities and Stockholder's Equity | | At September 30, 2022 | | At December 31, 2021 |
| | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | — | | | $ | 47 | |
| Notes payable | | 360 | | | 1,209 | |
| | | | |
| Accounts payable — | | | | |
| Affiliated | | 64 | | | 58 | |
| Other | | 592 | | | 361 | |
| Customer deposits | | 137 | | | 95 | |
| | | | |
| | | | |
| Accrued taxes | | 71 | | | 124 | |
| Accrued interest | | 67 | | | 59 | |
| | | | |
| Accrued compensation | | 92 | | | 110 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| Other regulatory liabilities | | 15 | | | 8 | |
| Other current liabilities | | 168 | | | 155 | |
| Total current liabilities | | 1,566 | | | 2,226 | |
| Long-term Debt | | 7,361 | | | 6,855 | |
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 1,662 | | | 1,555 | |
| Deferred credits related to income taxes | | 793 | | | 816 | |
| | | | |
| Employee benefit obligations | | 158 | | | 176 | |
| | | | |
| | | | |
| Operating lease obligations | | 53 | | | 59 | |
| Other cost of removal obligations | | 1,696 | | | 1,683 | |
| Accrued environmental remediation | | 217 | | | 197 | |
| | | | |
| | | | |
| | | | |
| Other deferred credits and liabilities | | 153 | | | 77 | |
| Total deferred credits and other liabilities | | 4,732 | | | 4,563 | |
| Total Liabilities | | 13,659 | | | 13,644 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
Common Stockholder's Equity (See accompanying statements) | | 10,438 | | | 9,916 | |
| Total Liabilities and Stockholder's Equity | | $ | 24,097 | | | $ | 23,560 | |
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY (UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Paid-In
Capital | | Retained
Earnings
(Accumulated Deficit) | | Accumulated
Other
Comprehensive
Income (Loss) | | Total |
| | | | | | (in millions) |
| Balance at December 31, 2020 | | | | | $ | 9,930 | | | $ | (141) | | | $ | (22) | | | $ | 9,767 | |
| Net income | | | | | — | | | 398 | | | — | | | 398 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Capital contributions from parent company | | | | | 57 | | | — | | | — | | | 57 | |
| Other comprehensive income | | | | | — | | | — | | | 4 | | | 4 | |
| Cash dividends on common stock | | | | | — | | | (132) | | | — | | | (132) | |
| | | | | | | | | | | |
| Balance at March 31, 2021 | | | | | 9,987 | | | 125 | | | (18) | | | 10,094 | |
| Net loss | | | | | — | | | (65) | | | — | | | (65) | |
| | | | | | | | | | | |
| Capital contributions from parent company | | | | | 25 | | | — | | | — | | | 25 | |
| Other comprehensive income | | | | | — | | | — | | | 8 | | | 8 | |
| Cash dividends on common stock | | | | | — | | | (133) | | | — | | | (133) | |
| | | | | | | | | | | |
| Balance at June 30, 2021 | | | | | 10,012 | | | (73) | | | (10) | | | 9,929 | |
| Net income | | | | | — | | | 56 | | | — | | | 56 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Capital contributions from parent company | | | | | 2 | | | — | | | — | | | 2 | |
| Other comprehensive income | | | | | — | | | — | | | 21 | | | 21 | |
| Cash dividends on common stock | | | | | — | | | (132) | | | — | | | (132) | |
| | | | | | | | | | | |
| Balance at September 30, 2021 | | | | | $ | 10,014 | | | $ | (149) | | | $ | 11 | | | $ | 9,876 | |
| | | | | | | | | | | |
| Balance at December 31, 2021 | | | | | $ | 10,024 | | | $ | (132) | | | $ | 24 | | | $ | 9,916 | |
| Net income | | | | | — | | | 319 | | | — | | | 319 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Capital contributions from parent company | | | | | 50 | | | — | | | — | | | 50 | |
| Other comprehensive income | | | | | — | | | — | | | 20 | | | 20 | |
| Cash dividends on common stock | | | | | — | | | (130) | | | — | | | (130) | |
| | | | | | | | | | | |
| Balance at March 31, 2022 | | | | | 10,074 | | | 57 | | | 44 | | | 10,175 | |
| Net income | | | | | — | | | 115 | | | — | | | 115 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Capital contributions from parent company | | | | | 312 | | | — | | | — | | | 312 | |
| Other comprehensive income (loss) | | | | | — | | | — | | | (12) | | | (12) | |
| Cash dividends on common stock | | | | | — | | | (130) | | | — | | | (130) | |
| | | | | | | | | | | |
| Balance at June 30, 2022 | | | | | 10,386 | | | 42 | | | 32 | | | 10,460 | |
| Net income | | | | | — | | | 83 | | | — | | | 83 | |
| | | | | | | | | | | |
| Capital contributions from parent company | | | | | 11 | | | — | | | — | | | 11 | |
| Other comprehensive income | | | | | — | | | — | | | 14 | | | 14 | |
| Cash dividends on common stock | | | | | — | | | (130) | | | — | | | (130) | |
| | | | | | | | | | | |
| Balance at September 30, 2022 | | | | | $ | 10,397 | | | $ | (5) | | | $ | 46 | | | $ | 10,438 | |
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS
FOR
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA POWER COMPANY
MISSISSIPPI POWER COMPANY
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
(UNAUDITED)
INDEX TO THE NOTES TO THE CONDENSED FINANCIAL STATEMENTS
INDEX TO APPLICABLE NOTES TO FINANCIAL STATEMENTS BY REGISTRANT
The following unaudited notes to the condensed financial statements are a combined presentation; however, information contained herein relating to any individual Registrant is filed by such Registrant on its own behalf and each Registrant makes no representation as to information related to the other Registrants. The list below indicates the Registrants to which each footnote applies.
| | | | | |
| Registrant | Applicable Notes |
| Southern Company | A, B, C, D, E, F, G, H, I, J, K, L |
| Alabama Power | A, B, C, D, F, G, H, I, J, K |
| Georgia Power | A, B, C, D, F, G, H, I, J |
| Mississippi Power | A, B, C, D, F, G, H, I, J |
| Southern Power | A, C, D, E, F, G, H, I, J, K |
| Southern Company Gas | A, B, C, D, E, F, G, H, I, J, K, L |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS
(UNAUDITED)
(A) INTRODUCTION
The condensed quarterly financial statements of each Registrant included herein have been prepared by such Registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets at December 31, 2021 have been derived from the audited financial statements of each Registrant. In the opinion of each Registrant's management, the information regarding such Registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended September 30, 2022 and 2021. 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 and other factors, 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 overall results of operations, financial position, or cash flows of any Registrant.
Goodwill and Other Intangible Assets
Goodwill at September 30, 2022 and December 31, 2021 was as follows:
| | | | | | |
| Goodwill | |
| (in millions) |
| Southern Company | $ | 5,280 | | |
| Southern Company Gas: | | |
| Gas distribution operations | $ | 4,034 | | |
| Gas marketing services | 981 | | |
| Southern Company Gas total | $ | 5,015 | | |
Goodwill is not amortized, but is subject to an annual impairment test during the fourth quarter of each year, or more frequently if impairment indicators arise.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Other intangible assets were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| At September 30, 2022 | | At December 31, 2021 |
| Gross Carrying Amount | Accumulated Amortization | Other
Intangible Assets, Net | | Gross Carrying Amount | Accumulated Amortization | Other
Intangible Assets, Net |
| (in millions) | | (in millions) |
| Southern Company | | | | | | | |
| Other intangible assets subject to amortization: | | | | | | | |
| Customer relationships | $ | 212 | $ | (159) | $ | 53 | | $ | 212 | | $ | (150) | | $ | 62 | |
| Trade names | 64 | (44) | 20 | | 64 | | (38) | | 26 | |
| PPA fair value adjustments | 390 | (124) | 266 | | 390 | | (109) | | 281 | |
| Other | 5 | (4) | 1 | | 11 | | (10) | | 1 | |
| Total other intangible assets subject to amortization | $ | 671 | | $ | (331) | | $ | 340 | | | $ | 677 | | $ | (307) | | $ | 370 | |
| Other intangible assets not subject to amortization: | | | | | | | |
| Federal Communications Commission licenses | 75 | | — | | 75 | | | 75 | | — | | 75 | |
| Total other intangible assets | $ | 746 | | $ | (331) | | $ | 415 | | | $ | 752 | | $ | (307) | | $ | 445 | |
| | | | | | | |
| Southern Power | | | | | | | |
| Other intangible assets subject to amortization: | | | | | | | |
| PPA fair value adjustments | $ | 390 | | $ | (124) | | $ | 266 | | | $ | 390 | | $ | (109) | | $ | 281 | |
| | | | | | | |
| Southern Company Gas | | | | | | | |
| Other intangible assets subject to amortization: | | | | | | | |
| Gas marketing services | | | | | | | |
| Customer relationships | $ | 156 | | $ | (137) | | $ | 19 | | | $ | 156 | | $ | (130) | | $ | 26 | |
| Trade names | 26 | | (17) | | 9 | | | 26 | | (15) | | 11 | |
| Total other intangible assets subject to amortization | $ | 182 | | $ | (154) | | $ | 28 | | | $ | 182 | | $ | (145) | | $ | 37 | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Amortization associated with other intangible assets was as follows:
| | | | | | | | |
| Three Months Ended | Nine Months Ended |
| September 30, 2022 |
| (in millions) |
Southern Company(a) | $ | 11 | | $ | 30 | |
Southern Power(b) | 5 | | 15 | |
| Southern Company Gas | 4 | | 9 | |
(a)Includes $5 million and $15 million for the three and nine months ended September 30, 2022, respectively, recorded as a reduction to operating revenues.
(b)Recorded as a reduction to operating revenues.
Cash, Cash Equivalents, and Restricted Cash
The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed balance sheets that total to the amount shown in the condensed statements of cash flows for the applicable Registrants:
| | | | | | | | | | | | | | | | | | | | | |
| Southern
Company | Southern
Power | | Southern
Company Gas |
| September 30, 2022 | December 31, 2021 | September 30, 2022 | December 31, 2021 | | September 30, 2022 | December 31, 2021 |
| (in millions) |
| Cash and cash equivalents | $ | 2,009 | | $ | 1,798 | | $ | 229 | | $ | 107 | | | $ | 26 | | $ | 45 | |
Restricted cash(a): | | | | | | | |
| Other current assets | 2 | | 2 | | — | | — | | | 2 | | 2 | |
| Other deferred charges and assets | 3 | | 29 | | 3 | | 29 | | | — | | — | |
Total cash, cash equivalents, and restricted cash(b) | $ | 2,013 | | $ | 1,829 | | $ | 231 | | $ | 135 | | | $ | 28 | | $ | 48 | |
(a)For Southern Power, reflects $3 million and $10 million at September 30, 2022 and December 31, 2021, respectively, held to fund estimated construction completion costs at the Deuel Harvest wind facility and $19 million at December 31, 2021 related to tax equity contributions restricted until the Garland battery energy storage facility achieved final contracted capacity. For Southern Company Gas, reflects collateral for workers' compensation, life insurance, and long-term disability insurance.
(b)Total may not add due to rounding.
Natural Gas for Sale
With the exception of Nicor Gas, Southern Company Gas records natural gas inventories 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. Nicor Gas' natural gas inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated.
Southern Company Gas recorded no material adjustments to natural gas inventories for either period presented. Nicor Gas had no inventory decrement at September 30, 2022.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Depreciation and Amortization
See Note 5 to the financial statements under "Depreciation and Amortization" in Item 8 of the Form 10-K for additional information.
Alabama Power
On September 23, 2022, the FERC authorized Alabama Power to use updated depreciation rates from its 2021 depreciation study effective January 1, 2023. The study was also provided to the Alabama PSC, and the new depreciation rates will be reflected in Alabama Power's future rate filings. See Note 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.
Southern Power
Effective January 1, 2022, Southern Power revised the depreciable lives of its wind generating facilities from up to 30 years to up to 35 years. This revision resulted in an immaterial decrease in depreciation for the three and nine months ended September 30, 2022.
(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 retail regulatory clauses of the traditional electric operating companies and Southern Company Gas at September 30, 2022 and December 31, 2021 were as follows:
| | | | | | | | | | | |
| Regulatory Clause | Balance Sheet Line Item | September 30,
2022 | December 31, 2021 |
| | (in millions) |
| Alabama Power | | | |
| | | |
| Rate CNP Compliance | Other regulatory liabilities, deferred | $ | 4 | | $ | — | |
| Other regulatory assets, deferred | — | | 16 | |
| | | |
| Rate CNP PPA | Other regulatory assets, deferred | 125 | | 84 | |
| | | |
| | | |
Retail Energy Cost Recovery(*) | Other regulatory assets, current | 93 | | — | |
| Other regulatory assets, deferred | 413 | | 126 | |
| | | |
| | | |
| Georgia Power | | | |
| | | |
| Fuel Cost Recovery | Deferred under recovered fuel clause revenues | $ | 1,697 | | $ | 410 | |
| | | |
| Mississippi Power | | | |
| | | |
| Fuel Cost Recovery | Other customer accounts receivable | $ | 13 | | $ | 4 | |
| Ad Valorem Tax | Other regulatory assets, current | 12 | | 12 | |
| Other regulatory assets, deferred | 22 | | 37 | |
| | | |
| | | |
| Southern Company Gas | | | |
| | | |
| Natural Gas Cost Recovery | Natural gas cost under recovery | $ | 390 | | $ | 266 | |
| Other regulatory assets, deferred | — | | 207 | |
| | | |
(*)In accordance with an Alabama PSC order issued on February 1, 2022, Alabama Power applied $126 million of its 2021 Rate RSE refund to reduce the Rate ECR under recovered balance.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Alabama Power
Certificates of Convenience and Necessity
On July 12, 2022, the Alabama PSC approved a certificate of convenience and necessity (CCN) authorizing Alabama Power to complete the acquisition of the Calhoun Generating Station, which was approved by the FERC on March 25, 2022. The transaction closed on September 30, 2022 and, on October 3, 2022, Alabama Power filed Rate CNP New Plant with the Alabama PSC to recover the related costs. The filing reflected an increase in annual revenues of $34 million, or 0.6%, effective with the billing month of November 2022. Alabama Power expects to recover all approved costs associated with the acquisition through existing rate mechanisms as outlined in Note 2 to the financial statements in Item 8 of the Form 10-K. See Note (K) under "Alabama Power" for additional information.
With the completion of the Calhoun Generating Station acquisition, Alabama Power expects to retire Plant Barry Unit 5 as early as 2023. In September 2022, Alabama Power reclassified approximately $600 million for Plant Barry Unit 5 from plant in service, net of depreciation to other utility plant, net and will continue to depreciate the asset according to the original depreciation rates. At retirement, Alabama Power will reclassify the remaining net investment costs of the unit to a regulatory asset to be recovered over the unit's remaining useful life, as established prior to the decision to retire, through Rate CNP Compliance. See Note 2 to the financial statements under "Alabama Power – Environmental Accounting Order" in Item 8 of the Form 10-K for additional information.
In its 2020 order authorizing the CCN for Alabama Power's construction of Plant Barry Unit 8, the Alabama PSC authorized recovery of estimated actual in-service costs of $652 million. At September 30, 2022, project expenditures associated with Plant Barry Unit 8 included in CWIP totaled approximately $484 million and the unit is expected to be placed in service in November 2023. The ultimate outcome of this matter cannot be determined at this time.
Rate ECR
On July 12, 2022, the Alabama PSC approved an adjustment to Rate ECR from 1.960 cents per KWH to 2.557 cents per KWH, or approximately $310 million annually, effective with August 2022 billings. The approved increase in the Rate ECR factor has no significant effect on Alabama Power's net income, but does increase operating cash flows related to fuel cost recovery. The rate will adjust to 5.910 cents per KWH in January 2025 absent a further order from the Alabama PSC.
Rate NDR
On July 12, 2022, the Alabama PSC approved modifications to Rate NDR, which include an adjustment to the charges to establish and maintain the reserve and an adjustment to the recovery period for any existing deferred storm-related operations and maintenance costs and future reserve deficits from 24 months to 48 months. As modified, the maximum total Rate NDR charge to recover a deficit is limited to $5.00 per month per non-residential customer account and $2.50 per month per residential customer account.
Beginning with August 2022 billings, the reserve establishment charge was suspended and the reserve maintenance charge was activated as a result of the NDR balance exceeding $75 million. Alabama Power expects to collect $6 million in the second half of 2022 and approximately $12 million annually beginning in 2023 under Rate NDR unless the NDR balance falls below $50 million. At September 30, 2022, Alabama Power's NDR balance was $103 million. Alabama Power continues to have the authority to accrue additional amounts to the NDR as circumstances warrant.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Reliability Reserve Accounting Order
On July 12, 2022, the Alabama PSC approved an accounting order authorizing Alabama Power to create a reliability reserve separate from the NDR and transition the previous Rate NDR authority related to reliability expenditures to the reliability reserve. Alabama Power may make accruals to the reliability reserve if the NDR balance exceeds $35 million.
Renewable Generation Certificate
Through the issuance of a Renewable Generation Certificate (RGC), Alabama Power is authorized by the Alabama PSC to procure up to 500 MWs of renewable capacity and energy by September 16, 2027 and to market the related energy and environmental attributes to customers and other third parties. In April 2022, one of the existing solar projects which was expected to be served through a PPA commencing in first quarter 2024 was terminated, resulting in the restoration of 80 MWs of capacity under the RGC. On October 4, 2022, the Alabama PSC approved two new solar PPAs totaling 160 MWs. Alabama Power has procured solar capacity totaling approximately 330 MWs under the RGC. The ultimate outcome of this matter cannot be determined at this time.
Georgia Power
Rate Plans
2022 Base Rate Case
On June 24, 2022, Georgia Power filed a base rate case (Georgia Power 2022 Base Rate Case) with the Georgia PSC. The filing, as modified on August 22, 2022, proposes a three-year alternate rate plan with requested rate increases totaling $889 million, $107 million, and $45 million effective January 1, 2023, January 1, 2024, and January 1, 2025, respectively. These increases are based on a proposed retail ROE of 11.00% using the currently approved 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 (DSM) programs, and related adjustments to the Municipal Franchise Fee tariff.
Georgia Power operateshas requested recovery of the proposed increases through its existing base rate tariffs as a vertically integrated utility providing electric servicefollows:
| | | | | | | | | | | | | | | | | |
| Tariff | 2023 | | 2024 | | 2025 |
| (in millions) |
| Traditional base | $ | 762 | | | $ | — | | | $ | — | |
| ECCR | | | | | |
| Traditional | 5 | | | — | | | — | |
CCR ARO(a) | 64 | | | 78 | | | 47 | |
DSM(a) | 37 | | | 27 | | | (2) | |
| Municipal Franchise Fee | 21 | | | 2 | | | 1 | |
Total(b) | $ | 889 | | | $ | 107 | | | $ | 45 | |
(a)As determined by the Georgia PSC through annual compliance filings.
(b)Totals may not add due to retail customers within its traditional service territory located withinrounding.
Georgia Power's filing primarily reflects requests to (i) recover the Statecosts of Georgiarecent and to wholesale customersfuture capital investments in the Southeast.electric grid including the transmission and distribution systems and the continuation of its grid investment plan, all designed to support customer long-term reliability and resiliency needs, (ii) recover the cost of coal-fired generation units proposed for retirement, or made unavailable, as requested in the 2022 IRP, as Georgia Power continues the transition of the generation fleet to more economical and cleaner resources, (iii) make the necessary investments and recover costs to comply with federal and state environmental regulations, including costs
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
associated with the opportunities,CCR AROs related to ash pond and landfill closures and post-closure care, and (iv) reduce operating costs despite significant inflationary pressures. In addition, the filing includes the following provisions:
•Continuation of an allowed retail ROE range of 9.50% to 12.00%.
•Continuation of the process whereby 80% of any earnings above the top of the allowed ROE range are shared with Georgia Power's customers and the remaining 20% 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 allowed ROE range during the three-year term of the plan.
Georgia Power expects the Georgia PSC to render a final decision in this matter on December 20, 2022. The ultimate outcome of this matter cannot be determined at this time.
2019 ARP
In 2020, the Georgia PSC denied a motion for reconsideration filed by Sierra Club regarding the Georgia PSC's decision in the 2019 ARP allowing Georgia Power to recover compliance costs for CCR AROs. The Superior Court of Fulton County subsequently affirmed the Georgia PSC's decision and, in October 2021, the Georgia Court of Appeals affirmed the Superior Court of Fulton County's order. In December 2021, Sierra Club filed a petition for writ of certiorari to the Georgia Supreme Court, which was denied on July 14, 2022. This matter is now concluded. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information regarding Georgia Power's AROs.
Integrated Resource Plans
In response to supply chain challenges in the solar industry, the Georgia PSC approved Georgia Power's request to amend 970 MWs of utility-scale solar PPAs that were authorized by the Georgia PSC in Georgia Power's 2019 IRP. The amendments extended the required commercial operation dates for the PPAs from 2023 to 2024.
On July 21, 2022, the Georgia PSC approved the 2022 IRP, as modified by a stipulated agreement among Georgia Power, the staff of the Georgia PSC, and riskscertain intervenors and as further modified by the Georgia PSC. In the 2022 IRP decision, the Georgia PSC approved the following requests:
•Decertification and retirement of Plant Wansley Units 1 and 2 (926 MWs based on 53.5% ownership), which occurred on August 31, 2022, and reclassification to regulatory asset accounts of the remaining net book values and any remaining unusable materials and supplies inventories upon retirement. The regulatory asset accounts for the remaining net book values of the units ($299 million and $277 million for Unit 1 and Unit 2, respectively, at September 30, 2022) are being amortized at a rate equal to the unit depreciation rates authorized in the 2019 ARP through December 31, 2022. In the Georgia Power 2022 Base Rate Case, Georgia Power requested recovery of the remaining regulatory asset balances for the net book values of the units through 2030 and requested that the timing of recovery of the regulatory asset account for the unusable materials and supplies inventories be determined in a future base rate case.
•Decertification and retirement of Plant Scherer Unit 3 (614 MWs based on 75% ownership) by December 31, 2028 and reclassification to regulatory asset accounts of the remaining net book value (approximately $608 million at September 30, 2022) and any remaining unusable materials and supplies inventory to regulatory asset accounts upon retirement. The timing of recovery for these regulatory assets is expected to be determined in a future base rate case.
•Decertification and retirement of Plant Gaston Units 1 through 4 (500 MWs based on 50% ownership through SEGCO) by December 31, 2028. See Note 7 to the financial statements under "SEGCO" in Item 8 of the Form 10-K for additional information.
•Georgia Power's environmental compliance strategy, including approval of Georgia Power's businessplans to address CCR at its ash ponds and landfills. Recovery of providing electric service. These factors include the abilityrelated costs is expected to maintainbe determined in future base rate cases. The Georgia PSC's approval included a constructive regulatory environment,change in the method of closure for one ash
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
pond. Georgia Power is currently evaluating the related impact on its cost estimates and grow energy sales,AROs; however, it is not expected to be material.
•Installation of environmental controls at Plants Bowen and to effectively manage and secure timely recovery of costs. These costs include thoseScherer for compliance with rules related to projected long-term demand growth, stringent environmental standards, reliability, fuel, capital expenditures,effluent limitations guidelines.
•Initiation of a license renewal application with the NRC for Plant Hatch.
•Investments related to the continued hydro operations of Plants Sinclair and restoration following major storms.Burton.
•Provisional authorization for development of a 265-MW battery energy storage facility with expected commercial operation in 2026.
•Issuance of requests for proposals (RFP) for 2,300 MWs of renewable resources, an additional 500 MWs of energy storage, and up to 140 MWs of biomass generation.
•Related transmission projects necessary to support the generation facilities plan.
•Certification of six PPAs (including five affiliate PPAs with Southern Power that are subject to approval by the FERC) with capacities of 1,567 MWs beginning in 2024, 380 MWs beginning in 2025, and 228 MWs beginning in 2028, procured through RFPs authorized in the 2019 IRP. See Note (F) under "Georgia Power Lease Modification" for additional information.
The Georgia PSC deferred a decision on the requested decertification and retirement of Plant Bowen Units 1 and 2 (1,400 MWs) to the 2025 IRP and rejected Georgia Power's request to certify approximately 88 MWs of wholesale capacity to be placed in retail rate base between January 1, 2024 and January 1, 2025. Georgia Power has variousmay offer such capacity in the wholesale market or to the retail jurisdiction in a future 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 challengeproceeding.
On August 26, 2022, Restore Chattooga Gorge Coalition (RCG) filed a petition in the Superior Court of Fulton County, Georgia against Georgia Power forand the foreseeable future.Georgia PSC. The petition challenges Georgia Power's plan to expend $115 million to modernize Plant Tugalo, as approved in the 2019 IRP, and seeks judicial review of the Georgia PSC's order in the 2022 IRP proceeding with respect to the denial of RCG's challenge to the modernization plan.
Georgia Power continues to focus on several key performance indicators including, but not limited to, customer satisfaction, plant availability, system reliability, the executionThe ultimate outcome of major construction projects, and net income after dividends on preferred and preference stock.these matters cannot be determined at this time.
Nuclear Construction
In 2009, the Georgia Power and the Vogtle Owners have been constructing Plant Vogtle Units 3 and 4 since 2009. On March 29, 2017, the EPC Contractor for Plant Vogtle Units 3 and 4 filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. To provide for a continuation of work, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an interim assessment agreement with the EPC Contractor (Interim Assessment Agreement), which the bankruptcy court approved on March 30, 2017. On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion (Guarantee Obligations), of which Georgia Power's proportionate share is approximately $1.7 billion, and that the Guarantee Obligations exist regardless of whether Plant Vogtle Units 3 and 4 are completed. On October 2, 2017, Georgia Power received the first installment of the Guarantee Obligations of $300 million from Toshiba, of which Georgia Power's proportionate share was $137 million.
Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into a services agreement (Services Agreement), which was amended and restated on July 20, 2017, for the EPC Contractor to transitionPSC certified construction management of Plant Vogtle Units 3 and 4, in which Georgia Power holds a 45.7% ownership interest. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to Southern Nuclearbegin. Until March 2017, construction on Plant Vogtle Units 3 and to provide ongoing design, engineering, and procurement services to Southern Nuclear. On July 27, 2017, the Services Agreement, and the EPC Contractor's rejection of4 continued under the Vogtle 3 and 4 Agreement, became effective upon approval bywhich was a substantially fixed price agreement.
In connection with the DOE and the Interim Assessment Agreement expired pursuant to its terms. The Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice. Effective October 23,EPC Contractor's bankruptcy filing in March 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement (Bechtel Agreement) with Bechtel Power Corporation (Bechtel), whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4.
In the seventeenth Vogtle Construction Monitoring (VCM) report filed on August 31, 2017, Georgia Power recommended that construction of Plant Vogtle Units 3 and 4 be continued, with Southern Nuclear serving as project manager. Georgia Power believes that the most reasonable schedule for completing Plant Vogtle Units 3 and
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
4 is by November 2021 for Unit 3 and by November 2022 for Unit 4, at an additional cost of approximately $1.41 billion, net of the Guarantee Settlement Agreement. The Georgia PSC is expected to make a decision on these matters by February 6, 2018.
On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to the financial statements of Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Georgia Power's financial statements. The ultimate outcome of these matters cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4, including Georgia Power's cost-to-complete and cancellation cost assessments for Plant Vogtle Units 3 and 4.
RESULTS OF OPERATIONS
Net Income
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(20) | | (3.3) | | $(29) | | (2.4) |
Georgia Power's net income after dividends on preferred and preference stock for the third quarter 2017 was $580 million compared to $600 million for the corresponding period in 2016. For year-to-date 2017, net income after dividends on preferred and preference stock was $1.19 billion compared to $1.22 billion for the corresponding period in 2016. The decreases were primarily due to lower revenues resulting from milder weather and lower customer usage as compared to the corresponding periods in 2016, partially offset by lower non-fuel operations and maintenance expenses.
Retail Revenues
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(138) | | (5.4) | | $(169) | | (2.7) |
In the third quarter 2017, retail revenues were $2.40 billion compared to $2.54 billion for the corresponding period in 2016. For year-to-date 2017, retail revenues were $6.00 billion compared to $6.16 billion for the corresponding period in 2016.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of the changes in retail revenues were as follows:
|
| | | | | | | | | | | | | |
| | Third Quarter 2017 | | Year-to-Date 2017 |
| | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | $ | 2,540 |
| | | | $ | 6,164 |
| | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 41 |
| | 1.6 |
| | 60 |
| | 1.0 |
|
| Sales decline | (39 | ) | | (1.5 | ) | | (50 | ) | | (0.8 | ) |
| Weather | (94 | ) | | (3.7 | ) | | (204 | ) | | (3.3 | ) |
| Fuel cost recovery | (46 | ) | | (1.8 | ) | | 25 |
| | 0.4 |
|
| Retail – current year | $ | 2,402 |
| | (5.4 | )% | | $ | 5,995 |
| | (2.7 | )% |
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016 primarily due to an increase in revenues related to the recovery of Plant Vogtle Units 3 and 4 construction financing costs under the NCCR tariff. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" of Georgia Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction – Regulatory Matters" herein for additional information related to the NCCR tariff.
Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016. Weather-adjusted residential KWH sales decreased 3.5% and 0.8% for the third quarter and year-to-date 2017, respectively, primarily due to a decline in average customer usage due to an increase in multi-family housing and energy saving initiatives, partially offset by customer growth. Weather-adjusted commercial KWH sales decreased 1.4% and 1.1% for the third quarter and year-to-date 2017, respectively, primarily due to a decline in average customer usage resulting from an increase in energy saving initiatives and electronic commerce transactions, partially offset by customer growth. Weather-adjusted industrial KWH sales increased 0.8% in the third quarter 2017 primarily due to increased demand in the non-manufacturing, rubber, and textile sectors, partially offset by decreased demand in the chemicals and paper sectors. Weather-adjusted industrial KWH sales decreased 1.2% for year-to-date 2017 primarily due to decreased demand in the paper and chemicals sectors, partially offset by increased demand in the non-manufacturing and rubber sectors. Despite a more stable dollar and improving global economy, the industrial sector remains constrained by economic policy uncertainty. Additionally, Hurricane Irma negatively impacted customer usage for all customer classes during the third quarter and year-to-date 2017.
Fuel revenues and costs are allocated between retail and wholesale jurisdictions. In the third quarter 2017, retail fuel cost recovery revenues decreased $46 million when compared to the corresponding period in 2016 primarily due to lower coal prices and lower energy sales resulting from milder weather. For year-to-date 2017, retail fuel cost recovery revenues increased $25 million when compared to the corresponding period in 2016 primarily due to higher natural gas prices, partially offset by lower coal prices and lower energy sales resulting from milder weather. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" of Georgia Power in Item 7 of the Form 10-K for additional information.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Revenues
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(7) | | (7.0) | | $(18) | | (6.0) |
In the third quarter 2017, other revenues were $93 million compared to $100 million for the corresponding period in 2016. The decrease was primarily due to a $3 million decrease in open access transmission tariff revenues, primarily as a result of the expiration of long-term transmission services contracts, and a $3 million decrease in solar application fee revenues, partially offset by a $3 million increase in outdoor lighting sales revenues primarily attributable to LED conversions.
For year-to-date 2017, other revenues were $284 million compared to $302 million for the corresponding period in 2016. The decrease was primarily due to a $14 million adjustment in 2016 for customer temporary facilities services revenues and a $12 million decrease in open access transmission tariff revenues, primarily as a result of the expiration of long-term transmission services contracts, partially offset by a $10 million increase in outdoor lighting sales revenues primarily attributable to LED conversions.
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | | | |
| | Third Quarter 2017
vs.
Third Quarter 2016 | | Year-to-Date 2017
vs.
Year-to-Date 2016 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | (93 | ) | | (16.2 | ) | | $ | (93 | ) | | (6.7 | ) |
| Purchased power – non-affiliates | 17 |
| | 16.7 |
| | 33 |
| | 11.9 |
|
| Purchased power – affiliates | 19 |
| | 13.4 |
| | 78 |
| | 19.9 |
|
| Total fuel and purchased power expenses | $ | (57 | ) | | | | $ | 18 |
| | |
In the third quarter 2017, total fuel and purchased power expenses were $762 million compared to $819 million in the corresponding period in 2016. The decrease was primarily due to a $59 million decrease related to the volume of KWHs generated primarily due to milder weather, resulting in lower customer demand, and slight decreases in the volume of KWHs purchased and the average cost of fuel. These decreases were partially offset by a $7 million increase in the average cost of purchased power primarily related to higher natural gas prices.
For year-to-date 2017, total fuel and purchased power expenses were $2.08 billion compared to $2.06 billion in the corresponding period in 2016. The increase was primarily due to a $97 million increase in the average cost of fuel and purchased power primarily related to higher natural gas prices, partially offset by a net decrease of $79 million related to the volume of KWHs generated and purchased primarily due to milder weather, resulting in lower customer demand.
Fuel and purchased power energy transactions do not have a significant impact on earnings since these fuel expenses are generally offset by fuel revenues through Georgia Power's fuel cost recovery mechanism. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" of Georgia Power in Item 7 of the Form 10-K for additional information.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of Georgia Power's generation and purchased power were as follows:
|
| | | | | | | |
| | Third Quarter 2017 | | Third Quarter 2016 | | Year-to-Date 2017 | | Year-to-Date 2016 |
Total generation (in billions of KWHs) | 18 | | 20 | | 48 | | 53 |
Total purchased power (in billions of KWHs) | 7 | | 7 | | 20 | | 19 |
Sources of generation (percent) — | | | | | | | |
| Coal | 35 | | 44 | | 33 | | 37 |
| Nuclear | 23 | | 22 | | 24 | | 23 |
| Gas | 41 | | 34 | | 41 | | 38 |
| Hydro | 1 | | — | | 2 | | 2 |
Cost of fuel, generated (in cents per net KWH) — | | | | | | | |
| Coal | 3.08 | | 3.16 | | 3.17 | | 3.32 |
| Nuclear | 0.84 | | 0.85 | | 0.84 | | 0.85 |
| Gas | 2.63 | | 2.61 | | 2.71 | | 2.27 |
Average cost of fuel, generated (in cents per net KWH) | 2.38 | | 2.47 | | 2.40 | | 2.34 |
Average cost of purchased power (in cents per net KWH)(*) | 4.68 | | 4.57 | | 4.63 | | 4.46 |
| |
(*) | Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider. |
Fuel
In the third quarter 2017, fuel expense was $482 million compared to $575 million in the corresponding period in 2016. The decrease was primarily due to a 9.6% decrease in the volume of KWHs generated largely due to milder weather, resulting in lower customer demand, and a 3.6% decrease in the average cost of fuel per KWH generated primarily resulting from lower coal prices.
For year-to-date 2017, fuel expense was $1.30 billion compared to $1.39 billion in the corresponding period in 2016. The decrease was primarily due to an 8.4% decrease in the volume of KWHs generated largely due to milder weather, resulting in lower customer demand, partially offset by a 19.4% increase in the average cost of natural gas per KWH generated.
Purchased Power – Non-Affiliates
In the third quarter 2017, purchased power expense from non-affiliates was $119 million compared to $102 million in the corresponding period in 2016. For year-to-date 2017, purchased power expense from non-affiliates was $310 million compared to $277 million in the corresponding period in 2016. The increases were primarily due to increases in the volume of KWHs purchased of 14.2% and 12.6% in the third quarter and year-to-date 2017, respectively, primarily due to unplanned outages at Georgia Power-owned generating units. The increase for year-to-date 2017 was partially offset by a 1.5% decrease in the average cost per KWH purchased.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the third quarter 2017, purchased power expense from affiliates was $161 million compared to $142 million in the corresponding period in 2016. The increase was primarily due to a 1.5% increase in the average cost per KWH purchased primarily resulting from higher natural gas prices, partially offset by a 5.6% decrease in the volume of
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
KWHs purchased due to the expiration of a PPA in May 2017 and milder weather, resulting in lower customer demand.
For year-to-date 2017, purchased power expense from affiliates was $470 million compared to $392 million in the corresponding period in 2016. The increase was primarily the result of a 4.3% increase in the volume of KWHs purchased to support Southern Company system transmission reliability and due to unplanned outages at Georgia Power-owned generating units and a 5.9% increase in the average cost per KWH purchased primarily resulting from higher natural gas prices.
Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(83) | | (16.7) | | $(199) | | (14.3) |
In the third quarter 2017, other operations and maintenance expenses were $413 million compared to $496 million in the corresponding period in 2016. The decrease was primarily due to cost containment and modernization activities implemented in the third quarter 2016 that contributed to decreases of $29 million in generation maintenance costs, $9 million in customer accounts, service, and sales costs, $8 million in employee benefits, and $8 million in transmission and distribution overhead line maintenance. Other factors include decreases of $12 million in charges related to employee attrition plans and $8 million in scheduled generation outage costs.
For year-to-date 2017, other operations and maintenance expenses were $1.19 billion compared to $1.39 billion in the corresponding period in 2016. The decrease was primarily due to cost containment and modernization activities implemented in the third quarter 2016 that contributed to decreases of $56 million in generation maintenance costs, $34 million in other employee compensation and benefits, and $23 million in transmission and distribution overhead line maintenance. Other factors include a $19 million increase in gains from sales of integrated transmission system assets, a $16 million decrease in customer assistance expenses primarily in demand-side management costs related to the timing of new programs, an $8 million decrease in charges related to employee attrition plans, and a $7 million decrease in billing adjustments with integrated transmission system owners.
Depreciation and Amortization
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $10 | | 4.7 | | $30 | | 4.7 |
In the third quarter 2017, depreciation and amortization was $225 million compared to $215 million in the corresponding period in 2016. The increase was primarily due to an $8 million increase related to additional plant in service and a $4 million decrease in amortization of regulatory liabilities related to other cost of removal obligations that expired in December 2016.
For year-to-date 2017, depreciation and amortization was $669 million compared to $639 million in the corresponding period in 2016. The increase was primarily due to a $25 million increase related to additional plant in service and an $11 million decrease in amortization of regulatory liabilities related to other cost of removal obligations that expired in December 2016, partially offset by a $5 million decrease in depreciation related to generating unit retirements in 2016.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Interest Expense, Net of Amounts Capitalized
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $7 | | 7.1 | | $20 | | 6.9 |
In the third quarter 2017, interest expense, net of amounts capitalized was $105 million compared to $98 million in the corresponding period in 2016. For year-to-date 2017, interest expense, net of amounts capitalized was $310 million compared to $290 million in the corresponding period in 2016. The increases were primarily due to increases in outstanding borrowings. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information.
Other Income (Expense), Net
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(6) | | (54.5) | | $6 | | 17.1 |
In the third quarter 2017, other income (expense), net was $5 million compared to $11 million in the corresponding period in 2016. The decrease was primarily due to a decrease of $9 million in AFUDC equity resulting from higher short-term borrowings, partially offset by increases of $3 million in customer contributions in aid of construction and $3 million in contract services revenue.
For year-to-date 2017, other income (expense), net was $41 million compared to $35 million in the corresponding period in 2016. The increase was primarily due to increases of $6 million in contract services revenue, $4 million in customer contributions in aid of construction, and $4 million in gains on purchases of state tax credits, partially offset by a $7 million decrease in AFUDC equity resulting from higher short-term borrowings.
Income Taxes
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(13) | | (3.6) | | $(29) | | (4.0) |
In the third quarter 2017, income taxes were $350 million compared to $363 million in the corresponding period in 2016. For year-to-date 2017, income taxes were $705 million compared to $734 million in the corresponding period in 2016. The decreases were primarily due to lower pre-tax earnings and increased state ITCs.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Georgia Power's future earnings potential. The level of Georgia Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Georgia Power's business of providing electric service. These factors include Georgia Power's ability to maintain a constructive regulatory environment that continuesseveral transitional arrangements to allow for the timely recovery of prudently-incurred costs during a time of increasing costs and limited projected demand growth over the next several years. Matters relatedconstruction to Plant Vogtle Units 3 and 4 construction and rate recovery are also major factors. Future earnings will be driven primarily by customer growth. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies, increasing volumes of electronic commerce transactions, and higher multi-family home construction. Earnings are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Georgia Power's service territory. Demand for electricity is primarily driven by the pace of economic
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
growth that may be affected by changes in regional and global economic conditions, which may impact future earnings.
Current proposals related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals, including any potential changes to the availability of nuclear PTCs, is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Georgia Power's financial statements.
For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Georgia Power in Item 7 of the Form 10-K and RISK FACTORS in Item 1A herein.
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Georgia Power's Environmental Compliance Cost Recovery (ECCR) tariff allows for the recovery of capital and operations and maintenance costs related to environmental controls mandated by state and federal regulations. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Statutes and Regulations
Air Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA's eight-hour ozone National Ambient Air Quality Standard (NAAQS).
On June 2, 2017, the EPA published a final rule redesignating a 15-county area within metropolitan Atlanta to attainment for the 2008 eight-hour ozone NAAQS.
On June 18, 2017, the EPA published a notice delaying attainment designations for the 2015 eight-hour ozone NAAQS by one year, setting a revised deadline of October 1, 2018. However, on August 2, 2017, the EPA issued a withdrawal notice of the one-year extension and reinstated the original October 1, 2017 designation deadline. The ultimate outcome of this matter cannot be determined at this time.
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the final effluent guidelines rule and the final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs.
On April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. On September 18, 2017, the EPA published a final rule establishing a stay of the compliance deadlines for certain effluent limitations and pretreatment standards under the rule.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
On June 27, 2017, the EPA and the U.S. Army Corps of Engineers proposed to rescind the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.
The ultimate outcome of these matters cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Georgia Power in Item 7 of the Form 10-K for additional information.
On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules. On October 16, 2017, the EPA published a proposed rule to repeal the Clean Power Plan. The EPA has not determined whether or when it will promulgate a replacement rule.
On June 1, 2017, the U.S. President announced that the United States will withdraw from the non-binding Paris Agreement and begin renegotiation of its terms.
The ultimate outcome of these matters cannot be determined at this time.
FERC Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS �� FUTURE EARNINGS POTENTIAL – "FERC Matters" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the traditional electric operating companies' and Southern Power's market power proceeding and amendment to their market-rate tariff.
On May 17, 2017, the FERC accepted the traditional electric operating companies' (including Georgia Power's) and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies (including Georgia Power) and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' (including Georgia Power's) and Southern Power's market power proceeding related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including Georgia Power's) and Southern Power's June 30, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including Georgia Power) and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order, or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including Georgia Power) and Southern Power expect to make a filing within the specified 60 days responding to the FERC's order.
The ultimate outcome of these matters cannot be determined at this time.
Retail Regulatory Matters
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.continue. In addition, financing costs related to the construction of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a separate fuel cost recovery tariff. See "Nuclear Construction" herein and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the NCCR tariff. Also see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
– "Retail Regulatory Matters – Fuel Cost Recovery" of Georgia Power in Item 7 of the Form 10-K for additional information regarding fuel cost recovery.
Renewables
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Integrated Resource Plan" of Georgia Power in Item 7 of the Form 10-K for additional information regarding renewable energy projects.
On May 16, 2017, the Georgia PSC approved Georgia Power's request to build, own, and operate a 139-MW solar generation facility at a U.S. Air Force base that is expected to be placed in service by the end of 2019.
During the nine months ended September 30, 2017, Georgia Power continued construction of a 31-MW solar generation facility at a U.S. Marine Corps base that is expected to be placed in service in the fourth quarter 2017.
The ultimate outcome of these matters cannot be determined at this time.
Integrated Resource Plan
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Integrated Resource Plan" of Georgia Power in Item 7 of the Form 10-K for additional information regarding Georgia Power's triennial Integrated Resource Plan.
On March 7, 2017, the Georgia PSC approved Georgia Power's decision to suspend work at a future generation site in Stewart County, Georgia, due to changing economics, including load forecasts and lower fuel costs. The timing of recovery for costs incurred of approximately $50 million will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time.
Storm Damage Recovery
Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, for incremental operating and maintenance costs of damage from major storms to its transmission and distribution facilities. During September 2017, Hurricane Irma caused significant damage to Georgia Power's transmission and distribution facilities. The total amount of incremental restoration costs related to this hurricane is estimated to be approximately $150 million. As of September 30, 2017, Georgia Power had deferred approximately $145 million in a regulatory asset related to storm damage. As of September 30, 2017, the total balance in the regulatory asset related to storm damage was $360 million. The rate of storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case required to be filed by July 1, 2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Georgia Power's financial statements. See Note 1 to the financial statements of Georgia Power under "Storm Damage Recovery" in Item 8 of the Form 10-K for additional information regarding Georgia Power's storm damage reserve.
Nuclear Construction
See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the construction of Plant Vogtle Units 3 and 4, VCM reports, the NCCR tariff, and the Contractor Settlement Agreement.
Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcy
In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Vogtle 3 and 4 Agreement, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4. Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. Georgia Power's proportionate share of Plant Vogtle Units 3 and 4 is 45.7%.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The Vogtle 3 and 4 Agreement also provided for liquidated damages upon the EPC Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to an aggregate cap of 10% of the contract price, or approximately $920 million (approximately $420 million based on Georgia Power's ownership interest). Under the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. In January 2016, Westinghouse delivered to the Vogtle Owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020 and require 60 days' written notice to Georgia Power in the event the Westinghouse Letters of Credit will not be renewed.
Under the terms of the Vogtle 3 and 4 Agreement, the EPC Contractor did not have the right to terminate the Vogtle 3 and 4 Agreement for convenience. In the event of an abandonment of work by the EPC Contractor, the maximum liability of the EPC Contractor under the Vogtle 3 and 4 Agreement was 40% of the contract price (approximately $1.7 billion based on Georgia Power's ownership interest).
On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. To provide for a continuation of work at Plant Vogtle Units 3 and 4, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Interim Assessment Agreement, which the bankruptcy court approved on March 30, 2017.
The Interim Assessment Agreement provided, among other items, that during the term of the Interim Assessment Agreement Georgia Power was obligated to pay, on behalf of the Vogtle Owners, all costs accrued by the EPC Contractor for subcontractors and vendors for services performed or goods provided. The Interim Assessment Agreement, as amended, expired on July 27, 2017.
Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor, including Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken, and continues to take, actions to remove liens filed by these subcontractors through the posting of surety bonds. Georgia Power estimates the aggregate liability, through September 30, 2017, of the Vogtle Owners for the removal of subcontractor liens and payment of other EPC Contractor pre-petition accounts payable to total approximately $386 million, of which $340 million had been paid or accrued as of September 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $176 million.
On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into the Guarantee Settlement Agreement. Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion, of which Georgia Power's proportionate share is approximately $1.7 billion, and that the Guarantee Obligations exist regardless of whether Plant Vogtle Units 3 and 4 are completed. The Guarantee Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations, which will reduce CWIP, beginning in October 2017 and continuing through January 2021. In the event Toshiba receives certain payments, including sale proceeds, from or related to Westinghouse (or its subsidiaries) or Toshiba Nuclear Energy Holdings (UK) Limited (or its subsidiaries), it will hold a portion of such payments in trust for the Vogtle Owners and promptly pay them as offsets against any remaining Guarantee Obligations. Under the Guarantee Settlement Agreement, the Vogtle Owners will forbear from exercising certain remedies, including drawing on the Westinghouse Letters of Credit, until June 30, 2020, unless certain events of nonpayment, insolvency, or other material breach of the Guarantee Settlement Agreement by Toshiba occur. If such an event occurs, the balance of the Guarantee Obligations will become immediately due and payable, and the Vogtle Owners may exercise any and all rights and remedies, including drawing on the Westinghouse Letters of Credit without restriction. In addition, the Guarantee Settlement Agreement does not restrict the Vogtle Owners from fully drawing on the Westinghouse Letters of Credit in the event they are not renewed or replaced prior to the expiration date. On October 2, 2017, Georgia Power received the first installment of the Guarantee Obligations of $300 million from Toshiba, of which Georgia Power's proportionate share was $137 million. Georgia Power is considering potential options with respect to its right to future payments under the Guarantee Settlement Agreement and its claims against
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the EPC Contractor in the EPC Contractor's bankruptcy proceeding, including a potential sale of those payment rights and bankruptcy claims. Any such transaction cannot be assured and would be subject to DOE consents and related approvals under the Loan Guarantee Agreement and related agreements.
On August 10, 2017, Toshiba released its financial results for the quarter ended June 30, 2017, which reflected a negative shareholders' equity balance of approximately $4.5 billion as of June 30, 2017. Toshiba previously announced the existence of material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern. As a result, substantial risk regarding the Vogtle Owners' ability to fully collect the Guarantee Obligations continues to exist. An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Georgia Power's financial statements.
Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Services Agreement, which was amended and restated on July 20, 2017, for the EPC Contractor to transition construction management of Plant Vogtle Units 3 and 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Services Agreement, (ii) assume and assign to the Vogtle Owners certain project-related contracts, (iii) join the Vogtle Owners as counterparties to certain assumed project-related contracts, and (iv) reject the Vogtle 3 and 4 Agreement. The Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE on July 27, 2017. The Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.
Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into the BechtelVogtle Services Agreement, whereby BechtelWestinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis. The Vogtle Services Agreement provides that it will serve ascontinue until the primary contractor for the remaining construction activities forstart-up and testing of Plant Vogtle Units 3 and 4. Facility design4 are complete and engineering remainselectricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the responsibility ofVogtle Owners upon 30 days' written notice.
In October 2017, Georgia Power, acting for itself and as agent for the EPC Contractor underother Vogtle Owners, executed the Services Agreement. The Bechtel Agreement, is a cost reimbursable plus fee arrangement, wherebyunder which Bechtel will beis reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the
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work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. Pursuant
See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for information on the Amended and Restated Loan Guarantee Agreement, including applicable covenants, events of default, and mandatory prepayment events.
Cost and Schedule
Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4, including contingency, through the end of the first quarter 2023 and the fourth quarter 2023, respectively, is as follows:
| | | | | |
| (in millions) |
Base project capital cost forecast(a)(b) | $ | 10,334 | |
| Construction contingency estimate | 49 | |
| |
Total project capital cost forecast(a)(b) | 10,383 | |
Net investment at September 30, 2022(b) | (9,280) | |
| Remaining estimate to complete | $ | 1,103 | |
(a)Includes approximately $590 million of costs that are not shared with the other Vogtle Owners and approximately $353 million of incremental costs under the cost-sharing and tender provisions of the joint ownership agreements described below. Excludes financing costs expected to be capitalized through AFUDC of approximately $385 million, of which $275 million had been accrued through September 30, 2022.
(b)Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds.
Georgia Power is required to obtain the DOE's approval of the Bechtel Agreement prior to obtaining any further advances under the Loan Guarantee Agreement.
In connection with the recommendation to continue withestimates that its financing costs for construction of Plant Vogtle Units 3 and 4 (described below)will total approximately $3.4 billion, of which $3.1 billion had been incurred through September 30, 2022.
As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of engineering support, commodity installation, system turnovers and related test results, and workforce statistics. Southern Nuclear establishes aggressive target values for monthly construction production and system turnover activities, which are reflected in the site work plans.
Since March 2020, the number of active COVID-19 cases at the site has fluctuated consistent with the surrounding area and impacted productivity levels and pace of activity completion, with the site experiencing peaks in the number of active cases in January 2021, August 2021, and January 2022. Georgia Power estimates the productivity impacts of the COVID-19 pandemic have consumed approximately three to four months of schedule margin previously embedded in the site work plan for Unit 3 and Unit 4. As of September 30, 2022, Georgia Power's proportionate share of the estimated incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is estimated to be between $160 million and $200 million and is included in the total project capital cost forecast. The continuing effects of the COVID-19 pandemic could further disrupt or delay construction and testing activities at Plant Vogtle Units 3 and 4.
On July 29, 2022, Southern Nuclear announced that all Unit 3 ITAACs had been submitted to the NRC. On August 3, 2022, the NRC published its 103(g) finding that the acceptance criteria in the combined license for Unit 3 had been met, which allowed nuclear fuel to be loaded and allows start-up testing to begin. Fuel load for Unit 3 was completed on October 17, 2022, and the unit is projected to be placed in service by the end of the first quarter 2023. Unit 4 is projected to be placed in service by the end of the fourth quarter 2023.
During the first nine months of 2022, established construction contingency totaling $170 million was assigned to the base capital cost forecast for costs primarily associated with construction productivity, the pace of system turnovers, additional craft and support resources, and procurement for Units 3 and 4. Georgia Power also increased its total
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project capital cost forecast by adding $36 million and $32 million to replenish construction contingency in the second quarter 2022 and the third quarter 2022, respectively.
After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded pre-tax charges to income in the second quarter 2022 and the third quarter 2022 of $36 million ($27 million after tax) and $32 million ($24 million after tax), respectively, for the increases in the total project capital cost forecast. Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery during the prudence review following the Unit 4 fuel load pursuant to the twenty-fourth VCM stipulation described below.
The projected schedule for Unit 3 primarily depends on the pace of system and area transitions to operations, including the completion of closure documentation necessary to support start-up testing, and the progression of start-up, final component, and pre-operational testing, which may be impacted by equipment or other operational failures. The projected schedule for Unit 4 primarily depends on Unit 3 progress through start-up and testing; overall construction productivity and production levels improving, particularly in electrical installation, including terminations; and appropriate levels of craft laborers, particularly electricians, being added and maintained. As Unit 4 progresses through construction and continues to transition into testing, ongoing and potential future challenges include the pace and quality of electrical, mechanical, and instrumentation and controls commodities installation; availability of craft and supervisory resources, including the temporary diversion of such resources to support Unit 3; the pace of work package closures and system turnovers; and the timeframe and duration of hot functional and other testing. Ongoing or future challenges for both units also include management of contractors and vendors; subcontractor performance; supervision of craft labor and related productivity; ability to attract and retain craft labor; and/or related cost escalation. New challenges also may arise, particularly as Units 3 and 4 move into initial testing and start-up, which may result in required engineering changes or remediation related to plant systems, structures, or components (some of which are based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale). These challenges may result in further schedule delays and/or cost increases.
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 ensure 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. On March 25, 2022, the NRC completed a follow-up inspection related to the November 2021 final significance report on its special inspection to review the root cause of additional construction remediation work identified in 2021 and Southern Nuclear's corresponding corrective action plans. The NRC closed the two white findings identified in November 2021 and returned Vogtle Unit 3 to the NRC's baseline inspection program.
With the receipt of the NRC's 103(g) finding, Unit 3 is now under the NRC's operating reactor oversight process and must meet applicable technical and operational requirements contained within Unit 3's operating license. Various design and other licensing-based compliance matters, including the timely submittal by Southern Nuclear of the ITAAC documentation and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel for Unit 4, may arise, which may result in additional license amendment requests or require other resolution. If any license amendment requests or other licensing-based compliance issues, including inspections and ITAACs for Unit 4, 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 in-service date beyond the first quarter 2023 for Unit 3 or the fourth quarter 2023 for Unit 4, including the current level of cost sharing described below, is estimated to result in additional base capital costs for Georgia Power of up to $15 million per month for Unit 3 and $35 million per month for Unit 4, as well as the related AFUDC and any additional related construction, support resources, or testing costs. While Georgia Power is not precluded from seeking retail recovery of any future capital cost forecast increase other than the amounts related to the cost-sharing
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and tender provisions of the joint ownership agreements described below, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.
Joint Owner Contracts
In November 2017, the Vogtle Owners agreed on a term sheetentered into an amendment to amend the existingtheir joint ownership agreements for Plant Vogtle Units 3 and 4 to provide for, among other conditions, additional Vogtle Owner approval requirements. UnderEffective in August 2018, the term sheet,Vogtle Owners further amended the joint ownership agreements to clarify and provide procedures for certain provisions of the joint ownership agreements related to adverse events that require the vote of the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including (i) the bankruptcy of Toshiba or a material breach by Toshiba of the Guarantee Settlement Agreement; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3(as amended, and 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report by more than $1 billion or extension of the project schedule contained in the seventeenth VCM report by more than one year. In addition, under the term sheet, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Services Agreement or agreementstogether with the primary construction contractor or Southern Nuclear.
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November 2017 amendment, the Vogtle Joint Ownership Agreements). The term sheetVogtle Joint Ownership Agreements also confirmsconfirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.
Amendments to the Vogtle Joint Ownership Agreements
In connection with a September 2018 vote by the Vogtle Owners to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and MEAG Power's wholly-owned subsidiaries MEAG Power SPVJ, LLC (MEAG SPVJ), MEAG Power SPVM, LLC (MEAG SPVM), and MEAG Power SPVP, LLC (MEAG SPVP) to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners, including additional amendments to the Vogtle Joint Ownership Agreements and the purchase of PTCs from the other Vogtle Owners at pre-established prices, and (ii) a term sheet (MEAG Term Sheet) with MEAG Power and MEAG SPVJ to provide up to $300 million of funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. In January 2019, Georgia Power, MEAG Power, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. In February 2019, Georgia Power, the other Vogtle Owners, and MEAG Power's wholly-owned subsidiaries MEAG SPVJ, MEAG SPVM, and MEAG SPVP entered into certain amendments to the Vogtle Joint Ownership Agreements to implement the provisions of the Vogtle Owner Term Sheet (Global Amendments).
Pursuant to the Global Amendments: (i) each Vogtle Owner must pay its proportionate share of qualifying construction costs for Plant Vogtle Units 3 and 4 based on its ownership percentage up to the estimated cost at completion (EAC) for Plant Vogtle Units 3 and 4 which formed the basis of Georgia Power's forecast of $8.4 billion in the nineteenth VCM plus $800 million; (ii) Georgia Power will be responsible for 55.7% of actual qualifying construction costs between $800 million and $1.6 billion over the EAC in the nineteenth VCM (resulting in $80 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests; and (iii) Georgia Power will be responsible for 65.7% of qualifying construction costs between $1.6 billion and $2.1 billion over the EAC in the nineteenth VCM (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests. The Global Amendments provide that if the EAC is revised and exceeds the EAC in the nineteenth VCM by more than $2.1 billion, each of the other Vogtle Owners will have a one-time option at the time the project budget cost forecast is so revised to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100% of such Vogtle Owner's remaining share of total construction costs in excess of the EAC in the nineteenth VCM plus $2.1 billion.
For purposes of the foregoing provisions, qualifying construction costs will not include costs (i) resulting from force majeure events, including epidemics and quarantines, governmental actions or inactions (or significant delays associated with issuance of such actions) that affect the licensing, completion, start-up, 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
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that are not subsidiaries or affiliates of Southern Company, and (iii) additional costs caused by requests from the Vogtle Owners 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.
In addition, pursuant to the Global Amendments, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events (Project Adverse Events) occur, including, among other events: (i) the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power's public announcement of its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 or the Georgia PSC determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Vogtle Owners pursuant to the Global Amendments described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Georgia PSC for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates; and (iv) an incremental extension of one year or more from the seventeenth VCM report estimated in-service dates of November 2021 and November 2022 for Units 3 and 4, respectively. The schedule extension announced in February 2022 triggered the requirement for a vote to continue construction. Effective February 25, 2022, all of the Vogtle Owners had voted to continue construction.
Georgia Power and the other Vogtle Owners do not agree on either the starting dollar amount for the determination of cost increases subject to the cost-sharing and tender provisions of the Global Amendments or the extent to which COVID-19-related costs impact those provisions. Based on the definition in the Global Amendments, Georgia Power believes the starting dollar amount is $18.38 billion and the current project capital cost forecast exceeds the cost-sharing provision threshold, but not the tender provision threshold. The other Vogtle Owners have notified Georgia Power that they believe the current capital cost expenditures have already exceeded the cost-sharing thresholds and the current project capital cost forecast triggers the tender provisions under the Global Amendments. In October 2021, Georgia Power and the other Vogtle Owners entered into an agreement, which was modified on June 3, 2022, to clarify the process for the tender provisions of the Global Amendments to provide for a decision between 120 and 194 days after the tender option is triggered, which the other Vogtle Owners assert occurred on February 14, 2022. On June 17, 2022 and July 26, 2022, OPC and Dalton, respectively, notified Georgia Power of their purported exercises of their tender options.
On June 18, 2022, OPC and MEAG Power each filed a separate lawsuit against Georgia Power in the Superior Court of Fulton County, Georgia seeking a declaratory judgment that the starting dollar amount is $17.1 billion and that the cost-sharing and tender provisions have been triggered. The lawsuits also assert other claims, including breach of contract allegations, and seek, among other remedies, damages and injunctive relief requiring Georgia Power to track and allocate construction costs consistent with MEAG Power's and OPC's interpretations of the Global Amendments. On July 25, 2022 and July 28, 2022, Georgia Power filed its answers in the lawsuits filed by MEAG Power and OPC, respectively, and included counterclaims seeking a declaratory judgment that the starting dollar amount is $18.38 billion and that costs related to force majeure events are excluded prior to calculating the cost-sharing and tender provisions and when calculating Georgia Power's related financial obligations. On September 26, 2022, Dalton filed complaints in each of these lawsuits. On September 29, 2022, Georgia Power and MEAG Power reached an agreement to resolve their dispute regarding the proper interpretation of the cost-sharing and tender provisions of the Global Amendments. Under the terms of the agreement, among other items, (i) MEAG Power will not exercise its tender option and will retain its full ownership interest in Plant Vogtle Units 3 and 4; (ii) Georgia Power will pay a portion of MEAG Power's costs of construction for Plant Vogtle Units 3 and 4 as such costs are incurred and with no further adjustment for force majeure costs, which payments will total approximately $79 million based on the current project capital cost forecast; and (iii) Georgia Power will pay 20% of MEAG Power's costs of construction with respect to any amounts over the current project capital cost forecast, with no further adjustment for force majeure costs. In addition, MEAG Power agreed to vote to continue construction upon occurrence of a Project Adverse Event unless the commercial operation date of either of Plant Vogtle Unit 3 or Unit 4 is not projected to occur by December 31, 2025. On October 4, 2022, MEAG Power and Georgia Power filed a
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notice of settlement and voluntary dismissal of their pending litigation, including Georgia Power's counterclaim, and, on October 6, 2022, Dalton dismissed its related complaint.
Georgia Power recorded pre-tax charges (credits) to income in the fourth quarter 2021, the second quarter 2022, and the third quarter 2022 of approximately $440 million ($328 million after tax), $16 million ($12 million after tax), and $(102) million ($(76) million after tax), respectively, associated with the cost-sharing and tender provisions of the Global Amendments, including the settlement with MEAG Power, which are included in the total project capital cost forecast and will not be recovered from retail customers. The settlement with MEAG Power does not resolve the separate pending litigation with OPC, including Dalton's associated complaint, described above. Georgia Power may be required to record further pre-tax charges to income of up to approximately $300 million associated with the cost-sharing and tender provisions of the Global Amendments for OPC and Dalton based on the current project capital cost forecast.
Georgia Power's ownership interest in Plant Vogtle Units 3 and 4 continues to be 45.7%; however, it could increase if OPC or Dalton effectively exercises the option to tender a portion of their ownership interest to Georgia Power and require Georgia Power to pay 100% of the remaining share of the costs necessary to complete Plant Vogtle Units 3 and 4. Georgia Power's incremental ownership interest would be calculated and conveyed to Georgia Power after Plant Vogtle Units 3 and 4 are placed in service.
The ultimate outcome of these matters cannot be determined at this time.
Regulatory Matters
In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for nuclear construction projects certified by the Georgia PSC.Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by includingup to the related CWIP accounts in rate base during the construction period. Ascertified capital cost of $4.418 billion. At September 30, 2017,2022, Georgia Power had recovered approximately $1.5$2.8 billion of financing costs. Financing costs related to capital costs above $4.418 billion are being recognized through AFUDC and are expected to be recovered through retail rates over the life of Plant Vogtle Units 3 and 4; however, Georgia Power expectsis not recording AFUDC related to file onany capital costs in excess of the total deemed reasonable by the Georgia PSC (currently $7.3 billion) and not requested for rate recovery. In November 1, 20172021, the Georgia PSC approved Georgia Power's request to increasedecrease the NCCR tariff by approximately $90$78 million annually, effective January 1, 2018, pending2022.
Georgia Power is required to file semi-annual VCM reports with the Georgia PSC approval.by February 28 and August 31 of each year. In 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.
On December 20,In 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) Georgia Power's seventeenth VCM report and modified the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following prudence matters:regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report willshould be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement iswas reasonable and prudent and none of the amounts paid or to be$0.3 billion paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) financing costs on verified and approved capital costs will be deemed prudent provided they are incurred prior to December 31, 2019 and December 31, 2020 for Plant Vogtle Units 3 and 4, respectively; and (iv) (a) the in-service capital cost forecast will be adjusted to $5.680 billion (Revised Forecast), which includes a contingency of $240 million above Georgia Power's then current forecast of $5.440 billion, (b) capital costs incurred up to the Revised Forecast will$5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, and (c)(b) Georgia Power would have the burden to show that any capital costs above $5.68 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the Revised Forecast are reasonable and prudent. Underimpact of payments received under the terms of the Vogtle CostGuarantee Settlement Agreement and related customer refunds) was found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the certified in-service capitalrevised cost for purposes of calculatingforecast does not represent a cost cap and that a prudence proceeding on cost recovery will occur following Unit 4 fuel load, consistent with applicable Georgia law; (vii) reduced the NCCR tariff will remain at $4.418 billion. Construction capital costs above $4.418 billion will accrue AFUDC through the date each unit is placed in service. The ROE used to calculate the NCCR tariff was reduced(a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP)alternate rate plan) to 10.00% effective January 1, 2016. For purposes of the AFUDC calculation,2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE on costs between $4.418 billion and $5.440 billionin no case will also be 10.00% and the ROE on any amounts above $5.440 billion would beless than Georgia Power's average cost of long-term debt. Ifdebt); (viii) reduced the Georgia PSC adjusts Georgia Power's ROE rate setting point in a rate case prior toused for AFUDC equity for Plant Vogtle Units 3 and 4 being placed intofrom 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that effective the first month after Unit 3 reaches commercial operation, retail rate base thenrates would be adjusted to include the ROEcosts related to Unit 3 and common facilities deemed prudent in the Vogtle Cost Settlement Agreement (see Note 2 to the financial statements under "Georgia Power – Plant Vogtle Unit 3 and Common Facilities Rate Proceeding" in Item 8 of the Form 10-K for purposes of calculating both the NCCR tariff and AFUDC will likewise be 95 basis points lower than the revised ROE rate setting point. Ifadditional information). The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not placed in servicecommercially operational by December 31, 2020, then (i)June 1, 2021 and June 1, 2022, respectively, the ROE for purposes of calculatingused to calculate the NCCR tariff will be further reduced an additional 300by 10 basis points or $8 million pereach month and may, at the Georgia PSC's discretion, be accrued to be used for the benefit of customers, until such time as the units are placed in service and (ii) the ROE used to calculate AFUDC will be(but not lower than Georgia Power's average cost of long-term debt.debt) until the respective Unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $270 million in 2021 and are estimated to have negative earnings impacts of approximately $300 million and $250 million in 2022 and 2023, respectively. In its January 11, 2018 order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.
In the August 2021 order approving the twenty-fourth VCM report, the Georgia PSC approved a stipulation addressing the following matters: (i) beginning with its twenty-fifth VCM report, Georgia Power will continue to report to the Georgia PSC all costs incurred during the period for review and will request for approval costs up to the $7.3 billion determined to be reasonable in the Georgia PSC's seventeenth VCM order and (ii) Georgia Power will not seek rate recovery of the $0.7 billion increase to the base capital cost forecast included in the nineteenth VCM report and charged to income by Georgia Power in the second quarter 2018. In addition, the stipulation confirms Georgia Power may request verification and approval of costs above $7.3 billion for inclusion in rate base at a later time, but no earlier than the prudence review contemplated by the seventeenth VCM order described previously.
The Georgia PSC has approved sixteen25 VCM reports covering the periods through December 31, 2016, includingJune 30, 2021. These reports reflect total construction capital costs incurred of $7.9 billion (net of $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds), of which the Georgia PSC has verified and approved $7.3 billion as described above. The Georgia PSC also has reviewed the twenty-sixth VCM report, which reflects $584 million of additional construction capital costs incurred through that date totaled $3.9 billion.December 31, 2021. Georgia Power filed its seventeenthtwenty-seventh VCM report covering the period from January 1 through June 30, 2017, requesting approval of $542 million of construction capital costs incurred during that period, with the Georgia PSC on August 31, 2017.
In2022, which reflects the seventeenth VCM report, Georgia Power recommended thatrevised capital cost forecast as of June 30, 2022 of $10.5 billion and $522 million of construction of Plant Vogtle Units 3 and 4 be continued, with Southern Nuclear serving as project manager. Georgia Power believes that the most reasonable schedule for completing Plant Vogtle Units 3 and 4 is by November 2021 for Unit 3 and by November 2022 for Unit 4. Georgia Power's recommendation to go forward with completion of Vogtle Units 3 and 4 is based on the following assumptions about the regulatory treatment of this recommendation, if the recommendation to go forward
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
is adopted by the Georgia PSC: (i) that pursuant to Georgia law, the Georgia PSC in the seventeenth VCM proceeding approves the new cost and schedule forecast and finds that it is a reasonable basis for going forward, and that if the Georgia PSC disapproves all or part of the proposed cost and schedule revisions, Georgia Power may cancel Plant Vogtle Units 3 and 4 and recover its actual investment in Plant Vogtle Units 3 and 4; (ii) that the Vogtle Cost Settlement Agreement remains in full force and effect, including Georgia Power retaining the burden of proving all capital costs above $5.680 billion were prudent; (iii) that while the Georgia PSC will make no prudence finding in the seventeenth VCM proceeding, nor will the certified amount be amended consistent with the Vogtle Cost Settlement Agreement, the Georgia PSC recognizes that the certified amount is not a cap, and all costs that are approved and presumed or shown to be prudently incurred will be recoverable by Georgia Power; (iv) that Georgia Power is not a guarantor of the Toshiba Guarantee, and the failure of Toshiba to pay the Toshiba Guarantee, the failure of the U.S. Congress to extend the PTCs for Plant Vogtle Units 3 and 4, or the failure of the DOE to extend the Loan Guarantee Agreement with Georgia Power to reflect the increased capital amounts, will not reduce the amount of investment Georgia Power is otherwise allowed to collect; and (v) that as conditions change and assumptions are either proven or disproven, Georgia Power and the Georgia PSC may reconsider the decision to go forward. The Georgia PSC is expected to make a decision on these matters by February 6, 2018.from January 1, 2022 through June 30, 2022.
The ultimate outcome of these matters cannot be determined at this time.
Revised Cost
Mississippi Power
Performance Evaluation Plan
On June 7, 2022, the Mississippi PSC approved Mississippi Power's annual retail PEP filing for 2022, resulting in an annual increase in revenues of approximately $18 million, or 1.9%, primarily due to increases in rate base, operations and Schedulemaintenance expenses, and depreciation and amortization. The rate increase became effective with the first billing cycle of April 2022 in accordance with the PEP rate schedule.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Ad Valorem Tax Adjustment
On June 7, 2022, the Mississippi PSC approved Mississippi Power's approximate proportionate shareannual ad valorem tax adjustment filing for 2022, resulting in an annual increase in revenues of $5 million, effective with the remaining estimated costfirst billing cycle of July 2022.
Municipal and Rural Associations Tariff
On August 26, 2022, the FERC accepted an amended shared service agreement (SSA) between Mississippi Power and Cooperative Energy, effective July 1, 2022, under which Cooperative Energy will continue to complete Plant Vogtle Units 3decrease its use of Mississippi Power's generation services under the MRA tariff up to 2.5% annually through 2035. At September 30, 2022, Mississippi Power is serving approximately 400 MWs of Cooperative Energy's annual demand. Beginning in 2036, Cooperative Energy will provide 100% of its electricity requirements at the MRA delivery points under the tariff. Neither party has the option to cancel the amended SSA.
On July 15, 2022, Mississippi Power filed a request with the FERC for a $23 million increase in annual wholesale base revenues under the MRA tariff and 4 isrequested an effective date of July 15, 2022. Cooperative Energy has filed a complaint with the FERC challenging the new rates. On September 13, 2022, the FERC issued an order accepting Mississippi Power's request effective September 14, 2022, subject to refund, and establishing hearing and settlement judge procedures. The ultimate outcome of this matter cannot be determined at this time.
Southern Company Gas
Infrastructure Replacement Programs and Capital Projects
Capital expenditures incurred under specific infrastructure replacement programs and capital projects during the first nine months of 2022 were as follows:
|
| | | |
| | (in billions) |
| Estimated cost to complete | $ | 4.2 |
|
| CWIP as of September 30, 2017 | 4.6 |
|
| Guarantee Obligations | (1.7 | ) |
| Estimated capital costs | $ | 7.1 |
|
| Vogtle Cost Settlement Agreement Revised Forecast | (5.7 | ) |
| Estimated net additional capital costs | $ | 1.4 |
|
Georgia Power's estimated financing costs during the construction period total approximately $3.4 billion, of which approximately $1.5 billion had been incurred through September 30, 2017.
Georgia Power's cancellation cost estimate results indicate that its proportionate share of the estimated costs to cancel both units is approximately $350 million. As a result, as of September 30, 2017, total estimated costs subject to evaluation by Georgia Power and the Georgia PSC in the event of a cancellation decision are as follows:
|
| | | |
| | Cancellation Cost Estimate |
| | (in billions) |
| CWIP as of September 30, 2017 | $ | 4.6 |
|
| Financing costs collected, net of tax | 1.5 |
|
Cancellation costs(*) | 0.4 |
|
| Guarantee Obligations | (1.7 | ) |
| Estimated net cancellation cost | $ | 4.8 |
|
| | | | | | | | |
(*)Utility | The estimate for cancellation costs includes, but is not limited to, costs to terminate contracts for construction and other services, as well as costs to secure the Plant Vogtle Units 3 and 4 construction site.Program | Nine Months Ended September 30, 2022 |
| | (in millions) |
| Nicor Gas | Investing in Illinois | $ | 311 | |
| Virginia Natural Gas | SAVE | 52 | |
| Atlanta Gas Light | System Reinforcement Rider | 51 | |
| Chattanooga Gas | Pipeline Replacement Program | 2 | |
| Total | | $ | 416 | |
Rate Proceedings
Atlanta Gas Light
On July 1, 2022, Atlanta Gas Light filed its annual GRAM update with the Georgia PSC. The Guarantee Obligations continuefiling requests an annual base rate increase of $53 million based on the projected 12-month period beginning January 1, 2023. Resolution of the GRAM filing is expected by December 28, 2022, with the new rates effective January 1, 2023. The ultimate outcome of this matter cannot be determined at this time.
Virginia Natural Gas
On August 1, 2022, Virginia Natural Gas filed a general base rate case with the Virginia Commission seeking an increase in annual base rate revenues of $69 million, including $15 million related to existthe recovery of investments under the SAVE program, primarily to recover investments and increased costs associated with infrastructure, technology, and workforce development. The requested increase is based on a projected 12-month period beginning January 1, 2023, a ROE of 10.35%, and an equity ratio of 53.2%. Rate adjustments are expected to be effective January 1, 2023, subject to refund. The Virginia Commission is expected to rule on the requested increase in the eventthird quarter 2023. The ultimate outcome of cancellation. In addition, under Georgia law, prudently incurred costs related to certificated projects cancelled by the Georgia PSC are allowed recovery, including carrying
this matter cannot be determined at this time.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OFNOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(UNAUDITED)
(C) CONTINGENCIES
See Note 3 to the financial statements in Item 8 of the Form 10-K for information relating to various lawsuits and other contingencies.
General Litigation Matters
The Registrants are involved in various matters being litigated and regulatory matters. The ultimate outcome of such pending or potential litigation or regulatory matters against each Registrant and any subsidiaries cannot be determined at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such Registrant's financial statements.
The Registrants believe the pending legal challenges discussed below have no merit; however, the ultimate outcome of these matters cannot be determined at this time.
Southern Company
In 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 named as defendants Southern Company, certain of its directors, certain of its current and former officers, and certain former Mississippi Power officers. In 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints alleged that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints alleged that the defendants were unjustly enriched and caused the waste of corporate assets and also alleged that the individual defendants violated their fiduciary duties.
In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, Georgia that named as defendants Southern Company, certain of its directors, certain of its current and former officers, and certain former Mississippi Power officers. The complaint alleged 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 alleged 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. In August 2019, the court granted a motion filed by the plaintiff in July 2019 to substitute a new named plaintiff, Martin J. Kobuck, in place of Helen E. Piper Survivor's Trust.
The plaintiffs in each of these cases sought to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in future retail rates.bringing the lawsuit. The plaintiffs also sought certain changes to Southern Company's corporate governance and internal processes. On January 21, 2022, the plaintiffs in the federal court action filed a motion for preliminary approval of settlement, together with an executed stipulation of settlement, which applied to both actions. On June 9, 2022, the U.S. District Court for the Northern District of Georgia granted final approval of the settlement and, on June 16, 2022, the Superior Court of Gwinnett County, Georgia entered an order awarding attorneys' fees and expenses related to the Martin J. Kobuck lawsuit. The settlement consisted of an aggregate payment by Southern Company's insurers of approximately $4.5 million for attorneys' fees and expenses, as well as adoption of various corporate governance reforms by Southern Company. These matters are now concluded.
Alabama Power
On September 26, 2022, Mobile Baykeeper, through its counsel Southern Environmental Law Center, filed a citizen suit in the U.S. District Court for the Southern District of Alabama alleging that Alabama Power's plan to close the Plant Barry ash pond utilizing a closure-in-place methodology violates the Resource Conservation and Recovery Act (RCRA) and regulations governing CCR. Among other relief requested, Mobile Baykeeper seeks a declaratory judgment that the RCRA and regulations governing CCR are being violated, preliminary and injunctive relief to
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
prevent implementation of Alabama Power's closure plan and the development of a closure plan that satisfies regulations governing CCR requirements. See Note 6 to the financial statements in Item 8 of the Form 10-K for a discussion of Alabama Power's ARO liabilities related to facilities that are subject to the CCR Rule and the related state rule. The ultimate outcome of this matter cannot be determined at this time.
Georgia Power
In 2011, plaintiffs filed a putative class action against Georgia Power will continue working within the Superior Court of Fulton County, Georgia alleging that Georgia Power's collection in rates of amounts for municipal franchise fees (which fees are paid to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state law claims. This case has been ruled upon and appealed numerous times over the other Vogtle Ownerslast several years. In 2019, the Georgia PSC issued an order that found Georgia Power has appropriately implemented the municipal franchise fee schedule. In March 2021, the Superior Court of Fulton County granted class certification and Georgia Power's motion for summary judgment and the plaintiffs filed a notice of appeal. In April 2021, Georgia Power filed a notice of cross appeal on the issue of class certification. In December 2021, the Georgia Court of Appeals affirmed the Superior Court's ruling that granted summary judgment to determine future actions related to Plant Vogtle Units 3Georgia Power and 4, including, but not limiteddismissed Georgia Power's cross appeal on the issue of class certification as moot. Also in December 2021, the plaintiffs filed a petition for writ of certiorari to the statusGeorgia Supreme Court. The amount of any possible losses cannot be estimated at this time because, among other factors, it is unknown whether any losses would be subject to recovery from any municipalities.
In July 2020, a group of individual plaintiffs filed a complaint in the Superior Court of Fulton County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater, surface water, and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages, a medical monitoring fund, and injunctive relief. Georgia Power has filed multiple motions to dismiss the complaint. In October 2021, three additional complaints were filed in the Superior Court of Monroe County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages. In November 2021, Georgia Power filed a notice to remove the three cases pending in the Superior Court of Monroe County, Georgia to the U.S. District Court for the Middle District of Georgia. On February 7, 2022, four additional complaints were filed in the Superior Court of Monroe County, Georgia against Georgia Power seeking damages for alleged personal injuries or property damage. On March 9, 2022, Georgia Power filed a notice to remove the four cases pending in the Superior Court of Monroe County, Georgia to the U.S. District Court for the Middle District of Georgia. The amount of any possible losses from these matters cannot be estimated at this time.
Mississippi Power
In 2018, Ray C. Turnage and 10 other individual plaintiffs filed a putative class action complaint against Mississippi Power and the three then-serving members of the Mississippi PSC in the U.S. District Court for the Southern District of Mississippi, which was amended in March 2019 to include four additional plaintiffs. 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 and make claims for gross negligence, reckless conduct, and intentional wrongdoing. 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. The district court dismissed the amended complaint; however, in March 2020, the plaintiffs filed a motion seeking to name the new members of the Mississippi PSC, the Mississippi Development Authority, and Southern Company as additional defendants and add a cause of action against all defendants based on a dormant commerce clause theory under the U.S. Constitution. In July 2020, the plaintiffs filed a motion for leave to file a third amended complaint, which included the same federal claims as the proposed second amended complaint, as well as several
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
additional state law claims based on the allegation that Mississippi Power failed to disclose the annual percentage rate recovery.of interest applicable to refunds. In November 2020, the district court denied each of the plaintiffs' pending motions and entered final judgment in favor of Mississippi Power. In January 2021, the district court denied further motions by the plaintiffs to vacate the judgment and to file a revised second amended complaint. In February 2021, the plaintiffs filed a notice of appeal with the U.S. Court of Appeals for the Fifth Circuit. On March 21, 2022, the U.S. Court of Appeals for the Fifth Circuit issued an opinion affirming the dismissal of the claims against the Mississippi PSC defendants but reversing the dismissal of the claims against Mississippi Power. On May 31, 2022, the U.S. Court of Appeals for the Fifth Circuit denied a petition by Mississippi Power for a rehearing en banc and remanded the case to the U.S. District Court for the Southern District of Mississippi for further proceedings. On June 17, 2022, Mississippi Power filed with the trial court a motion to dismiss the complaint. An adverse outcome in this proceeding could have a material impact on Mississippi Power's financial statements.
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 remediation 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 $16 million and $17 million at September 30, 2022 and December 31, 2021, 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 $270 million and $249 million at September 30, 2022 and December 31, 2021, respectively, based on the estimated cost of environmental investigation and remediation associated with known former manufactured gas plant operating sites.
The ultimate outcome of these matters cannot be determined at this time.time; however, as a result of the regulatory treatment for environmental remediation expenses described above, the final disposition of these matters is not expected to have a material impact on the financial statements of the applicable Registrants.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Other MattersPerformance Evaluation Plan
AsOn June 7, 2022, the Mississippi PSC approved Mississippi Power's annual retail PEP filing for 2022, resulting in an annual increase in revenues of approximately $18 million, or 1.9%, primarily due to increases in rate base, operations and maintenance expenses, and depreciation and amortization. The rate increase became effective with the first billing cycle of April 2022 in accordance with the PEP rate schedule.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Ad Valorem Tax Adjustment
On June 7, 2022, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment filing for 2022, resulting in an annual increase in revenues of $5 million, effective with the first billing cycle of July 2022.
Municipal and Rural Associations Tariff
On August 26, 2022, the FERC accepted an amended shared service agreement (SSA) between Mississippi Power and Cooperative Energy, effective July 1, 2022, under which Cooperative Energy will continue to decrease its use of Mississippi Power's generation services under the MRA tariff up to 2.5% annually through 2035. At September 30, 2017,2022, Mississippi Power is serving approximately 400 MWs of Cooperative Energy's annual demand. Beginning in 2036, Cooperative Energy will provide 100% of its electricity requirements at the MRA delivery points under the tariff. Neither party has the option to cancel the amended SSA.
On July 15, 2022, Mississippi Power filed a request with the FERC for a $23 million increase in annual wholesale base revenues under the MRA tariff and requested an effective date of July 15, 2022. Cooperative Energy has filed a complaint with the FERC challenging the new rates. On September 13, 2022, the FERC issued an order accepting Mississippi Power's request effective September 14, 2022, subject to refund, and establishing hearing and settlement judge procedures. The ultimate outcome of this matter cannot be determined at this time.
Southern Company Gas
Infrastructure Replacement Programs and Capital Projects
Capital expenditures incurred under specific infrastructure replacement programs and capital projects during the first nine months of 2022 were as follows:
| | | | | | | | |
| Utility | Program | Nine Months Ended September 30, 2022 |
| | (in millions) |
| Nicor Gas | Investing in Illinois | $ | 311 | |
| Virginia Natural Gas | SAVE | 52 | |
| Atlanta Gas Light | System Reinforcement Rider | 51 | |
| Chattanooga Gas | Pipeline Replacement Program | 2 | |
| Total | | $ | 416 | |
Rate Proceedings
Atlanta Gas Light
On July 1, 2022, Atlanta Gas Light filed its annual GRAM update with the Georgia Power had borrowed $2.6 billionPSC. The filing requests an annual base rate increase of $53 million based on the projected 12-month period beginning January 1, 2023. Resolution of the GRAM filing is expected by December 28, 2022, with the new rates effective January 1, 2023. The ultimate outcome of this matter cannot be determined at this time.
Virginia Natural Gas
On August 1, 2022, Virginia Natural Gas filed a general base rate case with the Virginia Commission seeking an increase in annual base rate revenues of $69 million, including $15 million related to Plant Vogtle Units 3the recovery of investments under the SAVE program, primarily to recover investments and 4increased costs through the Loan Guarantee Agreementassociated with infrastructure, technology, and workforce development. The requested increase is based on a multi-advance credit facility among Georgia Power, the DOE,projected 12-month period beginning January 1, 2023, a ROE of 10.35%, and the FFB, which provides for borrowingsan equity ratio of up53.2%. Rate adjustments are expected to $3.46 billion,be effective January 1, 2023, subject to refund. The Virginia Commission is expected to rule on the satisfactionrequested increase in the third quarter 2023. The ultimate outcome of certain conditions. On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. Final approval and issuance of these additional loan guarantees by the DOEthis matter cannot be assured and are subjectdetermined at this time.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
(C) CONTINGENCIES
See Note 63 to the financial statements of Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for information relating to various lawsuits and Note (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.other contingencies.
General Litigation Matters
The IRS has allocated PTCs to Plant Vogtle Units 3 and 4 which require that the applicable unit be placed in service prior to 2021. The net present value of Georgia Power's PTCs is estimated at approximately $400 million per unit.
There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise while construction proceeds. ProcessesRegistrants are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise while construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.
While construction continues, the risk remains that challenges with management of contractors, subcontractors, and vendors, labor productivity, fabrication, delivery, assembly, and installation of plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost.
The ultimate outcome of these matters cannot be determined at this time.
See RISK FACTORS of Georgia Power in Item 1A of the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world. See additional risks in Item 1A herein regarding the EPC Contractor's bankruptcy.
Other Matters
Georgia Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Georgia Power is subject to certain claims and legal actions arising in the ordinary course of business. Georgia Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The ultimate outcome of such pending or potential litigation or regulatory matters against each Registrant and any subsidiaries cannot be predicteddetermined at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Georgia Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
Georgia Power regularly reviews its business to transform and modernize. Primarily in response to changing customer expectations and payment patterns, including electronic payments and alternative payment locations, and ongoing efforts to increase overall operating efficiencies, Georgia Power initiated the closure of its remaining payment offices and an employee attrition plan affecting approximately 300 positions. Charges associated with these activities did not have a material impact on Georgia Power's results of operations, financial position, or cash flows. The efficiencies gained are expected to place downward pressure on operating costs in 2018.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Georgia Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Georgia Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Georgia Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Georgia Power in Item 7 of the Form 10-K for a complete discussion of Georgia Power's critical accounting policies and estimates related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, and Contingent Obligations.
Recently Issued Accounting Standards
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Georgia Power in Item 7 of the Form 10-K for additional information.
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
While Georgia Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Georgia Power's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs. Georgia Power expects that the revenue from contracts with these customers will not result in a significant shift in the timing of revenue recognition for such sales.
Georgia Power's ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Georgia Power's financial statements, if material. In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Georgia Power expects CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Georgia Power intends to use the modified retrospective method of adoption effective January 1, 2018. Georgia Power has
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
also elected to utilize practical expedients which allow it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Georgia Power's financial statements, Georgia Power will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Georgia Power's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Georgia Power's financial statements.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with early adoption permitted. Georgia Power is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on Georgia Power's financial statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Georgia Power in Item 7 of the Form 10-K for additional information. Georgia Power's financial condition remained stable at September 30, 2017. Georgia Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $1.48 billion for the first nine months of 2017 compared to $2.27 billion for the corresponding period in 2016. The decrease was primarily due to the timing of vendor payments and fossil fuel stock purchases and an increase in under-recovered fuel costs. Net cash used for investing activities totaled $1.83 billion for the first nine months of 2017 compared to $1.76 billion for the corresponding period in 2016 primarily related to installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities. Net cash provided from financing activities totaled $617 million for the first nine months of 2017 compared to $528 million used for financing activities in the
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
corresponding period in 2016. The increase in cash provided from financing activities is primarily due to an increase in short-term borrowings, higher issuances of senior notes and junior subordinated notes, and a decrease in maturities of senior notes, partially offset by a decrease in borrowings from the FFB for construction of Plant Vogtle Units 3 and 4 and an increase in redemptions of short-term borrowings. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first nine months of 2017 include increases of $1.2 billion in property, plant, and equipment to comply with environmental standards and the construction of generation, transmission, and distribution facilities, $1.2 billion in long-term debt primarily due to issuances of senior notes and junior subordinated notes, $423 million in accounts payable, other primarily due to charges for restoration costs related to Hurricane Irma and liabilities for the removal of subcontractor liens related to the EPC Contractor's bankruptcy, and $423 million in paid-in capital primarily due to capital contributions received from Southern Company. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Storm Damage Recovery" and " – Nuclear Construction" for additional information regarding Hurricane Irma and the EPC Contractor's bankruptcy, respectively.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Georgia Power in Item 7 of the Form 10-K for a description of Georgia Power's capital requirements for its construction program, including estimated capital expenditures for Plant Vogtle Units 3 and 4 and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. Approximately $261 million will be required through September 30, 2018 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information. Also see FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating units, to meet regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein for information regarding additional factors that may impact construction expenditures, including Georgia Power's cost-to-complete and cancellation cost assessments for Plant Vogtle Units 3 and 4.
Sources of Capital
Georgia Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, external security issuances, term loans, equity contributions from Southern Company, and, to the extent available, borrowings from the FFB. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Georgia Power in Item 7 of the Form 10-K for additional information.
In 2014, Georgia Power entered into the Loan Guarantee Agreement with the DOE, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
construction of Plant Vogtle Units 3 and 4. Under the Loan Guarantee Agreement, the DOE agreed to guarantee borrowings of up to $3.46 billion (not to exceed 70% of (i) Eligible Project Costs, less (ii) amounts received from Toshiba under the Guarantee Settlement Agreement and amounts received from the Westinghouse bankruptcy proceeding) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. As of September 30, 2017, Georgia Power had borrowed $2.6 billion under the FFB Credit Facility. On July 27, 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement, which provides that further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement and satisfaction of certain other conditions.
On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion of additional guaranteed loans under the Loan Guarantee Agreement. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to the financial statements of Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information regarding the Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and additional conditions to borrowing. Also see Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
At September 30, 2017, Georgia Power's current liabilities exceeded current assets by $698 million. Georgia Power's current liabilities frequently exceed current assets because of scheduled maturities of long-term debt ($261 million at September 30, 2017) and the periodic use of short-term debt as a funding source ($400 million at September 30, 2017), as well as significant seasonal fluctuations in cash needs. Georgia Power intends to utilize operating cash flows, short-term debt, external security issuances, term loans, equity contributions from Southern Company, and, to the extent available, borrowings from the FFB to fund its short-term capital needs. Georgia Power has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet liquidity needs.
At September 30, 2017, Georgia Power had approximately $266 million of cash and cash equivalents. Georgia Power's committed credit arrangement with banks at September 30, 2017 was $1.75 billion of which $1.73 billion was unused. In May 2017, Georgia Power amended its multi-year credit arrangement, which, among other things, extended the maturity date from 2020 to 2022.
This bank credit arrangement, as well as Georgia Power's term loan arrangements, contains a covenant that limits debt levels and contains a cross-acceleration provision to other indebtedness (including guarantee obligations) of Georgia Power. Such cross-acceleration provision to other indebtedness would trigger an event of default if Georgia Power defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2017, Georgia Power was in compliance with this covenant. This bank credit arrangement does not contain a material adverse change clause at the time of borrowing.
Subject to applicable market conditions, Georgia Power expects to renew or replace this credit arrangement, as needed, prior to expiration. In connection therewith, Georgia Power may extend the maturity date and/or increase or decrease the lending commitments thereunder.
See Note 6 to the financial statements of Georgia Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
A portion of the unused credit with banks is allocated to provide liquidity support to Georgia Power's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of September 30, 2017 was approximately $550 million as compared to $868 million at December 31, 2016. In June 2017, Georgia Power remarketed $318 million of variable rate pollution control bonds in index rate modes, reducing the liquidity support utilized under Georgia Power's bank
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
credit arrangement. In addition, at September 30, 2017, Georgia Power had $509 million of pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to September 30, 2017, $40 million of these pollution control revenue bonds which were in an index rate mode were remarketed to the public in a long-term fixed rate mode.
Georgia Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Georgia Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Georgia Power are loaned directly to Georgia Power. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support. Commercial paper is included in notes payable in the balance sheets.
Details of short-term borrowings were as follows:
|
| | | | | | | | | | | | | | | | | | |
| | | Short-term Debt at September 30, 2017 | | Short-term Debt During the Period(*) |
| | | Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) | | | | (in millions) |
| Commercial paper | | $ | — |
| | — | % | | $ | 109 |
| | 1.5 | % | | $ | 428 |
|
| Short-term bank debt | | 400 |
| | 2.0 | % | | 568 |
| | 2.0 | % | | 800 |
|
| Total | | $ | 400 |
| | 2.0 | % | | $ | 677 |
| | 2.0 | % | | |
| |
(*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2017. |
Georgia Power believes the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, short-term bank notes, and operating cash flows.
Credit Rating Risk
At September 30, 2017, Georgia Power did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, and transmission.
The maximum potential collateral requirements under these contracts at September 30, 2017 were as follows:
|
| | | |
| Credit Ratings | Maximum Potential
Collateral
Requirements |
| | (in millions) |
| At BBB- and/or Baa3 | $ | 87 |
|
| Below BBB- and/or Baa3 | $ | 1,021 |
|
Included in these amounts are certain agreements that could require collateral in the event that Georgia Power or Alabama Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Georgia Power to access capital markets and would be likely to impact the cost at which it does so.
On March 20, 2017, Moody's revised its rating outlook for Georgia Power from stable to negative.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including Georgia Power) from stable to negative.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
On March 30, 2017, Fitch placed the ratings of Georgia Power on rating watch negative.
Financing Activities
In March 2017, Georgia Power issued $450 million aggregate principal amount of Series 2017A 2.00% Senior Notes due March 30, 2020 and $400 million aggregate principal amount of Series 2017B 3.25% Senior Notes due March 30, 2027. The proceeds were used to repay a portion of Georgia Power's short-term indebtedness and for general corporate purposes, including Georgia Power's continuous construction program.
In April 2017, Georgia Power purchased and held $27 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1995. Subsequent to September 30, 2017, Georgia Power remarketed these bonds to the public.
In June 2017, Georgia Power repaid at maturity $450 million aggregate principal amount of Series 2007B 5.70% Senior Notes.
In June 2017, Georgia Power entered into three floating rate bank loans in aggregate principal amounts of $50 million, $150 million, and $100 million, with maturity dates of December 1, 2017, May 31, 2018, and June 28, 2018, respectively, which bear interest based on one-month LIBOR. Also in June 2017, Georgia Power borrowed $500 million pursuant to an uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Georgia Power and the bank from time to time and is payable on no less than 30 days' demand by the bank. The proceeds from these bank loans were used to repay a portion of Georgia Power's existing indebtedness and for working capital and other general corporate purposes, including Georgia Power's continuous construction program.
In August 2017, Georgia Power repaid $250 million of the $500 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement. Also in August 2017, Georgia Power amended its $100 million floating rate bank loan to extend the maturity date from June 28, 2018 to October 26, 2018.
Also in August 2017, Georgia Power issued $500 million aggregate principal amount of Series 2017C 2.00% Senior Notes due September 8, 2020. The proceeds were used to repay Georgia Power's $50 million floating rate bank loan due December 1, 2017 and outstanding commercial paper borrowings and for general corporate purposes.
Also in August 2017, Georgia Power purchased and held $38 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 1997. Subsequent to September 30, 2017, Georgia Power remarketed these bonds to the public.
In September 2017, Georgia Power issued $270 million aggregate principal amount of Series 2017A 5.00% Junior Subordinated Notes due October 1, 2077. The proceeds were used in October 2017 to redeem all 1.8 million shares ($45 million aggregate liquidation amount) of Georgia Power's 6.125% Series Class A Preferred Stock and 2.25 million shares ($225 million aggregate liquidation amount) of Georgia Power's 6.50% Series 2007A Preference Stock.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Georgia Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
GULF POWER COMPANY
GULF POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 |
| 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | |
| Retail revenues | $ | 375 |
| | $ | 377 |
| | $ | 972 |
| | $ | 978 |
|
| Wholesale revenues, non-affiliates | 14 |
| | 17 |
| | 44 |
| | 48 |
|
| Wholesale revenues, affiliates | 28 |
| | 23 |
| | 75 |
| | 59 |
|
| Other revenues | 20 |
| | 19 |
| | 53 |
| | 51 |
|
| Total operating revenues | 437 |
| | 436 |
| | 1,144 |
| | 1,136 |
|
| Operating Expenses: | | | | | | | |
| Fuel | 127 |
| | 141 |
| | 323 |
| | 342 |
|
| Purchased power, non-affiliates | 37 |
| | 33 |
| | 104 |
| | 95 |
|
| Purchased power, affiliates | 2 |
| | 3 |
| | 13 |
| | 9 |
|
| Other operations and maintenance | 81 |
| | 86 |
| | 252 |
| | 239 |
|
| Depreciation and amortization | 42 |
| | 49 |
| | 95 |
| | 129 |
|
| Taxes other than income taxes | 33 |
| | 34 |
| | 88 |
| | 93 |
|
| Loss on Plant Scherer Unit 3 | — |
| | — |
| | 33 |
| | — |
|
| Total operating expenses | 322 |
| | 346 |
| | 908 |
| | 907 |
|
| Operating Income | 115 |
| | 90 |
| | 236 |
| | 229 |
|
| Other Income and (Expense): | | | | | | | |
| Interest expense, net of amounts capitalized | (13 | ) | | (11 | ) | | (37 | ) | | (36 | ) |
| Other income (expense), net | 1 |
| | (2 | ) | | — |
| | (4 | ) |
| Total other income and (expense) | (12 | ) | | (13 | ) | | (37 | ) | | (40 | ) |
| Earnings Before Income Taxes | 103 |
| | 77 |
| | 199 |
| | 189 |
|
| Income taxes | 40 |
| | 30 |
| | 78 |
| | 74 |
|
| Net Income | 63 |
| | 47 |
| | 121 |
| | 115 |
|
| Dividends on Preference Stock | — |
| | 2 |
| | 4 |
| | 7 |
|
| Net Income After Dividends on Preference Stock | $ | 63 |
| | $ | 45 |
| | $ | 117 |
| | $ | 108 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) |
| Net Income | $ | 63 |
| | $ | 47 |
| | $ | 121 |
| | $ | 115 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
| Changes in fair value, net of tax of $-, $-, $(1), and $(3), respectively | — |
| | — |
| | (1 | ) | | (4 | ) |
| Total other comprehensive income (loss) | — |
| | — |
| | (1 | ) | | (4 | ) |
| Comprehensive Income | $ | 63 |
| | $ | 47 |
| | $ | 120 |
| | $ | 111 |
|
The accompanying notes as they relate to Gulf Power are an integral part of these condensedRegistrant's financial statements.
GULF POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
|
| | | | | | | |
| | For the Nine Months Ended September 30, |
| | 2017 | | 2016 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 121 |
| | $ | 115 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 100 |
| | 134 |
|
| Deferred income taxes | 57 |
| | 15 |
|
| Loss on Plant Scherer Unit 3 | 33 |
| | — |
|
| Other, net | (5 | ) | | (2 | ) |
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (65 | ) | | (9 | ) |
| -Fossil fuel stock | 7 |
| | 49 |
|
| -Other current assets | 11 |
| | 3 |
|
| -Accrued taxes | 21 |
| | 40 |
|
| -Accrued compensation | (10 | ) | | (5 | ) |
| -Over recovered regulatory clause revenues | (8 | ) | | 26 |
|
| -Other current liabilities | 10 |
| | 8 |
|
| Net cash provided from operating activities | 272 |
| | 374 |
|
| Investing Activities: | | | |
| Property additions | (142 | ) | | (106 | ) |
| Cost of removal, net of salvage | (16 | ) | | (8 | ) |
| Change in construction payables | (9 | ) | | (7 | ) |
| Other investing activities | (6 | ) | | (6 | ) |
| Net cash used for investing activities | (173 | ) | | (127 | ) |
| Financing Activities: | | | |
| Decrease in notes payable, net | (268 | ) | | (42 | ) |
| Proceeds — | | | |
| Common stock issued to parent | 175 |
| | — |
|
| Capital contributions from parent company | 7 |
| | 10 |
|
| Senior notes | 300 |
| | — |
|
| Redemptions — | | | |
| Preference stock | (150 | ) | | — |
|
| Senior notes | (85 | ) | | (125 | ) |
| Payment of common stock dividends | (94 | ) | | (90 | ) |
| Other financing activities | (3 | ) | | (5 | ) |
| Net cash used for financing activities | (118 | ) | | (252 | ) |
| Net Change in Cash and Cash Equivalents | (19 | ) | | (5 | ) |
| Cash and Cash Equivalents at Beginning of Period | 56 |
| | 74 |
|
| Cash and Cash Equivalents at End of Period | $ | 37 |
| | $ | 69 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid during the period for — | | | |
| Interest (net of $- and $- capitalized for 2017 and 2016, respectively) | $ | 24 |
| | $ | 29 |
|
| Income taxes, net | 19 |
| | 14 |
|
| Noncash transactions — Accrued property additions at end of period | 25 |
| | 13 |
|
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.
GULF POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At September 30, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 37 |
| | $ | 56 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 96 |
| | 72 |
|
| Unbilled revenues | | 68 |
| | 55 |
|
| Under recovered regulatory clause revenues | | 15 |
| | 17 |
|
| Income taxes receivable, current | | 15 |
| | — |
|
| Other accounts and notes receivable | | 12 |
| | 6 |
|
| Affiliated | | 13 |
| | 17 |
|
| Accumulated provision for uncollectible accounts | | (1 | ) | | (1 | ) |
| Fossil fuel stock | | 64 |
| | 71 |
|
| Materials and supplies | | 58 |
| | 55 |
|
| Other regulatory assets, current | | 55 |
| | 44 |
|
| Other current assets | | 15 |
| | 30 |
|
| Total current assets | | 447 |
| | 422 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 5,181 |
| | 5,140 |
|
| Less: Accumulated provision for depreciation | | 1,457 |
| | 1,382 |
|
| Plant in service, net of depreciation | | 3,724 |
| | 3,758 |
|
| Construction work in progress | | 75 |
| | 51 |
|
| Total property, plant, and equipment | | 3,799 |
| | 3,809 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 56 |
| | 58 |
|
| Other regulatory assets, deferred | | 499 |
| | 512 |
|
| Other deferred charges and assets | | 22 |
| | 21 |
|
| Total deferred charges and other assets | | 577 |
| | 591 |
|
| Total Assets | | $ | 4,823 |
| | $ | 4,822 |
|
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.
GULF POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholder's Equity | | At September 30, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 7 |
| | $ | 87 |
|
| Notes payable | | — |
| | 268 |
|
| Accounts payable — | | | | |
| Affiliated | | 46 |
| | 59 |
|
| Other | | 55 |
| | 54 |
|
| Customer deposits | | 35 |
| | 35 |
|
| Accrued taxes | | 41 |
| | 20 |
|
| Accrued interest | | 20 |
| | 8 |
|
| Accrued compensation | | 30 |
| | 40 |
|
| Deferred capacity expense, current | | 22 |
| | 22 |
|
| Other regulatory liabilities, current | | 1 |
| | 16 |
|
| Other current liabilities | | 37 |
| | 40 |
|
| Total current liabilities | | 294 |
| | 649 |
|
| Long-term Debt | | 1,285 |
| | 987 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 1,003 |
| | 948 |
|
| Employee benefit obligations | | 90 |
| | 96 |
|
| Deferred capacity expense | | 103 |
| | 119 |
|
| Asset retirement obligations, deferred | | 125 |
| | 120 |
|
| Other cost of removal obligations | | 218 |
| | 249 |
|
| Other regulatory liabilities, deferred | | 45 |
| | 47 |
|
| Other deferred credits and liabilities | | 71 |
| | 71 |
|
| Total deferred credits and other liabilities | | 1,655 |
| | 1,650 |
|
| Total Liabilities | | 3,234 |
| | 3,286 |
|
| Preference Stock | | — |
| | 147 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, without par value — | | | | |
| Authorized — 20,000,000 shares | | | | |
| Outstanding — September 30, 2017: 7,392,717 shares | | | | |
| — December 31, 2016: 5,642,717 shares | | 678 |
| | 503 |
|
| Paid-in capital | | 600 |
| | 589 |
|
| Retained earnings | | 312 |
| | 296 |
|
| Accumulated other comprehensive income (loss) | | (1 | ) | | 1 |
|
| Total common stockholder's equity | | 1,589 |
| | 1,389 |
|
| Total Liabilities and Stockholder's Equity | | $ | 4,823 |
| | $ | 4,822 |
|
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRD QUARTER 2017 vs. THIRD QUARTER 2016
AND
YEAR-TO-DATE 2017 vs. YEAR-TO-DATE 2016
OVERVIEW
Gulf Power operates as a vertically integrated utility providing electric service to retail customers within its traditional service territory located in northwest Florida and to wholesale customers inRegistrants believe the Southeast.
Many factors affect the opportunities, challenges, and risks of Gulf Power's business of providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, reliability, restoration following major storms, fuel, and capital expenditures. Gulf Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Gulf Power for the foreseeable future.
On April 4, 2017, the Florida PSC approved a settlement agreement (2017 Rate Case Settlement Agreement) among Gulf Power and three intervenors with respect to Gulf Power's request to increase retail base rates. Among the terms of the 2017 Rate Case Settlement Agreement, Gulf Power increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consisted of a $62.0 million increase in annual base revenues less an annual equivalent credit of approximately $7.7 million for 2017 for certain wholesale revenues to be provided through December 2019 through the purchased power capacity cost recovery clause. In addition, Gulf Power continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%), is deemed to have an equity ratio of 52.5% for all retail regulatory purposes, and implemented new dismantlement accruals effective July 1, 2017. Gulf Power will also begin amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 (357 MWs) over 15 years effective January 1, 2018 and will implement new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs), which was recorded in the first quarter 2017. The remaining issues related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause rate approved by the Florida PSC in November 2016.
Gulf Power continues to focus on several key performance indicators including, but not limited to, customer satisfaction, plant availability, system reliability, and net income after dividends on preference stock.
RESULTS OF OPERATIONS
Net Income
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $18 | | 40.0 | | $9 | | 8.3 |
Gulf Power's net income after dividends on preference stock for the third quarter 2017 was $63 million compared to $45 million for the corresponding period in 2016. The increase was primarily due to an increase in retail base revenues and a decrease in depreciation.
Gulf Power's net income after dividends on preference stock for year-to-date 2017 was $117 million compared to $108 million for the corresponding period in 2016. The increase was primarily due to a decrease in depreciation and
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
an increase in retail base revenues, partially offset by a write-down of $32.5 million ($20 million after tax) of Gulf Power's ownership of Plant Scherer Unit 3 resulting from the 2017 Rate Case Settlement Agreement and higher operations and maintenance expenses. See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information regarding the 2017 Rate Case Settlement Agreement.
Retail Revenues
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(2) | | (0.5) | | $(6) | | (0.6) |
In the third quarter 2017, retail revenues were $375 million compared to $377 million for the corresponding period in 2016. For year-to-date 2017, retail revenues were $972 million compared to $978 million for the corresponding period in 2016.
Details of the changes in retail revenues were as follows:
|
| | | | | | | | | | | | | |
| | Third Quarter 2017 | | Year-to-Date 2017 |
| | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | $ | 377 |
| | | | $ | 978 |
| | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 21 |
| | 5.6 |
| | 28 |
| | 2.9 |
|
| Sales growth | 3 |
| | 0.8 |
| | 1 |
| | 0.1 |
|
| Weather | (9 | ) | | (2.4 | ) | | (14 | ) | | (1.4 | ) |
| Fuel and other cost recovery | (17 | ) | | (4.5 | ) | | (21 | ) | | (2.2 | ) |
| Retail – current year | $ | 375 |
| | (0.5 | )% | | $ | 972 |
| | (0.6 | )% |
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" of Gulf Power in Item 7 and Note 1 to the financial statements of Gulf Power under "Revenues" and Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information regarding Gulf Power's retail base rate case and cost recovery clauses, including Gulf Power's fuel cost recovery, purchased power capacity recovery, environmental cost recovery, and energy conservation cost recovery clauses.
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016 primarily due to an increase in retail base revenues effective July 2017, as well as an increase in environmental cost recovery effective November 2016 resulting from Gulf Power's ownership of Plant Scherer Unit 3 being rededicated to retail service.
Revenues attributable to changes in sales increased slightly in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016. For the third quarter 2017, weather-adjusted KWH sales to residential and commercial customers increased 5.2% and 1.5%, respectively. Weather-adjusted KWH sales to residential customers increased 1.3% year-to-date 2017. These increases were primarily due to customer growth, partially offset by lower customer usage primarily resulting from efficiency improvements in appliances and lighting. Weather-adjusted KWH sales to commercial customers decreased slightly year-to-date 2017 as a result of lower customer usage primarily resulting from efficiency improvements in appliances and lighting, mostly offset by customer growth. KWH sales to industrial customers decreased 7.1% and 6.1% for the third quarter and year-to-date 2017, respectively, primarily due to changes in customers' operations and energy efficiency improvements.
Fuel and other cost recovery revenues decreased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016, primarily due to lower fuel, purchased power capacity, and energy conservation recoverable costs, partially offset by higher environmental recoverable costs. Fuel and other cost recovery
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
provisions include fuel expenses, the energy component of purchased power costs, purchased power capacity costs, the difference between projected and actual costs and revenues related to energy conservation and environmental compliance, and a credit for certain wholesale revenues as a result of the 2017 Rate Case Settlement Agreement. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K for additional information regarding cost recovery clauses and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information regarding the 2017 Rate Case Settlement Agreement.
Wholesale Revenues – Non-Affiliates
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(3) | | (17.6) | | $(4) | | (8.3) |
Wholesale revenues from sales to non-affiliates consist of long-term sales agreements to other utilities in Florida and Georgia and short-term opportunity sales. Capacity revenues from long-term sales agreements represent the greatest contribution to net income. The energy is generally sold at variable cost. Short-term opportunity sales are made at market-based rates that generally provide a margin above Gulf Power's variable cost of energy. Wholesale energy revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Gulf Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.
In the third quarter 2017, wholesale revenues from sales to non-affiliates were $14 million compared to $17 million for the corresponding period in 2016. The decrease was primarily due to a 28.4% decrease in KWH sales attributable to decreased market demand for energy as a result of milder weather.
For year-to-date 2017, wholesale revenues from sales to non-affiliates were $44 million compared to $48 million for the corresponding period in 2016. The decrease was primarily due to a 20.9% decrease in capacity revenues resulting from the expiration of a Plant Scherer Unit 3 long-term sales agreement in 2016.
Wholesale Revenues – Affiliates
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $5 | | 21.7 | | $16 | | 27.1 |
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since the revenue related to these energy sales generally offsets the cost of energy sold.
In the third quarter 2017, wholesale revenues from sales to affiliates were $28 million compared to $23 million for the corresponding period in 2016. The increase was primarily due to a 24.1% increase in KWH sales resulting from outages of affiliate generation resources.
For year-to-date 2017, wholesale revenues from sales to affiliates were $75 million compared to $59 million for the corresponding period in 2016. The increase was primarily due to a 19.5% increase in KWH sales as a result of the availability of lower-cost Gulf Power generation resources.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | | | |
| | Third Quarter 2017
vs.
Third Quarter 2016 | | Year-to-Date 2017
vs.
Year-to-Date 2016 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | (14 | ) | | (9.9 | ) | | $ | (19 | ) | | (5.6 | ) |
| Purchased power – non-affiliates | 4 |
| | 12.1 |
| | 9 |
| | 9.5 |
|
| Purchased power – affiliates | (1 | ) | | (33.3 | ) | | 4 |
| | 44.4 |
|
| Total fuel and purchased power expenses | $ | (11 | ) | | | | $ | (6 | ) | | |
In the third quarter 2017, total fuel and purchased power expenses were $166 million compared to $177 million for the corresponding period in 2016. The decrease was primarily the result of a $7 million net decrease due to the lower average cost of fuel and a $6 million net decrease related to the volume of KWHs generated and purchased due to milder weather in 2017 reducing demand.
For year-to-date 2017, total fuel and purchased power expenses were $440 million compared to $446 million for the corresponding period in 2016. The decrease was primarily the result of a $19 million net decrease related to the volume of KWHs generated and purchased due to milder weather in 2017 reducing demand, partially offset by a $12 million net increase related to the higher average cost of fuel and purchased power.
Fuel and purchased power transactions do not have a significant impact on earnings since energy and capacity expenses are generally offset by energy and capacity revenues through Gulf Power's fuel and purchased power capacity cost recovery clauses and long-term wholesale contracts. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Retail Fuel Cost Recovery" and " – Purchased Power Capacity Recovery" in Item 8 of the Form 10-K for additional information.
Details of Gulf Power's generation and purchased power were as follows:
|
| | | | | | | |
| | Third Quarter 2017 | | Third Quarter 2016 | | Year-to-Date 2017 | | Year-to-Date 2016 |
Total generation (in millions of KWHs) | 2,780 | | 2,775 | | 7,000 | | 6,654 |
Total purchased power (in millions of KWHs) | 1,686 | | 1,906 | | 4,362 | | 5,295 |
Sources of generation (percent) – | | | | | | | |
| Coal | 59 | | 68 | | 55 | | 57 |
| Gas | 41 | | 32 | | 45 | | 43 |
Cost of fuel, generated (in cents per net KWH) – | | | | | | | |
| Coal | 3.04 | | 3.55 | | 3.15 | | 3.80 |
| Gas | 3.71 | | 4.38 | | 3.60 | | 4.06 |
Average cost of fuel, generated (in cents per net KWH) | 3.31 | | 3.81 | | 3.35 | | 3.91 |
Average cost of purchased power (in cents per net KWH)(*) | 4.32 | | 3.79 | | 4.70 | | 3.51 |
| |
(*) | Average cost of purchased power includes fuel purchased by Gulf Power for tolling agreements where power is generated by the provider. |
Fuel
In the third quarter 2017, fuel expense was $127 million compared to $141 million for the corresponding period in 2016. The decrease was primarily due to a 13.1% decrease in the average cost of fuel resulting from lower coal and natural gas prices, partially offset by a 29.3% increase in the volume of KWHs generated by Gulf Power's gas-fired generation resources.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2017, fuel expense was $323 million compared to $342 million for the corresponding period in 2016. The decrease was primarily due to a 14.3% decrease in the average cost of fuel resulting from lower coal and natural gas prices, partially offset by a 10.3% increase in the volume of KWHs generated by Gulf Power's gas-fired generation resources.
Purchased Power – Non-Affiliates
In the third quarter 2017, purchased power expense from non-affiliates was $37 million compared to $33 million for the corresponding period in 2016. For year-to-date 2017, purchased power expense from non-affiliates was $104 million compared to $95 million for the corresponding period in 2016. These increases were primarily due to increases of 16.3% and 35.9% for the third quarter and year-to-date 2017, respectively, in the average cost per KWH purchased, partially offset by decreases of 11.1% and 20.2% for the third quarter and year-to-date 2017, respectively, in the volume of KWHs purchased due to lower territorial load.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the third quarter 2017, purchased power expense from affiliates was $2 million compared to $3 million for the corresponding period in 2016. The decrease was primarily due to a 38.3% decrease in the average cost per KWH purchased primarily resulting from lower priced power pool resources and a 20.5% decrease in the volume of KWHs purchased due to lower territorial load.
For year-to-date 2017, purchased power expense from affiliates was $13 million compared to $9 million for the corresponding period in 2016. The increase was primarily due to a 13.2% increase in the volume of KWHs purchased due to more planned outages for Gulf Power generation resources and a 29.3% increase in the average cost per KWH purchased primarily due to increased natural gas prices.
Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(5) | | (5.8) | | $13 | | 5.4 |
In the third quarter 2017, other operations and maintenance expenses were $81 million compared to $86 million for the corresponding period in 2016. The decrease was primarily due to lower employee compensation and benefits, including pension costs, and the suspension of the property damage reserve accrual in accordance with the 2017 Rate Case Settlement Agreement.
For year-to-date 2017, other operations and maintenance expenses were $252 million compared to $239 million for the corresponding period in 2016. The increase was primarily due to higher expenses at generation facilities associated with routine and planned maintenance.
See Note (A) to the Condensed Financial Statements under "Property Damage Reserve" herein for additional information regarding Gulf Power's property damage reserve accrual suspension and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information regarding the 2017 Rate Case Settlement Agreement.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Depreciation and Amortization
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(7) | | (14.3) | | $(34) | | (26.4) |
In the third quarter 2017, depreciation and amortization was $42 million compared to $49 million for the corresponding period in 2016. For year-to-date 2017, depreciation and amortization was $95 million compared to $129 million for the corresponding period in 2016. These decreases were primarily due to changes in the reductions in depreciation, as authorized in a settlement agreement approved by the Florida PSC in 2013 (2013 Rate Case Settlement Agreement), of $6 million and $34 million in the third quarter and year-to-date 2017, respectively, compared to the corresponding periods in 2016. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Case" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information.
Income Taxes
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $10 | | 33.3 | | $4 | | 5.4 |
In the third quarter 2017, income taxes were $40 million compared to $30 million for the corresponding period in 2016. For year-to-date 2017, income taxes were $78 million compared to $74 million for the corresponding period in 2016. These increases were primarily due to higher pre-tax earnings.
Dividends on Preference Stock
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(2) | | N/M | | $(3) | | (42.9) |
N/M - Not meaningful
In the third quarter 2017, there were no dividends on preference stock compared to $2 million for the corresponding period in 2016. For year-to-date 2017, dividends on preference stock were $4 million compared to $7 million for the corresponding period in 2016. These decreases were the result of the redemption of all preference stock in June 2017. See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Gulf Power's future earnings potential. The level of Gulf Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Gulf Power's business of providing electric service. These factors include Gulf Power's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs during a time of increasing costs and limited projected demand growth over the next several years. Future earnings will be driven primarily by customer growth. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies due to changes in the minimum allowable equipment efficiencies along with the continuation of changes in customer behavior. Earnings are subject to a variety of other factors. These factors include weather, competition, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Gulf Power's service territory. Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings. Current proposals related to
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Gulf Power's financial statements. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Gulf Power in Item 7 of the Form 10-K.
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in retail rates or through long-term wholesale agreements on a timely basis or through market-based contracts. The State of Florida has statutory provisions that allow a utility to petition the Florida PSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. Gulf Power's current long-term wholesale agreements contain provisions that permit charging the customer with costs incurred as a result of changes in environmental laws and regulations. The full impact of any such legislative or regulatory changes cannot be determined at this time. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and aspending legal challenges to rules are completed. Further, higher costs that are recovered through regulated rates or long-term wholesale agreements could contribute to reduced demand for electricity as well as impactdiscussed below have no merit; however, the cost competitiveness of wholesale capacity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters," "Retail Regulatory Matters – Cost Recovery Clauses – Environmental Cost Recovery," and "Other Matters" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Statutes and Regulations
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the final effluent guidelines rule and the final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs.
On April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. On September 18, 2017, the EPA published a final rule establishing a stay of the compliance deadlines for certain effluent limitations and pretreatment standards under the rule.
On June 27, 2017, the EPA and the U.S. Army Corps of Engineers proposed to rescind the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.
The ultimate outcome of these matters cannot be determined at this time.
Global Climate IssuesSouthern Company
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues"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 GulfGeorgia. Each of these lawsuits named as defendants Southern Company, certain of its directors, certain of its current and former officers, and certain former Mississippi Power officers. In 2017, these two shareholder derivative lawsuits were consolidated in Item 7the U.S. District Court for the Northern District of Georgia. The complaints alleged that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints alleged that the defendants were unjustly enriched and caused the waste of corporate assets and also alleged that the individual defendants violated their fiduciary duties.
In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, Georgia that named as defendants Southern Company, certain of its directors, certain of its current and former officers, and certain former Mississippi Power officers. The complaint alleged 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 Form 10-KKemper County energy facility. The complaint further alleged 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. In August 2019, the court granted a motion filed by the plaintiff in July 2019 to substitute a new named plaintiff, Martin J. Kobuck, in place of Helen E. Piper Survivor's Trust.
The plaintiffs in each of these cases sought 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. The plaintiffs also sought certain changes to Southern Company's corporate governance and internal processes. On January 21, 2022, the plaintiffs in the federal court action filed a motion for additional information.preliminary approval of settlement, together with an executed stipulation of settlement, which applied to both actions. On June 9, 2022, the U.S. District Court for the Northern District of Georgia granted final approval of the settlement and, on June 16, 2022, the Superior Court of Gwinnett County, Georgia entered an order awarding attorneys' fees and expenses related to the Martin J. Kobuck lawsuit. The settlement consisted of an aggregate payment by Southern Company's insurers of approximately $4.5 million for attorneys' fees and expenses, as well as adoption of various corporate governance reforms by Southern Company. These matters are now concluded.
Alabama Power
On March 28, 2017,September 26, 2022, Mobile Baykeeper, through its counsel Southern Environmental Law Center, filed a citizen suit in the U.S. President signed an executive order directing agenciesDistrict Court for the Southern District of Alabama alleging that Alabama Power's plan to review actionsclose the Plant Barry ash pond utilizing a closure-in-place methodology violates the Resource Conservation and Recovery Act (RCRA) and regulations governing CCR. Among other relief requested, Mobile Baykeeper seeks a declaratory judgment that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPARCRA and regulations governing CCR are being violated, preliminary and injunctive relief to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OFNOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
FINANCIAL CONDITION AND RESULTS OF OPERATIONS(UNAUDITED)
those rules. On October 16, 2017, the EPA published a proposed rule to repeal the Clean Power Plan. The EPA has not determined whether or when it will promulgate a replacement rule.
On June 1, 2017, the U.S. President announced that the United States will withdraw from the non-binding Paris Agreement and begin renegotiationprevent implementation of its terms.
The ultimate outcome of these matters cannot be determined at this time.
FERC Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the traditional electric operating companies' and SouthernAlabama Power's market power proceeding and amendment to their market-rate tariff.
On May 17, 2017, the FERC accepted the traditional electric operating companies' (including Gulf Power's) and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies (including Gulf Power) and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' (including Gulf Power's) and Southern Power's market power proceeding related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including Gulf Power's) and Southern Power's June 30, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including Gulf Power) and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order, or to provide a mitigationclosure plan to further address market power concerns. The traditional electric operating companies (including Gulf Power) and Southern Power expect to make a filing within the specified 60 days responding to the FERC's order.
The ultimate outcome of these matters cannot be determined at this time.
Retail Regulatory Matters
Gulf Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Florida PSC. Gulf Power's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased energy costs, purchased power capacity costs, energy conservation and demand side management programs, and the costsdevelopment of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are recovered through base rates.a closure plan that satisfies regulations governing CCR requirements. See Note 36 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.
Retail Base Rate Cases
The 2013 Rate Case Settlement Agreement authorized Gulf Power to reduce depreciation and record a regulatory asset up to $62.5 million from January 2014 through June 2017. In any given month, such depreciation reduction could not exceed the amount necessary for the retail ROE, as reported to the Florida PSC monthly, to reach the midpointdiscussion of the authorized retail ROE range then in effect. For 2014 and 2015, Gulf Power recognized reductions in depreciation of $8.4 million and $20.1 million, respectively. No net reduction in depreciation was recorded in 2016. Through June 2017, Gulf Power recognized the remaining allowable reductions in depreciation totaling $34.0 million.
On April 4, 2017, the Florida PSC approved the 2017 Rate Case Settlement Agreement among Gulf Power and three intervenors with respect to GulfAlabama Power's request to increase retail base rates. Among the terms of the 2017 Rate Case Settlement Agreement, Gulf Power increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consisted of a $62.0 million increase in annual base revenues less an annual equivalent credit of approximately $7.7 million for 2017 for
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
certain wholesale revenues to be provided through December 2019 through the purchased power capacity cost recovery clause. In addition, Gulf Power continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%), is deemed to have an equity ratio of 52.5% for all retail regulatory purposes, and implemented new dismantlement accruals effective July 1, 2017. Gulf Power will also begin amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 over 15 years effective January 1, 2018 and will implement new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3, which was recorded in the first quarter 2017. The remaining issuesARO liabilities related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause rate approved by the Florida PSC in November 2016.
Cost Recovery Clauses
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Cost Recovery Clauses" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K for additional information regarding Gulf Power's recovery of retail costs through various regulatory clauses and accounting orders. Gulf Power has four regulatory clauses which are approved by the Florida PSC. See Note (B) to the Condensed Financial Statements herein for additional information.
As discussed previously, the 2017 Rate Case Settlement Agreement resolved the remaining issues related to Gulf Power's inclusion of certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 in the environmental cost recovery clause and no adjustment to the environmental cost recovery clause rate approved by the Florida PSC in November 2016 was made.
On October 25, 2017, the Florida PSC approved Gulf Power's annual rate clause request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2018. The net effect of the approved changes is a $63 million increase in annual revenues effective in January 2018, the majority of which will be offset by related expense increases.
Renewables
In 2015, the Florida PSC approved three energy purchase agreements totaling 120 MWs of utility-scale solar generation located at three military installations in northwest Florida. Purchases under these agreements began in the summer of 2017.
Other Matters
Gulf Power is involved in various other matters being litigated and regulatory mattersfacilities that could affect future earnings. In addition, Gulf Power is subject to certain claims and legal actions arising in the ordinary course of business. Gulf Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Gulf Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Gulf Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Gulf Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Gulf Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Gulf Power in Item 7 of the Form 10-K for a complete discussion of Gulf Power's critical accounting policies and estimates related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, and Contingent Obligations.
Recently Issued Accounting Standards
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Gulf Power in Item 7 of the Form 10-K for additional information.
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
While Gulf Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Gulf Power's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs. Gulf Power expects that the revenue from contracts with these customers will not result in a significant shift in the timing of revenue recognition for such sales.
Gulf Power's ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Gulf Power's financial statements, if material. In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Gulf Power expects CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Gulf Power intends to use the modified retrospective method of adoption effective January 1, 2018. Gulf Power has also elected to utilize practical expedients which allow it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Gulf Power's financial statements, Gulf Power will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
costs to be separately presented in the income statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Gulf Power's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Gulf Power's financial statements.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with early adoption permitted. Gulf Power is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on Gulf Power's financial statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Gulf Power in Item 7 of the Form 10-K for additional information. Gulf Power's financial condition remained stable at September 30, 2017. Gulf Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $272 million for the first nine months of 2017 compared to $374 million for the corresponding period in 2016. The $102 million decrease in net cash was primarily due to decreases related to certain cost recovery clauses, the timing of fossil fuel stock purchases, and a federal income tax refund received in 2016. Net cash used for investing activities totaled $173 million in the first nine months of 2017 primarily due to property additions to utility plant. Net cash used for financing activities totaled $118 million for the first nine months of 2017 primarily due to the payment of short-term debt, redemptions of preference stock and long-term debt, and common stock dividend payments, partially offset by proceeds from issuances of long-term debt and common stock. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first nine months of 2017 primarily reflect the financing activities described above. Other significant changes include an increase in accumulated deferred income taxes due to accelerated depreciation and repair deductions and a decrease in other cost of removal obligations, as authorized in the 2013 Rate Case Settlement Agreement. See "Financing Activities" herein and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Gulf Power in Item 7 of the Form 10-K for a description of Gulf Power's capital requirements for its construction program, including estimated capital expenditures to comply
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, leases, derivative obligations, purchase commitments, and trust funding requirements. Approximately $7 million will be required through September 30, 2018 to fund maturities of long-term debt. See "Financing Activities" herein for additional information.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating units, to meet regulatory requirements; changes in the expected environmental compliance programs; changes in FERC rules and regulations; Florida PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Sources of Capital
Gulf Power plans to obtain the funds required to meet its future capital needs from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, external security issuances, term loans, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Gulf Power in Item 7 of the Form 10-K for additional information.
Gulf Power's current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt, as well as significant seasonal fluctuations in cash needs. Gulf Power has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet short-term liquidity needs, including its commercial paper program which is supported by bank credit facilities.
At September 30, 2017, Gulf Power had approximately $37 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2017 were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Expires | | | | | | Executable Term Loans | | Expires Within One Year |
| 2017 | | 2018 | | 2019 | | 2020 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out |
| (in millions) |
| $ | 30 |
| | $ | 195 |
| | $ | 25 |
| | $ | 30 |
| | $ | 280 |
| | $ | 280 |
| | $ | 45 |
| | $ | — |
| | $ | — |
| | $ | 40 |
|
See Note 6 to the financial statements of Gulf Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
Most of these bank credit arrangements contain covenants that limit debt levels and contain cross-acceleration provisions to other indebtedness (including guarantee obligations) of Gulf Power. Such cross-acceleration provisions to other indebtedness would trigger an event of default if Gulf Power defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2017, Gulf Power was in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, Gulf Power expects to renew or replace its bank credit arrangements, as needed, prior to expiration. In connection therewith, Gulf Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Most of the unused credit arrangements with banks are allocated to provide liquidity support to Gulf Power's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of September 30, 2017 was approximately $82 million. In addition, at September 30, 2017, Gulf Power had approximately $140 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months.
Gulf Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Gulf Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Gulf Power are loaned directly to Gulf Power. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support. Short-term borrowings are included in notes payable in the balance sheets.
Details of short-term borrowings were as follows:
|
| | | | | | | | | | | |
| | | Short-term Debt During the Period(*) |
| | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) |
| Commercial paper | | $ | 23 |
| | 1.4 | % | | $ | 78 |
|
| |
(*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2017. No short-term debt was outstanding at September 30, 2017. |
Gulf Power believes the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, short-term bank loans, and operating cash flows.
Credit Rating Risk
At September 30, 2017, Gulf Power did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management.
The maximum potential collateral requirements under these contracts at September 30, 2017 were as follows:
|
| | | |
| Credit Ratings | Maximum Potential Collateral Requirements |
| | (in millions) |
| At BBB- and/or Baa3 | $ | 167 |
|
| Below BBB- and/or Baa3 | $ | 579 |
|
Included in these amounts are certain agreements that could require collateral in the event that Alabama Power or Georgia Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Gulf Power to access capital markets and would be likely to impact the cost at which it does so.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including Gulf Power) from stable to negative.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Market Price Risk
Gulf Power's market risk exposure relative to interest rate changes for the third quarter and year-to-date 2017 has not changed materially compared to the December 31, 2016 reporting period. Gulf Power's exposure to market volatility in commodity fuel prices and prices of electricity with respect to its wholesale generating capacity is limited because its long-term sales agreement shifts substantially all fuel cost responsibility to the purchaser.
In connection with the 2017 Rate Case Settlement Agreement, Gulf Power recorded a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 in the first quarter 2017 to resolve the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates and no adjustment to the environmental cost recovery clause rate approved by the Florida PSC in November 2016 was made. The 2017 Rate Case Settlement Agreement provides that 100% of Gulf Power's ownership of Plant Scherer Unit 3 will be included in retail rates. This resolved the market price risk concern around Gulf Power's uncontracted wholesale generating capacity related to Plant Scherer Unit 3. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" herein for additional information.
The Florida PSC extended the moratorium on Gulf Power's fuel-hedging program until January 1, 2021 in connection with the 2017 Rate Case Settlement Agreement. The moratorium does not have an impact on the recovery of existing hedges entered into under the previously-approved hedging program.
For additional discussion of Gulf Power's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Gulf Power in Item 7 of the Form 10-K.
Financing Activities
In January 2017, Gulf Power issued 1,750,000 shares of common stock to Southern Company and realized proceeds of $175 million. The proceeds were used for general corporate purposes, including Gulf Power's continuous construction program.
In March 2017, Gulf Power extended the maturity of a $100 million short-term floating rate bank loan bearing interest based on one-month LIBOR from April 2017 to October 2017 and subsequently repaid the loan in May 2017.
In May 2017, Gulf Power issued $300 million aggregate principal amount of Series 2017A 3.30% Senior Notes due May 30, 2027. The proceeds, together with other funds, were used to repay at maturity $85 million aggregate principal amount of Series 2007A 5.90% Senior Notes due June 15, 2017; to repay outstanding commercial paper borrowings; to repay a $100 million short-term floating rate bank loan, as discussed above; and to redeem, in June 2017, 550,000 shares ($55 million aggregate liquidation amount) of 6.00% Series Preference Stock, 450,000 shares ($45 million aggregate liquidation amount) of Series 2007A 6.45% Preference Stock, and 500,000 shares ($50 million aggregate liquidation amount) of Series 2013A 5.60% Preference Stock.
In addition to any financings that may be necessary to meet capital requirements, contractual obligations, and storm recovery, Gulf Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
MISSISSIPPI POWER COMPANY
MISSISSIPPI POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | |
| Retail revenues | $ | 243 |
| | $ | 263 |
| | $ | 665 |
| | $ | 652 |
|
| Wholesale revenues, non-affiliates | 72 |
| | 78 |
| | 196 |
| | 198 |
|
| Wholesale revenues, affiliates | 21 |
| | 7 |
| | 40 |
| | 23 |
|
| Other revenues | 5 |
| | 4 |
| | 14 |
| | 12 |
|
| Total operating revenues | 341 |
| | 352 |
| | 915 |
| | 885 |
|
| Operating Expenses: | | | | | | | |
| Fuel | 120 |
| | 112 |
| | 301 |
| | 268 |
|
| Purchased power, non-affiliates | 4 |
| | 3 |
| | 7 |
| | 4 |
|
| Purchased power, affiliates | 2 |
| | 5 |
| | 13 |
| | 14 |
|
| Other operations and maintenance | 66 |
| | 74 |
| | 206 |
| | 211 |
|
| Depreciation and amortization | 39 |
| | 30 |
| | 120 |
| | 114 |
|
| Taxes other than income taxes | 25 |
| | 31 |
| | 77 |
| | 81 |
|
| Estimated loss on Kemper IGCC | 34 |
| | 88 |
| | 3,155 |
| | 222 |
|
| Total operating expenses | 290 |
| | 343 |
| | 3,879 |
| | 914 |
|
| Operating Income (Loss) | 51 |
| | 9 |
| | (2,964 | ) | | (29 | ) |
| Other Income and (Expense): | | | | | | | |
| Allowance for equity funds used during construction | 1 |
| | 31 |
| | 72 |
| | 90 |
|
| Interest expense, net of amounts capitalized | 13 |
| | (15 | ) | | (23 | ) | | (46 | ) |
| Other income (expense), net | (1 | ) | | (1 | ) | | (3 | ) | | (4 | ) |
| Total other income and (expense) | 13 |
| | 15 |
| | 46 |
| | 40 |
|
| Earnings (Loss) Before Income Taxes | 64 |
| | 24 |
| | (2,918 | ) | | 11 |
|
| Income taxes (benefit) | 24 |
| | (2 | ) | | (885 | ) | | (29 | ) |
| Net Income (Loss) | 40 |
| | 26 |
| | (2,033 | ) | | 40 |
|
| Dividends on Preferred Stock | — |
| | — |
| | 1 |
| | 1 |
|
| Net Income (Loss) After Dividends on Preferred Stock | $ | 40 |
| | $ | 26 |
| | $ | (2,034 | ) | | $ | 39 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) |
| Net Income (Loss) | $ | 40 |
| | $ | 26 |
| | $ | (2,033 | ) | | $ | 40 |
|
| Other comprehensive income (loss) |
| |
| |
| |
|
| Qualifying hedges: | | | | | | | |
| Changes in fair value, net of tax of $-, $-, $-, and $-, respectively | (1 | ) | | — |
| | — |
| | (1 | ) |
Reclassification adjustment for amounts included in net
income, net of tax of $-, $-, $-, and $-, respectively | — |
| | — |
| | 1 |
| | 1 |
|
| Total other comprehensive income (loss) | (1 | ) | | — |
| | 1 |
| | — |
|
| Comprehensive Income (Loss) | $ | 39 |
| | $ | 26 |
| | $ | (2,032 | ) | | $ | 40 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED) |
| | | | | | | |
| | For the Nine Months Ended September 30, |
| | 2017 | | 2016 |
| | (in millions) |
| Operating Activities: | | | |
| Net income (loss) | $ | (2,033 | ) | | $ | 40 |
|
| Adjustments to reconcile net income (loss) to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 144 |
| | 115 |
|
| Deferred income taxes | (1,159 | ) | | 34 |
|
| Allowance for equity funds used during construction | (72 | ) | | (90 | ) |
| Estimated loss on Kemper IGCC | 3,148 |
| | 222 |
|
| Other, net | (26 | ) | | (1 | ) |
| Changes in certain current assets and liabilities — | | | |
| -Receivables | 438 |
| | 3 |
|
| -Fossil fuel stock | 21 |
| | 8 |
|
| -Other current assets | (9 | ) | | 34 |
|
| -Accounts payable | (21 | ) | | 5 |
|
| -Accrued taxes | 20 |
| | 96 |
|
| -Accrued compensation | (12 | ) | | (5 | ) |
| -Over recovered regulatory clause revenues | (47 | ) | | (20 | ) |
| -Customer liability associated with Kemper refunds | — |
| | (73 | ) |
| -Other current liabilities | (31 | ) | | 5 |
|
| Net cash provided from operating activities | 361 |
| | 373 |
|
| Investing Activities: | | | |
| Property additions | (411 | ) | | (592 | ) |
| Construction payables | (47 | ) | | (25 | ) |
| Government grant proceeds | — |
| | 137 |
|
| Other investing activities | (25 | ) | | (29 | ) |
| Net cash used for investing activities | (483 | ) | | (509 | ) |
| Financing Activities: | | | |
| Decrease in notes payable, net | (23 | ) | | — |
|
| Proceeds — | | | |
| Capital contributions from parent company | 1,002 |
| | 227 |
|
| Long-term debt to parent company | 40 |
| | 200 |
|
| Other long-term debt | — |
| | 900 |
|
| Short-term borrowings | 113 |
| | — |
|
| Redemptions — | | | |
| Short-term borrowings | (109 | ) | | (475 | ) |
| Long-term debt to parent company | (591 | ) | | (225 | ) |
| Other long-term debt | (300 | ) | | (425 | ) |
| Other financing activities | (3 | ) | | (5 | ) |
| Net cash provided from financing activities | 129 |
| | 197 |
|
| Net Change in Cash and Cash Equivalents | 7 |
| | 61 |
|
| Cash and Cash Equivalents at Beginning of Period | 224 |
| | 98 |
|
| Cash and Cash Equivalents at End of Period | $ | 231 |
| | $ | 159 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
Interest (paid $73 and $72, net of $28 and $36 capitalized for 2017
and 2016, respectively) | $ | 45 |
| | $ | 36 |
|
| Income taxes, net | (209 | ) | | (231 | ) |
| Noncash transactions — Accrued property additions at end of period | 32 |
| | 80 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At September 30, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 231 |
| | $ | 224 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 38 |
| | 29 |
|
| Unbilled revenues | | 41 |
| | 42 |
|
| Income taxes receivable, current | | 102 |
| | 544 |
|
| Other accounts and notes receivable | | 15 |
| | 14 |
|
| Affiliated | | 15 |
| | 15 |
|
| Fossil fuel stock | | 20 |
| | 100 |
|
| Materials and supplies | | 45 |
| | 76 |
|
| Other regulatory assets, current | | 113 |
| | 115 |
|
| Other current assets | | 8 |
| | 8 |
|
| Total current assets | | 628 |
| | 1,167 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 4,836 |
| | 4,865 |
|
| Less: Accumulated provision for depreciation | | 1,312 |
| | 1,289 |
|
| Plant in service, net of depreciation | | 3,524 |
| | 3,576 |
|
| Construction work in progress | | 75 |
| | 2,545 |
|
| Total property, plant, and equipment | | 3,599 |
| | 6,121 |
|
| Other Property and Investments | | 28 |
| | 12 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 62 |
| | 361 |
|
| Other regulatory assets, deferred | | 436 |
| | 518 |
|
| Accumulated deferred income taxes | | 279 |
| | — |
|
| Other deferred charges and assets | | 23 |
| | 56 |
|
| Total deferred charges and other assets | | 800 |
| | 935 |
|
| Total Assets | | $ | 5,055 |
| | $ | 8,235 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholder's Equity | | At September 30, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year — | | | | |
| Parent | | $ | — |
| | $ | 551 |
|
| Other | | 1,028 |
| | 78 |
|
| Notes payable | | 4 |
| | 23 |
|
| Accounts payable — | | | | |
| Affiliated | | 56 |
| | 62 |
|
| Other | | 82 |
| | 135 |
|
| Customer deposits | | 16 |
| | 16 |
|
| Accrued taxes | | 78 |
| | 99 |
|
| Unrecognized tax benefits | | 2 |
| | 383 |
|
| Accrued interest | | 16 |
| | 46 |
|
| Accrued compensation | | 29 |
| | 42 |
|
| Asset retirement obligations, current | | 15 |
| | 32 |
|
| Over recovered fuel clause liabilities | | 4 |
| | 51 |
|
| Other current liabilities | | 67 |
| | 20 |
|
| Total current liabilities | | 1,397 |
| | 1,538 |
|
| Long-term Debt | | 1,167 |
| | 2,424 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | — |
| | 756 |
|
| Employee benefit obligations | | 109 |
| | 115 |
|
| Asset retirement obligations, deferred | | 150 |
| | 146 |
|
| Other cost of removal obligations | | 175 |
| | 170 |
|
| Other regulatory liabilities, deferred | | 87 |
| | 84 |
|
| Other deferred credits and liabilities | | 23 |
| | 26 |
|
| Total deferred credits and other liabilities | | 544 |
| | 1,297 |
|
| Total Liabilities | | 3,108 |
| | 5,259 |
|
| Redeemable Preferred Stock | | 33 |
| | 33 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, without par value — | | | | |
| Authorized — 1,130,000 shares | | | | |
| Outstanding — 1,121,000 shares | | 38 |
| | 38 |
|
| Paid-in capital | | 4,529 |
| | 3,525 |
|
| Accumulated deficit | | (2,650 | ) | | (616 | ) |
| Accumulated other comprehensive loss | | (3 | ) | | (4 | ) |
| Total common stockholder's equity | | 1,914 |
| | 2,943 |
|
| Total Liabilities and Stockholder's Equity | | $ | 5,055 |
| | $ | 8,235 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRD QUARTER 2017 vs. THIRD QUARTER 2016
AND
YEAR-TO-DATE 2017 vs. YEAR-TO-DATE 2016
OVERVIEW
Mississippi Power operates as a vertically integrated utility providing electric service to retail customers within its traditional service territory located within the State of Mississippi and to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of Mississippi Power's business of providing electric service. These factors include Mississippi Power's ability to maintain and grow energy sales and to operate in a constructive regulatory environment that provides timely recovery of prudently-incurred costs. These costs include those related to the Kemper County energy facility, projected long-term demand growth, reliability, fuel, and stringent environmental standards, as well as ongoing capital expenditures required for maintenance and restoration following major storms. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Mississippi Power for the foreseeable future.
The Kemper IGCC was approved by the Mississippi PSC in the 2010 CPCN proceedings, subject to a construction cost cap of $2.88 billion, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (Initial DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (construction cost increase demonstrated to produce efficiencies that result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions). The combined cycle and associated common facilities portion of the Kemper IGCC were placed in service in August 2014.
In December 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order), based on a stipulation (2015 Stipulation) between Mississippi Power and the Mississippi Public Utilities Staff (MPUS), authorizing rates that provide for the recovery of approximately $126 million annually related to the combined cycle and associated common facilities portion of Kemper IGCC assets previously placed in service. As required by the In-Service Asset Rate Order, on June 5, 2017, Mississippi Power made a rate filing requesting to adjust the amortization schedules of the regulatory assets reviewed and determined prudent in a manner that would not change customer rates or annual revenues. On June 28, 2017, the Mississippi PSC suspended this filing. On July 6, 2017, the Mississippi PSC issued an order requiring Mississippi Power to establish a regulatory liability account to maintain current rates related to the Kemper IGCC following the July 2017 completion of the amortization period for certain regulatory assets approved in the In-Service Asset Rate Order that would allow for subsequent refund if the Mississippi PSC deems the rates unjust and unreasonable. At September 30, 2017, the related regulatory liability totaled $7 million.
The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO2, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast has decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations has increased significantly since certification.
On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC (Kemper Settlement Order). The Kemper Settlement Order established a new docket for the purposes of pursuing a global
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
settlement of costs of the Kemper IGCC (Kemper IGCC Settlement Docket). The Mississippi PSC requested any such proposed settlement agreement reflect: (i) at a minimum, no rate increase to Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and related assets; and (iii) modification or amendment of the CPCN for the Kemper IGCC to allow only for ownership and operation of a natural gas facility.
On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014. At the time of project suspension, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in additional grants from the DOE received on April 8, 2016 (Additional DOE Grants).
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred.
Total pre-tax charges to income for the estimated probable losses on the Kemper IGCC were $34 million ($21 million after tax) for the third quarter 2017 and $3.2 billion ($2.2 billion after tax) for the nine months ended September 30, 2017. In the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $6.0 billion ($4.0 billion after tax) through September 30, 2017.
Mississippi Power reached and filed a settlement agreement on August 21, 2017 with certain parties (not including the MPUS), which it believes met the conditions of the Kemper Settlement Order. The settlement agreement provides for an annual revenue requirement of $126 million for Kemper IGCC-related costs, which would (i) be effective January 1, 2018, (ii) represent no rate increase for customers, and (iii) include no recovery for the costs associated with the gasifier portion of the Kemper IGCC in 2018 or at any future date. In addition, under the settlement agreement, the CPCN for the Kemper IGCC would be modified to limit the Kemper County energy facility to natural gas combined cycle operation and Mississippi Power would, in the future, file a reserve margin plan with the Mississippi PSC. The Mississippi PSC issued a scheduling order, as amended on October 5, 2017, noting Mississippi Power and the MPUS had failed to reach a joint stipulation and ordering a full hearing. The Mississippi PSC is expected to rule on an order resolving this matter in January 2018.
As of September 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which $0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility, as well as the 15% that was previously contracted to Cooperative Energy. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For additional information on the Kemper IGCC, including information on the project economic viability analysis, pending lawsuits, and an ongoing SEC investigation, see Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and "Other Matters" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein.
In June 2017, Southern Company made equity contributions totaling $1.0 billion to Mississippi Power. Mississippi Power used a portion of the proceeds to (i) prepay $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan; (ii) repay $591 million of the outstanding principal amount of promissory notes to Southern Company; and (iii) repay $10 million of the outstanding principal amount of bank loans.
Mississippi Power's financial statement presentation contemplates continuation of Mississippi Power as a going concern as a result of Southern Company's anticipated ongoing financial support of Mississippi Power. For additional information, see Notes 1 and 6 to the financial statements of Mississippi Power under "Recently Issued Accounting Standards" and "Going Concern," respectively, in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Going Concern" herein.
In addition to the rate recovery of the Kemper County energy facility, Mississippi Power continues to focus on several key performance indicators. In recognition that Mississippi Power's long-term financial success is dependent upon how well it satisfies its customers' needs, Mississippi Power's retail base rate mechanism, PEP, includes performance indicators that directly tie customer service indicators to Mississippi Power's allowed ROE. Mississippi Power also focuses on broader measures of customer satisfaction, plant availability, system reliability, and net income after dividends on preferred stock.
RESULTS OF OPERATIONS
Net Income (Loss)
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $14 | | 53.8 | | $(2,073) | | N/M |
N/M - Not meaningful
Mississippi Power's net income after dividends on preferred stock for the third quarter 2017 was $40 million compared to $26 million for the corresponding period in 2016. The increase was due to lower pre-tax charges associated with the Kemper IGCC and a decrease in interest expense, net of amounts capitalized, partially offset by an increase in income taxes and decreases in retail revenues and AFUDC equity.
Mississippi Power's net loss after dividends on preferred stock for year-to-date 2017 was $2.03 billion compared to net income of $39 million for the corresponding period in 2016. The decrease in net income was related to higher pre-tax charges associated with the Kemper IGCC.
See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Retail Revenues
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(20) | | (7.6) | | $13 | | 2.0 |
In the third quarter 2017, retail revenues were $243 million compared to $263 million for the corresponding period in 2016. For year-to-date 2017, retail revenues were $665 million compared to $652 million for the corresponding period in 2016.
Details of the changes in retail revenues were as follows:
|
| | | | | | | | | | | | | |
| | Third Quarter 2017 | | Year-to-Date 2017 |
| | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | $ | 263 |
| | | | $ | 652 |
| | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | (10 | ) | | (3.8 | ) | | 9 |
| | 1.4 |
|
| Sales growth | 1 |
| | 0.4 |
| | 4 |
| | 0.6 |
|
| Weather | (9 | ) | | (3.4 | ) | | (16 | ) | | (2.5 | ) |
| Fuel and other cost recovery | (2 | ) | | (0.8 | ) | | 16 |
| | 2.5 |
|
| Retail – current year | $ | 243 |
| | (7.6 | )% | | $ | 665 |
| | 2.0 | % |
Revenues associated with changes in rates and pricing decreased in the third quarter 2017 when compared to the corresponding period in 2016 primarily due to recognition of a regulatory liability as directed by the Mississippi PSC in a July 6, 2017 order following full amortization of certain regulatory assets and an ECO Plan rate decrease implemented in the second quarter 2017.
Revenues associated with changes in rates and pricing increased in year-to-date 2017 when compared to the corresponding period in 2016 primarily due to an ECO Plan rate increase implemented in the third quarter 2016, partially offset by the recognition of a regulatory liability as directed by the Mississippi PSC in a July 6, 2017 order following full amortization of certain regulatory assets and an ECO Plan rate decrease implemented in the second quarter 2017.
See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Mississippi Power – Environmental Compliance Overview Plan" and "Integrated Coal Gasification Combined Cycle" herein for additional information.
Revenues attributable to changes in sales increased slightly for the third quarter 2017 when compared to the corresponding period in 2016. Weather-adjusted KWH sales to residential customers increased 2.9% due to higher customer usage. Weather-adjusted KWH sales to commercial customers decreased 1.2% due to lower customer usage, partially offset by customer growth. KWH sales to industrial customers decreased 2.4% primarily due to an unplanned outage by a large customer in 2017, the impacts of Hurricane Harvey on petroleum pipeline customers, and a decrease in the number of mid-size customers.
Revenues attributable to changes in sales increased slightly for year-to-date 2017 when compared to the corresponding period in 2016. Weather-adjusted KWH sales to residential customers increased 0.8% due to higher customer usage. Weather-adjusted KWH sales to commercial customers decreased 0.7% due to lower customer usage, partially offset by customer growth. KWH sales to industrial customers decreased 1.1% primarily due to unplanned outages by a large customer in 2017, the impacts of Hurricane Harvey on petroleum pipeline customers, and a decrease in the number of mid-size customers.
Fuel and other cost recovery revenues decreased in the third quarter 2017 when compared to the corresponding period in 2016 primarily as a result of lower recoverable fuel costs. Fuel and other cost recovery revenues increased
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
for year-to-date 2017 when compared to the corresponding period in 2016 primarily as a result of higher recoverable fuel costs. See "Fuel and Purchased Power Expenses" herein for additional information. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power's service territory. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income.
Wholesale Revenues – Affiliates
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $14 | | N/M | | $17 | | 73.9 |
N/M - Not meaningful
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.
In the third quarter 2017, wholesale revenues from sales to affiliates were $21 million compared to $7 million for the corresponding period in 2016. The increase was due to a $13 million increase in KWH sales as a result of supporting Southern Company system transmission reliability and a $1 million increase primarily due to higher natural gas prices.
For year-to-date 2017, wholesale revenues from sales to affiliates were $40 million compared to $23 million for the corresponding period in 2016. The increase was primarily due to higher KWH sales as a result of supporting Southern Company system transmission reliability and higher natural gas prices.
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | |
| | Third Quarter 2017
vs.
Third Quarter 2016 | | Year-to-Date 2017
vs.
Year-to-Date 2016 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | 8 |
| | 7.1 | | $ | 33 |
| | 12.3 |
| Purchased power – non-affiliates | 1 |
| | 33.3 | | 3 |
| | 75.0 |
| Purchased power – affiliates | (3 | ) | | (60.0) | | (1 | ) | | (7.1) |
| Total fuel and purchased power expenses | $ | 6 |
| | | | $ | 35 |
| | |
In the third quarter 2017, total fuel and purchased power expenses were $126 million compared to $120 million for the corresponding period in 2016. The increase was due to a $6 million increase in the volume of KWHs generated and purchased.
For year-to-date 2017, total fuel and purchased power expenses were $321 million compared to $286 million for the corresponding period in 2016. The increase was primarily due to a $42 million increase in the average cost of natural gas and purchased power, partially offset by a $4 million decrease in coal prices and a $3 million decrease in the volume of KWHs generated and purchased.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Mississippi Power's fuel cost recovery clause.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of Mississippi Power's generation and purchased power were as follows:
|
| | | | | | | |
| | Third Quarter 2017 | | Third Quarter 2016 | | Year-to-Date 2017 | | Year-to-Date 2016 |
Total generation (in millions of KWHs) | 4,453 | | 4,255 | | 11,542 | | 11,570 |
Total purchased power (in millions of KWHs)(*) | 164 | | 288 | | 527 | | 877 |
Sources of generation (percent) – | | | | | | | |
| Coal | 8 | | 10 | | 8 | | 9 |
| Gas | 92 | | 90 | | 92 | | 91 |
Cost of fuel, generated (in cents per net KWH) – | | | | | | | |
| Coal | 3.80 | | 4.02 | | 3.60 | | 4.09 |
| Gas | 2.77 | | 2.64 | | 2.72 | | 2.34 |
Average cost of fuel, generated (in cents per net KWH) | 2.86 | | 2.79 | | 2.80 | | 2.50 |
Average cost of purchased power (in cents per net KWH)(*) | 3.74 | | 2.59 | | 3.78 | | 2.04 |
| |
(*) | Includes energy produced during the test period for the Kemper IGCC, which is accounted for in accordance with FERC guidance. |
Fuel
In the third quarter 2017, total fuel expense was $120 million compared to $112 million for the corresponding period in 2016. The increase was due to a 2.5% increase in the average cost of fuel per KWH generated, primarily due to a 4.5% higher cost of natural gas, and a 5.4% increase in the volume of KWHs generated.
For year-to-date 2017, total fuel expense was $301 million compared to $268 million for the corresponding period in 2016. The increase was due to a 12.0% increase in the average cost of fuel per KWH generated primarily due to a 16.2% higher cost of natural gas.
Purchased Power
Energy purchases will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation. Energy purchases from affiliates are made in accordance with the IIC, as approved by the FERC.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(8) | | (10.8) | | $(5) | | (2.4) |
In the third quarter 2017, other operations and maintenance expenses were $66 million compared to $74 million for the corresponding period in 2016. The decrease was primarily due to a $5 million decrease in transmission and distribution expenses related to overhead line maintenance and a $4 million decrease related to decreases in employee compensation and benefits and corporate advertising.
For year-to-date 2017, other operations and maintenance expenses were $206 million compared to $211 million for the corresponding period in 2016. The decrease was primarily due to a $6 million decrease in transmission and distribution expenses related to overhead line maintenance and a $5 million decrease related to decreases in employee compensation and benefits and corporate advertising, partially offset by a $5 million increase associated with the Kemper IGCC in-service assets.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Rate Case" herein for additional information.
Depreciation and Amortization
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $9 | | 30.0 | | $6 | | 5.3 |
In the third quarter 2017, depreciation and amortization was $39 million compared to $30 million for the corresponding period in 2016. The increase was primarily related to $6 million in amortization and deferrals associated with regulatory assets and liabilities and $3 million in depreciation related to additional plant in service.
For year-to-date 2017, depreciation and amortization was $120 million compared to $114 million for the corresponding period in 2016. The increase was primarily related to $5 million in depreciation related to additional plant in service.
See Note 1 to the financial statements of Mississippi Power under "Depreciation, Depletion, and Amortization" in Item 8 of the Form 10-K.
Taxes Other Than Income Taxes
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(6) | | (19.4) | | $(4) | | (4.9) |
In the third quarter 2017, taxes other than income taxes were $25 million compared to $31 million for the corresponding period in 2016. For year-to-date 2017, taxes other than income taxes were $77 million compared to $81 million for the corresponding period in 2016. These decreases were primarily due to a decrease in franchise taxes of $5 million and $4 million for the third quarter and year-to-date 2017, respectively, as well as a decrease in payroll taxes of $1 million for the third quarter 2017.
Estimated Loss on Kemper IGCC
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(54) | | (61.4) | | $2,933 | | N/M |
N/M - Not meaningful
Estimated probable losses on the Kemper IGCC of $34 million and $3.2 billion were recorded in the third quarter and year-to-date 2017, respectively, compared to $88 million and $222 million in the third quarter and year-to-date 2016, respectively. While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable. As a result, Mississippi Power suspended the project on June 28, 2017, and recorded $34 million and $2.9 billion of additional charges to income in the third quarter and year-to-date 2017, respectively, for the estimated costs associated with the gasification portions of the plant and lignite mine.
Prior to the project's suspension, Mississippi Power recorded losses for revisions of estimated costs expected to be incurred on construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of the Initial DOE Grants and excluding the Cost Cap Exceptions.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Allowance for Equity Funds Used During Construction
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(30) | | (96.8) | | $(18) | | (20.0) |
In the third quarter 2017, AFUDC equity was $1 million compared to $31 million for the corresponding period in 2016. For year-to-date 2017, AFUDC equity was $72 million compared to $90 million for the corresponding period in 2016. The decreases resulted from the Kemper IGCC project suspension in June 2017.
See Note 3 to the financial statements of Mississippi Power under "FERC Matters" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "FERC Matters" and "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the Kemper IGCC.
Interest Expense, Net of Amounts Capitalized
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(28) | | N/M | | $(23) | | 50.0 |
N/M - Not meaningful
In the third quarter 2017, interest expense, net of amounts capitalized was $(13) million compared to $15 million for the corresponding period in 2016. The decrease was primarily associated with a $33 million net reduction in interest following a settlement with the IRS related to research and experimental (R&E) deductions. Also contributing to the decrease was a $4 million decrease in interest related to long-term debt. These decreases were partially offset by an $11 million reduction in interest capitalized following suspension of the Kemper IGCC construction.
For year-to-date 2017, interest expense, net of amounts capitalized was $23 million compared to $46 million for the corresponding period in 2016. The decrease was primarily associated with a $33 million net reduction in interest following a settlement with the IRS related to R&E deductions. Also contributing to the decrease was a $2 million decrease in interest related to short-term debt and a $1 million decrease in interest related to long-term debt. These decreases were partially offset by an $8 million reduction in interest capitalized following suspension of the Kemper IGCC construction and the amortization of $7 million in interest deferrals in accordance with the In-Service Asset Rate Order.
See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Income Taxes (Benefit)
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $26 | | N/M | | $(856) | | N/M |
N/M - Not meaningful
In the third quarter 2017, income taxes were $24 million compared to an income tax benefit of $2 million for the corresponding period in 2016. For year-to-date 2017, income tax benefit was $885 million compared to $29 million
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
for the corresponding period in 2016. The changes were primarily due to the estimated probable losses on the Kemper IGCC, net of the non-deductible AFUDC equity portionRule and the related state valuation allowances.
See Note (G) to the Condensed Financial Statements herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Mississippi Power's future earnings potential. The level of Mississippi Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Mississippi Power's business of providing electric service. These factors include Mississippi Power's ability to recover its prudently-incurred costs, including those related to the remainder of the Kemper County energy facility not included in current rates, in a timely manner during a time of increasing costs and its ability to prevail against legal challenges associated with the Kemper County energy facility. Future earnings will be driven primarily by customer growth. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions. Earnings are subject to a variety of other factors. These factors include weather, competition, developing new and maintaining existing energy contracts and associated load requirements with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Mississippi Power's service territory. Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings.
On October 4, 2017, Mississippi Power executed agreements with its largest retail customer, Chevron Products Company (Chevron), to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038, subject to the approval of the Mississippi PSC. The new agreements are not expected to have a material impact on Mississippi Power's earnings; however, the co-generation assets located at the refinery are expected to be accounted for as a sales-type lease in accordance with the new lease accounting rules that become effective in 2019. These assets are also subject to a security interest granted to Chevron. See FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein for additional information.rule. The ultimate outcome of this matter cannot be determined at this time.
Current proposals related
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 potential federal tax reform legislation are primarily focusedmunicipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state law claims. This case has been ruled upon and appealed numerous times over the last several years. In 2019, the Georgia PSC issued an order that found Georgia Power has appropriately implemented the municipal franchise fee schedule. In March 2021, the Superior Court of Fulton County granted class certification and Georgia Power's motion for summary judgment and the plaintiffs filed a notice of appeal. In April 2021, Georgia Power filed a notice of cross appeal on reducing the corporate income tax rate, allowing 100%issue of capital expendituresclass certification. In December 2021, the Georgia Court of Appeals affirmed the Superior Court's ruling that granted summary judgment to be deducted,Georgia Power and eliminatingdismissed Georgia Power's cross appeal on the interest deduction.issue of class certification as moot. Also in December 2021, the plaintiffs filed a petition for writ of certiorari to the Georgia Supreme Court. The ultimate impactamount of any tax reform proposals is dependent on the final form of any legislation enacted and the related transition rules andpossible losses cannot be determinedestimated at this time because, among other factors, it is unknown whether any losses would be subject to recovery from any municipalities.
In July 2020, a group of individual plaintiffs filed a complaint in the Superior Court of Fulton County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater, surface water, and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages, a medical monitoring fund, and injunctive relief. Georgia Power has filed multiple motions to dismiss the complaint. In October 2021, three additional complaints were filed in the Superior Court of Monroe County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages. In November 2021, Georgia Power filed a notice to remove the three cases pending in the Superior Court of Monroe County, Georgia to the U.S. District Court for the Middle District of Georgia. On February 7, 2022, four additional complaints were filed in the Superior Court of Monroe County, Georgia against Georgia Power seeking damages for alleged personal injuries or property damage. On March 9, 2022, Georgia Power filed a notice to remove the four cases pending in the Superior Court of Monroe County, Georgia to the U.S. District Court for the Middle District of Georgia. The amount of any possible losses from these matters cannot be estimated at this time.
Mississippi Power
In 2018, Ray C. Turnage and 10 other individual plaintiffs filed a putative class action complaint against Mississippi Power and the three then-serving members of the Mississippi PSC in the U.S. District Court for the Southern District of Mississippi, which was amended in March 2019 to include four additional plaintiffs. 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 and make claims for gross negligence, reckless conduct, and intentional wrongdoing. 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. The district court dismissed the amended complaint; however, in March 2020, the plaintiffs filed a motion seeking to name the new members of the Mississippi PSC, the Mississippi Development Authority, and Southern Company as additional defendants and add a cause of action against all defendants based on a dormant commerce clause theory under the U.S. Constitution. In July 2020, the plaintiffs filed a motion for leave to file a third amended complaint, which included the same federal claims as the proposed second amended complaint, as well as several
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
additional state law claims based on the allegation that Mississippi Power failed to disclose the annual percentage rate of interest applicable to refunds. In November 2020, the district court denied each of the plaintiffs' pending motions and entered final judgment in favor of Mississippi Power. In January 2021, the district court denied further motions by the plaintiffs to vacate the judgment and to file a revised second amended complaint. In February 2021, the plaintiffs filed a notice of appeal with the U.S. Court of Appeals for the Fifth Circuit. On March 21, 2022, the U.S. Court of Appeals for the Fifth Circuit issued an opinion affirming the dismissal of the claims against the Mississippi PSC defendants but reversing the dismissal of the claims against Mississippi Power. On May 31, 2022, the U.S. Court of Appeals for the Fifth Circuit denied a petition by Mississippi Power for a rehearing en banc and remanded the case to the U.S. District Court for the Southern District of Mississippi for further proceedings. On June 17, 2022, Mississippi Power filed with the trial court a motion to dismiss the complaint. An adverse outcome in this proceeding could have a material impact on Mississippi Power's financial statements.
For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Mississippi Power in Item 7 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Environmental MattersRemediation
Compliance costs related to federal and stateThe Southern Company system must comply with environmental statuteslaws and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis or through long-term wholesale agreements. Environmental compliance spending overgoverning the next several years may differ materially from the amounts estimated. The timing, specific requirements,handling and estimated costs could change as environmental statutesdisposal of waste and releases of hazardous substances. Under these various laws and regulations, are adopted or modified, as compliance plans are revised or updated, and as legal challengesthe Southern Company system could incur substantial costs to rules are completed. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Mississippi
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Statutes and Regulations
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the final effluent guidelines ruleclean up affected sites. The traditional electric operating companies and the final rule revisingnatural 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 remediation 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 definition of waters of the U.S. for all Clean Water Act (CWA) programs.agencies.
On April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. OnGeorgia Power's environmental remediation liability was $16 million and $17 million at September 18, 2017, the EPA published a final rule establishing a stay of the compliance deadlines for certain effluent limitations30, 2022 and pretreatment standards under the rule.
On June 27, 2017, the EPA and the U.S. Army Corps of Engineers proposed to rescind the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final ruleDecember 31, 2021, respectively. Georgia Power has been stayed since October 2015designated or identified as a potentially responsible party at sites governed by the U.S. CourtGeorgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of Appeals forsuch sites is expected.
Southern Company Gas' environmental remediation liability was $270 million and $249 million at September 30, 2022 and December 31, 2021, respectively, based on the Sixth Circuit.estimated cost of environmental investigation and remediation associated with known former manufactured gas plant operating sites.
The ultimate outcome of these matters cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Mississippi Power in Item 7time; however, as a result of the Form 10-Kregulatory treatment for additional information.
On March 28, 2017,environmental remediation expenses described above, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules. On October 16, 2017, the EPA published a proposed rule to repeal the Clean Power Plan. The EPA has not determined whether or when it will promulgate a replacement rule.
On June 1, 2017, the U.S. President announced that the United States will withdraw from the non-binding Paris Agreement and begin renegotiation of its terms.
The ultimate outcomedisposition of these matters cannot be determined at this time.
FERC Matters
Municipal and Rural Associations Tariff
See Note 3is not expected to have a material impact on the financial statements of Mississippi Power under "FERC Matters" in Item 8 of the Form 10-K for additional information regarding a settlement agreement entered into by Mississippi Power regarding the establishment of a regulatory asset for Kemper IGCC-related costs. See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for information regarding the Kemper IGCC.
In March 2016, Mississippi Power reached a settlement agreement with its wholesale customers, which was subsequently approved by the FERC, for an increase in wholesale base revenues under the MRA cost-based electric tariff, primarily as a result of placing scrubbers for Plant Daniel Units 1 and 2 in service in 2015. The settlement agreement became effective for services rendered beginning May 1, 2016, resulting in an estimated annual revenue increase of $7 million under the MRA cost-based electric tariff. Additionally, under the settlement agreement, the tariff customers agreed to similar regulatory treatment for MRA tariff ratemaking as the treatment approved for retail ratemaking under the In-Service Asset Rate Order. This regulatory treatment primarily includes (i) recovery of the Kemper IGCC assets currently operational and providing service to customers and other related costs, (ii)
applicable Registrants.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Fuel Cost Recovery
Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At September 30, 2017, the amount of over-recovered wholesale MRA fuel costs included in the balance sheets was $3 million compared to $13 million at December 31, 2016. Over-recovered wholesale MB fuel costs included in the balance sheets were immaterial at September 30, 2017 and December 31, 2016.NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
See Note 3 to the financial statements of Mississippi Power under "FERC Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.
Market-Based Rate Authority
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters – Market-Based Rate Authority" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the traditional electric operating companies' and Southern Power's market power proceeding and amendment to their market-rate tariff.
On May 17, 2017, the FERC accepted the traditional electric operating companies' (including Mississippi Power's) and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies (including Mississippi Power) and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' (including Mississippi Power's) and Southern Power's market power proceeding related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including Mississippi Power's) and Southern Power's June 30, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including Mississippi Power) and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order, or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including Mississippi Power) and Southern Power expect to make a filing within the specified 60 days responding to the FERC's order.
The ultimate outcome of these matters cannot be determined at this time.
Cooperative Energy Shared Service Agreement and PPA
Mississippi Power provides electricity to a municipality and various rural electric cooperative associations located in southeastern Mississippi, including Cooperative Energy. These generation services are provided under long-term contracts subject to a cost-based, FERC regulated MRA electric tariff and a long-term market-based wholesale contract.
On September 18, 2017, Mississippi Power and Cooperative Energy executed a Shared Service Agreement (SSA), as part of the MRA tariff, under which Mississippi Power and Cooperative Energy will share in providing electricity to all Cooperative Energy delivery points, in lieu of the current arrangement under which each delivery point is specifically assigned to either entity. The SSA becomes effective on January 1, 2018, subject to the FERC's acceptance, and may be cancelled by Cooperative Energy with 10 years notice after December 31, 2021.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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The SSA provides Cooperative Energy the option to decrease its use of Mississippi Power's generation services under the MRA tariff, subject to annual and cumulative caps and a one-year notice requirement. In the event Cooperative Energy elects to reduce these services, the related reduction in Mississippi Power's revenues is not expected to be significant through 2020.
In 2008, Mississippi Power entered into a 10-year Power Supply Agreement (PSA) with Cooperative Energy for approximately 152 MWs, which became effective in 2011. Following certain plant retirements, the current PSA capacity is 86 MWs. On September 28, 2017, Mississippi Power and Cooperative Energy executed an amendment to the PSA effective October 1, 2017, increasing the capacity to 286 MWs under the PSA.
Cooperative Energy also has a 10-year Network Integration Transmission Service Agreement (NITSA) with SCS for transmission service to certain delivery points on the Mississippi Power transmission system that became effective in 2011. As a result of the PSA amendments, Cooperative Energy and SCS are amending the terms of the NITSA to provide for the purchase of incremental transmission capacity for service beginning April 1, 2018. This NITSA amendment remains subject to execution and acceptance by the FERC.
The ultimate outcome of these matters cannot be determined at this time.
Retail Regulatory Matters
Mississippi Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Mississippi PSC. Mississippi Power's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased power, energy efficiency programs, ad valorem taxes, property damage, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are expected to be recovered through Mississippi Power's base rates. See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Mississippi Power" and "Integrated Coal Gasification Combined Cycle" herein for additional information.
Renewables
Mississippi Power placed in service three solar projects in January, June, and October 2017. Mississippi Power may retire the renewable energy credits (REC) generated on behalf of its customers or sell the RECs, separately or bundled with energy, to third parties.
On August 17, 2017, the Mississippi PSC approved Mississippi Power's CPCN for the construction, operation, and maintenance of a 52.5-MW solar energy generating facility, which is expected to be placed in service by January 2020. The ultimate outcome of this matter cannot be determined at this time.
Performance Evaluation Plan
On March 15, 2017, Mississippi Power submitted its annual PEP lookback filing for 2016, which reflected the need for a $5 million surcharge to be recovered from customers. The filing has been suspended for review byJune 7, 2022, the Mississippi PSC.
On November 15, 2017,PSC approved Mississippi Power is expected to make itsPower's annual retail PEP filing for 2018. Retail2022, resulting in an annual increase in revenues of approximately $18 million, or 1.9%, primarily due to increases in rate adjustments underbase, operations and maintenance expenses, and depreciation and amortization. The rate increase became effective with the first billing cycle of April 2022 in accordance with the PEP are limitedrate schedule.
The ultimate outcome of these matters cannot be determined at this time.
Energy EfficiencyNOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Ad Valorem Tax Adjustment
On July 6, 2017,June 7, 2022, the Mississippi PSC issued an order approvingapproved Mississippi Power's Energy Efficiency Cost Rider complianceannual ad valorem tax adjustment filing which increasedfor 2022, resulting in an annual retailincrease in revenues by approximately $2of $5 million, effective with the first billing cycle for August 2017.of July 2022.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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Environmental Compliance Overview PlanMunicipal and Rural Associations Tariff
On May 4, 2017,August 26, 2022, the FERC accepted an amended shared service agreement (SSA) between Mississippi PSC approvedPower and Cooperative Energy, effective July 1, 2022, under which Cooperative Energy will continue to decrease its use of Mississippi Power's ECO Plan filing for 2017, which requestedgeneration services under the maximum 2% annual increase in revenues, approximately $18 million, primarily relatedMRA tariff up to the Plant Daniel Units 1 and 2 scrubbers placed in service in 2015. The rates became effective with the first billing cycle for June 2017. Approximately $26 million of related revenue requirements in excess of the 2% maximum was deferred for inclusion in the 2018 filing.
Fuel Cost Recovery
2.5% annually through 2035. At September 30, 2017, the amount of over-recovered retail fuel costs included on the condensed balance sheet was $2 million compared to $37 million at December 31, 2016.
On November 15, 2017,2022, Mississippi Power is expected to fileserving approximately 400 MWs of Cooperative Energy's annual demand. Beginning in 2036, Cooperative Energy will provide 100% of its annual rate adjustmentelectricity requirements at the MRA delivery points under the retail fuel cost recovery clause.tariff. Neither party has the option to cancel the amended SSA.
On July 15, 2022, Mississippi Power filed a request with the FERC for a $23 million increase in annual wholesale base revenues under the MRA tariff and requested an effective date of July 15, 2022. Cooperative Energy has filed a complaint with the FERC challenging the new rates. On September 13, 2022, the FERC issued an order accepting Mississippi Power's request effective September 14, 2022, subject to refund, and establishing hearing and settlement judge procedures. The ultimate outcome of this matter cannot be determined at this time.
Ad Valorem Tax Adjustment
Southern Company Gas
Infrastructure Replacement Programs and Capital Projects
Capital expenditures incurred under specific infrastructure replacement programs and capital projects during the first nine months of 2022 were as follows:
| | | | | | | | |
| Utility | Program | Nine Months Ended September 30, 2022 |
| | (in millions) |
| Nicor Gas | Investing in Illinois | $ | 311 | |
| Virginia Natural Gas | SAVE | 52 | |
| Atlanta Gas Light | System Reinforcement Rider | 51 | |
| Chattanooga Gas | Pipeline Replacement Program | 2 | |
| Total | | $ | 416 | |
Rate Proceedings
Atlanta Gas Light
On July 6, 2017,1, 2022, Atlanta Gas Light filed its annual GRAM update with the Mississippi PSC approved Mississippi Power'sGeorgia PSC. The filing requests an annual ad valorem tax adjustment factor filing for 2017, which included an annualbase rate increase of 0.85%, or $8$53 million in annual retail revenues, primarily due to increased assessments.
Provision for Property Damage
On October 8, 2017, Hurricane Nate hitbased on the Gulf Coastprojected 12-month period beginning January 1, 2023. Resolution of Mississippi causing minor damage to Mississippi Power's distribution infrastructure. Preliminary storm damage repair costs have been estimated to be immaterial. These costs may be charged to the retail property damage reserve and addressed in a subsequent System Restoration Rider rate filing.GRAM filing is expected by December 28, 2022, with the new rates effective January 1, 2023. The ultimate outcome of this matter cannot be determined at this time.
Integrated Coal Gasification Combined Cycle
See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding Mississippi Power's construction of the Kemper IGCC.
Kemper IGCC Overview
The Kemper IGCC was designed to utilize IGCC technology with an expected output capacity of 582 MWs and to be fueled by locally mined lignite (an abundant, lower heating value coal) fromOn August 1, 2022, Virginia Natural Gas filed a mine owned by Mississippi Power and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connectiongeneral base rate case with the Kemper IGCC, Mississippi Power constructed approximately 61 milesVirginia Commission seeking an increase in annual base rate revenues of CO2 pipeline infrastructure for the transport of captured CO2 for use in enhanced oil recovery.
Kemper IGCC Schedule and Cost Estimate
In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245$69 million, of Initial DOE Grants and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, and AFUDCincluding $15 million related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014.
The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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CO2, and produced sulfuric acid and ammonia, each of acceptable qualityinvestments under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up processSAVE program, primarily to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead timerecover investments and significant cost. In addition, the long-term natural gas price forecast has decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations has increased significantly since certification.
On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC. On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014.
Mississippi Power's Kemper IGCC 2010 project estimate totaled $2.97 billion, which included capped costs of $2.4 billion. At the time of project suspension in June 2017, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants.
Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate above the cost cap for the Kemper IGCC of $196 million ($121 million after tax) in the second quarter through May 31, 2017 and a total of $305 million ($188 million after tax) for year-to-date through May 31, 2017. In the aggregate, Mississippi Power incurred charges of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017. The May 31, 2017 cost estimate included approximately $175 million of estimated costs to be incurred beyond the then-estimated in-service date of June 30, 2017 that were expected to be subject to the $2.88 billion cost cap.
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portionsinfrastructure, technology, and workforce development. The requested increase is based on a projected 12-month period beginning January 1, 2023, a ROE of the plant10.35%, and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional chargeequity ratio of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million53.2%. Rate adjustments are expected to be incurred. In the aggregate, Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC totaling $34 million ($21 million after tax) for the third quarter 2017 and $3.2 billion ($2.2 billion after tax) for the nine months ended September 30, 2017.
As of September 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC. The Kemper combined cycle balances as presented in the condensed balance sheet at September 30, 2017 include $1.1 billion in property, plant, and equipment, net of $80 million in accumulated depreciation; $15 million in materials and supplies; $10 million in other deferred charges and assets; and $113 million in regulatory assets, net of accumulated amortization of $63 million, of which $21 million is included in other regulatory assets, current and $92 million in other regulatory assets, deferred.
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Rate Recovery of Kemper IGCC Costs
Given the variety of potential scenarios and the uncertainty of the outcome of future regulatory proceedings with the Mississippi PSC (and any subsequent related legal challenges), the ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, cannot now be determined but could result in further material charges that could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity.
Kemper IGCC Settlement Docket
On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC. The Kemper Settlement Order established the Kemper IGCC Settlement Docket. The Mississippi PSC requested any such proposed settlement agreement reflect: (i) at a minimum, no rate increase to Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and related assets; and (iii) modification or amendment of the CPCN for the Kemper IGCC to allow only for ownership and operation of a natural gas facility.
On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014. At the time of project suspension, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants.
Mississippi Power reached and filed a settlement agreement on August 21, 2017 with certain parties (not including the MPUS), which it believes met the conditions of the Kemper Settlement Order. The settlement agreement provides for an annual revenue requirement of $126 million for Kemper IGCC-related costs, which would (i) be effective January 1, 2018, (ii) represent no rate increase for customers, and (iii) include no recovery for the costs associated with the gasifier portion of the Kemper IGCC in 2018 or at any future date. In addition, under the settlement agreement, the CPCN for the Kemper IGCC would be modified2023, subject to limit the Kemper County energy facility to natural gas combined cycle operation and Mississippi Power would, in the future, file a reserve margin plan with the Mississippi PSC.refund. The Mississippi PSC issued a scheduling order, as amended on October 5, 2017, noting Mississippi Power and the MPUS had failed to reach a joint stipulation and ordering a full hearing. The Mississippi PSCVirginia Commission is expected to rule on an order resolving this matterthe requested increase in January 2018.
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred.
As of September 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which
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$0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility, as well as the 15% that was previously contracted to Cooperative Energy. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.
Prudence
On August 17, 2016, the Mississippi PSC issued an order establishing a discovery docket to manage all filings related to the prudence of the Kemper IGCC. On October 3, 2016, Mississippi Power made a required compliance filing, which included a review and explanation of differences between the Kemper IGCC project estimate set forth in the 2010 CPCN proceedings and the most recent Kemper IGCC project estimate, as well as comparisons of current cost estimates and current expected plant operational parameters to the estimates presented in the 2010 CPCN proceedings for the first five years after the Kemper IGCC was to be placed in service. Compared to amounts presented in the 2010 CPCN proceedings, operations and maintenance expenses have increased an average of $105 million annually and maintenance capital has increased an average of $44 million annually for the first full five years of operations for the Kemper IGCC. Additionally, while the current estimated operational availability estimates reflect ultimate results similar to those presented in the 2010 CPCN proceedings, the ramp up period for the current estimates reflects a lower starting point and a slower escalation rate. On November 17, 2016, Mississippi Power submitted a supplemental filing to the October 3, 2016 compliance filing to present revised non-fuel operations and maintenance expense projections for the first year after the Kemper IGCC was to be placed in service. This supplemental filing included approximately $68 million in additional estimated operations and maintenance costs expected to be required to support the operations of the Kemper IGCC during that period.
Mississippi Power responded to numerous requests for information from interested parties in the discovery docket, which is now complete. Mississippi Power expects the Mississippi PSC to utilize this information in connection with the ultimate resolution of Kemper IGCC cost recovery.
Economic Viability Analysis
In the fourth quarter 2016, as a part of its Integrated Resource Plan process, the Southern Company system completed its regular annual updated fuel forecast, the 2017 Annual Fuel Forecast. This updated fuel forecast reflected significantly lower long-term estimated costs for natural gas than were previously projected. As a result of the updated long-term natural gas forecast, as well as the revised operating expense projections reflected in the discovery docket filings discussed above, on February 21, 2017, Mississippi Power filed an updated project economic viability analysis of the Kemper IGCC as required under the 2012 MPSC CPCN Order confirming authorization of the Kemper IGCC. The project economic viability analysis measures the life cycle economics of the Kemper IGCC compared to feasible alternatives, natural gas combined cycle generating units, under a variety of scenarios and considering fuel, operating and capital costs, and operating characteristics, as well as federal and state taxes and incentives. The reduction in the projected long-term natural gas prices in the 2017 Annual Fuel Forecast and, to a lesser extent, the increase in the estimated Kemper IGCC operating costs, negatively impact the updated project economic viability analysis.
Mississippi Power expects the Mississippi PSC to address this matter in connection with the Kemper IGCC Settlement Docket.
2015 Rate Case
On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order adopting in full the 2015 Stipulation entered into between Mississippi Power and the MPUS regarding the Kemper IGCC assets that were commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power's actual
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average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The In-Service Asset Rate Order also included a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets. The stipulated revenue requirement excluded the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by Cooperative Energy but reserved Mississippi Power's right to seek recovery in a future proceeding. See "Termination of Proposed Sale of Undivided Interest" herein for additional information.
In 2011, the Mississippi PSC authorized Mississippi Power to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date. In connection with the implementation of the In-Service Asset Order and wholesale rates, Mississippi Power began expensing certain ongoing project costs and certain retail debt carrying costs that previously were deferred and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees. The amortization periods for these regulatory assets vary from two years to 10 years as set forth in the In-Service Asset Rate Order and the settlement agreement with wholesale customers. As of September 30, 2017, the balance associated with these regulatory assets was $113 million, of which $21 million is included in current assets. See "FERC Matters" herein for additional information related to the 2016 settlement agreement with wholesale customers.
The In-Service Asset Rate Order requires Mississippi Power to submit an annual true-up calculation of its actual cost of capital, compared to the stipulated total cost of capital, for the May 31, 2016 and 2017 calculations. At September 30, 2017, Mississippi Power's related regulatory liability totaled approximately $10 million.
As required by the In-Service Asset Rate Order, on June 5, 2017, Mississippi Power made a rate filing requesting to adjust the amortization schedules of the regulatory assets reviewed and determined prudent in the In-Service Asset Order in a manner that would not change customer rates or annual revenues. On June 28, 2017, the Mississippi PSC suspended this filing. On July 6, 2017, the Mississippi PSC issued an order requiring Mississippi Power to establish a regulatory liability account to maintain current rates related to the Kemper IGCC following the July 2017 completion of the amortization period for certain regulatory assets approved in the In-Service Asset Rate Order that would allow for subsequent refund if the Mississippi PSC deems the rates unjust and unreasonable. At September 30, 2017, the related regulatory liability totaled $7 million.
2013 MPSC Rate Order
In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that was intended to establish the process for resolving matters regarding cost recovery related to the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. In March 2013, the Mississippi PSC issued a rate order approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designed to collect $156 million annually beginning in 2014 (2013 MPSC Rate Order) to be used to mitigate customer rate impacts after the Kemper IGCC was placed in service, based on a mirror CWIP methodology (Mirror CWIP rate).
On February 12, 2015, the Mississippi Supreme Court reversed the 2013 MPSC Rate Order and, on July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015 and required the fourth quarter 2015 refund of the $342 million previously collected, along with associated carrying costs of $29 million.
Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continued to record AFUDC on the Kemper IGCC. Between the original May 2014 estimated in-service date and the June 2017 project suspension date, Mississippi Power recorded $494 million of AFUDC on the Kemper IGCC subject to the $2.88 billion cost cap and Cost Cap Exception amounts, of which $460 million related to the gasification portions of the Kemper IGCC.
Mississippi Power expects the Mississippi PSC to address this matter in connection with the Kemper IGCC Settlement Docket.
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Lignite Mine and CO2 Pipeline Facilities
In conjunction with the Kemper IGCC, Mississippi Power owns the lignite mine and equipment and mineral reserves located around the Kemper IGCC site. The mine started commercial operation in June 2013.
In 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is responsible for the mining operations through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. In addition to the obligation to fund the reclamation activities, Mississippi Power provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. During the suspension period, these costs are approximately $2 million per month and are being recognized in income as incurred. See Note 1 to the financial statements of Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" and "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.
In addition, Mississippi Power constructed the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery. Mississippi Power entered into agreements with Denbury Onshore (Denbury) and Treetop Midstream Services, LLC (Treetop), pursuant to which Denbury would purchase 70% of the CO2 captured from the Kemper IGCC and Treetop would purchase 30% of the CO2 captured from the Kemper IGCC. On June 3, 2016, Mississippi Power cancelled its contract with Treetop and amended its contract with Denbury to reflect, among other things, Denbury's agreement to purchase 100% of the CO2 captured from the Kemper IGCC and an initial contract term of 16 years. Denbury has the right to terminate the contract at any time because Mississippi Power did not place the Kemper IGCC in service by July 1, 2017.
The ultimate outcome of these matters cannot be determined at this time.
Termination of Proposed Sale of Undivided Interest
In 2010 and as amended in 2012, Mississippi Power and Cooperative Energy (formerly known as SMEPA) entered into an agreement whereby Cooperative Energy agreed to purchase a 15% undivided interest in the Kemper IGCC. On May 20, 2015, Cooperative Energy notified Mississippi Power of its termination of the agreement. Mississippi Power previously received a total of $275 million of deposits from Cooperative Energy that were required to be returned to Cooperative Energy with interest. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to Cooperative Energy. Subsequently, Mississippi Power issued a promissory note in the aggregate principal amount of approximately $301 million to Southern Company, which was repaid in June 2017.
Litigation
On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff alleges that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper IGCC and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper IGCC; ask the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper IGCC in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper IGCC costs from being charged to customers through electric rates. On June 23, 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the plaintiffs filed notice of an appeal.
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On June 9, 2016, Treetop, Greenleaf CO2 Solutions, LLC (Greenleaf), Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint relates to the cancelled CO2 contract with Treetop and alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and seeks compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS moved to compel arbitration pursuant to the terms of the CO2 contract, which the court granted on May 4, 2017. On June 28, 2017, Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a claim for arbitration requesting $500 million in damages.
Mississippi Power believes these legal challenges have no merit; however, an adverse outcome in these proceedings could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity. Mississippi Power will vigorously defend itself in these matters, and the ultimate outcome of these matters cannot be determined at this time.
Baseload Act
In 2008, the Baseload Act was signed by the Governor of Mississippi. The Baseload Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism that includes in retail base rates, prior to and during construction, all or a portion of the prudently-incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passage of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews by the Mississippi PSC and prohibits the cancellation of any such generating plant without the approval of the Mississippi PSC. In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery or implement credits, refunds, or rebates to customers for costs incurred in connection with such cancelled generating plant.
Income Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Mississippi Power in Item 7 of the Form 10-K and Note (G) to the Condensed Financial Statements under "Section 174 Research and Experimental Deduction" herein for additional information on bonus depreciation, investment tax credits, and the Section 174 research and experimental deduction.
Bonus Depreciation
All projected tax benefits previously received for bonus depreciation related to the Kemper IGCC were repaid in connection with third quarter 2017 estimated tax payments. If the suspension of the Kemper IGCC start-up activities ultimately results in an abandonment for income tax purposes, the related deduction would be claimed in the year of the abandonment. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein and Note (G) to the Condensed Financial Statements herein for additional information.2023. The ultimate outcome of this matter cannot be determined at this time.
Section 174 Research and Experimental Deduction
Southern Company, on behalf of Mississippi Power, has reflected deductions for R&E expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation (JCT), resolving a methodology for these deductions. As a result of the JCT approval, Mississippi Power recognized $176 million of previously unrecognized tax benefits and reversed $36 million of associated accrued interest. See Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Section 174 Research and Experimental Deduction," respectively, herein for additional information.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OFNOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
FINANCIAL CONDITION AND RESULTS OF OPERATIONS(UNAUDITED)
(C) CONTINGENCIES
OtherSee 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
Mississippi Power isThe Registrants are involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Mississippi Power is subject to certain claims and legal actions arising in the ordinary course of business. Mississippi Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation or regulatory matters against each Registrant and any subsidiaries cannot be predicteddetermined at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Mississippi Power'ssuch Registrant's financial statements.
The Registrants believe the pending legal challenges discussed below have no merit; however, the ultimate outcome of these matters cannot be determined at this time.
Southern Company
In 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 named as defendants Southern Company, certain of its directors, certain of its current and former officers, and certain former Mississippi Power officers. In 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints alleged that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints alleged that the defendants were unjustly enriched and caused the waste of corporate assets and also alleged that the individual defendants violated their fiduciary duties.
In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, Georgia that named as defendants Southern Company, certain of its directors, certain of its current and former officers, and certain former Mississippi Power officers. The complaint alleged 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 alleged 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. In August 2019, the court granted a motion filed by the plaintiff in July 2019 to substitute a new named plaintiff, Martin J. Kobuck, in place of Helen E. Piper Survivor's Trust.
The plaintiffs in each of these cases sought 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. The plaintiffs also sought certain changes to Southern Company's corporate governance and internal processes. On January 21, 2022, the plaintiffs in the federal court action filed a motion for preliminary approval of settlement, together with an executed stipulation of settlement, which applied to both actions. On June 9, 2022, the U.S. District Court for the Northern District of Georgia granted final approval of the settlement and, on June 16, 2022, the Superior Court of Gwinnett County, Georgia entered an order awarding attorneys' fees and expenses related to the Martin J. Kobuck lawsuit. The settlement consisted of an aggregate payment by Southern Company's insurers of approximately $4.5 million for attorneys' fees and expenses, as well as adoption of various corporate governance reforms by Southern Company. These matters are now concluded.
Alabama Power
On September 26, 2022, Mobile Baykeeper, through its counsel Southern Environmental Law Center, filed a citizen suit in the U.S. District Court for the Southern District of Alabama alleging that Alabama Power's plan to close the Plant Barry ash pond utilizing a closure-in-place methodology violates the Resource Conservation and Recovery Act (RCRA) and regulations governing CCR. Among other relief requested, Mobile Baykeeper seeks a declaratory judgment that the RCRA and regulations governing CCR are being violated, preliminary and injunctive relief to
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
prevent implementation of Alabama Power's closure plan and the development of a closure plan that satisfies regulations governing CCR requirements. See Note (B)6 to the Condensed Financial Statements hereinfinancial statements in Item 8 of the Form 10-K for a discussion of various other contingencies, regulatory matters,Alabama Power's ARO liabilities related to facilities that are subject to the CCR Rule and other matters being litigated which may affect future earnings potential.
The SEC is conducting a formal investigation of Southern Company and Mississippi Power concerning the estimated costs and expected in-service date of the Kemper IGCC. Southern Company and Mississippi Power believe the investigation is focused primarily on periods subsequent to 2010 and on accounting matters, disclosure controls and procedures, and internal controls over financial reporting associated with the Kemper IGCC. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" herein for additional information on the Kemper IGCC.related state rule. The ultimate outcome of this matter 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 law claims. This case has been ruled upon and appealed numerous times over the last several years. In 2019, the Georgia PSC issued an order that found Georgia Power has appropriately implemented the municipal franchise fee schedule. In March 2021, the Superior Court of Fulton County granted class certification and Georgia Power's motion for summary judgment and the plaintiffs filed a notice of appeal. In April 2021, Georgia Power filed a notice of cross appeal on the issue of class certification. In December 2021, the Georgia Court of Appeals affirmed the Superior Court's ruling that granted summary judgment to Georgia Power and dismissed Georgia Power's cross appeal on the issue of class certification as moot. Also in December 2021, the plaintiffs filed a petition for writ of certiorari to the Georgia Supreme Court. The amount of any possible losses cannot be estimated at this time because, among other factors, it is unknown whether any losses would be subject to recovery from any municipalities.
In July 2020, a group of individual plaintiffs filed a complaint in the Superior Court of Fulton County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater, surface water, and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages, a medical monitoring fund, and injunctive relief. Georgia Power has filed multiple motions to dismiss the complaint. In October 2021, three additional complaints were filed in the Superior Court of Monroe County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages. In November 2021, Georgia Power filed a notice to remove the three cases pending in the Superior Court of Monroe County, Georgia to the U.S. District Court for the Middle District of Georgia. On February 7, 2022, four additional complaints were filed in the Superior Court of Monroe County, Georgia against Georgia Power seeking damages for alleged personal injuries or property damage. On March 9, 2022, Georgia Power filed a notice to remove the four cases pending in the Superior Court of Monroe County, Georgia to the U.S. District Court for the Middle District of Georgia. The amount of any possible losses from these matters cannot be estimated at this time.
Mississippi Power
In 2018, Ray C. Turnage and 10 other individual plaintiffs filed a putative class action complaint against Mississippi Power and the three then-serving members of the Mississippi PSC in the U.S. District Court for the Southern District of Mississippi, which was amended in March 2019 to include four additional plaintiffs. 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 and make claims for gross negligence, reckless conduct, and intentional wrongdoing. 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. The district court dismissed the amended complaint; however, in March 2020, the plaintiffs filed a motion seeking to name the new members of the Mississippi PSC, the Mississippi Development Authority, and Southern Company as additional defendants and add a cause of action against all defendants based on a dormant commerce clause theory under the U.S. Constitution. In July 2020, the plaintiffs filed a motion for leave to file a third amended complaint, which included the same federal claims as the proposed second amended complaint, as well as several
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
additional state law claims based on the allegation that Mississippi Power failed to disclose the annual percentage rate of interest applicable to refunds. In November 2020, the district court denied each of the plaintiffs' pending motions and entered final judgment in favor of Mississippi Power. In January 2021, the district court denied further motions by the plaintiffs to vacate the judgment and to file a revised second amended complaint. In February 2021, the plaintiffs filed a notice of appeal with the U.S. Court of Appeals for the Fifth Circuit. On March 21, 2022, the U.S. Court of Appeals for the Fifth Circuit issued an opinion affirming the dismissal of the claims against the Mississippi PSC defendants but reversing the dismissal of the claims against Mississippi Power. On May 31, 2022, the U.S. Court of Appeals for the Fifth Circuit denied a petition by Mississippi Power for a rehearing en banc and remanded the case to the U.S. District Court for the Southern District of Mississippi for further proceedings. On June 17, 2022, Mississippi Power filed with the trial court a motion to dismiss the complaint. An adverse outcome in this proceeding could have a material impact on Mississippi Power's financial statements.
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 remediation 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 $16 million and $17 million at September 30, 2022 and December 31, 2021, 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 $270 million and $249 million at September 30, 2022 and December 31, 2021, respectively, based on the estimated cost of environmental investigation and remediation associated with known former manufactured gas plant operating sites.
The ultimate outcome of these matters cannot be determined at this time; however, itas 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 Mississippi Power.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Mississippi Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Mississippi Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Mississippi Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Mississippi Power in Item 7 of the Form 10-K for a complete discussion of Mississippi Power's critical accounting policies and estimates related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, AFUDC, Unbilled Revenues, and Contingent Obligations.
Kemper IGCC Rate Recovery
For periods prior to the second quarter 2017, significant accounting estimates included Kemper IGCC estimated construction costs, project completion date, and rate recovery. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Kemper IGCC Estimated Construction Costs, Project Completion Date, and Rate Recovery" of Mississippi Power in Item 7 of the Form 10-K for additional information. Mississippi Power recorded total pre-tax charges to income related to the Kemper IGCC of $428 million ($264 million after tax) in 2016, $365 million ($226 million after tax) in 2015, $868 million ($536 million after tax) in 2014, and $1.2 billion ($729 million after tax) in prior years.
As a result of the Mississippi PSC's June 21, 2017 stated intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant rather than an IGCC plant, as well as Mississippi Power's June 28, 2017 suspension of the operation and start-up of the gasifier portion of the Kemper IGCC, the estimated construction costs and
applicable Registrants.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OFNOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
FINANCIAL CONDITION AND RESULTS OF OPERATIONS(UNAUDITED)
Other Matters
project completion date are no longer considered significant accounting estimates. Significant accounting estimatesMississippi Power
In conjunction with Southern Company's 2019 sale of Gulf Power, NextEra Energy, Inc. held back $75 million of the purchase price pending Mississippi Power and Gulf Power negotiating a mutually acceptable revised operating agreement for Plant Daniel. On July 12, 2022, the co-owners executed a revised operating agreement and Southern Company subsequently received the remaining $75 million of the purchase price. The revised operating agreement contains dispatch procedures for the September 30, 2017 financial statements presented herein includetwo jointly-owned coal units at Plant Daniel such that Mississippi Power will designate one of the overall assessment of rate recovery for the Kemper County energy facilitytwo units as primary and the estimated costs for the potential cancellationother as secondary in lieu of the Kemper IGCC.
While the ultimate dispositioneach company separately owning 100% of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred.
As of September 30, 2017,a single generating unit. Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which $0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimateoption to purchase its co-owner's ownership interest for the combined cycle portion of the facility, as well as the 15%$1 on January 15, 2024, provided that was previously contracted to Cooperative Energy. Mississippi Power has calculatedexercises the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects themoption no later than 120 days prior to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions.that date. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.
In the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $6.00 billion ($3.96 billion after tax) through September 30, 2017. Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $34 million ($21 million after tax) and $88 million ($54 million after tax) in the third quarter 2017 and the third quarter 2016, respectively, and total pre-tax charges of $3.2 billion ($2.2 billion after tax) and $222 million ($137 million after tax) year-to-date in 2017 and 2016, respectively.
Given the significant judgment involved in estimating the costs to cancel the gasifier portion of the Kemper IGCC, the ultimate rate recovery for the Kemper IGCC, including the $0.5 billion of combined cycle-related costs not yet in rates, and the impact on Mississippi Power's results of operations, Mississippi Power considers these items to be critical accounting estimates. See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Recently Issued Accounting Standards
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Mississippi Power in Item 7 of the Form 10-K for additional information.
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
While Mississippi Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Mississippi Power's revenue, including
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs. Mississippi Power expects that the revenue from contracts with these customers will not result in a significant shift in the timing of revenue recognition for such sales.
Mississippi Power's ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements, such as alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Mississippi Power's financial statements, if material. In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Mississippi Power expects CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Mississippi Power intends to use the modified retrospective method of adoption effective January 1, 2018. Mississippi Power has also elected to utilize practical expedients which allow it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Mississippi Power's financial statements, Mississippi Power will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Mississippi Power'srevised operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07agreement is not expected to have a material impact on Mississippi Power's financial statements.
On August 28, 2017, See Note 15 to the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with early adoption permitted. Mississippi Power is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on Mississippi Power's financial statements.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Mississippi Powerstatements under "Southern Company" in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information. Earnings for the nine months ended September 30, 2017 were negatively affected by revisions to the cost estimate for the Kemper IGCC.
Mississippi Power's capital expenditures and debt maturities are expected to materially exceed operating cash flows through 2022. Projected capital expenditures in that period include investments to maintain existing generation facilities, to add environmental modifications to existing generating units, and to expand and improve transmission and distribution facilities.
In the second quarter 2017, Mississippi Power borrowed an additional $40 million under a promissory note issued to Southern Company. In June 2017, Southern Company made equity contributions totaling $1.0 billion to Mississippi Power. Mississippi Power used a portion of the proceeds to prepay $901 million of outstanding debt.
As of September 30, 2017, Mississippi Power's current liabilities exceeded current assets by approximately $769 million primarily due to $935 million in long-term debt that matures within the next 12 months and $94 million of short-term debt. Mississippi Power intends to utilize operating cash flows, lines of credit, and bank term loans, as market conditions permit, as well as, under certain circumstances, commercial paper and/or equity contributions and/or loans from Southern Company to fund Mississippi Power's short-term capital needs.
Net cash provided from operating activities totaled $361 million for the first nine months of 2017, a decrease of $12 million as compared to the corresponding period in 2016. The decrease in cash provided from operating activities is primarily due to deferred income taxes related to the Kemper IGCC, partially offset by the timing of payments received from affiliates and customers and the completion of Mirror CWIP refunds in 2016. See Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" and "Unrecognized Tax Benefits – Section 174 Research and Experimental Deduction" herein for additional information. Net cash used for investing activities totaled $483 million for the first nine months of 2017 primarily due to gross property additions related to the Kemper IGCC. Net cash provided from financing activities totaled $129 million for the first nine months of 2017 primarily due to capital contributions from Southern Company, partially offset by redemptions of long-term debt and short-term borrowings. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first nine months of 2017 include an increase in paid-in capital of $1.0 billion due to capital contributions from Southern Company, a portion of which was used to repay $300 million of securities due within one year, $591 million of long-term debt, and $10 million of short-term debt. Securities due within one year decreased $551 million due to the repayment of promissory notes to Southern Company. Long-term debt decreased primarily due to the reclassification of $1.2 billion in unsecured term loans to securities due within one year. Other significant changes include decreases of $2.5 billion in CWIP, $756 million in accumulated deferred income taxes, and $299 million in deferred charges related to income taxes. All of these changes primarily resulted from the Kemper IGCC suspension and related estimated loss. Income taxes receivable and unrecognized tax benefits also decreased due to tax refunds associated with the IRS Section 174 R&E settlement. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Section 174 Research and Experimental Deduction," respectively, herein for additional information.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Mississippi Power in Item 7 of the Form 10-K for a description of Mississippi Power's capital requirements for its construction program, including estimated capital expenditures for new generating resources and to comply with existing environmental statutes and regulations,
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
scheduled maturities of long-term debt, as well as related interest, leases, purchase commitments, derivative obligations, preferred stock dividends, trust funding requirements, and unrecognized tax benefits. Approximately $935 million will be required through September 30, 2018 to fund maturities of long-term debt and $4 million will be required to fund maturities of short-term debt. In addition, Mississippi Power has $40 million of tax-exempt variable rate demand obligations that are supported by short-term credit facilities and $50 million of fixed rate pollution control revenue bonds that are required to be remarketed over the next 12 months. See "Sources of Capital" and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information.
The construction program of Mississippi Power is currently estimated to be $582 million for 2017, $203 million for 2018, $177 million for 2019, $204 million for 2020, $199 million for 2021, and $240 million for 2022. These estimated expenditures do not include potential compliance costs that may arise from the EPA's final rules and guidelines or future state plans that would limit CO2 emissions from existing, new, modified, or reconstructed fossil-fuel-fired electric generating units.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital.
Sources of Capital
Mississippi Power plans to obtain the funds required for construction and other purposes from operating cash flows, external security issuances, term loans, and/or short-term debt, as well as, under certain circumstances, equity contributions and/or loans from Southern Company. The amount, type, and timing of future financings will depend upon regulatory approval, prevailing market conditions, and other factors, which includes resolution of the Kemper County energy facility cost recovery. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" and – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" of Mississippi Power in Item 78 of the Form 10-K for additional information.information regarding the sale of Gulf Power.
On February 28, 2017,August 31, 2022, the maturity dates for $551 million in promissory notes to Southern Company were extended to July 31, 2018. In the second quarter 2017,Mississippi Department of Revenue (Mississippi DOR) completed an audit of sales and use taxes paid by Mississippi Power borrowed an additional $40from 2016 to 2019 and entered a final assessment, indicating a total amount due of $28 million, under a promissory note issued to Southern Company. In June 2017, Southern Company made equity contributions totaling $1.0 billion to Mississippi Power.including associated penalties and interest. Mississippi Power used a portion ofdoes not agree with the proceedsaudit findings and expects to (i) prepay $300 million ofexercise its rights to an administrative appeal with the outstanding principal amount under its $1.2 billion unsecured term loan; (ii) repay all ofMississippi DOR by October 30, 2022. Excluding amounts associated with the $591 million outstanding principal amount of promissory notes to Southern Company;gasifier and (iii) repay $10 million of the outstanding principal amount of bank loans.
In September 2017, Mississippi Power issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $150 million bearing interest based on one-month LIBOR. Mississippi Power borrowed $109 million under this promissory note primarily to satisfy its federal income tax obligations for the quarter ending September 30, 2017 and subsequently repaid the promissory note upon receipt of its income tax refund from the U.S. federal government related to the settlement concerning deductible R&E expenditures. See Note (G) to the Condensed Financial Statements under "Section 174 Research and Experimental Deduction" herein for additional information.
As of September 30, 2017,other abandoned Kemper IGCC assets, Mississippi Power's current liabilities exceeded current assets by approximately $769 million primarily due to $935 million in long-term debt that matures withinsales and use taxes are generally authorized for rate recovery; however, the next 12 months and $94 millionultimate outcome of short-term debt. Mississippi Power intends to utilize operating cash flows, lines of credit, and bank term loans, as
this matter cannot be determined at this time.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OFNOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
FINANCIAL CONDITION AND RESULTS OF OPERATIONS(UNAUDITED)
(D) REVENUE FROM CONTRACTS WITH CUSTOMERS AND LEASE INCOME
market conditions permit, as well as, under certain circumstances, commercial paper and/or equity contributions and/or loansRevenue from Southern Company to fund Mississippi Power's short-term capital needs. Specifically, Mississippi Power has been informed by Southern Company that in the event sufficient fundsContracts with Customers
The Registrants generate revenues from a variety of sources, some of which are not availableaccounted for as revenue from external sources, Southern Company intends to provide Mississippi Powercontracts with loans and/or equity contributions sufficient to fund the remaining indebtedness scheduled to maturecustomers, such as leases, derivatives, and other cash needs over the next 12 months. Therefore, Mississippi Power's financial statement presentation contemplates continuation of Mississippi Power as a going concern as a result of Southern Company's anticipated ongoing financial support of Mississippi Power. For additional information, see Notescertain cost recovery mechanisms. See Note 1 and 6 to the financial statements under "Revenues" in Item 8 of Mississippi Powerthe Form 10-K for additional information on the revenue policies of the Registrants. See "Lease Income" herein and Note (J) for additional information on revenue accounted for under "Recently Issued Accounting Standards"lease and "Going Concern," respectively,derivative accounting guidance, respectively.
The following table disaggregates revenue from contracts with customers for the three and nine months ended September 30, 2022 and 2021:
| | | | | | | | | | | | | | | | | | | | |
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| (in millions) |
| Three Months Ended September 30, 2022 | | | | | | |
| Operating revenues | | | | | | |
| Retail electric revenues | | | | | | |
| Residential | $ | 2,104 | | $ | 799 | | $ | 1,212 | | $ | 93 | | $ | — | | $ | — | |
| Commercial | 1,637 | | 499 | | 1,051 | | 87 | | — | | — | |
| Industrial | 1,183 | | 452 | | 642 | | 89 | | — | | — | |
| Other | 27 | | 3 | | 22 | | 2 | | — | | — | |
| Total retail electric revenues | 4,951 | | 1,753 | | 2,927 | | 271 | | — | | — | |
| Natural gas distribution revenues | | | | | | |
| Residential | 331 | | — | | — | | — | | — | | 331 | |
| Commercial | 93 | | — | | — | | — | | — | | 93 | |
| Transportation | 259 | | — | | — | | — | | — | | 259 | |
| Industrial | 12 | | — | | — | | — | | — | | 12 | |
| Other | 49 | | — | | — | | — | | — | | 49 | |
| Total natural gas distribution revenues | 744 | | — | | — | | — | | — | | 744 | |
| Wholesale electric revenues | | | | | | |
| PPA energy revenues | 812 | | 187 | | 40 | | 4 | | 591 | | — | |
| PPA capacity revenues | 175 | | 56 | | 12 | | 1 | | 107 | | — | |
| Non-PPA revenues | 58 | | 67 | | 4 | | 242 | | 303 | | — | |
| Total wholesale electric revenues | 1,045 | | 310 | | 56 | | 247 | | 1,001 | | — | |
| Other natural gas revenues | | | | | | |
| | | | | | |
| | | | | | |
| Gas marketing services | 84 | | — | | — | | — | | — | | 84 | |
| Other natural gas revenues | 15 | | — | | — | | — | | — | | 15 | |
| Total natural gas revenues | 99 | | — | | — | | — | | — | | 99 | |
| Other revenues | 277 | | 65 | | 110 | | 13 | | 9 | | — | |
| Total revenue from contracts with customers | 7,116 | | 2,128 | | 3,093 | | 531 | | 1,010 | | 843 | |
Other revenue sources(a) | 1,262 | | 316 | | 796 | | (21) | | 170 | | 14 | |
| | | | | | |
| Total operating revenues | $ | 8,378 | | $ | 2,444 | | $ | 3,889 | | $ | 510 | | $ | 1,180 | | $ | 857 | |
| | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | | | | | | | |
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| (in millions) |
| Nine Months Ended September 30, 2022 | | | | | | |
| Operating revenues | | | | | | |
| Retail electric revenues | | | | | | |
| Residential | $ | 5,282 | | $ | 2,049 | | $ | 2,995 | | $ | 238 | | $ | — | | $ | — | |
| Commercial | 4,202 | | 1,285 | | 2,688 | | 229 | | — | | — | |
| Industrial | 2,914 | | 1,143 | | 1,529 | | 242 | | — | | — | |
| Other | 79 | | 10 | | 62 | | 7 | | — | | — | |
| Total retail electric revenues | 12,477 | | 4,487 | | 7,274 | | 716 | | — | | — | |
| Natural gas distribution revenues | | | | | | |
| Residential | 1,821 | | — | | — | | — | | — | | 1,821 | |
| Commercial | 493 | | — | | — | | — | | — | | 493 | |
| Transportation | 872 | | — | | — | | — | | — | | 872 | |
| Industrial | 60 | | — | | — | | — | | — | | 60 | |
| Other | 244 | | — | | — | | — | | — | | 244 | |
| Total natural gas distribution revenues | 3,490 | | — | | — | | — | | — | | 3,490 | |
| Wholesale electric revenues | | | | | | |
| PPA energy revenues | 1,739 | | 354 | | 112 | | 11 | | 1,285 | | — | |
| PPA capacity revenues | 443 | | 135 | | 35 | | 4 | | 273 | | — | |
| Non-PPA revenues | 182 | | 166 | | 19 | | 511 | | 572 | | — | |
| Total wholesale electric revenues | 2,364 | | 655 | | 166 | | 526 | | 2,130 | | — | |
| Other natural gas revenues | | | | | | |
| | | | | | |
| | | | | | |
| Gas marketing services | 417 | | — | | — | | — | | — | | 417 | |
| Other natural gas revenues | 41 | | — | | — | | — | | — | | 41 | |
| Total natural gas revenues | 458 | | — | | — | | — | | — | | 458 | |
| Other revenues | 810 | | 173 | | 327 | | 34 | | 27 | | — | |
| Total revenue from contracts with customers | 19,599 | | 5,315 | | 7,767 | | 1,276 | | 2,157 | | 3,948 | |
Other revenue sources(a) | 2,633 | | 708 | | 1,451 | | 3 | | 461 | | 50 | |
| | | | | | |
| Total operating revenues | $ | 22,232 | | $ | 6,023 | | $ | 9,218 | | $ | 1,279 | | $ | 2,618 | | $ | 3,998 | |
| | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | | | | | | | |
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| (in millions) |
| Three Months Ended September 30, 2021 | | | | | | |
| Operating revenues | | | | | | |
| Retail electric revenues | | | | | | |
| Residential | $ | 1,974 | | $ | 750 | | $ | 1,138 | | $ | 86 | | $ | — | | $ | — | |
| Commercial | 1,432 | | 471 | | 882 | | 79 | | — | | — | |
| Industrial | 902 | | 394 | | 428 | | 80 | | — | | — | |
| Other | 24 | | 4 | | 18 | | 2 | | — | | — | |
| Total retail electric revenues | 4,332 | | 1,619 | | 2,466 | | 247 | | — | | — | |
| Natural gas distribution revenues | | | | | | |
| Residential | 218 | | — | | — | | — | | — | | 218 | |
| Commercial | 55 | | — | | — | | — | | — | | 55 | |
| Transportation | 239 | | — | | — | | — | | — | | 239 | |
| Industrial | 6 | | — | | — | | — | | — | | 6 | |
| Other | 31 | | — | | — | | — | | — | | 31 | |
| Total natural gas distribution revenues | 549 | | — | | — | | — | | — | | 549 | |
| Wholesale electric revenues | | | | | | |
| PPA energy revenues | 359 | | 61 | | 41 | | 2 | | 261 | | — | |
| PPA capacity revenues | 125 | | 14 | | 14 | | 1 | | 97 | | — | |
| Non-PPA revenues | 63 | | 54 | | 3 | | 120 | | 134 | | — | |
| Total wholesale electric revenues | 547 | | 129 | | 58 | | 123 | | 492 | | — | |
| Other natural gas revenues | | | | | | |
| | | | | | |
| | | | | | |
| Gas marketing services | 45 | | — | | — | | — | | — | | 45 | |
| Other natural gas revenues | 11 | | — | | — | | — | | — | | 11 | |
| Total natural gas revenues | 56 | | — | | — | | — | | — | | 56 | |
| Other revenues | 248 | | 53 | | 112 | | 8 | | 9 | | — | |
| Total revenue from contracts with customers | 5,732 | | 1,801 | | 2,636 | | 378 | | 501 | | 605 | |
Other revenue sources(a) | 506 | | 103 | | 220 | | — | | 178 | | 18 | |
| | | | | | |
| Total operating revenues | $ | 6,238 | | $ | 1,904 | | $ | 2,856 | | $ | 378 | | $ | 679 | | $ | 623 | |
| | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | | | | | | | |
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| (in millions) |
| Nine Months Ended September 30, 2021 | | | | | | |
| Operating revenues | | | | | | |
| Retail electric revenues | | | | | | |
| Residential | $ | 4,910 | | $ | 1,931 | | $ | 2,765 | | $ | 214 | | $ | — | | $ | — | |
| Commercial | 3,727 | | 1,229 | | 2,293 | | 205 | | — | | — | |
| Industrial | 2,299 | | 1,048 | | 1,034 | | 217 | | — | | — | |
| Other | 70 | | 13 | | 51 | | 6 | | — | | — | |
| Total retail electric revenues | 11,006 | | 4,221 | | 6,143 | | 642 | | — | | — | |
| Natural gas distribution revenues | | | | | | |
| Residential | 1,143 | | — | | — | | — | | — | | 1,143 | |
| Commercial | 298 | | — | | — | | — | | — | | 298 | |
| Transportation | 775 | | — | | — | | — | | — | | 775 | |
| Industrial | 29 | | — | | — | | — | | — | | 29 | |
| Other | 187 | | — | | — | | — | | — | | 187 | |
| Total natural gas distribution revenues | 2,432 | | — | | — | | — | | — | | 2,432 | |
| Wholesale electric revenues | | | | | | |
| PPA energy revenues | 782 | | 143 | | 71 | | 9 | | 575 | | — | |
| PPA capacity revenues | 375 | | 86 | | 41 | | 4 | | 247 | | — | |
| Non-PPA revenues | 181 | | 108 | | 14 | | 283 | | 273 | | — | |
| Total wholesale electric revenues | 1,338 | | 337 | | 126 | | 296 | | 1,095 | | — | |
| Other natural gas revenues | | | | | | |
| | | | | | |
| Wholesale gas services | 2,168 | | — | | — | | — | | — | | 2,168 | |
| Gas marketing services | 303 | | — | | — | | — | | — | | 303 | |
| Other natural gas revenues | 27 | | — | | — | | — | | — | | 27 | |
| Total natural gas revenues | 2,498 | | — | | — | | — | | — | | 2,498 | |
| Other revenues | 792 | | 150 | | 362 | | 22 | | 18 | | — | |
| Total revenue from contracts with customers | 18,066 | | 4,708 | | 6,631 | | 960 | | 1,113 | | 4,930 | |
Other revenue sources(a) | 2,979 | | 311 | | 419 | | 28 | | 497 | | 1,763 | |
Other adjustments(b) | (3,699) | | — | | — | | — | | — | | (3,699) | |
| Total operating revenues | $ | 17,346 | | $ | 5,019 | | $ | 7,050 | | $ | 988 | | $ | 1,610 | | $ | 2,994 | |
(a)Other revenue sources relate to revenues from customers accounted for as derivatives and leases, alternative revenue programs at Southern Company Gas, and cost recovery mechanisms and revenues that meet other scope exceptions for revenues from contracts with customers at the traditional electric operating companies.
(b)Other adjustments relate to the cost of Southern Company Gas' energy and risk management activities. Wholesale gas services revenues are presented net of the related costs of those activities on the statement of income. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K and Note (E)(L) under "Southern Company Gas" for information on the sale of Sequent and components of wholesale gas services' operating revenues, respectively.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Contract Balances
The following table reflects the closing balances of receivables, contract assets, and contract liabilities related to revenues from contracts with customers at September 30, 2022 and December 31, 2021:
| | | | | | | | | | | | | | | | | | | | |
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| (in millions) |
| Accounts Receivable | | | | | | |
| At September 30, 2022 | $ | 2,760 | | $ | 800 | | $ | 1,035 | | $ | 98 | | $ | 264 | | $ | 433 | |
| At December 31, 2021 | 2,504 | | 589 | | 736 | | 73 | | 149 | | 753 | |
| Contract Assets | | | | | | |
| At September 30, 2022 | $ | 178 | | $ | 5 | | $ | 114 | | $ | — | | $ | — | | $ | — | |
| At December 31, 2021 | 117 | | 2 | | 63 | | — | | 1 | | — | |
| Contract Liabilities | | | | | | |
| At September 30, 2022 | $ | 56 | | $ | 5 | | $ | 6 | | $ | 7 | | $ | 2 | | $ | — | |
| At December 31, 2021 | 57 | | 4 | | 14 | | — | | 1 | | — | |
At September 30, 2017, Mississippi2022 and December 31, 2021, Georgia Power had approximately $231contract assets primarily related to retail customer fixed bill programs, where the payment is contingent upon Georgia Power's continued performance and the customer's continued participation in the program over a one-year contract term, and unregulated service agreements, where payment is contingent on project completion. Contract liabilities for Georgia Power relate to cash collections recognized in advance of revenue for unregulated service agreements. Southern Company's unregulated distributed generation business had $59 million and $50 million of cashcontract assets and cash equivalents. Committed credit arrangements with banks$37 million and $39 million of contract liabilities at September 30, 20172022 and December 31, 2021, respectively, for outstanding performance obligations.
Revenues recognized in the three and nine months ended September 30, 2022, which were included in contract liabilities at December 31, 2021, were $13 million and $32 million, respectively, for Southern Company and immaterial for the other Registrants.
Remaining Performance Obligations
The Subsidiary Registrants have long-term contracts with customers in which revenues are recognized as performance obligations are satisfied over the contract term. For the traditional electric operating companies and Southern Power, these contracts primarily relate to PPAs whereby electricity and generation capacity are provided 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. For Southern Company Gas, these contracts involve energy infrastructure enhancement and upgrade projects for certain governmental customers. Southern Company's unregulated distributed generation business also has partially satisfied performance obligations related to certain fixed price contracts. Revenues from contracts with customers related to these performance obligations remaining at September 30, 2022 are expected to be recognized as follows:
| | | | | | | | | | | | | | | | | | | | |
| 2022 (remaining) | 2023 | 2024 | 2025 | 2026 | Thereafter |
| (in millions) |
| Southern Company | $ | 243 | | $ | 619 | | $ | 434 | | $ | 322 | | $ | 307 | | $ | 2,340 | |
| Alabama Power | 8 | | 24 | | 7 | | 5 | | — | | — | |
| Georgia Power | 20 | | 70 | | 34 | | 22 | | 11 | | 21 | |
| | | | | | |
| Southern Power | 80 | | 341 | | 344 | | 294 | | 299 | | 2,334 | |
| Southern Company Gas | 12 | | 29 | | 29 | | — | | — | | — | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Expires | | | | Executable Term Loans | | Expires Within One Year |
| 2017 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out |
| (in millions) |
| $ | 100 |
| | $ | 100 |
| | $ | 100 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 100 |
|
Lease Income
Lease income for the three and nine months ended September 30, 2022 and 2021 is as follows:
| | | | | | | | | | | | | | | | | | | | |
| Southern
Company | Alabama Power | Georgia Power | Mississippi
Power | Southern Power | Southern Company Gas |
| | (in millions) |
| For the Three Months Ended September 30, 2022 |
| Lease income - interest income on sales-type leases | $ | 7 | | $ | — | | $ | — | | $ | 4 | | $ | 3 | | $ | — | |
| Lease income - operating leases | 50 | | 19 | | 8 | | 1 | | 21 | | 9 | |
| Variable lease income | 139 | | — | | — | | — | | 145 | | — | |
| Total lease income | $ | 196 | | $ | 19 | | $ | 8 | | $ | 5 | | $ | 169 | | $ | 9 | |
| | | | | | |
| For the Nine Months Ended September 30, 2022 |
| Lease income - interest income on sales-type leases | $ | 19 | | $ | — | | $ | — | | $ | 11 | | $ | 8 | | $ | — | |
| Lease income - operating leases | 149 | | 58 | | 24 | | 1 | | 64 | | 27 | |
| Variable lease income | 355 | | 1 | | — | | — | | 372 | | — | |
| Total lease income | $ | 523 | | $ | 59 | | $ | 24 | | $ | 12 | | $ | 444 | | $ | 27 | |
| | | | | | |
| For the Three Months Ended September 30, 2021 |
| Lease income - interest income on sales-type leases | $ | 4 | | $ | — | | $ | — | | $ | 4 | | $ | — | | $ | — | |
| Lease income - operating leases | 56 | | 21 | | 11 | | — | | 21 | | 9 | |
| Variable lease income | 143 | | — | | — | | — | | 151 | | — | |
| Total lease income | $ | 203 | | $ | 21 | | $ | 11 | | $ | 4 | | $ | 172 | | $ | 9 | |
| | | | | | |
| For the Nine Months Ended September 30, 2021 |
| Lease income - interest income on sales-type leases | $ | 11 | | $ | — | | $ | — | | $ | 10 | | $ | — | | $ | — | |
| Lease income - operating leases | 168 | | 62 | | 31 | | 1 | | 64 | | 26 | |
| Variable lease income | 355 | | — | | — | | — | | 379 | | — | |
| Total lease income | $ | 534 | | $ | 62 | | $ | 31 | | $ | 11 | | $ | 443 | | $ | 26 | |
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. Lease income for Alabama Power and Southern Power is included in wholesale revenues.
(E) CONSOLIDATED ENTITIES AND EQUITY METHOD INVESTMENTS
See Note 67 to the financial statements in Item 8 of Mississippithe Form 10-K for additional information.
Southern Power
Variable Interest Entities
Southern Power has certain subsidiaries that are determined to be VIEs. Southern Power is considered the 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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
SP Solar and SP Wind
At September 30, 2022 and December 31, 2021, SP Solar had total assets of $6.0 billion and $6.1 billion, respectively, total liabilities of $0.4 billion, 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.
At September 30, 2022 and December 31, 2021, SP Wind had total assets of $2.3 billion, total liabilities of $191 million and $130 million, respectively, and noncontrolling interests of $40 million and $41 million, respectively. 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.
Southern Power consolidates both SP Solar and SP Wind, as the primary beneficiary, since it controls the most significant activities of each entity, including operating and maintaining their assets. Certain transfers and sales of the assets in the VIEs are subject to 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.
Other Variable Interest Entities
Southern Power has other consolidated VIEs that relate to certain subsidiaries that have either sold noncontrolling interests to tax equity investors or acquired less than a 100% interest from facility developers. These entities are considered VIEs because the arrangements are structured similar to a limited partnership and the noncontrolling members do not have substantive kick-out rights.
At September 30, 2022 and December 31, 2021, the other VIEs had total assets of $1.9 billion, total liabilities of $0.2 billion and $0.3 billion, respectively, and noncontrolling interests of $0.8 billion and $0.9 billion, respectively. Under the terms of the partnership agreements, distributions of all available cash are required each month or quarter and additional distributions require partner consent.
Equity Method Investments
At September 30, 2022 and December 31, 2021, Southern Power had equity method investments in wind and battery energy storage projects totaling $49 million and $86 million, respectively. Earnings (loss) from these investments were immaterial for all periods presented. During the nine months ended September 30, 2022, Southern Power sold equity method investments in wind projects and received proceeds totaling $38 million. The gains associated with the sales were immaterial.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Southern Company Gas
Equity Method Investments
The carrying amounts of Southern Company Gas' equity method investments at September 30, 2022 and December 31, 2021 and related earnings (loss) from those investments for the three and nine months ended September 30, 2022 and 2021 were as follows:
| | | | | | | | |
| Investment Balance | September 30, 2022 | December 31, 2021 |
| (in millions) |
| SNG | $ | 1,091 | | $ | 1,129 | |
Other(*) | 34 | | 44 | |
| Total | $ | 1,125 | | $ | 1,173 | |
(*)Balance at September 30, 2022 reflects an $11 million distribution received in 2022 from PennEast Pipeline.
| | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| Earnings (Loss) from Equity Method Investments | 2022 | 2021 | | 2022 | 2021 |
| (in millions) |
| SNG | $ | 34 | | $ | 27 | | | $ | 104 | | $ | 93 | |
PennEast Pipeline(*) | — | | (2) | | | — | | (81) | |
| Other | — | | — | | | 1 | | 2 | |
| Total | $ | 34 | | $ | 25 | | | $ | 105 | | $ | 14 | |
(*)Primarily reflects pre-tax impairment charges. See Note 7 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
(F) FINANCING AND LEASES
Bank Credit Arrangements
See Note 8 to the financial statements under "Bank Credit Arrangements" in Item 8 of the Form 10-K for additional information.
At September 30, 2022, committed credit arrangements with banks were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Expires | | | | | | | | |
| Company | | 2023 | 2024 | 2025 | 2026 | | Total | | Unused | | | | | | | | Expires within
One Year |
| | (in millions) |
| Southern Company parent | | $ | — | | $ | — | | $ | — | | $ | 2,000 | | | $ | 2,000 | | | $ | 1,998 | | | | | | | | | $ | — | |
| Alabama Power | | — | | 550 | | — | | 700 | | | 1,250 | | | 1,250 | | | | | | | | | — | |
| Georgia Power | | — | | — | | — | | 1,750 | | | 1,750 | | | 1,726 | | | | | | | | | — | |
| Mississippi Power | | — | | 150 | | 125 | | — | | | 275 | | | 275 | | | | | | | | | — | |
Southern Power(a) | | — | | — | | — | | 600 | | | 600 | | | 569 | | | | | | | | | — | |
Southern Company Gas(b) | | 250 | | — | | — | | 1,500 | | | 1,750 | | | 1,748 | | | | | | | | | 250 | |
| SEGCO | | 30 | | — | | — | | — | | | 30 | | | 30 | | | | | | | | | 30 | |
| Southern Company | | $ | 280 | | $ | 700 | | $ | 125 | | $ | 6,550 | | | $ | 7,655 | | | $ | 7,596 | | | | | | | | | $ | 280 | |
(a)Does not include Southern Power Company's two $75 million continuing letter of credit facilities for standby letters of credit, expiring in 2023 and Note (E)2025, respectively, of which $11 million and $5 million, respectively, was unused at September 30, 2022. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities.
(b)Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $800 million of the credit arrangement expiring in 2026. Southern Company Gas' committed credit arrangement expiring in 2026 also includes $700 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. Pursuant to the Condensed Financial Statements under "Bank Credit Arrangements" hereinmulti-year credit arrangement expiring in 2026, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted. Nicor Gas is also the borrower of a new $250 million credit arrangement expiring in 2023.
As reflected in the table above, in March 2022, Mississippi Power amended and restated its $125 million revolving credit arrangement, which among other things, extended the maturity date from 2023 to 2025 and allows for additional information.borrowing based on term SOFR.
Most of theseSubject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
These bank credit arrangements, as well as Mississippi Power'sthe term loan agreement,arrangements of the Registrants, Nicor Gas, and SEGCO, contain covenants that limit debt levels and typically contain cross accelerationcross-acceleration or, in the case of Southern Power, cross-default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of Mississippi Power.the individual company. Such cross-default provisions to other indebtedness would trigger an event of default if Southern Power defaulted on indebtedness or guarantee obligations over a specified threshold. Such cross-acceleration provisions to other indebtedness would trigger an event of default if Mississippi Powerthe applicable borrower defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2017, Mississippi Power was2022, the Registrants, Nicor Gas, and SEGCO were in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowing.borrowings.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
A portion of the $100 million unused credit arrangements with banks is allocated to provide liquidity support to Mississippi Power's pollution controlthe revenue bonds.bonds of the traditional electric operating companies and the commercial paper programs of the Registrants, Nicor Gas, and SEGCO. The amount of variable rate pollution control revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as ofat September 30, 20172022 was approximately $40 million.$1.4 billion (comprised of approximately $789 million at Alabama Power, $619 million at Georgia Power, and $34 million at Mississippi Power). In addition, at September 30, 2017, Mississippi2022, Georgia Power had approximately $50$288 million of fixed rate pollution controlrevenue bonds outstanding that wereare required to be remarketed within the next 12 months.
Short-term borrowings
Equity Units
In May 2022, Southern Company remarketed $862.5 million aggregate principal amount of its Series 2019A Remarketable Junior Subordinated Notes due August 1, 2024 (2019A RSNs) and $862.5 million aggregate principal amount of its Series 2019B Remarketable Junior Subordinated Notes due August 1, 2027 (2019B RSNs), pursuant to the terms of its 2019 Series A Equity Units (Equity Units). In connection with the remarketing, the interest rates on the 2019A RSNs and the 2019B RSNs were reset to 4.475% and 5.113%, respectively, payable on a semi-annual basis, and Southern Company ceased to have the ability to redeem these securities prior to maturity or to defer interest payments. Southern Company did not receive any proceeds from the remarketing, which were used to purchase a portfolio of treasury securities maturing on July 28, 2022. On August 1, 2022, the proceeds from this portfolio were used to settle the purchase contracts entered into as part of the Equity Units and Southern Company issued approximately 25.2 million shares of common stock and received proceeds of $1.725 billion. At September 30, 2022 and December 31, 2021, the 2019A RSNs and the 2019B RSNs are included in notes payablelong-term debt on Southern Company's consolidated balance sheets.
Earnings per Share
For Southern Company, the only differences in computing basic and diluted earnings per share are attributable to awards outstanding under stock-based compensation plans and the balance sheets. DetailsEquity Units until they were settled in August 2022. Earnings per share dilution resulting from stock-based compensation plans and the Equity Units issuance is determined using the treasury stock method. See Note 8 to the financial statements under "Equity Units" in Item 8 of short-term borrowingsthe Form 10-K and "Equity Units" herein for information on the Equity Units and Note 12 to the financial statements in Item 8 of the Form 10-K for information on stock-based compensation plans. Shares used to compute diluted earnings per share were as follows:
| | | | | | | | | | | | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
| 2022 | 2021 | 2022 | 2021 |
| | (in millions) |
| As reported shares | 1,082 | | 1,061 | | 1,070 | | 1,060 | |
| Effect of stock-based compensation | 6 | | 7 | | 6 | | 7 | |
| | | | |
| Diluted shares | 1,088 | | 1,068 | | 1,076 | | 1,067 | |
For all periods presented, an immaterial number of stock-based compensation awards was not included in the diluted earnings per share calculation because the awards were anti-dilutive.
Southern Company Leveraged Lease
See Note 9 to the financial statements in Item 8 of the Form 10-K for information on a leveraged lease agreement related to energy generation. On June 30, 2022, the Southern Holdings subsidiary operating the generating plant for the lessee provided notice to the lessee to terminate the related operating and maintenance agreement effective June 30, 2023. The parties to the lease agreement are currently negotiating a potential restructuring, which could result in rescission of the termination notice. 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.
|
| | | | | | | | | | | | | | | | |
| | | Short-term Debt at September 30, 2017 | | Short-term Debt During the Period(*) |
| | | Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) | | | | (in millions) |
| Short-term bank debt | | $ | 4 |
| | 3.8% | | $ | 28 |
| | 2.8% | | $ | 126 |
|
| |
(*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2017. |
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OFNOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
FINANCIAL CONDITION AND RESULTS OF OPERATIONS(UNAUDITED)
Georgia Power Lease Modification
See Note 9 to the financial statements in Item 8 of the Form 10-K for information on Georgia Power's leases. In July 2022, Georgia Power recognized a lease modification related to an existing non-affiliate PPA which converted from an operating lease to a finance lease upon its approval in the 2022 IRP. As a result, Georgia Power removed from its balance sheet operating lease right-of-use assets, net of amortization of $17 million and lease obligations of $18 million maturing through 2024 and recorded finance lease right-of-use assets of $112 million and lease obligations of $113 million maturing through 2039.
(G) INCOME TAXES
See Note 10 to the financial statements in Item 8 of the Form 10-K for additional tax information.
Current and Deferred Income Taxes
Tax Credit Rating Riskand Net Operating Loss Carryforwards
Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) totaling $1.0 billion at September 30, 2022 compared to $1.2 billion at December 31, 2021.
The federal PTC and ITC carryforwards begin expiring in 2032, but are expected to be fully utilized by 2025. The utilization of each Registrant's estimated tax credit and state net operating loss carryforwards and related valuation allowances could be impacted by numerous factors, including the acquisition of additional renewable projects, the purchase of rights to additional PTCs of Plant Vogtle Units 3 and 4 pursuant to certain joint ownership agreements, an increase in Georgia Power's ownership interest percentage in Plant Vogtle Units 3 and 4, changes in taxable income projections, and potential income tax rate changes. See Note (B) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information on Plant Vogtle Units 3 and 4.
Effective Tax Rate
Southern Company's effective tax rate is typically lower than the statutory rate due to employee stock plans' dividend deduction, non-taxable AFUDC equity at the traditional electric operating companies, flowback of excess deferred income taxes at the regulated utilities, and federal income tax benefits from ITCs and PTCs primarily at Southern Power.
Details of significant changes in the effective tax rate for the applicable Registrants are provided herein.
Southern Company
Southern Company's effective tax rate was 20.0% for the nine months ended September 30, 2022 compared to 17.5% for the corresponding period in 2021. The effective tax rate increase was primarily due to higher pre-tax earnings and an adjustment related to a prior year state tax credit carryforward at Georgia Power in 2022, partially offset by additional tax expense in 2021 as a result of the sale of Sequent. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Georgia Power
Georgia Power's effective tax rate was 18.5% for the nine months ended September 30, 2022 compared to 7.3% for the corresponding period in 2021. The effective tax rate increase was primarily due to higher pre-tax earnings and an adjustment related to a prior year state tax credit carryforward in 2022.
Mississippi Power
Mississippi Power's effective tax rate was 20.1% for the nine months ended September 30, 2022 compared to 14.3% for the corresponding period in 2021. The effective tax rate increase was primarily due to a decrease in the flowback of excess deferred income taxes in 2022.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Southern Power
Southern Power's effective tax rate was 18.8% for the nine months ended September 30, 2022 compared to a tax benefit rate of (1.6)% for the corresponding period in 2021. The effective tax rate increase was primarily due to higher pre-tax earnings in 2022 and a change in state apportionment methodology resulting from tax legislation enacted by the State of Alabama in the first quarter 2021, partially offset by higher wind PTCs in 2022.
Southern Company Gas
Southern Company Gas' effective tax rate was 23.7% for the nine months ended September 30, 2022 compared to 36.6% for the corresponding period in 2021. The effective tax rate decrease was primarily due to additional tax expense in 2021 as a result of the sale of Sequent. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Unrecognized Tax Benefits
Southern Company's and Southern Company Gas' unrecognized tax positions balances at September 30, 2022 were $79 million and $32 million, respectively, compared to $47 million for Southern Company at December 31, 2021. The increases from prior periods are related to the amendment of certain 2018 state tax filing positions related to Southern Company Gas dispositions. If accepted by the states, these positions would decrease Southern Company's and Southern Company Gas' annual effective tax rates. The ultimate outcome of these unrecognized tax benefits is dependent on acceptance by each state and is not expected to be resolved in the next 12 months.
(H) RETIREMENT BENEFITS
The Southern Company system has a qualified defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees at PowerSecure. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2022. The Southern Company system also provides certain non-qualified defined benefits for a select group of management and highly compensated employees, which are funded on a cash basis. In addition, the Southern Company system provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric operating companies fund other postretirement trusts to the extent required by their respective regulatory commissions. Southern Company Gas has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses.
During 2022, the qualified pension plan achieved the predetermined funding threshold whereby the asset allocation was adjusted to invest a larger portion of the portfolio in fixed rate debt securities.
See Note 11 to the financial statements in Item 8 of the Form 10-K for additional information.
On each Registrant's condensed statements of income, the service cost component of net periodic benefit costs is included in other operations and maintenance expenses and all other components of net periodic benefit costs are included in other income (expense), net. Components of the net periodic benefit costs for the three and nine months ended September 30, 2022 and 2021 are presented in the following tables.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Southern
Company | | Alabama
Power | | Georgia
Power | | Mississippi
Power | | Southern Power | | Southern Company Gas |
| (in millions) |
| Three Months Ended September 30, 2022 | | | | | | | | | | |
| Pension Plans | | | | | | | | | | | |
| Service cost | $ | 103 | | | $ | 25 | | | $ | 26 | | | $ | 5 | | | $ | 2 | | | $ | 9 | |
| Interest cost | 102 | | | 24 | | | 31 | | | 5 | | | 2 | | | 7 | |
| Expected return on plan assets | (316) | | | (77) | | | (99) | | | (15) | | | (4) | | | (22) | |
| Amortization: | | | | | | | | | | | |
| Prior service costs | — | | | — | | | — | | | — | | | — | | | (1) | |
| Regulatory asset | — | | | — | | | — | | | — | | | — | | | 3 | |
| Net loss | 60 | | | 16 | | | 18 | | | 2 | | | 1 | | | 2 | |
| Net periodic pension cost (income) | $ | (51) | | | $ | (12) | | | $ | (24) | | | $ | (3) | | | $ | 1 | | | $ | (2) | |
| | | | | | | | | | | |
| Postretirement Benefits | | | | | | | | | | | |
| Service cost | $ | 6 | | | $ | 2 | | | $ | 2 | | | $ | 1 | | | $ | 1 | | | $ | — | |
| Interest cost | 10 | | | 3 | | | 4 | | | — | | | — | | | 1 | |
| Expected return on plan assets | (20) | | | (9) | | | (8) | | | — | | | — | | | (2) | |
| Amortization: | | | | | | | | | | | |
| Prior service costs | (1) | | | — | | | — | | | — | | | — | | | — | |
| Regulatory asset | — | | | — | | | — | | | — | | | — | | | 2 | |
| Net (gain)/loss | 1 | | | — | | | — | | | — | | | — | | | (1) | |
| Net periodic postretirement benefit cost (income) | $ | (4) | | | $ | (4) | | | $ | (2) | | | $ | 1 | | | $ | 1 | | | $ | — | |
| | | | | | | | | | | |
| Nine Months Ended September 30, 2022 | | | | | | | | | | |
| Pension Plans |
| Service cost | $ | 309 | | | $ | 74 | | | $ | 78 | | | $ | 13 | | | $ | 7 | | | $ | 26 | |
| Interest cost | 306 | | | 72 | | | 92 | | | 14 | | | 5 | | | 21 | |
| Expected return on plan assets | (949) | | | (229) | | | (298) | | | (44) | | | (12) | | | (68) | |
| Amortization: | | | | | | | | | | | |
| Prior service costs | — | | | — | | | 1 | | | — | | | — | | | (2) | |
| Regulatory asset | — | | | — | | | — | | | — | | | — | | | 11 | |
| Net loss | 180 | | | 47 | | | 55 | | | 9 | | | 2 | | | 5 | |
| Net periodic pension cost (income) | $ | (154) | | | $ | (36) | | | $ | (72) | | | $ | (8) | | | $ | 2 | | | $ | (7) | |
| | | | | | | | | | | |
| Postretirement Benefits |
| Service cost | $ | 17 | | | $ | 5 | | | $ | 5 | | | $ | 1 | | | $ | 1 | | | $ | 1 | |
| Interest cost | 31 | | | 8 | | | 11 | | | 1 | | | — | | | 4 | |
| Expected return on plan assets | (60) | | | (25) | | | (21) | | | (1) | | | — | | | (6) | |
| Amortization: | | | | | | | | | | | |
| Prior service costs | (1) | | | — | | | — | | | — | | | — | | | — | |
| Regulatory asset | — | | | — | | | — | | | — | | | — | | | 5 | |
| Net (gain)/loss | 1 | | | — | | | 1 | | | — | | | — | | | (2) | |
| Net periodic postretirement benefit cost (income) | $ | (12) | | | $ | (12) | | | $ | (4) | | | $ | 1 | | | $ | 1 | | | $ | 2 | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Southern
Company | | Alabama
Power | | Georgia
Power | | Mississippi
Power | | Southern Power | | Southern Company Gas |
| (in millions) |
| Three Months Ended September 30, 2021 | | | | | | | | | | |
| Pension Plans |
| Service cost | $ | 109 | | | $ | 26 | | | $ | 28 | | | $ | 4 | | | $ | 2 | | | $ | 10 | |
| Interest cost | 87 | | | 20 | | | 26 | | | 4 | | | 2 | | | 6 | |
| Expected return on plan assets | (298) | | | (72) | | | (94) | | | (14) | | | (4) | | | (21) | |
| Amortization: | | | | | | | | | | | |
| Prior service costs | — | | | — | | | — | | | — | | | — | | | (1) | |
| Regulatory asset | — | | | — | | | — | | | — | | | — | | | 3 | |
| Net loss | 78 | | | 21 | | | 25 | | | 4 | | | 1 | | | 3 | |
| Net periodic pension cost (income) | $ | (24) | | | $ | (5) | | | $ | (15) | | | $ | (2) | | | $ | 1 | | | $ | — | |
| | | | | | | | | | | |
| Postretirement Benefits | | | | | | | | | | | |
| Service cost | $ | 6 | | | $ | 2 | | | $ | 2 | | | $ | 1 | | | $ | 1 | | | $ | — | |
| Interest cost | 9 | | | 2 | | | 3 | | | — | | | — | | | 1 | |
| Expected return on plan assets | (19) | | | (8) | | | (7) | | | (1) | | | — | | | (2) | |
| Amortization: | | | | | | | | | | | |
| | | | | | | | | | | |
| Regulatory asset | — | | | — | | | — | | | — | | | — | | | 2 | |
| Net (gain)/loss | 1 | | | — | | | 1 | | | — | | | — | | | (1) | |
| Net periodic postretirement benefit cost (income) | $ | (3) | | | $ | (4) | | | $ | (1) | | | $ | — | | | $ | 1 | | | $ | — | |
| | | | | | | | | | | |
| Nine Months Ended September 30, 2021 | | | | | | | | | | |
| Pension Plans |
| Service cost | $ | 326 | | | $ | 77 | | | $ | 84 | | | $ | 13 | | | $ | 7 | | | $ | 28 | |
| Interest cost | 260 | | | 61 | | | 78 | | | 12 | | | 4 | | | 18 | |
| Expected return on plan assets | (893) | | | (215) | | | (282) | | | (41) | | | (11) | | | (64) | |
| Amortization: | | | | | | | | | | | |
| Prior service costs | — | | | — | | | 1 | | | — | | | — | | | (2) | |
| Regulatory asset | — | | | — | | | — | | | — | | | — | | | 11 | |
| Net loss | 235 | | | 62 | | | 75 | | | 11 | | | 3 | | | 9 | |
| Net periodic pension cost (income) | $ | (72) | | | $ | (15) | | | $ | (44) | | | $ | (5) | | | $ | 3 | | | $ | — | |
| | | | | | | | | | | |
| Postretirement Benefits |
| Service cost | $ | 18 | | | $ | 5 | | | $ | 5 | | | $ | 1 | | | $ | 1 | | | $ | 1 | |
| Interest cost | 26 | | | 6 | | | 9 | | | 1 | | | — | | | 3 | |
| Expected return on plan assets | (57) | | | (22) | | | (20) | | | (2) | | | — | | | (6) | |
| Amortization: | | | | | | | | | | | |
| Prior service costs | (1) | | | — | | | — | | | — | | | — | | | — | |
| Regulatory asset | — | | | — | | | — | | | — | | | — | | | 5 | |
| Net (gain)/loss | 3 | | | — | | | 2 | | | — | | | — | | | (2) | |
| Net periodic postretirement benefit cost (income) | $ | (11) | | | $ | (11) | | | $ | (4) | | | $ | — | | | $ | 1 | | | $ | 1 | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
(I) FAIR VALUE MEASUREMENTS
At September 30, 2017,2022, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using: | | |
| At September 30, 2022 | 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) | $ | 49 | | | $ | 454 | | | $ | — | | | $ | — | | | $ | 503 | |
| | | | | | | | | |
| | | | | | | | | |
Investments in trusts:(b)(c) | | | | | | | | | |
| Domestic equity | 610 | | | 161 | | | — | | | — | | | 771 | |
| Foreign equity | 111 | | | 129 | | | — | | | — | | | 240 | |
| U.S. Treasury and government agency securities | — | | | 265 | | | — | | | — | | | 265 | |
| Municipal bonds | — | | | 52 | | | — | | | — | | | 52 | |
| Pooled funds – fixed income | — | | | 7 | | | — | | | — | | | 7 | |
| Corporate bonds | — | | | 438 | | | — | | | — | | | 438 | |
| Mortgage and asset backed securities | — | | | 87 | | | — | | | — | | | 87 | |
| Private equity | — | | | — | | | — | | | 156 | | | 156 | |
| Cash and cash equivalents | 4 | | | — | | | — | | | — | | | 4 | |
| Other | 17 | | | 13 | | | — | | | — | | | 30 | |
| Cash equivalents | 1,402 | | | 18 | | | — | | | — | | | 1,420 | |
| Other investments | 9 | | | 26 | | | — | | | — | | | 35 | |
| Total | $ | 2,202 | | | $ | 1,650 | | | $ | — | | | $ | 156 | | | $ | 4,008 | |
| Liabilities: | | | | | | | | | |
Energy-related derivatives(a) | $ | 20 | | | $ | 141 | | | $ | — | | | $ | — | | | $ | 161 | |
| Interest rate derivatives | — | | | 311 | | | — | | | — | | | 311 | |
| Foreign currency derivatives | — | | | 323 | | | — | | | — | | | 323 | |
| Contingent consideration | — | | | — | | | 14 | | | — | | | 14 | |
| Other | — | | | 13 | | | — | | | — | | | 13 | |
| Total | $ | 20 | | | $ | 788 | | | $ | 14 | | | $ | — | | | $ | 822 | |
| | | | | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using: | | |
| At September 30, 2022 | 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 | $ | — | | | $ | 147 | | | $ | — | | | $ | — | | | $ | 147 | |
| | | | | | | | | |
Nuclear decommissioning trusts:(b) | | | | | | | | | |
| Domestic equity | 370 | | | 152 | | | — | | | — | | | 522 | |
| Foreign equity | 111 | | | — | | | — | | | — | | | 111 | |
| U.S. Treasury and government agency securities | — | | | 15 | | | — | | | — | | | 15 | |
| Municipal bonds | — | | | 2 | | | — | | | — | | | 2 | |
| Corporate bonds | — | | | 230 | | | — | | | — | | | 230 | |
| Mortgage and asset backed securities | — | | | 20 | | | — | | | — | | | 20 | |
| Private equity | — | | | — | | | — | | | 156 | | | 156 | |
| Other | 10 | | | — | | | — | | | — | | | 10 | |
| Cash equivalents | 1,225 | | | 18 | | | — | | | — | | | 1,243 | |
| Other investments | — | | | 26 | | | — | | | — | | | 26 | |
| Total | $ | 1,716 | | | $ | 610 | | | $ | — | | | $ | 156 | | | $ | 2,482 | |
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — | | | $ | 35 | | | $ | — | | | $ | — | | | $ | 35 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Georgia Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — | | | $ | 145 | | | $ | — | | | $ | — | | | $ | 145 | |
| | | | | | | | | |
Nuclear decommissioning trusts:(b)(c) | | | | | | | | | |
| Domestic equity | 240 | | | 1 | | | — | | | — | | | 241 | |
| Foreign equity | — | | | 128 | | | — | | | — | | | 128 | |
| U.S. Treasury and government agency securities | — | | | 250 | | | — | | | — | | | 250 | |
| Municipal bonds | — | | | 50 | | | — | | | — | | | 50 | |
| Corporate bonds | — | | | 208 | | | — | | | — | | | 208 | |
| Mortgage and asset backed securities | — | | | 67 | | | — | | | — | | | 67 | |
| Other | 7 | | | 13 | | | — | | | — | | | 20 | |
| | | | | | | | | |
| Total | $ | 247 | | | $ | 862 | | | $ | — | | | $ | — | | | $ | 1,109 | |
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — | | | $ | 51 | | | $ | — | | | $ | — | | | $ | 51 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using: | | |
| At September 30, 2022 | 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 | $ | — | | | $ | 133 | | | $ | — | | | $ | — | | | $ | 133 | |
| | | | | | | | | |
| Cash equivalents | 30 | | | — | | | — | | | — | | | 30 | |
| Total | $ | 30 | | | $ | 133 | | | $ | — | | | $ | — | | | $ | 163 | |
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — | | | $ | 24 | | | $ | — | | | $ | — | | | $ | 24 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Southern Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — | | | $ | 7 | | | $ | — | | | $ | — | | | $ | 7 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — | | | $ | 13 | | | $ | — | | | $ | — | | | $ | 13 | |
| Foreign currency derivatives | — | | | 80 | | | — | | | — | | | 80 | |
| Contingent consideration | — | | | — | | | 14 | | | — | | | 14 | |
| Other | — | | | 13 | | | — | | | — | | | 13 | |
| Total | $ | — | | | $ | 106 | | | $ | 14 | | | $ | — | | | $ | 120 | |
| | | | | | | | | |
| Southern Company Gas | | | | | | | | | |
| Assets: | | | | | | | | | |
Energy-related derivatives(a) | $ | 49 | | | $ | 22 | | | $ | — | | | $ | — | | | $ | 71 | |
| | | | | | | | | |
| Non-qualified deferred compensation trusts: | | | | | | | | | |
| Domestic equity | — | | | 8 | | | — | | | — | | | 8 | |
| Foreign equity | — | | | 1 | | | — | | | — | | | 1 | |
| Pooled funds – fixed income | — | | | 7 | | | — | | | — | | | 7 | |
| Cash equivalents | 4 | | | — | | | — | | | — | | | 4 | |
| | | | | | | | | |
| | | | | | | | | |
| Total | $ | 53 | | | $ | 38 | | | $ | — | | | $ | — | | | $ | 91 | |
| Liabilities: | | | | | | | | | |
Energy-related derivatives(a) | $ | 20 | | | $ | 17 | | | $ | — | | | $ | — | | | $ | 37 | |
| Interest rate derivatives | — | | | 87 | | | — | | | — | | | 87 | |
| | | | | | | | | |
| Total | $ | 20 | | | $ | 104 | | | $ | — | | | $ | — | | | $ | 124 | |
(a)Excludes cash collateral of $15 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. At September 30, 2022, approximately $46 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan to creditors under the funds' managers' securities lending program. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. The fair value of the funds, including reinvested interest and dividends and excluding the funds' expenses, increased (decreased) by the amounts shown in the table below for the three and nine months ended September 30, 2022 and 2021. The changes were recorded as a change to the regulatory assets and liabilities related to AROs for Georgia Power and Alabama Power, respectively.
| | | | | | | | | | | | | | |
| Fair value increases (decreases) | Three Months Ended September 30, 2022 | Three Months Ended September 30, 2021 | Nine Months Ended September 30, 2022 | Nine Months Ended September 30, 2021 |
| (in millions) |
| Southern Company | $ | (106) | | $ | 9 | | $ | (486) | | $ | 173 | |
| Alabama Power | (53) | | 15 | | (245) | | 133 | |
| Georgia Power | (53) | | (6) | | (241) | | 40 | |
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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Southern Power has contingent payment obligations related to certain acquisitions whereby it 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 obligations are 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.
Southern Power also has payment obligations through 2040 whereby it must reimburse the transmission owners for interconnection facilities and network upgrades constructed to support connection of a Southern Power generating facility to the transmission system. The obligations are categorized as Level 2 under Fair Value Measurements as the fair value is determined using observable inputs for the contracted amounts and reimbursement period, as well as a discount rate. The fair value of the obligations reflects the net present value of expected payments.
"Other investments" include investments traded in the open market that have maturities greater than 90 days, which are categorized as Level 2 under Fair Value Measurements and are comprised of corporate bonds, bank certificates of deposit, treasury bonds, and/or agency bonds.
At September 30, 2022, 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 $156 million and unfunded commitments related to the private equity investments totaled $84 million. Private equity investments include high-quality private equity funds across several market sectors and funds that invest in real estate assets. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated.
At September 30, 2022, 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 billions) |
| Long-term debt, including securities due within one year: | | | | |
| Carrying amount | $ | 53.4 | | $ | 10.8 | | $ | 14.5 | | $ | 1.5 | | $ | 2.9 | | $ | 7.4 | |
| Fair value | 46.4 | | 9.3 | | 12.6 | | 1.2 | | 2.7 | | 6.3 | |
(*)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 remaining lives of the respective bonds, the latest being through 2043.
The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to the Registrants.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
(J) DERIVATIVES
The Registrants are exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Prior to the sale of Sequent on July 1, 2021, Southern Company Gas' wholesale gas operations used various contracts in its commercial activities that generally met the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note (I) for additional fair value information. In the statements of cash flows, any cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Any cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with the classification of the hedged interest or principal, respectively. See Note 1 to the financial statements under "Financial Instruments" in Item 8 of the Form 10-K for additional information. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information regarding the sale of Sequent.
Energy-Related Derivatives
The Subsidiary Registrants enter into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies and the natural gas distribution utilities have limited exposure to market volatility in energy-related commodity prices. Each of the traditional electric operating companies and certain of the natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs, implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies, through the use of financial derivative contracts, which are expected to continue to mitigate price volatility. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in energy-related commodity prices because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted capacity is used to sell electricity. Southern Company Gas retains exposure to price changes that can, in a volatile energy market, be material and can adversely affect its results of operations.
Southern Company Gas also enters into weather derivative contracts as economic hedges in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in operating revenues.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Energy-related derivative contracts are accounted for under one of three methods:
•Regulatory Hedges – Energy-related derivative contracts designated as regulatory hedges relate primarily to the traditional electric operating companies' and the natural gas distribution utilities' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through an approved cost recovery mechanism.
•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 September 30, 2022, the net volume of energy-related derivative contracts for natural gas positions, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows:
| | | | | | | | | | | | | | | | | |
| Net
Purchased
mmBtu | | Longest
Hedge
Date | | Longest
Non-Hedge
Date |
| (in millions) | | | | |
Southern Company(*) | 399 | | 2030 | | 2025 |
| Alabama Power | 105 | | 2026 | | — |
| Georgia Power | 116 | | 2025 | | — |
| Mississippi Power | 82 | | 2027 | | — |
| Southern Power | 11 | | 2030 | | 2023 |
Southern Company Gas(*) | 85 | | 2025 | | 2025 |
(*)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 95.7 million mmBtu and short natural gas positions of 10.6 million mmBtu at September 30, 2022, 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 15 million mmBtu for Southern Company, which includes 4 million mmBtu for Alabama Power, 5 million mmBtu for Georgia Power, 2 million mmBtu for Mississippi Power, doesand 4 million mmBtu for Southern Power.
For cash flow hedges of energy-related derivatives, the estimated pre-tax gains (losses) expected to be reclassified from accumulated OCI to earnings for the 12-month period ending September 30, 2023 are $17 million for Southern Company, $26 million for Southern Company Gas, and immaterial for the other Registrants.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Interest Rate Derivatives
Southern Company and certain subsidiaries may enter into interest rate derivatives to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and presented on the same income statement line item as the earnings effect of the hedged transactions. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
At September 30, 2022, 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, 2022 |
| | (in millions) | | | | | | (in millions) |
| Cash Flow Hedges of Existing Debt | | | | | | |
| Southern Company parent | $ | 175 | | | — | 4.25% | September 2025 | | $ | — | |
| Southern Company parent | 175 | | | — | 3.83% | August 2032 | | — | |
| Fair Value Hedges of Existing Debt | | | | | | |
| Southern Company parent | 400 | | | 1.75% | 1-month LIBOR + 0.68% | March 2028 | | (57) | |
| Southern Company parent | 1,000 | | | 3.70% | 1-month LIBOR + 2.36% | April
2030 | | (167) | |
| Southern Company Gas | 500 | | | 1.75% | 1-month LIBOR + 0.38% | January 2031 | | (87) | |
| Southern Company | $ | 2,250 | | | | | | | $ | (311) | |
For cash flow hedges of interest rate derivatives, the estimated pre-tax gains (losses) expected to be reclassified from accumulated OCI to interest expense for the 12-month period ending September 30, 2023 are $(17) million for Southern Company and immaterial for the other Registrants. Deferred gains and losses related to interest rate derivatives are expected to be amortized into earnings through 2052 for Southern Company, Alabama Power, and Georgia Power, 2028 for Mississippi Power, and 2046 for Southern Company Gas.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Foreign Currency Derivatives
Southern Company and certain subsidiaries, including Southern Power, may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and on the same income statement line as the earnings effect of the hedged transactions, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. 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, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Southern Company has elected to exclude the cross-currency basis spread from the assessment of effectiveness in the fair value hedges of its foreign currency risk and record any difference between the change in the fair value of the excluded components and the amounts recognized in earnings as a component of OCI.
At September 30, 2022, the following foreign currency derivatives were outstanding:
| | | | | | | | | | | | | | | | | | | | |
| Pay Notional | Pay
Rate | Receive Notional | Receive
Rate | Hedge
Maturity Date | Fair Value Gain (Loss) at September 30, 2022 |
| (in millions) | | (in millions) | | | (in millions) |
| Cash Flow Hedges of Existing Debt | | | | | |
| Southern Power | $ | 564 | | 3.78% | € | 500 | | 1.85% | June 2026 | $ | (80) | |
| | | | | | |
| Fair Value Hedges of Existing Debt | | | | | |
| | | | | | |
| Southern Company parent | 1,476 | | 3.39% | 1,250 | | 1.88% | September 2027 | (243) | |
| | | | | | |
| | | | | | |
| Southern Company | $ | 2,040 | | | € | 1,750 | | | | $ | (323) | |
For cash flow hedges of foreign currency derivatives, the estimated pre-tax losses expected to be reclassified from accumulated OCI to earnings for the 12-month period ending September 30, 2023 are $12 million for Southern Power.
Derivative Financial Statement Presentation and Amounts
The Registrants 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 sheets 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:
| | | | | | | | | | | | | | |
| At September 30, 2022 | At December 31, 2021 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| (in millions) | (in millions) |
| Southern Company | | | | |
| Energy-related derivatives designated as hedging instruments for regulatory purposes | | | | |
| | | | |
| Assets from risk management activities/Other current liabilities | $ | 299 | | $ | 70 | | $ | 129 | | $ | 30 | |
| Other deferred charges and assets/Other deferred credits and liabilities | 150 | | 59 | | 72 | | 6 | |
| | | | |
| | | | |
| Total derivatives designated as hedging instruments for regulatory purposes | 449 | | 129 | | 201 | | 36 | |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Energy-related derivatives: | | | | |
| Assets from risk management activities/Other current liabilities | 27 | | 13 | | 7 | | 5 | |
| Other deferred charges and assets/Other deferred credits and liabilities | 7 | | 1 | | 1 | | — | |
| Interest rate derivatives: | | | | |
| Assets from risk management activities/Other current liabilities | — | | 44 | | 19 | | — | |
| Other deferred charges and assets/Other deferred credits and liabilities | — | | 266 | | — | | 29 | |
| Foreign currency derivatives: | | | | |
| Assets from risk management activities/Other current liabilities | — | | 37 | | — | | 39 | |
| Other deferred charges and assets/Other deferred credits and liabilities | — | | 285 | | — | | 40 | |
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | 34 | | 646 | | 27 | | 113 | |
| Energy-related derivatives not designated as hedging instruments | | | | |
| | | | |
| Assets from risk management activities/Other current liabilities | 19 | | 18 | | 9 | | 4 | |
| Other deferred charges and assets/Other deferred credits and liabilities | 2 | | 1 | | 1 | | — | |
| | | | |
| Total derivatives not designated as hedging instruments | 21 | | 19 | | 10 | | 4 | |
| Gross amounts recognized | 504 | | 794 | | 238 | | 153 | |
Gross amounts offset(a) | (113) | | (128) | | (25) | | (28) | |
Net amounts recognized in the Balance Sheets(b) | $ | 391 | | $ | 666 | | $ | 213 | | $ | 125 | |
| | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | |
| At September 30, 2022 | At December 31, 2021 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| (in millions) | (in millions) |
| Alabama Power | | | | |
| Energy-related derivatives designated as hedging instruments for regulatory purposes | | | | |
| | | | |
| Other current assets/Other current liabilities | $ | 90 | | $ | 12 | | $ | 30 | | $ | 9 | |
| Other deferred charges and assets/Other deferred credits and liabilities | 57 | | 23 | | 25 | | 2 | |
| Total derivatives designated as hedging instruments for regulatory purposes | 147 | | 35 | | 55 | | 11 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| Gross amounts offset | (31) | | (31) | | (5) | | (5) | |
| Net amounts recognized in the Balance Sheets | $ | 116 | | $ | 4 | | $ | 50 | | $ | 6 | |
| | | | |
| Georgia Power | | | | |
| Energy-related derivatives designated as hedging instruments for regulatory purposes | | | | |
| | | | |
| Assets from risk management activities/Other current liabilities | $ | 107 | | $ | 28 | | $ | 54 | | $ | 6 | |
| Other deferred charges and assets/Other deferred credits and liabilities | 38 | | 23 | | 21 | | 2 | |
| Total derivatives designated as hedging instruments for regulatory purposes | 145 | | 51 | | 75 | | 8 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| Energy-related derivatives not designated as hedging instruments | | | | |
| | | | |
| Other current assets/Other current liabilities | 1 | | — | | — | | — | |
| | | | |
| Gross amounts recognized | 146 | | 51 | | 75 | | 8 | |
| Gross amounts offset | (41) | | (41) | | (8) | | (8) | |
| Net amounts recognized in the Balance Sheets | $ | 105 | | $ | 10 | | $ | 67 | | $ | — | |
| | | | |
| Mississippi Power | | | | |
| Energy-related derivatives designated as hedging instruments for regulatory purposes | | | | |
| | | | |
| Assets from risk management activities/Other current liabilities | $ | 78 | | $ | 12 | | $ | 30 | | $ | 3 | |
| Other deferred charges and assets/Other deferred credits and liabilities | 55 | | 12 | | 26 | | 2 | |
| Total derivatives designated as hedging instruments for regulatory purposes | 133 | | 24 | | 56 | | 5 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| Gross amounts offset | (20) | | (20) | | (4) | | (4) | |
| Net amounts recognized in the Balance Sheets | $ | 113 | | $ | 4 | | $ | 52 | | $ | 1 | |
| | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | |
| At September 30, 2022 | At December 31, 2021 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| (in millions) | (in millions) |
| Southern Power | | | | |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | — | | $ | 10 | | $ | 2 | | $ | — | |
| Other deferred charges and assets/Other deferred credits and liabilities | 5 | | 1 | | 1 | | — | |
| Foreign currency derivatives: | | | | |
| Other current assets/Other current liabilities | — | | 12 | | — | | 16 | |
| Other deferred charges and assets/Other deferred credits and liabilities | — | | 68 | | — | | — | |
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | 5 | | 91 | | 3 | | 16 | |
| Energy-related derivatives not designated as hedging instruments | | | | |
| | | | |
| Other current assets/Other current liabilities | 2 | | 2 | | 1 | | — | |
| | | | |
| | | | |
| | | | |
| | | | |
| Gross amounts recognized | 7 | | 93 | | 4 | | 16 | |
| Gross amounts offset | (3) | | (3) | | — | | — | |
| Net amounts recognized in the Balance Sheets | $ | 4 | | $ | 90 | | $ | 4 | | $ | 16 | |
| | | | |
| Southern Company Gas | | | | |
| Energy-related derivatives designated as hedging instruments for regulatory purposes | | | | |
| | | | |
| Other current assets/Other current liabilities | $ | 24 | | $ | 17 | | $ | 15 | | $ | 12 | |
| | | | |
| | | | |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | 26 | | 3 | | 5 | | 5 | |
| Other deferred charges and assets/Other deferred credits and liabilities | 3 | | — | | — | | — | |
| Interest rate derivatives: | | | | |
| Other current assets/Other current liabilities | — | | 13 | | 6 | | — | |
| Other deferred charges and assets/Other deferred credits and liabilities | — | | 74 | | — | | 6 | |
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | 29 | | 90 | | 11 | | 11 | |
| Energy-related derivatives not designated as hedging instruments | | | | |
| | | | |
| Other current assets/Other current liabilities | 16 | | 16 | | 8 | | 4 | |
| Other deferred charges and assets/Other deferred credits and liabilities | 2 | | 1 | | 1 | | — | |
| | | | |
| Total derivatives not designated as hedging instruments | 18 | | 17 | | 9 | | 4 | |
| Gross amounts recognized | 71 | | 124 | | 35 | | 27 | |
Gross amounts offset(a) | (18) | | (33) | | (8) | | (11) | |
Net amounts recognized in the Balance Sheets(b) | $ | 53 | | $ | 91 | | $ | 27 | | $ | 16 | |
(a)Gross amounts offset includes cash collateral held on deposit in broker margin accounts of $15 million and $3 million at September 30, 2022 and December 31, 2021, respectively.
(b)Net amounts of derivative instruments outstanding exclude immaterial premium and intrinsic value associated with weather derivatives for all periods presented.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Energy-related derivatives not designated as hedging instruments were immaterial for Alabama Power and Mississippi Power at September 30, 2022. There were no such instruments for the traditional electric operating companies at December 31, 2021.
At September 30, 2022 and December 31, 2021, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:
| | | | | | | | | | | | | | | | | |
| Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet |
Derivative Category and Balance Sheet
Location | Southern
Company | Alabama
Power | Georgia
Power | Mississippi
Power | Southern Company Gas |
| | (in millions) |
| At September 30, 2022: | | | | | |
| Energy-related derivatives: | | | | | |
| Other regulatory assets, current | $ | (17) | | $ | (2) | | $ | (8) | | $ | (3) | | $ | (4) | |
| Other regulatory assets, deferred | (6) | | (2) | | (3) | | (1) | | — | |
| | | | | |
| | | | | |
| Other regulatory liabilities, current | 246 | | 80 | | 87 | | 69 | | 10 | |
| Other regulatory liabilities, deferred | 98 | | 36 | | 18 | | 44 | | — | |
| Total energy-related derivative gains (losses) | $ | 321 | | $ | 112 | | $ | 94 | | $ | 109 | | $ | 6 | |
| | | | | |
| At December 31, 2021: | | | | | |
| Energy-related derivatives: | | | | | |
| Other regulatory assets, current | $ | (17) | | $ | (6) | | $ | — | | $ | — | | $ | (11) | |
| | | | | |
| Other regulatory liabilities, current | 107 | | 28 | | 48 | | 27 | | 4 | |
| Other regulatory liabilities, deferred | 65 | | 22 | | 19 | | 24 | | — | |
| Total energy-related derivative gains (losses) | $ | 155 | | $ | 44 | | $ | 67 | | $ | 51 | | $ | (7) | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
For the three and nine months ended September 30, 2022 and 2021, the pre-tax effects of cash flow and fair value 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, |
| 2022 | 2021 | 2022 | 2021 |
| (in millions) | (in millions) |
| Southern Company | | | | |
| Cash flow hedges: | | | | |
| Energy-related derivatives | $ | 11 | | $ | 38 | | $ | 51 | | $ | 59 | |
| Interest rate derivatives | 6 | | 5 | | 36 | | 7 | |
| Foreign currency derivatives | (35) | | (36) | | (137) | | (79) | |
Fair value hedges(*): | | | | |
| Foreign currency derivatives | 20 | | (4) | | 18 | | (4) | |
| Total | $ | 2 | | $ | 3 | | $ | (32) | | $ | (17) | |
| | | | |
| | | | |
| Georgia Power | | | | |
| | | | |
| Interest rate derivatives | $ | — | | $ | — | | $ | 31 | | $ | — | |
| | | | |
| | | | |
| | | | |
| Southern Power | | | | |
| Cash flow hedges: | | | | |
| Energy-related derivatives | $ | (11) | | $ | 8 | | $ | (4) | | $ | 16 | |
| | | | |
| Foreign currency derivatives | (35) | | (36) | | (137) | | (79) | |
| Total | $ | (46) | | $ | (28) | | $ | (141) | | $ | (63) | |
| Southern Company Gas | | | | |
| Cash flow hedges: | | | | |
| Energy-related derivatives | $ | 22 | | $ | 30 | | $ | 55 | | $ | 43 | |
| Interest rate derivatives | 5 | | — | | — | | — | |
| Total | $ | 27 | | $ | 30 | | $ | 55 | | $ | 43 | |
(*)Represents amounts excluded from the assessment of effectiveness for which the difference between changes in fair value and periodic amortization is recorded in OCI.
For the three and nine months ended September 30, 2022 and 2021, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments on accumulated OCI were immaterial for the other Registrants.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
For the three and nine months ended September 30, 2022 and 2021, 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, |
|
| 2022 | 2021 | 2022 | 2021 |
| (in millions) | (in millions) |
| Southern Company | | | | |
| Total cost of natural gas | $ | 294 | | $ | 129 | | $ | 1,840 | | $ | 943 | |
Gain (loss) on energy-related cash flow hedges(a) | 9 | | 2 | | 28 | | — | |
| Total depreciation and amortization | 922 | | 896 | | 2,728 | | 2,658 | |
Gain (loss) on energy-related cash flow hedges(a) | (1) | | 3 | | 5 | | 6 | |
| Total interest expense, net of amounts capitalized | (511) | | (451) | | (1,461) | | (1,352) | |
Gain (loss) on interest rate cash flow hedges(a) | (7) | | (7) | | (19) | | (20) | |
Gain (loss) on foreign currency cash flow hedges(a) | (3) | | (6) | | (16) | | (18) | |
Gain (loss) on interest rate fair value hedges(b) | (102) | | (4) | | (300) | | (16) | |
| Total other income (expense), net | 132 | | 131 | | 414 | | 290 | |
Gain (loss) on foreign currency cash flow hedges(a)(c) | (32) | | (34) | | (129) | | (76) | |
| Gain (loss) on foreign currency fair value hedges | (59) | | (32) | | (180) | | (32) | |
| Amount excluded from effectiveness testing recognized in earnings | (21) | | 4 | | (17) | | 4 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| Southern Power | | | | |
| Total depreciation and amortization | $ | 133 | | $ | 132 | | $ | 384 | | $ | 383 | |
Gain (loss) on energy-related cash flow hedges(a) | (1) | | 3 | | 5 | | 6 | |
| Total interest expense, net of amounts capitalized | (32) | | (36) | | (105) | | (111) | |
Gain (loss) on foreign currency cash flow hedges(a) | (3) | | (6) | | (16) | | (18) | |
| Total other income (expense), net | 3 | | 2 | | 5 | | 10 | |
Gain (loss) on foreign currency cash flow hedges(a)(c) | (32) | | (34) | | (129) | | (76) | |
| Southern Company Gas | | | | |
| Total cost of natural gas | $ | 294 | | $ | 129 | | $ | 1,840 | | $ | 943 | |
Gain (loss) on energy-related cash flow hedges(a) | 9 | | 2 | | 28 | | — | |
| Total interest expense, net of amounts capitalized | (65) | | (57) | | (187) | | (175) | |
Gain (loss) on interest rate cash flow hedges(a) | (2) | | (1) | | (3) | | (2) | |
Gain (loss) on interest rate fair value hedges(b) | (30) | | — | | (87) | | 2 | |
(a)Reclassified from accumulated OCI into earnings.
(b)For fair value hedges, changes in the fair value of the derivative contracts are generally equal to changes in the fair value of the underlying debt and have no material impact on income.
(c)The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes.
For the three and nine months ended September 30, 2022 and 2021, the pre-tax effects of cash flow hedge accounting on income for interest rate derivatives were immaterial for Alabama Power, Georgia Power, and Mississippi Power.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
At September 30, 2022 and December 31, 2021, 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 | At September 30, 2022 | At December 31, 2021 | | At September 30, 2022 | At December 31, 2021 |
| (in millions) | | (in millions) |
| Southern Company | | | | | |
| | | | | |
| Long-term debt | $ | (2,788) | | $ | (3,280) | | | $ | 306 | | $ | 9 | |
| | | | | |
| Southern Company Gas | | | | | |
| | | | | |
| Long-term debt | $ | (411) | | $ | (493) | | | $ | 86 | | $ | 2 | |
For the three and nine months ended September 30, 2022 and 2021, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income of Southern Company and Southern Company Gas were as follows:
| | | | | | | | | | | | | | | | | | | | |
| | Gain (Loss) |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| Derivatives in Non-Designated Hedging Relationships | Statements of Income Location | 2022 | 2021 | | 2022 | 2021 |
| | (in millions) | | (in millions) |
| | | | | | |
| Energy-related derivatives: | Natural gas revenues(*) | $ | 3 | | $ | (2) | | | $ | (10) | | $ | (122) | |
| Cost of natural gas | (2) | | 20 | | | (7) | | 36 | |
| | | | | | |
| Total derivatives in non-designated hedging relationships | $ | 1 | | $ | 18 | | | $ | (17) | | $ | (86) | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | |
(*)Excludes immaterial gains (losses) recorded in natural gas revenues associated with weather derivatives for all periods presented.
For the three and nine months ended September 30, 2022 and 2021, the pre-tax effects of energy-related derivatives not designated as hedging instruments were immaterial for the other Registrants.
Contingent Features
The Registrants do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
On October 4, 2017, Mississippi Power executed agreements with its largest retail customer, Chevron, to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038. The agreements grant Chevron a security interest in the co-generation assets located at the refinery that is exercisable upon the occurrence of (i) certain bankruptcy events or (ii) other events of default coupled with specific reductions in steam output at the facility and a downgrade of Mississippi Power's credit rating to below investment grade by two of the three rating agencies.
There are certain contractsderivatives that have required or could require collateral, but not accelerated payment, in the event of avarious credit rating change to BBB and/or Baa2 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, energy price risk management, and transmission. At September 30, 2017, the maximum potential collateral requirements at a rating below BBB- and/or Baa3 equaled approximately $255 million.
Included in these amounts arechanges of certain agreements that could require collateral in the event that Alabama Power or Georgia Power has a credit rating change to below investment grade.Southern Company subsidiaries. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally,At September 30, 2022, the Registrants had no collateral posted with derivative counterparties to satisfy these arrangements.
For Southern Company and Southern Power, 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, were $156 million and $38 million, respectively at September 30, 2022. For the traditional electric operating companies and Southern Power, 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 at September 30, 2022. 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 downgrade could impactchange to below investment grade. Following the abilitysale of MississippiGulf Power to access capital markets, and would be likely to impactNextEra Energy, Inc., Gulf Power continued participating in the cost at which it does so.
On March 1, 2017, Moody's downgraded the senior unsecured debt rating of Mississippi Power to Ba1 from Baa3.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including Mississippi Power) from stable to negative.
On March 30, 2017, Fitch placed the ratings of Mississippi Power on rating watch negative.
On June 22, 2017, Moody's placed the ratings of Mississippi Power on review for downgrade. On September 21, 2017, Moody's revised its rating outlook for Mississippi Power from under review to stable.
Financing Activities
In March 2017, Mississippi Power issued a $9 million short-term bank note bearing interest at 5% per annum, which was repaid in April 2017.
In February 2017, Mississippi Power amended $551 million in promissory notes to Southern Company extending the maturity dates of the notes from December 1, 2017 topower pool through July 31, 2018. In the second quarter 2017, Mississippi Power borrowed an additional $40 million under a promissory note issued to Southern Company.
In June 2017, Southern Company made equity contributions totaling $1.0 billion to Mississippi Power. Mississippi Power used a portion of the proceeds to (i) prepay $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018; (ii) repay all of the $591 million outstanding principal amount of promissory notes to Southern Company; and (iii) repay a $10 million short-term bank loan.
In August 2017, Mississippi Power repaid a $12.5 million short-term bank note.
In September 2017, Mississippi Power issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $150 million bearing interest based on one-month LIBOR. Mississippi Power borrowed $109 million under this promissory note primarily to satisfy its federal income tax obligations for the quarter ending September 30, 2017 and subsequently repaid the promissory note upon receipt of its income tax refund from the U.S. federal government related to the settlement concerning deductible R&E expenditures. See Note (G) to the Condensed Financial Statements under "Section 174 Research and Experimental Deduction" herein for additional information.
13, 2022.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OFNOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
FINANCIAL CONDITION AND RESULTS OF OPERATIONS(UNAUDITED)
In additionAlabama Power and Southern Power maintain accounts with certain regional transmission organizations to any financings thatfacilitate financial derivative transactions and they may be necessaryrequired to meet capital requirements and contractual obligations, Mississippi Power plans, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
SOUTHERN POWER COMPANY
AND SUBSIDIARY COMPANIES
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | |
| Wholesale revenues, non-affiliates | $ | 510 |
| | $ | 387 |
| | $ | 1,293 |
| | $ | 866 |
|
| Wholesale revenues, affiliates | 105 |
| | 110 |
| | 295 |
| | 313 |
|
| Other revenues | 3 |
| | 3 |
| | 9 |
| | 10 |
|
| Total operating revenues | 618 |
| | 500 |
| | 1,597 |
| | 1,189 |
|
| Operating Expenses: | | | | | | | |
| Fuel | 189 |
| | 154 |
| | 460 |
| | 341 |
|
| Purchased power, non-affiliates | 36 |
| | 25 |
| | 90 |
| | 60 |
|
| Purchased power, affiliates | 7 |
| | 8 |
| | 23 |
| | 16 |
|
| Other operations and maintenance | 83 |
| | 81 |
| | 272 |
| | 246 |
|
| Depreciation and amortization | 131 |
| | 93 |
| | 379 |
| | 247 |
|
| Taxes other than income taxes | 13 |
| | 5 |
| | 37 |
| | 17 |
|
| Total operating expenses | 459 |
|
| 366 |
| | 1,261 |
| | 927 |
|
| Operating Income | 159 |
| | 134 |
| | 336 |
| | 262 |
|
| Other Income and (Expense): | | | | | | | |
| Interest expense, net of amounts capitalized | (47 | ) | | (35 | ) | | (144 | ) | | (78 | ) |
| Other income (expense), net | 3 |
| | 2 |
| | 3 |
| | 3 |
|
| Total other income and (expense) | (44 | ) | | (33 | ) | | (141 | ) | | (75 | ) |
| Earnings Before Income Taxes | 115 |
| | 101 |
| | 195 |
| | 187 |
|
| Income taxes (benefit) | (39 | ) | | (102 | ) | | (129 | ) | | (167 | ) |
| Net Income | 154 |
| | 203 |
| | 324 |
| | 354 |
|
| Less: Net income attributable to noncontrolling interests | 30 |
| | 27 |
| | 48 |
| | 39 |
|
| Net Income Attributable to Southern Power | $ | 124 |
| | $ | 176 |
| | $ | 276 |
| | $ | 315 |
|
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) |
| Net Income | $ | 154 |
| | $ | 203 |
| | $ | 324 |
| | $ | 354 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
Changes in fair value, net of tax of
$15, $14, $35, and $(1), respectively | 25 |
| | 23 |
| | 58 |
| | (1 | ) |
Reclassification adjustment for amounts included in net income,
net of tax of $(12), $(1), $(42), and $7, respectively | (20 | ) | | (1 | ) | | (68 | ) | | 13 |
|
| Total other comprehensive income (loss) | 5 |
| | 22 |
| | (10 | ) | | 12 |
|
| Comprehensive Income | 159 |
| | 225 |
| | 314 |
| | 366 |
|
| Less: Comprehensive income attributable to noncontrolling interests | 30 |
| | 27 |
| | 48 |
| | 39 |
|
| Comprehensive Income Attributable to Southern Power | $ | 129 |
| | $ | 198 |
| | $ | 266 |
| | $ | 327 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
|
| | | | | | | |
| | For the Nine Months Ended September 30, |
| | 2017 | | 2016 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 324 |
| | $ | 354 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 404 |
| | 262 |
|
| Deferred income taxes | 240 |
| | (668 | ) |
| Amortization of investment tax credits | (42 | ) | | (25 | ) |
| Collateral deposits | (1 | ) | | (80 | ) |
| Income taxes receivable, non-current | (42 | ) | | — |
|
| Other, net | (2 | ) | | 19 |
|
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (77 | ) | | (82 | ) |
| -Other current assets | 38 |
| | (15 | ) |
| -Accounts payable | (31 | ) | | 7 |
|
| -Accrued taxes | 79 |
| | 483 |
|
| -Other current liabilities | 5 |
| | 14 |
|
| Net cash provided from operating activities | 895 |
| | 269 |
|
| Investing Activities: | | | |
| Business acquisitions | (1,032 | ) | | (1,134 | ) |
| Property additions | (218 | ) | | (1,702 | ) |
| Change in construction payables | (166 | ) | | (69 | ) |
| Payments pursuant to LTSAs | (99 | ) | | (58 | ) |
| Investment in restricted cash | (16 | ) | | (750 | ) |
| Distribution of restricted cash | 33 |
| | 746 |
|
| Other investing activities | 7 |
| | (41 | ) |
| Net cash used for investing activities | (1,491 | ) | | (3,008 | ) |
| Financing Activities: | | | |
| Increase (decrease) in notes payable, net | (89 | ) | | 692 |
|
| Proceeds — | | | |
| Senior notes | — |
| | 1,531 |
|
| Capital contributions from parent company | — |
| | 800 |
|
| Other long-term debt | 43 |
| | 63 |
|
| Redemptions — Other long-term debt | (4 | ) | | (84 | ) |
| Distributions to noncontrolling interests | (89 | ) | | (22 | ) |
| Capital contributions from noncontrolling interests | 79 |
| | 367 |
|
| Purchase of membership interests from noncontrolling interests | — |
| | (129 | ) |
| Payment of common stock dividends | (238 | ) | | (204 | ) |
| Other financing activities | (27 | ) | | (14 | ) |
| Net cash provided from (used for) financing activities | (325 | ) | | 3,000 |
|
| Net Change in Cash and Cash Equivalents | (921 | ) | | 261 |
|
| Cash and Cash Equivalents at Beginning of Period | 1,099 |
| | 830 |
|
| Cash and Cash Equivalents at End of Period | $ | 178 |
| | $ | 1,091 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
| Interest (net of $7 and $32 capitalized for 2017 and 2016, respectively) | $ | 144 |
| | $ | 49 |
|
| Income taxes, net | (343 | ) | | 71 |
|
| Noncash transactions — Accrued property additions at end of period | 16 |
| | 210 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At September 30, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 178 |
| | $ | 1,099 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 148 |
| | 102 |
|
| Other | | 61 |
| | 34 |
|
| Affiliated | | 74 |
| | 57 |
|
| Fossil fuel stock | | 15 |
| | 15 |
|
| Materials and supplies | | 351 |
| | 337 |
|
| Prepaid income taxes | | 51 |
| | 74 |
|
| Other current assets | | 26 |
| | 39 |
|
| Total current assets | | 904 |
| | 1,757 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 13,734 |
| | 12,728 |
|
| Less: Accumulated provision for depreciation | | 1,823 |
| | 1,484 |
|
| Plant in service, net of depreciation | | 11,911 |
| | 11,244 |
|
| Construction work in progress | | 425 |
| | 398 |
|
| Total property, plant, and equipment | | 12,336 |
| | 11,642 |
|
| Other Property and Investments: | | | | |
Intangible assets, net of amortization of $41 and $22
at September 30, 2017 and December 31, 2016, respectively | | 417 |
| | 436 |
|
| Total other property and investments | | 417 |
| | 436 |
|
| Deferred Charges and Other Assets: | | | | |
| Prepaid LTSAs | | 77 |
| | 101 |
|
| Accumulated deferred income taxes | | 400 |
| | 594 |
|
| Income taxes receivable, non-current | | 53 |
| | 11 |
|
| Other deferred charges and assets — affiliated | | 6 |
| | 13 |
|
| Other deferred charges and assets — non-affiliated | | 455 |
| | 615 |
|
| Total deferred charges and other assets | | 991 |
| | 1,334 |
|
| Total Assets | | $ | 14,648 |
| | $ | 15,169 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholders' Equity | | At September 30, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 864 |
| | $ | 560 |
|
| Notes payable | | 120 |
| | 209 |
|
| Accounts payable — | | | | |
| Affiliated | | 93 |
| | 88 |
|
| Other | | 84 |
| | 278 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 101 |
| | 148 |
|
| Other accrued taxes | | 30 |
| | 7 |
|
| Accrued interest | | 36 |
| | 36 |
|
| Acquisitions payable | | — |
| | 461 |
|
| Contingent consideration | | 15 |
| | 46 |
|
| Other current liabilities | | 58 |
| | 70 |
|
| Total current liabilities | | 1,401 |
| | 1,903 |
|
| Long-term Debt | | 4,946 |
| | 5,068 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 191 |
| | 152 |
|
| Accumulated deferred ITCs | | 1,900 |
| | 1,839 |
|
| Asset retirement obligations | | 76 |
| | 64 |
|
| Other deferred credits and liabilities | | 232 |
| | 304 |
|
| Total deferred credits and other liabilities | | 2,399 |
| | 2,359 |
|
| Total Liabilities | | 8,746 |
| | 9,330 |
|
| Redeemable Noncontrolling Interests | | 59 |
| | 164 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, par value $.01 per share — | | | | |
| Authorized — 1,000,000 shares | | | | |
| Outstanding — 1,000 shares | | — |
| | — |
|
| Paid-in capital | | 3,661 |
| | 3,671 |
|
| Retained earnings | | 762 |
| | 724 |
|
| Accumulated other comprehensive income | | 25 |
| | 35 |
|
| Total common stockholder's equity | | 4,448 |
| | 4,430 |
|
| Noncontrolling interests | | 1,395 |
| | 1,245 |
|
| Total stockholders' equity | | 5,843 |
| | 5,675 |
|
| Total Liabilities and Stockholders' Equity | | $ | 14,648 |
| | $ | 15,169 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRD QUARTER 2017 vs. THIRD QUARTER 2016
AND
YEAR-TO-DATE 2017 vs. YEAR-TO-DATE 2016
OVERVIEW
Southern Power constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates inpost collateral based on the wholesale market. Southern Power continually seeks opportunities to execute its strategy to create value through various transactions including acquisitions and sales of assets, construction and development of new generating facilities, and entry into PPAs primarily with investor-owned utilities, independent power producers, municipalities, and other load-serving entities, as well as commercial and industrial customers. In general, Southern Power has constructed or acquired new generating capacity only after entering into or assuming long-term PPAs for the new facilities.
During the nine months ended September 30, 2017, Southern Power acquired or completed the construction of, and placed in service, approximately 498 MWs of solar and wind facilities. In addition, Southern Power began construction at the recently acquired Cactus Flats wind facility, continued development of its portfolio of wind projects, and continued expansion of the Mankato natural gas facility by 345 MWs of capacity. See FUTURE EARNINGS POTENTIAL – "Acquisitions"positions in these accounts and "Construction Projects" herein for additional information.
Southern Power is considering the sale of up to a one-third equity interest in its solar asset portfolio. The ultimate outcome of this matter cannot be determined at this time.
associated margin requirements. At September 30, 2017,2022, cash collateral posted in these accounts was immaterial. Southern Power had an averageCompany 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 September 30, 2022, cash collateral held on deposit in broker margin accounts was $15 million.
The Registrants are exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Registrants only enter into agreements and material transactions with counterparties that have investment coverage ratiograde credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Registrants have also established risk management policies and controls to determine and monitor the creditworthiness of 91% through 2021 and 90% through 2026, with an average remaining contract duration of approximately 16 years. These ratios include the PPAs and capacity associated with facilities currently under construction and acquisitions discussed herein. See FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" herein for additional information.counterparties in order to mitigate their exposure to counterparty credit risk.
Southern Power continuesCompany Gas uses established credit policies to focus on several key performance indicators,determine and monitor the creditworthiness of counterparties, including but not limitedrequirements to peak season equivalent forced outage rate, contract availability, and net income.
RESULTS OF OPERATIONS
Net Income
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(52) | | (29.5) | | $(39) | | (12.4) |
Net income attributable to Southern Power for the third quarter 2017 was $124 million compared to $176 million for the corresponding period in 2016. The decrease was primarily due to decreased income tax benefits from solar ITCs and increased interest expense primarily due to a decrease in capitalized interest associated with completing construction of and placing in service solar facilities, partially offset by additional operating income related to new generating facilities.
Net income attributable to Southern Power for year-to-date 2017 was $276 million compared to $315 million for the corresponding period in 2016. The decrease was primarily due to decreased income tax benefits resulting from a reduction in solar ITCs, partially offset by an increase in wind PTCs, and increased interest expense from debt issuances to fund Southern Power's growth strategy and continuous construction program, partially offset by additional operating income from new generating facilities.
For additional information on new generating facilities placed in service during 2016 and 2017, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Acquisitions" and
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
"Construction Projects" of Southern Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein.
Operating Revenues
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $118 | | 23.6 | | $408 | | 34.3 |
Total operating revenues include PPA capacity revenues, which are derived primarily from long-term contracts involving natural gas and biomass generating facilities, and PPA energy revenues, which include sales from Southern Power's natural gas, biomass, solar, and wind facilities. To the extent Southern Power has capacity not contracted under a PPA, it may sell power into the wholesale market and, to the extent the generation assets are part of the IIC, as approved by the FERC, it may sell power into the power pool.
Natural Gas and Biomass Capacity and Energy Revenue
Capacity revenues generally represent the greatest contribution to net income and are designed to provide recovery of fixed costs plus a return on investment.
Energy is generally sold at variable costpost collateral or is indexed to published gas indices. Energy revenues will vary depending on the energy demand of Southern Power's customers and their generation capacity,other credit security, as well as the market pricesquality of wholesale energy compared topledged collateral. Collateral or credit security is most often in the costform of Southern Power's energy. Energy revenuescash or letters of credit from an investment-grade financial institution, but may also include fees for support services, fuel storage,cash or U.S. government securities held by a trustee. Prior to entering a physical transaction, Southern Company Gas assigns its counterparties an internal credit rating and unit start charges. Increasescredit limit based on the counterparties' Moody's, S&P, and decreases inFitch ratings, commercially available credit reports, and audited financial statements. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.
Southern Company Gas utilizes netting agreements whenever possible to mitigate exposure to counterparty credit risk. Netting agreements enable Southern Company Gas to net certain assets and liabilities by counterparty across product lines and against cash collateral, provided the netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, counterparties are settled net, they are recorded on a gross basis on the balance sheet as energy revenues under PPAs that are driven by fuel or purchased power prices are accompanied by an increase or decrease in fuelmarketing receivables and purchased power costs andenergy marketing payables.
The Registrants do not haveanticipate a significant impactmaterial adverse effect 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 sold to the grid. Astheir respective financial statements as a result Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, and other factors.counterparty nonperformance.
See FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" herein for additional information regarding Southern Power's PPAs.
Details of Southern Power's operating revenues were as follows:
|
| | | | | | | | | | | | | | | |
| | Third Quarter 2017 | | Third Quarter 2016 | | Year-to-Date 2017 | | Year-to-Date 2016 |
| | (in millions) |
| PPA capacity revenues | $ | 169 |
| | $ | 149 |
| | $ | 466 |
| | $ | 406 |
|
| PPA energy revenues | 299 |
| | 247 |
| | 765 |
| | 532 |
|
| Total PPA revenues | 468 |
| | 396 |
| | 1,231 |
| | 938 |
|
| Non-PPA revenues | 147 |
| | 101 |
| | 357 |
| | 241 |
|
| Other revenues | 3 |
| | 3 |
| | 9 |
| | 10 |
|
| Total operating revenues | $ | 618 |
| | $ | 500 |
| | $ | 1,597 |
| | $ | 1,189 |
|
SOUTHERN POWER COMPANY(K) ACQUISITIONS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In the third quarter 2017, total operating revenues were $618 million, reflecting a $118 million, or 24%, increase from the corresponding period in 2016. The increase in operating revenues was primarily due to the following:
PPA capacity revenues increased $20 million, or 13%, primarily due to additional customer capacity requirements and a new PPA related to natural gas facilities.
PPA energy revenues increased $52 million, or 21%, primarily due to a $55 million increase in sales from new solar and wind facilities, partially offset by a $3 million decrease in sales from natural gas PPAs due to a $24 million decrease in volume primarily due to the expiration of a PPA and reduced customer load, partially offset by a $21 million increase in the average cost of fuel.
Non-PPA revenues increased $46 million, or 46%, due to a $58 million increase in the volume of KWHs sold primarily from uncovered natural gas capacity through short-term opportunity sales, offset by a $12 million decrease in the price of energy in the wholesale markets.
For year-to-date 2017, total operating revenues were $1.6 billion, reflecting a $408 million, or 34%, increase from the corresponding period in 2016. The increase in operating revenues was primarily due to the following:
PPA capacity revenues increased $60 million, or 15%, primarily due to additional customer capacity requirements and a new PPA related to natural gas facilities.
PPA energy revenues increased $233 million, or 44%, primarily due to a $188 million increase in sales from new solar and wind facilities and a $35 million increase in sales from natural gas PPAs primarily due to a $69 million increase in the average cost of fuel, partially offset by a $34 million decrease in volume primarily due to the expiration of a PPA and reduced customer load.
Non-PPA revenues increased $116 million, or 48%, due to a $104 million increase in the volume of KWHs sold primarily from uncovered natural gas capacity through short-term opportunity sales, as well as a $12 million increase in the price of energy in the wholesale markets.
Fuel and Purchased Power Expenses
Fuel costs constitute the single largest expense for Southern Power. In addition, Southern Power purchases a portion of its electricity needs from the wholesale market. Details of Southern Power's generation and purchased power were as follows:
|
| | | | | |
| | Third Quarter 2017 | Third Quarter 2016 | | Year-to-Date 2017 | Year-to-Date 2016 |
| | (in billions of KWHs) |
| Generation | 12.5 | 11.1 | | 33.2 | 27.9 |
| Purchased power | 1.2 | 0.9 | | 3.4 | 2.5 |
| Total generation and purchased power | 13.7 | 12.0 | | 36.6 | 30.4 |
| | | | | | |
| Total generation and purchased power, excluding solar, wind, and tolling agreements | 7.2 | 6.7 | | 17.8 | 17.7 |
Southern Power's PPAs for natural gas and biomass generation generally provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing Southern Power for substantially all of the cost of fuel relating to the energy delivered under such PPAs. Consequently, changes in such fuel costs are generally accompanied by a corresponding change in related fuel revenues and do not have a significant impact on net income. Southern Power is responsible for the cost of fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the wholesale market or into the power pool for capacity owned directly by Southern Power.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Purchased power expenses will vary depending on demand, availability, and the cost of generating resources throughout the Southern Company system and other contract resources. Load requirements are submitted to the power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power, an affiliate company, or external parties. Such purchased power costs are generally recovered through PPA revenues.
Details of Southern Power's fuel and purchased power expenses were as follows:
|
| | | | | | | | | | | |
| | Third Quarter 2017
vs.
Third Quarter 2016 | | Year-to-Date 2017
vs.
Year-to-Date 2016 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | 35 |
| | 22.7 | | $ | 119 |
| | 34.9 |
| Purchased power | 10 |
| | 30.3 | | 37 |
| | 48.7 |
| Total fuel and purchased power expenses | $ | 45 |
| | | | $ | 156 |
| | |
In the third quarter 2017, total fuel and purchased power expenses increased $45 million, or 24.1%, compared to the corresponding period in 2016. Fuel expense increased $35 million primarily due to a $29 million increase in the average cost of natural gas per KWH generated and an $8 million increase in the volume of KWHs generated, excluding solar, wind, and tolling agreements. Purchased power expense increased $10 million primarily due to an increase in the volume of KWHs purchased.
For year-to-date 2017, total fuel and purchased power expenses increased $156 million, or 37.4%, compared to the corresponding period in 2016. Fuel expense increased $119 million primarily due to a $139 million increase in the average cost of natural gas per KWH generated, partially offset by a $19 million decrease in the volume of KWHs generated, excluding solar, wind, and tolling agreements. Purchased power expense increased $37 million due to a $28 million increase in the volume of KWHs purchased and a $9 million increase associated with the average cost of purchased power.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $2 | | 2.5 | | $26 | | 10.6 |
In the third quarter 2017, other operations and maintenance expenses were $83 million compared to $81 million for the corresponding period in 2016. The increase was primarily due to a $13 million increase associated with new solar, wind, and gas facilities, partially offset by a $5 million decrease in scheduled outage maintenance expenses and a $5 million decrease in non-outage operations and maintenance expenses.
For year-to-date 2017, other operations and maintenance expenses were $272 million compared to $246 million for the corresponding period in 2016. The increase was primarily due to a $48 million increase associated with new solar, wind, and gas facilities and an $8 million increase associated with employee compensation and expenses in support of Southern Power's overall growth strategy, partially offset by a $22 million decrease in scheduled outage maintenance expenses and an $8 million decrease in non-outage operations and maintenance expenses.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Depreciation and Amortization
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $38 | | 40.9 | | $132 | | 53.4 |
In the third quarter 2017, depreciation and amortization was $131 million compared to $93 million for the corresponding period in 2016. For year-to-date 2017, depreciation and amortization was $379 million compared to $247 million for the corresponding period in 2016. The increases were primarily due to new solar, wind, and gas facilities placed in service.
Taxes Other Than Income Taxes
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $8 | | 160.0 | | $20 | | 117.6 |
In the third quarter 2017, taxes other than income taxes were $13 million compared to $5 million for the corresponding period in 2016. For year-to-date 2017, taxes other than income taxes were $37 million compared to $17 million for the corresponding period in 2016. These increases were primarily due to additional property taxes due to new solar, wind, and gas facilities.
Interest Expense, net of Amounts Capitalized
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $12 | | 34.3 | | $66 | | 84.6 |
In the third quarter 2017, interest expense, net of amounts capitalized was $47 million compared to $35 million for the corresponding period in 2016. The increase was primarily due to an $8 million decrease in capitalized interest associated with completing construction of and placing in service solar facilities and an increase of $3 million in interest expense due to an increase in average outstanding long-term debt, primarily to fund Southern Power's growth strategy and continuous construction program.
For year-to-date 2017, interest expense, net of amounts capitalized was $144 million compared to $78 million for the corresponding period in 2016. The increase was primarily due to an increase of $39 million in interest expense due to an increase in average outstanding long-term debt, primarily to fund Southern Power's growth strategy and continuous construction program, as well as a $25 million decrease in capitalized interest associated with completing construction of and placing in service solar facilities.
Other Income (Expense), Net
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1 | | 50.0 | | $— | | — |
In the third quarter 2017, other income (expense), net was $3 million compared to $2 million for the corresponding period in 2016. Other income (expense), net was $3 million for both year-to-date 2017 and 2016. The changes include increases of $36 million and $152 million from currency losses arising from translation of €1.1 billion euro-denominated fixed-rate notes into U.S. dollars for the third quarter and year-to-date 2017, respectively, fully offset by an equal change in gains on the foreign currency hedges that were reclassified from accumulated OCI into earnings. See Note (H) to the Condensed Financial Statements herein for additional information.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Income Taxes (Benefit)
|
| | | | | | |
| Third Quarter 2017 vs. Third Quarter 2016 | | Year-to-Date 2017 vs. Year-to-Date 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $63 | | 61.8 | | $38 | | 22.8 |
In the third quarter 2017, income tax benefit was $39 million compared to $102 million for the corresponding period in 2016. The decrease was primarily due to a $61 million decrease in income tax benefits from solar ITCs.
For year-to-date 2017, income tax benefit was $129 million compared to $167 million for the corresponding period in 2016. The decrease was primarily due to a $102 million decrease in income tax benefits from solar ITCs, partially offset by a $58 million increase in wind PTCs and a $4 million increase resulting from state apportionment rate changes.DISPOSITIONS
See Note (G) to the Condensed Financial Statements herein for additional information on income taxes and Note 115 to the financial statements of Southern Power under "Income and Other Taxes" in Item 8 of the Form 10-K for additional information on ITCs and PTCs.information.
FUTURE EARNINGS POTENTIALAlabama Power
On September 30, 2022, Alabama Power completed its acquisition of the Calhoun Generating Station, which was accounted for as an asset acquisition. The resultstotal purchase price was $179 million, of operations discussed above are not necessarily indicative of Southern Power's future earnings potential. The level of Southern Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Power's competitive wholesale business. These factors include: Southern Power's ability to achieve sales growth while containing costs; regulatory matters; creditworthiness of customers; total generating capacity available in Southern Power's market areas; the successful remarketing of capacity as current contracts expire; Southern Power's ability to execute its growth strategy, including successful additional investments in renewable and other energy projects, and to develop and construct generating facilities. Current proposalswhich $171 million was related to potential federal tax reform legislation arenet assets recorded within property, plant, and equipment on the balance sheet and the remainder primarily focused on reducing the corporate income tax rate, allowing 100% of capital expendituresrelated to be deducted,fossil fuel stock and eliminating the interest deduction. The ultimate impact of any tax reform proposals, including any potential changesmaterials and supplies. See Note (B) and Note 15 to the availability or realizability of ITCs and PTCs, is dependent on the final form of any legislation enacted and the related transition rules, and cannot be determined at this time, but could have a material impact on Southern Power's consolidated financial statements.
Southern Power is considering the sale of up to a one-third equity interest in its solar asset portfolio. The ultimate outcome of this matter cannot be determined at this time.
Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, as well as renewable portfolio standards, which may impact future earnings.
Other factors that could influence future earnings include weather, demand, cost of generation from facilities within the power pool, and operational limitations. For additional information relating to these factors, see RISK FACTORSstatements 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 18 of the Form 10-K for additional information regarding Southern Power's PPAs. Generally, under the solar and wind generation PPAs, the purchasing party retains the right to keep or resell the renewable energy credits.
At September 30, 2017, Southern Power's average investment coverage ratio for its generating assets, based on the ratio of investment under contract to total investment using the respective generation facilities' net book value (or expected in-service value for facilities under construction) as the investment amount, was 91% through 2021 and 90% through 2026, with an average remaining contract duration of approximately 16 years.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Environmental Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Power in Item 7 of the Form 10-K for information on the development by federal and state environmental regulatory agencies of additional control strategies for emissions of air pollution from industrial sources, including electric generating facilities. Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, water quality, or other environmental and health concerns could also significantly affect Southern Power. While Southern Power's PPAs generally contain provisions that permit charging the counterparty with some of the new costs incurred as a result of changes in environmental laws and regulations, the full impact of any such legislative or regulatory changes cannot be determined at this time.
Environmental Statutes and Regulations
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Southern Power in Item 7 of the Form 10-K for additional information regarding the final effluent guidelines rule.
On April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. On September 18, 2017, the EPA published a final rule establishing a stay of the compliance deadlines for certain effluent limitations and pretreatment standards under the rule.
The ultimate outcome of this matter cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Southern Power in Item 7 of the Form 10-K"Alabama Power" for additional information.
On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules. On October 16, 2017, the EPA published a proposed rule to repeal the Clean Power Plan. The EPA has not determined whether or when it will promulgate a replacement rule.
On June 1, 2017, the U.S. President announced that the United States will withdraw from the non-binding Paris Agreement and begin renegotiation of its terms.
The ultimate outcome of these matters cannot be determined at this time.
FERC Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Southern Power in Item 7 of the Form 10-K for additional information regarding the traditional electric operating companies' and Southern Power's market power proceeding and amendment to their market-rate tariff.
On May 17, 2017, the FERC accepted the traditional electric operating companies' and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' and Southern Power's market power proceeding related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' and Southern Power's June 30, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
order, or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and Southern Power expect to make a filing within the specified 60 days responding to the FERC's order.
The ultimate outcome of these matters cannot be determined at this time.
Acquisitions
During the nine months ended September 30, 2017, in accordance with Southern Power's overall growth strategy, one of Southern Power's wholly-owned subsidiaries acquired the project discussed below. Acquisition-related costs were expensed as incurred and were not material. See Note (I) to the Condensed Financial Statements under "Southern Power" herein and MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Power in Item 7 of the Form 10-K for additional information.
|
| | | | | | | | | |
| Project Facility | Resource | Approximate Nameplate Capacity (MW) | Location | Percentage Ownership | Actual COD | PPA Counterparties | PPA Contract Period |
| Bethel | Wind | 276 | Castro County, TX | 100 | % | | January 2017 | Google Energy, LLC | 12 years |
The aggregate amounts of revenue and net income recognized by Southern Power related to the Bethel facility included in Southern Power's condensed consolidated statements of income for year-to-date 2017 were immaterial. The Bethel facility did not have operating revenues or activities prior to completion of construction and the assets being placed in service; therefore, supplemental pro forma information as though the acquisition occurred as of the beginning of 2017 and for the comparable 2016 period is not meaningful and has been omitted.
Subsequent to September 30, 2017, Southern Power purchased all of the redeemable noncontrolling interests, representing 10% of the membership interests, in Southern Turner Renewable Energy, LLC and repaid $14 million of notes payable to Turner Renewable Energy, LLC.
Construction Projects
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" of Southern Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information.
Construction Projects Completed and in Progress
During the nine months ended September 30, 2017, in accordance with its overall growth strategy,2022, Southern Power completed construction of and placed in service or continued constructionthe remaining 40 MWs of the projects set forthTranquillity battery energy storage facility and the remaining 15 MWs of the Garland battery energy storage facility.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | | | | |
| Project Facility | Resource | Approximate Nameplate Capacity (MW) | Location | COD | PPA Contract Period |
| Projects Completed During the Nine Months Ended September 30, 2022 |
Garland Solar Storage(a) | Battery energy storage system | 88 | Kern County, CA | September 2021 through February 2022(b) | 20 years |
Tranquillity Solar Storage(a) | Battery energy storage system | 72 | Fresno County, CA | November 2021 through March 2022(c) | 20 years |
(a)Southern Power consolidates each project's operating results in its financial statements and the tax equity partner and two other partners each own a noncontrolling interest.
(b)The facility has a total capacity of 88 MWs, of which 73 MWs were placed in service in 2021 and 15 MWs were placed in service in February 2022.
(c)The facility has a total capacity of 72 MWs, of which 32 MWs were placed in service in 2021 and 40 MWs were placed in service in March 2022.
Southern Company Gas
Sale of Natural Gas Storage Facilities
On September 7, 2022, certain affiliates of Southern Company Gas entered into agreements to sell two natural gas storage facilities located in California and Texas for an aggregate purchase price of $186 million, plus working capital and certain other adjustments. Completion of the sales is subject to material closing conditions, including, among others, release of a Southern Company Gas parent guarantee, approval from the California Public Utility Commission without a material burdensome condition, and the expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. The parent guarantee release was executed on October 20, 2022, which resolved a material closing condition. As a result, Southern Company Gas expects to record pre-tax impairment charges totaling approximately $125 million ($95 million after tax) in the following table. Through September 30, 2017, total costsfourth quarter 2022. The sale of construction incurred for these projects were $494 million, of which $122 million remained in CWIP. Total aggregate construction costs, excluding the acquisition costs, areTexas facility is expected to be between $360 millioncompleted later in the fourth quarter 2022, and $415 million for the Mankato and Cactus Flats facilities. Thesale of the California facility is expected to be completed during 2023; however, the ultimate outcome of these matters cannot be determined at this time.
Sale of Pivotal LNG
On May 20, 2022, Southern Company Gas received the final $5 million contingent payment from Dominion Modular LNG Holdings, Inc. in connection with its 2020 sale of Pivotal LNG, Inc.
(L) 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 traditional electric operating companies are vertically integrated utilities providing electric service in three Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy and battery energy storage 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 pipeline investments and gas marketing services. Prior to the sale of Sequent on July 1, 2021, Southern Company Gas' other businesses also included wholesale gas services.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OFNOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(UNAUDITED)
Southern Company's reportable business segments are the sale of electricity by the traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Company Gas. Revenues from sales by Southern Power to the traditional electric operating companies were $336 million and $673 million for the three and nine months ended September 30, 2022, respectively, and $167 million and $361 million for the three and nine months ended September 30, 2021, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies were immaterial for all periods presented. Revenues from sales of natural gas from Southern Company Gas (prior to its sale of Sequent) to Southern Power were $18 million for the nine months ended September 30, 2021. 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 distributed energy and resilience solutions and deploying microgrids for commercial, industrial, governmental, and utility customers, as well as investments in telecommunications and, for the three and nine months ended September 30, 2021, leveraged lease projects. All other inter-segment revenues are not material.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Financial data for business segments and products and services for the three and nine months ended September 30, 2022 and 2021 was as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Electric Utilities | | | | |
| Traditional
Electric Operating
Companies | Southern
Power | Eliminations | Total | Southern Company Gas | All
Other | Eliminations | Consolidated |
| (in millions) |
| Three Months Ended September 30, 2022 | | | | | | | |
| Operating revenues | $ | 6,938 | | $ | 1,180 | | $ | (691) | | $ | 7,427 | | $ | 857 | | $ | 135 | | $ | (41) | | $ | 8,378 | |
Segment net income (loss)(a)(b) | 1,445 | | 95 | | — | | 1,540 | | 83 | | (152) | | 1 | | 1,472 | |
| Nine Months Ended September 30, 2022 | | | | | | | |
| Operating revenues | $ | 16,716 | | $ | 2,618 | | $ | (1,391) | | $ | 17,943 | | $ | 3,998 | | $ | 418 | | $ | (127) | | $ | 22,232 | |
Segment net income (loss)(a)(b) | 3,256 | | 265 | | — | | 3,521 | | 516 | | (415) | | (11) | | 3,611 | |
| At September 30, 2022 | | | | | | | | |
| Goodwill | $ | — | | $ | 2 | | $ | — | | $ | 2 | | $ | 5,015 | | $ | 263 | | $ | — | | $ | 5,280 | |
| Total assets | 95,659 | | 13,283 | | (748) | | 108,194 | | 24,097 | | 2,372 | | (658) | | 134,005 | |
| Three Months Ended September 30, 2021 | | | | | | | |
| Operating revenues | $ | 5,018 | | $ | 679 | | $ | (170) | | $ | 5,527 | | $ | 623 | | $ | 124 | | $ | (36) | | $ | 6,238 | |
Segment net income (loss)(a)(b)(c) | 1,085 | | 78 | | — | | 1,163 | | 56 | | (121) | | 3 | | 1,101 | |
| Nine Months Ended September 30, 2021 | | | | | | | |
| Operating revenues | $ | 12,813 | | $ | 1,610 | | $ | (372) | | $ | 14,051 | | $ | 2,994 | | $ | 412 | | $ | (111) | | $ | 17,346 | |
Segment net income (loss)(a)(b)(c)(d)(e) | 2,352 | | 211 | | — | | 2,563 | | 389 | | (338) | | (6) | | 2,608 | |
| At December 31, 2021 | | | | | | | | |
| Goodwill | $ | — | | $ | 2 | | $ | — | | $ | 2 | | $ | 5,015 | | $ | 263 | | $ | — | | $ | 5,280 | |
| Total assets | 89,051 | | 13,390 | | (667) | | 101,774 | | 23,560 | | 2,975 | | (775) | | 127,534 | |
(a)Attributable to Southern Company.
(b)For the traditional electric operating companies, includes pre-tax charges (credits) to income at Georgia Power for the estimated probable loss associated with the construction of Plant Vogtle Units 3 and 4 of $(70) million ($(52) million after tax) and $(18) million ($(13) million after tax) for the three and nine months ended September 30, 2022, respectively, and $264 million ($197 million after tax) and $772 million ($576 million after tax) for the three and nine months ended September 30, 2021, respectively. See Note (B) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.
(c)For Southern Company Gas, includes a pre-tax gain of $121 million ($93 million after tax) related to its sale of Sequent, as well as the resulting $85 million of additional tax expense as a result of the sale. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
(d)For Southern Power, includes gains on wind turbine equipment contributed to various equity method investments totaling approximately $37 million pre-tax ($28 million after tax). See Note 15 to the financial statements under "Southern Power – Development Projects" in Item 8 of the Form 10-K for additional information.
(e)For Southern Company Gas, includes pre-tax impairment charges totaling $84 million ($67 million after tax) related to its equity method investment in the PennEast Pipeline project. See Note 7 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Products and Services
| | | | | | | | | | | | | | |
| | Electric Utilities' Revenues |
| Retail | Wholesale | Other | Total |
| (in millions) |
| Three Months Ended September 30, 2022 | $ | 5,961 | | $ | 1,197 | | $ | 269 | | $ | 7,427 | |
| Three Months Ended September 30, 2021 | 4,551 | | 731 | | 245 | | 5,527 | |
| Nine Months Ended September 30, 2022 | $ | 14,363 | | $ | 2,798 | | $ | 782 | | $ | 17,943 | |
| Nine Months Ended September 30, 2021 | 11,492 | | 1,822 | | 737 | | 14,051 | |
| | | | | | | | | | | | | | | | | |
| | Southern Company Gas' Revenues |
| Gas
Distribution
Operations | Wholesale Gas Services(*) | Gas
Marketing
Services | Other | Total |
| (in millions) |
| Three Months Ended September 30, 2022 | $ | 748 | | $ | — | | $ | 85 | | $ | 24 | | $ | 857 | |
| Three Months Ended September 30, 2021 | 553 | | — | | 52 | | 18 | | 623 | |
| Nine Months Ended September 30, 2022 | $ | 3,513 | | $ | — | | $ | 420 | | $ | 65 | | $ | 3,998 | |
| Nine Months Ended September 30, 2021 | 2,451 | | 188 | | 311 | | 44 | | 2,994 | |
(*)Prior to the sale of Sequent, the revenues for wholesale gas services were netted with costs associated with its energy and risk management activities. See "Southern Company Gas" herein and Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Southern Company Gas
Southern Company Gas manages its business through three reportable segments – gas distribution operations, gas pipeline investments, and gas marketing services. Prior to the sale of Sequent on July 1, 2021, Southern Company Gas' reportable segments also included wholesale gas services. The non-reportable segments are combined and presented as all other. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information on the sale of Sequent.
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 four states.
Gas pipeline investments consists of joint ventures in natural gas pipeline investments including a 50% interest in SNG 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. Gas pipeline investments also includes a 20% ownership interest in the PennEast Pipeline project, which was cancelled in September 2021. See Note 7 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Through July 1, 2021, wholesale gas services provided 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 engaged in natural gas storage and gas pipeline arbitrage and related activities.
Gas marketing services provides natural gas marketing to end-use customers primarily in Georgia and Illinois through SouthStar.
The all other column includes segments and subsidiaries that fall below the quantitative threshold for separate disclosure, including storage and fuels operations. See Note (K) under "Southern Company Gas" for information regarding agreements by certain affiliates of Southern Company Gas to sell two natural gas storage facilities.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Business segment financial data for the three and nine months ended September 30, 2022 and 2021 was as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Gas Distribution Operations | Gas Pipeline Investments | Wholesale Gas Services(a) | Gas Marketing Services | Total | All Other | Eliminations | Consolidated |
| (in millions) |
| Three Months Ended September 30, 2022 | | | | | | |
| Operating revenues | $ | 751 | | $ | 8 | | $ | — | | $ | 85 | | $ | 844 | | $ | 16 | | $ | (3) | | $ | 857 | |
| Segment net income (loss) | 59 | | 24 | | — | | (2) | | 81 | | 2 | | — | | 83 | |
| Nine Months Ended September 30, 2022 | | | | | | |
| Operating revenues | $ | 3,533 | | $ | 24 | | $ | — | | $ | 420 | | $ | 3,977 | | $ | 43 | | $ | (22) | | $ | 3,998 | |
| Segment net income (loss) | 365 | | 76 | | — | | 65 | | 506 | | 10 | | — | | 516 | |
| Total assets at September 30, 2022 | 21,605 | | 1,425 | | — | | 1,595 | | 24,625 | | 9,100 | | (9,628) | | 24,097 | |
| Three Months Ended September 30, 2021 | | | | | | |
| Operating revenues | $ | 556 | | $ | 8 | | $ | — | | $ | 52 | | $ | 616 | | $ | 11 | | $ | (4) | | $ | 623 | |
Segment net income (loss)(b)(c) | 45 | | 10 | | 94 | | (2) | | 147 | | (91) | | — | | 56 | |
| Nine Months Ended September 30, 2021 | | | | | | | |
| Operating revenues | $ | 2,466 | | $ | 24 | | $ | 188 | | $ | 311 | | $ | 2,989 | | $ | 29 | | $ | (24) | | $ | 2,994 | |
Segment net income (loss)(b)(c)(d) | 308 | | 3 | | 108 | | 60 | | 479 | | (90) | | — | | 389 | |
| Total assets at December 31, 2021 | 20,917 | | 1,467 | | 31 | | 1,556 | | 23,971 | | 12,114 | | (12,525) | | 23,560 | |
(a)As a result of the sale of Sequent, wholesale gas services is no longer a reportable segment for the three and nine months ended September 30, 2022. Prior to the sale of Sequent, the revenues for wholesale gas services were 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) |
| | | | | |
| | | | | |
| | | | | |
| Nine Months Ended September 30, 2021 | $ | 3,881 | | $ | 90 | | $ | 3,971 | | $ | 3,783 | | $ | 188 | |
(b)For wholesale gas services, includes a pre-tax gain of $121 million ($93 million after tax) related to the sale of Sequent. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
(c)For the "All Other" column, includes $85 million of additional tax expense as a result of the sale. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
(d)For gas pipeline investments, includes pre-tax impairment charges totaling $84 million ($67 million after tax) related to the equity method investment in the PennEast Pipeline project. See Note 7 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.
|
| | | | | | |
Project Facility | Resource | Approximate Nameplate Capacity (MW)
| Location | Actual/Expected COD | PPA Counterparties | PPA Contract PeriodPage |
Projects Completed During the Nine Months Ended September 30, 2017 |
East Pecos | Solar | 120 | Pecos County, TX | March 2017 | Austin Energy | 15 years |
Lamesa | Solar | 102 | Dawson County, TX | April 2017 | CityCombined Management's Discussion and Analysis of Garland, Texas | 15 years |
| | | | | | |
Projects Under Construction asFinancial Condition and Results of September 30, 2017 |
Cactus Flats(*)
| Wind | 148 | Concho County, TX | Third quarter 2018 | General Motors, LLC
and
General Mills Operations LLC | 12 years
and
15 years |
Mankato | Natural Gas | 345 | Mankato, MN | Second quarter 2019 | Northern States Power Company | 20 years |
Development Projects
In December 2016,The following Management's Discussion and Analysis of Financial Condition and Results of Operations is a combined presentation; however, information contained herein relating to any individual Registrant is filed by such Registrant on its own behalf and each Registrant makes no representation as part of Southern Power's renewable development strategy, one of Southern Power's wholly-owned subsidiaries entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct approximately 3,000 MWs of wind projects. Also in December 2016, Southern Power signed agreements and made payments to purchase wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. All of the wind turbine equipment was delivered by April 2017, which allows the projects to qualify for 100% PTCs for 10 years following their expected commercial operation dates between 2018 and 2020. The ultimate outcome of these matters cannot be determined at this time.
Income Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Southern Power in Item 7 of the Form 10-K and Note (G)information related to the Condensed Financial Statements herein for additional information.
During the third quarter 2017, Southern Power began a legal entity reorganization of various direct and indirect subsidiaries that own and operate solar facilities, including certain subsidiaries owned in partnership with various third parties. Southern Power's ownership interests in the various solar entities and facilities will not be affected by the reorganization. The reorganization is expected to result in estimated tax benefits totaling approximately $40 million that will be recorded in the fourth quarter 2017 related to certain changes in state apportionment rates and net operating loss carryforward utilization. The ultimate outcome of this matter cannot be determined at this time.
Other Matters
Southern Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Power is subject to certain claims and legal actions arising in the ordinary course of business. Southern Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
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
Registrants.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Power's financial statements.
During 2015, Southern Power indirectly acquired a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock facility in Pecos County, Texas, which was under construction by Recurrent Energy, LLC and was subsequently placed in service in November 2016. Prior to placing the facility in service, certain solar panels were damaged during installation. While the facility currently is generating energy consistent with operational expectations and PPA obligations, Southern Power is pursuing remedies under its insurance policies and other contracts to repair or replace these solar panels. In connection therewith, Southern Power is withholding payments of approximately $26 million from the construction contractor, who has placed a lien on the Roserock facility for the same amount. The amounts withheld are included in other accounts payable and other current liabilities on Southern Power's consolidated balance sheets. On May 18, 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas, against X.L. America, Inc. (XL) and North American Elite Insurance Company (North American Elite) seeking recovery from an insurance policy for damages resulting from a hail storm and certain installation practices by the construction contractor, McCarthy Building Companies, Inc. (McCarthy). On May 19, 2017, Roserock filed a separate lawsuit against McCarthy in the state district court in Travis County, Texas alleging breach of contract and breach of warranty for the damages sustained at the Roserock facility, which has since been moved to the U.S. District Court for the Western District of Texas. On May 22, 2017, McCarthy filed a counter lawsuit against Roserock, Array Technologies, Inc., Canadian Solar (USA), Inc., XL, and North American Elite in the U.S. District Court for the Western District of Texas alleging, among other things, breach of contract, and requesting foreclosure of mechanic's liens against Roserock. On July 18, 2017, the U.S. District Court for the Western District of Texas consolidated the two pending lawsuits. Southern Power intends to vigorously pursue and defend these matters, the ultimate outcome of which cannot be determined at this time.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Power prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Power in Item 7 of the Form 10-K for a complete discussion of Southern Power's critical accounting policies and estimates related to Revenue Recognition, Impairment of Long-Lived Assets and Intangibles, Acquisition Accounting, and ITCs.
Recently Issued Accounting Standards
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Southern Power in Item 7 of the Form 10-K for additional information.
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
While Southern Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. However, given Southern Power's core activities of selling generation capacity and energy to high credit rated customers, Southern Power currently does not expect the new standard to have a significant impact to net income. Southern Power's ongoing evaluation of revenue streams and
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
related contracts includes the evaluation of identified revenue streams tied to longer-term contractual arrangements, such as certain capacity and energy payments under PPAs that are expected to be excluded from the scope of ASC 606 and included in the scope of the current leasing guidance (ASC 840).
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Southern Power intends to use the modified retrospective method of adoption effective January 1, 2018. Southern Power has also elected to utilize practical expedients which allow it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Southern Power's financial statements, Southern Power will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with early adoption permitted. Southern Power is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on Southern Power's financial statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Power in Item 7 of the Form 10-K for additional information. Southern Power's financial condition remained stable at September 30, 2017. Southern Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements as needed to meet future capital and liquidity needs. See "Sources of Capital" herein for additional information on lines of credit.
Southern Power anticipates utilizing third-party tax equity as one of the financing sources to fund its renewable growth strategy; however, the use of third-party tax equity structures is not expected to have a material impact on future earnings. Subsequent to September 30, 2017, Southern Power secured third-party tax equity funding for the recently acquired Cactus Flats project subject to achieving commercial operation and various other customary conditions to closing. The ultimate outcome of this matter cannot be determined at this time.
Net cash provided from operating activities totaled $895 million for the first nine months of 2017 compared to $269 million for the first nine months of 2016. The increase in net cash provided from operating activities was primarily due to income tax refunds received and an increase in energy sales arising from new solar and wind facilities, partially offset by an increase in interest paid. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Bonus Depreciation" of Southern Power in Item 7 of the Form 10-K for additional information. Net cash used for investing activities totaled $1.5 billion for the first nine months of 2017 primarily due to payments for renewable acquisitions and the construction of generating facilities. Net cash used for financing activities totaled $325 million for the first nine months of 2017 primarily due to common stock dividend payments, a decrease in notes payable, and distributions to noncontrolling interests, partially offset by capital contributions from noncontrolling interests. Cash flows from financing activities may vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first nine months of 2017 include a $1.0 billion increase in property, plant,
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
and equipment in-service primarily related to acquisitions and completing construction of and placing in service solar facilities, a $921 million decrease in cash and cash equivalents, and a $461 million decrease in acquisitions payable.
See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Power in Item 7 of the Form 10-K for a description of Southern Power's capital requirements for its construction program, scheduled maturities of long-term debt, as well as the related interest, derivative obligations, leases, unrecognized tax benefits, and other purchase commitments. Approximately $864 million will be required to repay maturities of long-term debt through September 30, 2018.
Southern Power's construction program includes estimates for potential plant acquisitions, new construction and development, capital improvements, and work to be performed under LTSAs and is subject to periodic review and revision. Planned expenditures for plant acquisitions may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. Actual capital costs may vary from these estimates because of numerous factors such as: changes in business conditions; changes in the expected environmental compliance program; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in FERC rules and regulations; changes in load projections; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. See Note (I) to the Condensed Financial Statements herein for additional information.
Sources of Capital
Southern Power plans to obtain the funds required for acquisitions, construction, development, debt maturities, and other purposes from operating cash flows, short-term debt, securities issuances, term loans, tax equity partnership contributions, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Power in Item 7 of the Form 10-K for additional information.
As of September 30, 2017, Southern Power's current liabilities exceeded current assets by $497 million due to long-term debt maturing in the next 12 months, the use of short-term debt as a funding source, and fluctuations in cash needs, due to both seasonality and the stage of acquisitions and construction projects. Southern Power believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility (as defined below), bank term loans, the debt capital markets, and operating cash flows.
As of September 30, 2017, Southern Power had cash and cash equivalents of approximately $178 million.
Southern Power's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities, for general corporate purposes, and to finance maturing debt. Commercial paper is included in notes payable on the condensed consolidated balance sheet at September 30, 2017.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of commercial paper were as follows:
|
| | | | | | | | | | | | | | | | |
| | Short-term Debt at September 30, 2017 | | Short-term Debt During the Period (*) |
| | Amount Outstanding | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | (in millions) | | | (in millions) | | | | (in millions) |
| Commercial paper | $ | 120 |
| 1.5 | % | | $ | 322 |
| | 1.5 | % | | $ | 416 |
|
| |
(*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2017. |
At September 30, 2017, Southern Power had a committed credit facility (Facility) of $750 million, of which $22 million has been used for letters of credit and $728 million remains unused. In May 2017, Southern Power amended the Facility, which, among other things, extended the maturity date from 2020 to 2022 and increased Southern Power's borrowing ability under this Facility to $750 million from $600 million. Proceeds from the Facility may be used for working capital and general corporate purposes as well as liquidity support for Southern Power's commercial paper program. Subject to applicable market conditions, Southern Power expects to renew or replace the Facility, as needed, prior to expiration. In connection therewith, Southern Power may extend the maturity date and/or increase or decrease the lending commitment thereunder. See Note 6 to the financial statements of Southern Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
The Facility, as well as Southern Power's term loan agreement, contains a covenant that limits the ratio of debt to capitalization (as defined in the Facility) to a maximum of 65% and contains a cross-default provision that is restricted only to indebtedness of Southern Power. For purposes of this definition, debt excludes any project debt incurred by certain subsidiaries of Southern Power to the extent such debt is non-recourse to Southern Power, and capitalization excludes the capital stock or other equity attributable to such subsidiary. Southern Power is currently in compliance with all covenants in the Facility.
Southern Power also has a $120 million continuing letter of credit facility for standby letters of credit expiring in 2019. At September 30, 2017, $111 million has been used for letters of credit and $9 million remains unused.
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.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2, or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, energy price risk management, and transmission.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The maximum potential collateral requirements under these contracts at September 30, 2017 were as follows:
|
| | | |
| Credit Ratings | Maximum Potential
Collateral
Requirements |
| | (in millions) |
| At BBB and/or Baa2 | $ | 37 |
|
| At BBB- and/or Baa3 | $ | 398 |
|
At BB+ and/or Ba1(*) | $ | 1,124 |
|
| |
(*) | 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 Alabama Power or Georgia Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Power to access capital markets and would be likely to impact the cost at which it does so.
In addition, Southern Power has a PPA that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power's credit. The PPA requires credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses resulting from a credit downgrade.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including Southern Power) from stable to negative.
Financing Activities
In September 2017, Southern Power amended its $60 million aggregate principal amount floating rate bank loan to, among other things, increase the aggregate principal amount to $100 million and extend the maturity date from September 2017 to October 2018. The additional $40 million of proceeds were used to repay existing indebtedness and for other general corporate purposes.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
SOUTHERN COMPANY GAS
AND SUBSIDIARY COMPANIES
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | For the Three Months Ended September 30, | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | | July 1, 2016 through September 30, | | | January 1, 2016 through
June 30, |
| | 2017 | | 2016 | | 2017 | | 2016 | | | 2016 |
| | (in millions) | | | (in millions) |
| Operating Revenues: | | | | | | | | | | |
Natural gas revenues (includes revenue
taxes of $9, $9, $75, $9, and $57 for the
periods presented, respectively) | $ | 532 |
| | $ | 518 |
| | $ | 2,746 |
| | $ | 518 |
| | | $ | 1,841 |
|
| Other revenues | 33 |
| | 25 |
| | 95 |
| | 25 |
| | | 64 |
|
| Total operating revenues | 565 |
| | 543 |
| | 2,841 |
| | 543 |
| | | 1,905 |
|
| Operating Expenses: | | | | | | | | | | |
| Cost of natural gas | 134 |
| | 133 |
| | 1,085 |
| | 133 |
| | | 755 |
|
| Cost of other sales | 7 |
| | 2 |
| | 20 |
| | 2 |
| | | 14 |
|
| Other operations and maintenance | 205 |
| | 216 |
| | 671 |
| | 216 |
| | | 454 |
|
| Depreciation and amortization | 125 |
| | 116 |
| | 370 |
| | 116 |
| | | 206 |
|
| Taxes other than income taxes | 26 |
| | 29 |
| | 140 |
| | 29 |
| | | 99 |
|
| Merger-related expenses | — |
| | 35 |
| | — |
| | 35 |
| | | 56 |
|
| Total operating expenses | 497 |
| | 531 |
| | 2,286 |
| | 531 |
| | | 1,584 |
|
| Operating Income | 68 |
| | 12 |
| | 555 |
| | 12 |
| | | 321 |
|
| Other Income and (Expense): | | | | | | | | | | |
| Earnings from equity method investments | 32 |
| | 29 |
| | 100 |
| | 29 |
| | | 2 |
|
| Interest expense, net of amounts capitalized | (51 | ) | | (39 | ) | | (145 | ) | | (39 | ) | | | (96 | ) |
| Other income (expense), net | 18 |
| | 9 |
| | 26 |
| | 9 |
| | | 5 |
|
| Total other income and (expense) | (1 | ) | | (1 | ) | | (19 | ) | | (1 | ) | | | (89 | ) |
| Earnings Before Income Taxes | 67 |
| | 11 |
| | 536 |
| | 11 |
| | | 232 |
|
| Income taxes | 52 |
| | 7 |
| | 233 |
| | 7 |
| | | 87 |
|
| Net Income | 15 |
| | 4 |
| | 303 |
| | 4 |
| | | 145 |
|
Less: Net income attributable to
noncontrolling interest | — |
| | — |
| | — |
| | — |
| | | 14 |
|
Net Income Attributable to
Southern Company Gas | $ | 15 |
| | $ | 4 |
| | $ | 303 |
| | $ | 4 |
| | | $ | 131 |
|
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | For the Three Months Ended September 30, | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | | July 1, 2016 through September 30, | | | January 1, 2016 through
June 30, |
| | 2017 | | 2016 | | 2017 | | 2016 | | | 2016 |
| | (in millions) | | | (in millions) |
| Net Income | $ | 15 |
| | $ | 4 |
| | $ | 303 |
| | $ | 4 |
| | | $ | 145 |
|
| Other comprehensive income (loss): | | | | | | | | | | |
| Qualifying hedges: | | | | | | | | | | |
Changes in fair value, net of tax of
$-, $(2), $(2), $(2), and $(23),
respectively | — |
| | (3 | ) | | (3 | ) | | (3 | ) | | | (41 | ) |
Reclassification adjustment for
amounts included in net income,
net of tax of $-, $-, $-, $-, and $-,
respectively | — |
| | — |
| | — |
| | — |
| | | 1 |
|
Pension and other postretirement
benefit plans: | | | | | | | | | | |
Reclassification adjustment for
amounts included in net income,
net of tax of $-, $-, $(1), $-, and $4,
respectively | — |
| | — |
| | — |
| | — |
| | | 5 |
|
| Total other comprehensive income (loss) | — |
| | (3 | ) | | (3 | ) | | (3 | ) | | | (35 | ) |
| Comprehensive Income | 15 |
| | 1 |
| | 300 |
| | 1 |
| | | 110 |
|
Less: Comprehensive income attributable to
noncontrolling interest | — |
| | — |
| | — |
| | — |
| | | 14 |
|
Comprehensive Income Attributable to
Southern Company Gas | $ | 15 |
| | $ | 1 |
| | $ | 300 |
| | $ | 1 |
| | | $ | 96 |
|
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | For the Nine Months Ended September 30, | | July 1, 2016 through September 30, | | | January 1, 2016 through
June 30, |
| | 2017 | | 2016 | | | 2016 |
| | (in millions) | | | (in millions) |
| Operating Activities: | | | | | | |
| Net income | $ | 303 |
| | $ | 4 |
| | | $ | 145 |
|
Adjustments to reconcile net income
to net cash provided from operating activities — | | | | | | |
| Depreciation and amortization, total | 370 |
| | 116 |
| | | 206 |
|
| Deferred income taxes | 265 |
| | (30 | ) | | | 8 |
|
| Pension, postretirement, and other employee benefits | (4 | ) | | (123 | ) | | | 5 |
|
| Stock based compensation expense | 25 |
| | 11 |
| | | 20 |
|
| Hedge settlements | — |
| | (35 | ) | | | (26 | ) |
| Mark-to-market adjustments | (32 | ) | | 17 |
| | | 162 |
|
| Other, net | (67 | ) | | (47 | ) | | | (82 | ) |
| Changes in certain current assets and liabilities — | | | | | | |
| -Receivables | 534 |
| | (18 | ) | | | 181 |
|
| -Natural gas for sale, net of temporary LIFO liquidation | — |
| | (222 | ) | | | 273 |
|
| -Prepaid income taxes | (7 | ) | | 1 |
| | | 151 |
|
| -Other current assets | (42 | ) | | (36 | ) | | | 37 |
|
| -Accounts payable | (169 | ) | | 78 |
| | | 43 |
|
| -Accrued taxes | (24 | ) | | (11 | ) | | | 41 |
|
| -Accrued compensation | (11 | ) | | (36 | ) | | | (21 | ) |
| -Other current liabilities | 8 |
| | (11 | ) | | | (30 | ) |
| Net cash provided from (used for) operating activities | 1,149 |
| | (342 | ) | | | 1,113 |
|
| Investing Activities: | | | | | | |
| Property additions | (1,093 | ) | | (287 | ) | | | (509 | ) |
| Cost of removal, net of salvage | (45 | ) | | (21 | ) | | | (32 | ) |
| Change in construction payables, net | 49 |
| | 9 |
| | | (7 | ) |
| Investment in unconsolidated subsidiaries | (128 | ) | | (1,421 | ) | | | (14 | ) |
| Returned investment in unconsolidated subsidiaries | 22 |
| | 2 |
| | | 3 |
|
| Other investing activities | 3 |
| | 3 |
| | | — |
|
| Net cash used for investing activities | (1,192 | ) | | (1,715 | ) | | | (559 | ) |
| Financing Activities: | | | | | | |
| Increase (decrease) in notes payable, net | (323 | ) | | 472 |
| | | (896 | ) |
| Proceeds — | | | | | | |
| First mortgage bonds | 200 |
| | — |
| | | 250 |
|
| Capital contributions from parent company | 79 |
| | 1,089 |
| | | — |
|
| Senior notes | 450 |
| | 900 |
| | | 350 |
|
| Redemptions and repurchases — | | | | | | |
| Medium-term notes | (22 | ) | | — |
| | | — |
|
| First mortgage bonds | — |
| | — |
| | | (125 | ) |
| Senior notes | — |
| | (300 | ) | | | — |
|
| Distributions to noncontrolling interest | — |
| | — |
| | | (19 | ) |
| Payment of common stock dividends | (332 | ) | | (63 | ) | | | (128 | ) |
| Other financing activities | (7 | ) | | (8 | ) | | | 10 |
|
| Net cash provided from (used for) financing activities | 45 |
| | 2,090 |
| | | (558 | ) |
| Net Change in Cash and Cash Equivalents | 2 |
| | 33 |
| | | (4 | ) |
| Cash and Cash Equivalents at Beginning of Period | 19 |
| | 15 |
| | | 19 |
|
| Cash and Cash Equivalents at End of Period | $ | 21 |
| | $ | 48 |
| | | $ | 15 |
|
| Supplemental Cash Flow Information: | | | | | | |
| Cash paid (received) during the period for — | | | | | | |
| Interest (net of $9, $2, and $3 capitalized, respectively) | $ | 146 |
| | $ | 86 |
| | | $ | 119 |
|
| Income taxes, net | 17 |
| | 54 |
| | | (100 | ) |
Noncash transactions —
Accrued property additions at end of period | 112 |
| | 50 |
| | | 41 |
|
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At September 30, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 21 |
| | $ | 19 |
|
| Receivables — | | | | |
| Energy marketing receivables | | 427 |
| | 623 |
|
| Customer accounts receivable | | 221 |
| | 364 |
|
| Unbilled revenues | | 61 |
| | 239 |
|
| Other accounts and notes receivable | | 61 |
| | 76 |
|
| Accumulated provision for uncollectible accounts | | (26 | ) | | (27 | ) |
| Materials and supplies | | 24 |
| | 26 |
|
| Natural gas for sale | | 631 |
| | 631 |
|
| Prepaid expenses | | 103 |
| | 80 |
|
| Assets from risk management activities, net of collateral | | 103 |
| | 128 |
|
| Other regulatory assets, current | | 96 |
| | 81 |
|
| Other current assets | | 25 |
| | 10 |
|
| Total current assets | | 1,747 |
| | 2,250 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 15,383 |
| | 14,508 |
|
| Less: Accumulated depreciation | | 4,567 |
| | 4,439 |
|
| Plant in service, net of depreciation | | 10,816 |
| | 10,069 |
|
| Construction work in progress | | 596 |
| | 496 |
|
| Total property, plant, and equipment | | 11,412 |
| | 10,565 |
|
| Other Property and Investments: | | | | |
| Goodwill | | 5,967 |
| | 5,967 |
|
| Equity investments in unconsolidated subsidiaries | | 1,609 |
| | 1,541 |
|
Other intangible assets, net of amortization of $100 and $34
at September 30, 2017 and December 31, 2016, respectively | | 300 |
| | 366 |
|
| Miscellaneous property and investments | | 21 |
| | 21 |
|
| Total other property and investments | | 7,897 |
| | 7,895 |
|
| Deferred Charges and Other Assets: | | | | |
| Other regulatory assets, deferred | | 944 |
| | 973 |
|
| Other deferred charges and assets | | 190 |
| | 170 |
|
| Total deferred charges and other assets | | 1,134 |
| | 1,143 |
|
| Total Assets | | $ | 22,190 |
| | $ | 21,853 |
|
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholder's Equity | | At September 30, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | — |
| | $ | 22 |
|
| Notes payable | | 934 |
| | 1,257 |
|
| Energy marketing trade payables | | 451 |
| | 597 |
|
| Accounts payable | | 368 |
| | 348 |
|
| Customer deposits | | 137 |
| | 153 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | — |
| | 26 |
|
| Other accrued taxes | | 70 |
| | 68 |
|
| Accrued interest | | 66 |
| | 48 |
|
| Accrued compensation | | 46 |
| | 58 |
|
| Liabilities from risk management activities, net of collateral | | 28 |
| | 62 |
|
| Other regulatory liabilities, current | | 126 |
| | 102 |
|
| Accrued environmental remediation, current | | 54 |
| | 69 |
|
| Other current liabilities | | 112 |
| | 108 |
|
| Total current liabilities | | 2,392 |
| | 2,918 |
|
| Long-term Debt | | 5,862 |
| | 5,259 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 2,214 |
| | 1,975 |
|
| Employee benefit obligations | | 431 |
| | 441 |
|
| Other cost of removal obligations | | 1,656 |
| | 1,616 |
|
| Accrued environmental remediation, deferred | | 345 |
| | 357 |
|
| Other regulatory liabilities, deferred | | 35 |
| | 51 |
|
| Other deferred credits and liabilities | | 88 |
| | 127 |
|
| Total deferred credits and other liabilities | | 4,769 |
| | 4,567 |
|
| Total Liabilities | | 13,023 |
| | 12,744 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, par value $0.01 per share — | | | | |
| Authorized — 100 million shares | | | | |
| Outstanding — 100 shares | | — |
| | — |
|
| Paid in capital | | 9,185 |
| | 9,095 |
|
| Accumulated deficit | | (41 | ) | | (12 | ) |
| Accumulated other comprehensive income | | 23 |
| | 26 |
|
| Total common stockholder's equity | | 9,167 |
| | 9,109 |
|
| Total Liabilities and Stockholder's Equity | | $ | 22,190 |
| | $ | 21,853 |
|
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
Southern Company Gas is an energy servicesa holding company whosethat owns all of the common stock of three traditional electric operating companies (Alabama Power, Georgia Power, and Mississippi Power), Southern Power, and Southern Company Gas and owns other direct and indirect subsidiaries. The primary business isbusinesses of the Southern Company system are electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas through utilities in seven states – Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee, and Maryland.by Southern Company GasGas. Southern Company's reportable segments are the sale of electricity by the traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and its subsidiaries are also involved in severalthe sale of natural gas and other complementary businesses.
products and services by Southern Company Gas has fourGas. Southern Company Gas' reportable segments –are gas distribution operations, gas marketing services, wholesale gas services,pipeline investments, and gas midstream operations – and one non-reportable segment – all other. For additional information on these segments, see Note (K)marketing services. Prior to the Condensed Financial Statements herein and "BUSINESS – Southern Company Gas" in Itemsale of Sequent on July 1, of the Form 10-K.
Many factors affect the opportunities, challenges, and risks of2021, Southern Company Gas' business. These factors include the ability to maintain constructive regulatory environments, to maintain and grow naturalreportable segments also included wholesale gas sales, and to effectively manage and secure timely recovery of costs. Southern Company Gas has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Southern Company Gas for the foreseeable future.
Merger, Acquisition, and Disposition Activities
On July 1, 2016, Southern Company Gas completed the Merger, which was accounted for by Southern Company using the acquisition method of accounting whereby the assets acquired and liabilities assumed were recognized at fair value as of the acquisition date. Pushdown accounting was applied to create a new cost basis for Southern Company Gas assets, liabilities, and equity as of the acquisition date. Accordingly, the successor financial statements reflect a new basis of accounting and successor and predecessor period financial results (separated by a heavy black line) are presented, but are not comparable. As a result of the application of acquisition accounting, certain discussions herein include disclosure of the predecessor and successor periods.services. See Note (I)(L) to the Condensed Financial Statements herein for additional information relatingon segment reporting. For additional information on the Registrants' primary business activities and the sale of Sequent, see BUSINESS – "The Southern Company System" in Item 1 of the Form 10-K and Note 15 to the Merger.financial statements under "Southern Company Gas" in Item 8 of the Form 10-K, respectively.
In September 2016,The Registrants continue to focus on several key performance indicators. For the traditional electric operating companies and Southern Company Gas, paid approximately $1.4 billionthese indicators include, but are not limited to, acquire a 50% equity interest in SNG. On March 31, 2017,customer satisfaction, plant availability, electric and natural gas system reliability, and execution of major construction projects. For Southern Power, these indicators include, but are not limited to, the equivalent forced outage rate and contract availability to evaluate operating results and help ensure its ability to meet its contractual commitments to customers. In addition, Southern Company Gas madeand the Subsidiary Registrants focus on earnings per share and net income, respectively, as a key performance indicator.
Recent Developments
Alabama Power
On July 12, 2022, the Alabama PSC approved the following items:
•Alabama Power's petition for a certificate of convenience and necessity authorizing Alabama Power to complete the acquisition of the Calhoun Generating Station. The transaction closed on September 30, 2022 and, on October 3, 2022, Alabama Power filed Rate CNP New Plant with the Alabama PSC to recover the related costs. The filing reflected an additional $50increase in annual revenues of $34 million, contributionor 0.6%, effective with the billing month of November 2022.
•An increase to maintain its 50% equity interestRate ECR effective with August 2022 billings, which is expected to result in SNG. Southern Company Gas recorded equity investment incomean increase of $28approximately $310 million and $86 million from this investmentannually. The approved increase in the successor third quarterRate ECR factor has no significant effect on Alabama Power's net income, but does increase operating cash flows related to fuel cost recovery.
•Modifications to Rate NDR.
•An accounting order authorizing Alabama Power to create a reliability reserve separate from the NDR and year-to-date 2017, respectively, and $27 million in September 2016. transition the previous Rate NDR authority related to reliability expenditures to the reliability reserve. Alabama Power may make accruals to the reliability reserve if the NDR balance exceeds $35 million.
See Note (J)(B) to the Condensed Financial Statements under "Alabama Power" herein for additional information.
On September 23, 2022, the FERC authorized Alabama Power to use updated depreciation rates from its 2021 depreciation study effective January 1, 2023. The study was also provided to the Alabama PSC, and Notesthe new depreciation rates will be reflected in Alabama Power's future rate filings. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Alabama Power" herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Georgia Power
Plant Vogtle Units 3 and 4 Construction and 11Start-Up Status
Construction continues on Plant Vogtle Units 3 and 4 (with electric generating capacity of approximately 1,100 MWs each), in which Georgia Power currently holds a 45.7% ownership interest. Georgia Power's share of the total project capital cost forecast to complete Plant Vogtle Units 3 and 4, including contingency, through the end of the first quarter 2023 and the fourth quarter 2023, respectively, is $10.4 billion.
On July 29, 2022, Southern Nuclear announced that all Unit 3 ITAACs had been submitted to the NRC. On August 3, 2022, the NRC published its 103(g) finding that the acceptance criteria in the combined license for Unit 3 had been met, which allowed nuclear fuel to be loaded and allows start-up testing to begin. Fuel load for Unit 3 was completed on October 17, 2022, and the unit is projected to be placed in service by the end of the first quarter 2023. The projected schedule for Unit 3 primarily depends on the pace of system and area transitions to operations, including the completion of closure documentation necessary to support start-up testing, and the progression of start-up, final component, and pre-operational testing, which may be impacted by equipment or other operational failures. Unit 4 is projected to be placed in service by the end of the fourth quarter 2023. The projected schedule for Unit 4 primarily depends on Unit 3 progress through start-up and testing; overall construction productivity and production levels improving, particularly in electrical installation, including terminations; and appropriate levels of craft laborers, particularly electricians, being added and maintained. Any further delays could result in later in-service dates and cost increases.
During the first nine months of 2022, established construction contingency totaling $170 million was assigned to the base capital cost forecast for costs primarily associated with construction productivity, the pace of system turnovers, additional craft and support resources, and procurement for Units 3 and 4. Georgia Power also increased its total project capital cost forecast by adding $36 million and $32 million to replenish construction contingency in the second quarter 2022 and the third quarter 2022, respectively. After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded pre-tax charges to income in the second quarter 2022 and the third quarter 2022 of $36 million ($27 million after tax) and $32 million ($24 million after tax), respectively, for the increases in the total project capital cost forecast. Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery during the prudence review following the Unit 4 fuel load pursuant to the twenty-fourth VCM stipulation described in Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction – Regulatory Matters" herein.
Georgia Power and the other Vogtle Owners do not agree on the starting dollar amount for the determination of cost increases subject to the cost-sharing and tender provisions of the Global Amendments (as defined in Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction – Joint Owner Contracts" herein). The other Vogtle Owners have notified Georgia Power that they believe the current capital cost expenditures have already exceeded the cost-sharing thresholds and the current project capital cost forecast triggers the tender provisions under the Global Amendments.
On June 17, 2022 and July 26, 2022, OPC and Dalton, respectively, notified Georgia Power of their purported exercises of their tender options. On June 18, 2022, OPC and MEAG Power each filed a separate lawsuit against Georgia Power in the Superior Court of Fulton County, Georgia seeking a declaratory judgment that the starting dollar amount is $17.1 billion and that the cost-sharing and tender provisions have been triggered. On July 25, 2022 and July 28, 2022, Georgia Power filed its answers in the lawsuits filed by MEAG Power and OPC, respectively, and included counterclaims seeking a declaratory judgment that the starting dollar amount is $18.38 billion and that costs related to force majeure events are excluded prior to calculating the cost-sharing and tender provisions and when calculating Georgia Power's related financial obligations. On September 26, 2022, Dalton filed complaints in each of these lawsuits.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
On September 29, 2022, Georgia Power and MEAG Power reached an agreement to resolve their dispute regarding the proper interpretation of the cost-sharing and tender provisions of the Global Amendments. Under the terms of the agreement, among other items, (i) MEAG Power will not exercise its tender option and will retain its full ownership interest in Plant Vogtle Units 3 and 4; (ii) Georgia Power will pay a portion of MEAG Power's costs of construction for Plant Vogtle Units 3 and 4 as such costs are incurred and with no further adjustment for force majeure costs, which payments will total approximately $79 million based on the current project capital cost forecast; and (iii) Georgia Power will pay 20% of MEAG Power's costs of construction with respect to any amounts over the current project capital cost forecast, with no further adjustment for force majeure costs. On October 4, 2022, MEAG Power and Georgia Power filed a notice of settlement and voluntary dismissal of the pending litigation described above, including Georgia Power's counterclaim, and, on October 6, 2022, Dalton dismissed its related complaint. Georgia Power recorded pre-tax charges (credits) to income in the fourth quarter 2021, the second quarter 2022, and the third quarter 2022 of approximately $440 million ($328 million after tax), $16 million ($12 million after tax), and $(102) million ($(76) million after tax), respectively, associated with the cost-sharing and tender provisions of the Global Amendments, including the settlement with MEAG Power, which are included in the total project capital cost forecast. The settlement with MEAG Power does not resolve the separate pending litigation with OPC, including Dalton's associated complaint. Georgia Power may be required to record further pre-tax charges to income of up to approximately $300 million associated with the cost-sharing and tender provisions of the Global Amendments for OPC and Dalton based on the current project capital cost forecast.
The ultimate impact of these matters on the construction schedule and project capital cost forecast for Plant Vogtle Units 3 and 4 cannot be determined at this time. See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information.
2022 Base Rate Case
On June 24, 2022, Georgia Power filed a base rate case (Georgia Power 2022 Base Rate Case) with the Georgia PSC. The filing, as modified on August 22, 2022, proposes a three-year alternate rate plan with requested rate increases totaling $889 million, $107 million, and $45 million effective January 1, 2023, January 1, 2024, and January 1, 2025, respectively. Georgia Power expects the Georgia PSC to render a final decision in this matter on December 20, 2022. The ultimate outcome of this matter cannot be determined at this time. See Note (B) to the Condensed Financial Statements under "Georgia Power – Rate Plans – 2022 Base Rate Case" herein for additional information.
Integrated Resource Plan
On July 21, 2022, the Georgia PSC approved Georgia Power's triennial IRP (2022 IRP), as modified by a stipulated agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors and as further modified by the Georgia PSC. In the 2022 IRP decision, the Georgia PSC approved several requests, including the following:
•Decertification and retirement of Plant Wansley Units 1 and 2 (926 MWs based on 53.5% ownership), which occurred on August 31, 2022, and Plant Scherer Unit 3 (614 MWs based on 75% ownership) by December 31, 2028, as well as the reclassification to regulatory asset accounts of the remaining net book values of these units and any remaining unusable materials and supplies inventories upon retirement.
•Decertification and retirement of Plant Gaston Units 1 through 4 (500 MWs based on 50% ownership through SEGCO) by December 31, 2028. See Note 7 to the financial statements of Southern Company Gas under "Equity Method Investments – SNG" and "Investment in SNG," respectively,"SEGCO" in Item 8 of the Form 10-K for additional information.
In October 2016, •Georgia Power's environmental compliance strategy, including approval of Georgia Power's plans to address CCR at its ash ponds and landfills.
The Georgia PSC deferred a decision on the requested decertification and retirement of Plant Bowen Units 1 and 2 (1,400 MWs) to the 2025 IRP.
See Note (B) to the Condensed Financial Statements under "Georgia Power – Integrated Resource Plans" herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Mississippi Power
On June 7, 2022, the Mississippi PSC approved Mississippi Power's annual retail PEP filing for 2022, resulting in an annual increase in revenues of approximately $18 million, or 1.9%. The rate increase became effective with the first billing cycle of April 2022 in accordance with the PEP rate schedule.
On August 26, 2022, the FERC accepted an amended shared service agreement (SSA) between Mississippi Power and Cooperative Energy, effective July 1, 2022, under which Cooperative Energy will continue to decrease its use of Mississippi Power's generation services under the MRA tariff up to 2.5% annually through 2035. At September 30, 2022, Mississippi Power is serving approximately 400 MWs of Cooperative Energy's annual demand.Beginning in 2036, Cooperative Energy will provide 100% of its electricity requirements at the MRA delivery points under the tariff. Neither party has the option to cancel the amended SSA. Mississippi Power expects to remarket this capacity, including the potential development of future arrangements with Cooperative Energy.
On July 15, 2022, Mississippi Power filed a request with the FERC for a $23 million increase in annual wholesale base revenues under the MRA tariff and requested an effective date of July 15, 2022. Cooperative Energy has filed a complaint with FERC challenging the new rates. On September 13, 2022, the FERC issued an order accepting Mississippi Power's request effective September 14, 2022, subject to refund, and establishing hearing and settlement judge procedures. The ultimate outcome of this matter cannot be determined at this time.
See Note (B) to the Condensed Financial Statements under "Mississippi Power" herein for additional information.
Southern Power
During the nine months ended September 30, 2022, Southern Power completed construction of and placed in service the remaining 40 MWs of the Tranquillity battery energy storage facility and the remaining 15 MWs of the Garland battery energy storage facility. See Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information.
At September 30, 2022, Southern Power's average investment coverage ratio for its generating assets, including those owned with various partners, based on the ratio of investment under contract to total investment using the respective facilities' net book value (or expected in-service value for facilities under construction) as the investment amount was 95% through 2026 and 92% through 2031, with an average remaining contract duration of approximately 13 years.
Southern Company Gas completed
On July 1, 2022, Atlanta Gas Light filed its purchaseannual GRAM update with the Georgia PSC. The filing requests an annual base rate increase of Piedmont's 15% interest$53 million based on the projected 12-month period beginning January 1, 2023. Resolution of the GRAM filing is expected by December 28, 2022, with the new rates effective January 1, 2023.
On August 1, 2022, Virginia Natural Gas filed a general base rate case with the Virginia Commission seeking an increase in SouthStar, which eliminatedannual base rate revenues of $69 million, including $15 million related to the noncontrolling interestrecovery of investments under the SAVE program, primarily to recover investments and increased costs associated with SouthStar. See Note 4infrastructure, technology, and workforce development. The requested increase is based on a projected 12-month period beginning January 1, 2023, a ROE of 10.35%, and an equity ratio of 53.2%. Rate adjustments are expected to be effective January 1, 2023, subject to refund. The Virginia Commission is expected to rule on the financial statementsrequested increase in the third quarter 2023.
On September 7, 2022, certain affiliates of Southern Company Gas entered into agreements to sell two natural gas storage facilities located in California and Texas for an aggregate purchase price of $186 million, plus working capital and certain other adjustments. On October 20, 2022, the release of a Southern Company Gas parent guarantee was executed, which resolved a material closing condition. As a result, Southern Company Gas expects to record pre-tax impairment charges totaling approximately $125 million ($95 million after tax) in the fourth quarter
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
2022. See Note (K) to the Condensed Financial Statements under "Variable Interest Entities" in Item 8 of the Form 10-K"Southern Company Gas" herein for additional information.
On October 15, 2017, Southern Company Gas subsidiary, Pivotal Utility Holdings, entered into agreements for the sale of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion. As of September 30, 2017, the net book value of the assets to be disposed of in the sale was approximately $1.5 billion, which includes approximately $0.5 billion of goodwill. The goodwill is not deductible for tax purposes and as a result, a deferred tax liability has not yet been provided for goodwill. Through the completion of the sale, Southern Company Gas intends to invest approximately $0.1 billion in capital expenditures which are required for ordinary business operations. The completion of each sale is subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act; (ii) the receipt of required regulatory approvals, including the FERC, the Federal Communications Commission, the New Jersey BPU, and, with respect to the sale of Elkton Gas, the Maryland PSC; and (iii) other customary closing conditions. The sales are expected to be completed by the end of the third quarter 2018.
The ultimate outcome of these matters cannot be determined at this time.
RESULTS OF OPERATIONS
Southern Company
Net Income
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $371 | | 33.7 | | $1,003 | | 38.5 |
Consolidated net income attributable to Southern Company was $1.5 billion ($1.36 per share) in the third quarter 2022 compared to $1.1 billion ($1.04 per share) for the corresponding period in 2021. Consolidated net income attributable to Southern Company was $3.6 billion ($3.38 per share) for year-to-date 2022 compared to $2.6 billion ($2.46 per share) for the corresponding period in 2021. The increases were primarily due to decreases of $249 million and $589 million in the third quarter and year-to-date 2022, respectively, in after-tax charges related to the construction of Plant Vogtle Units 3 and 4, increases in retail electric revenues associated with rates and pricing, warmer weather, and sales growth, and increases in natural gas revenues from base rate increases and continued infrastructure replacement, partially offset by higher non-fuel operations and maintenance costs. The increase for year-to-date 2022 also reflects after-tax charges totaling $67 million in 2021 related to the PennEast Pipeline project at Southern Company Gas.
See Note (B) to the Condensed Financial Statements herein and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4 and Note 7 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information on the PennEast Pipeline project.
Retail Electric Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1,410 | | 31.0 | | $2,871 | | 25.0 |
In the third quarter 2022, retail electric revenues were $6.0 billion compared to $4.6 billion for the corresponding period in 2021. For year-to-date 2022, retail electric revenues were $14.4 billion compared to $11.5 billion for the corresponding period in 2021.
Details of the changes in retail electric revenues were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Third Quarter 2022 | | Year-To-Date 2022 |
| (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail electric – prior year | $ | 4,551 | | | | | $ | 11,492 | | | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 165 | | | 3.6 | % | | 458 | | | 4.0 | % |
| Sales growth | 73 | | | 1.6 | | | 158 | | | 1.4 | |
| Weather | 26 | | | 0.6 | | | 188 | | | 1.6 | |
| Fuel and other cost recovery | 1,146 | | | 25.2 | | | 2,067 | | | 18.0 | |
| Retail electric – current year | $ | 5,961 | | | 31.0 | % | | $ | 14,363 | | | 25.0 | % |
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
(Continued)
Operating Metrics
Southern Company Gas continuesRevenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2022 when compared to focus on several operating metrics, including Heating Degree Days,the corresponding periods in 2021. The increases were primarily due to higher contributions from commercial and industrial customers with variable demand-driven pricing, base tariff increases in accordance with Georgia Power's 2019 ARP, and pricing effects associated with customer count, and volumes of natural gas sold. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSISusage. See Note 2 to the financial statements under "Georgia Power – RESULTS OF OPERATIONS – "Operating Metrics" of Southern Company GasRate Plans" in Item 78 of the Form 10-K.10-K for additional information.
Southern Company Gas measures weather and the effect on its business using Heating Degree Days. Generally, increased Heating Degree Days result in higher demand for natural gas on Southern Company Gas' distribution system. With the exception of Southern Company Gas' utilities in Illinois and Florida, Southern Company Gas has various regulatory mechanisms, such as weather normalization mechanisms, which limit its exposure to weather changes within typical ranges in each of its utilities' respective service territory. However, the utility customers in Illinois and the gas marketing services customers primarily in Georgia and Illinois can be impacted by warmer- or colder-than-normal weather. Southern Company Gas utilizes weather hedges at gas distribution operations and gas marketing services to reduce negative earnings impact in the event of warmer-than-normal weather, while retaining most of the earnings upside.
The number of customers at gas distribution operations and energy customers at gas marketing services can be impacted by natural gas prices, economic conditions, and competition from alternative fuels. Gas marketing services' customers are primarily located in Georgia and Illinois.
Southern Company Gas' natural gas volume metrics for gas distribution operations and gas marketing services illustrate the effects of weather and customer demand for natural gas. Wholesale gas services' physical sales volumes represent the daily average natural gas volumes sold to its customers.
Seasonality of Results
Heating Season is the period from November through March when natural gas usage and operating revenues are generally higher, as more customers are connected to the gas distribution systems and natural gas usage is higher in periods of colder weather. Occasionally in the summer, wholesale gas services' operating revenues are impacted due to peak usage by power generators in response to summer energy demands. Southern Company Gas' base operating expenses, excluding cost of natural gas, bad debt expense, and certain incentive compensation costs, are incurred relatively evenly throughout the year. Seasonality also affects the comparison of certain balance sheet items across quarters, including receivables, unbilled revenues, natural gas for sale, and notes payable. However, these items are comparable when reviewing Southern Company Gas' annual results. 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
|
| | |
Successor |
Third Quarter 2017 vs. Third Quarter 2016 |
(change in millions) | | (% change) |
$11 | | N/M |
N/M - Not meaningful
Net incomeRevenues attributable to Southern Company Gas was $15 million forchanges in sales increased in the third quarter 2017and year-to-date 2022 when compared to $4the corresponding periods in 2021. Weather-adjusted residential KWH sales increased 1.3% and 0.4% in the third quarter and year-to-date 2022, respectively, and weather-adjusted commercial KWH sales increased 2.0% in both the third quarter and year-to-date 2022 when compared to the corresponding periods in 2021 primarily due to customer growth. In addition, commercial customer usage increased in the third quarter and year-to-date 2022 and residential customer usage decreased for year-to-date 2022 when compared to the corresponding periods in 2021 as customers return to pre-pandemic levels of activity outside the home. Industrial KWH sales increased 2.2% and 2.6% in the third quarter and year-to-date 2022, respectively, when compared to the corresponding periods in 2021 primarily due to increases in the pipeline and paper sectors, partially offset by a decrease in the chemicals sector.
Fuel and other cost recovery revenues increased $1.1 billion and $2.1 billion in the third quarter and year-to-date 2022, respectively, compared to the corresponding periods in 2021 primarily due to higher fuel and purchased power costs and an increase in the volume of KWHs generated. 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. 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.
Wholesale Electric Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $466 | | 63.7 | | $976 | | 53.6 |
In the third quarter 2022, wholesale electric revenues were $1.2 billion compared to $731 million for the corresponding period in 2016. This2021. For year-to-date 2022, wholesale electric revenues were $2.8 billion compared to $1.8 billion for the corresponding period in 2021. The increases were primarily due to increases of $437 million and $930 million in the third quarter and year-to-date 2022, respectively, in energy revenues as a result of fuel and purchased power price increases when compared to the corresponding periods in 2021, an increase in the volume of KWHs sold primarily associated with natural gas PPAs at Southern Power, and increased opportunity sales at Alabama Power due to warmer weather.
Wholesale electric revenues consist of revenues from PPAs and short-term opportunity sales. Wholesale electric revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues generally represent the greatest contribution to net income and are designed to provide recovery of fixed costs plus a return on investment. Energy revenues will vary depending on fuel prices, the market prices of wholesale energy compared to the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Energy sales from solar and wind PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or through a fixed price related to the energy. As a result, the ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors. Wholesale electric revenues at Mississippi Power include FERC-regulated municipal and rural association sales
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
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.
Other Electric Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $6 | | 3.4 | | $29 | | 5.5 |
In the third quarter 2022, other electric revenues were $185 million compared to $179 million for the corresponding period in 2021. The increase was primarily due to $11increases of $14 million of additional income from infrastructure replacement programsin transmission revenues primarily associated with open access transmission tariff sales and base rate increases, net of associated depreciation, and a $7 million gain from the settlement of contractor litigation claims,in cogeneration steam revenues associated with higher natural gas prices at Alabama Power, partially offset by $12a $14 million lower net incomeincrease in realized losses associated with price stability products for retail customers on variable demand-driven pricing tariffs at wholesale gas services. Also contributingGeorgia Power.
For year-to-date 2022, other electric revenues were $554 million compared to $525 million for the corresponding period in 2021. The increase was $24primarily due to increases of $41 million in Merger-related expensestransmission revenues primarily associated with open access transmission tariff sales, $15 million in the third quarter 2016,cogeneration steam revenues associated with higher natural gas prices at Alabama Power, and $13 million in outdoor lighting sales at Georgia Power, partially offset by $23a decrease of $26 million resulting from the termination of additional deferred income tax expense in the third quarter 2017.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
| | | | | | | | | | | | | |
| | | Successor | | | Predecessor |
| | | Year-to-Date 2017 | | July 1, 2016 through September 30, 2016 | | | January 1, 2016 through June 30, 2016 |
| | | (in millions) | | (in millions) | | | (in millions) |
Net Income Attributable to
Southern Company Gas | | $ | 303 |
| | $ | 4 |
| | | $ | 131 |
|
Net income attributable to Southern Company Gas for the successor year-to-date 2017 included $28 million of net income from wholesale gas services and $38$21 million in earnings from the SNG investment, net of related interest expense. Also included in net incomerealized losses associated with price stability products for this period was $29 million generated from the continued investment in infrastructure replacement programs and base rate increases, primarilyretail customers on variable demand-driven pricing tariffs, both at Atlanta Gas Light effective March 1, 2017, less the associated increases in depreciation. For additional information, see FUTURE EARNINGS POTENTIAL– "Regulatory Matters – Base Rate Cases" herein. These increases were partially offset by $23 million of additional deferred income tax expense.Georgia Power.
Net income attributable to Southern Company Gas for the successor period of July 1, 2016 through September 30, 2016 and the predecessor period of January 1, 2016 through June 30, 2016 included $11 million and $42 million, respectively, in net losses from wholesale gas services. The successor period of July 1, 2016 through September 30, 2016 also included $16 million in earnings from the SNG investment, net of related interest expense. Also included in net income for these periods were $24 million and $41 million, respectively, of Merger-related expenses and $14 million of net income attributable to noncontrolling interest in the predecessor period of January 1, 2016 through June 30, 2016. As a result of purchasing the remaining interest in SouthStar in October 2016, all net income was attributable to Southern Company Gas in the successor periods.
Natural Gas Revenues
|
| | |
| Successor |
| Third Quarter 2017 vs. Third Quarter 2016 |
| (change in millions) | | (% change) |
| $14 | | 2.7 |
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $234 | | 37.6 | | $1,004 | | 33.5 |
In the third quarter 2017,2022, natural gas revenues were $532$857 million compared to $518$623 million for the corresponding period in 2016.2021. For year-to-date 2022, natural gas revenues were $4.0 billion compared to $3.0 billion for the corresponding period in 2021.
Details of the changes in natural gas revenues were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 | | Year-To-Date 2022 |
| (in millions) | | (% change) | | (in millions) | | (% change) |
| Natural gas revenues – prior year | $ | 623 | | | | | $ | 2,994 | | | |
| Estimated change resulting from – | | | | | | | |
| Infrastructure replacement programs and base rate changes | 54 | | | 8.7 | % | | 186 | | | 6.2 | % |
| Gas costs and other cost recovery | 172 | | | 27.6 | | | 955 | | | 31.9 | |
| Gas marketing services | 1 | | | 0.2 | | | 14 | | | 0.5 | |
| Wholesale gas services | — | | | — | | | (187) | | | (6.2) | |
| Other | 7 | | | 1.1 | | | 36 | | | 1.1 | |
| Natural gas revenues – current year | $ | 857 | | | 37.6 | % | | $ | 3,998 | | | 33.5 | % |
|
| | | | | | | |
| | | Third Quarter 2017 |
| | | (in millions) | | (% change) |
| Natural gas – prior year | | $ | 518 |
| | |
| Estimated change resulting from – | | | | |
| Infrastructure replacement programs and base rate increases | | 25 |
| | 4.8 | % |
| Gas costs and other cost recovery | | 1 |
| | 0.2 |
|
| Mark-to-market adjustments at gas marketing services | | 3 |
| | 0.6 |
|
| Wholesale gas services | | (16 | ) | | (3.1 | ) |
| Other | | 1 |
| | 0.2 |
|
| Natural gas – current year | | $ | 532 |
| | 2.7 | % |
The increase inRevenues from infrastructure replacement programs and base rate changes at the natural gas revenuedistribution utilities increased in the third quarter and year-to-date 2022 compared to the corresponding periods in 2021 primarily relatesdue to gas distribution operations as a result ofrate increases at Nicor Gas, Atlanta Gas Light, and Chattanooga Gas and continued investment in infrastructure replacement programs and increasesreplacement. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" in base rate revenues, primarily at Atlanta Gas Light effective March 1, 2017, as well asItem 8 of the positive impact from the amortization of assets established in the application of acquisition accounting at gas marketing services. These increases were partially offset by mark-to-
Form 10-K for additional information.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
(Continued)
market losses from derivative instruments at wholesaleRevenues associated with gas servicescosts and gas marketing servicesother cost recovery increased in the third quarter and year-to-date 2022 compared to the corresponding periods in 2021 primarily due to changes inhigher natural gas prices and a decrease in commercial activity at wholesale gas services. For information on commercial activity at wholesale gas services, see "Segment Information – Wholesale Gas Services – Change in Commercial Activity" herein.
|
| | | | | | | | | | | | | |
| | | Successor | | | Predecessor |
| | | Year-to-Date 2017 | | July 1, 2016 through September 30, 2016 | | | January 1, 2016 through June 30, 2016 |
| | | (in millions) | | (in millions) | | | (in millions) |
| Natural gas revenues | | $ | 2,746 |
| | $ | 518 |
| | | $ | 1,841 |
|
For the successor year-to-date 2017, natural gas revenues included recovery of $1.1 billion in cost of natural gas and $95 million in net revenues from wholesale gas services, net of $14 million of amortization associated with assets established in the application of acquisition accounting. Also included in natural gas revenues were $69 million in additional revenues generated from gas distribution operations as a result of continued investment in infrastructure replacement programs and increases in base rate revenues, primarily at Atlanta Gas Light effective March 1, 2017, partially offset by a $16 million decrease attributable to warmer-than-normal weather, net of hedging.
For the successor period of July 1, 2016 through September 30, 2016 and the predecessor period of January 1, 2016 through June 30, 2016, natural gas revenues included recovery of $133 million and $755 million, respectively, in cost of natural gas, as well as $8 million and $32 million, respectively, in net losses from wholesale gas services. Also included in natural gas revenues for the predecessor period of January 1, 2016 through June 30, 2016 was a $7 million decrease attributable to warmer-than-normal weather, net of hedging.
See "Segment Information" herein for additional information on wholesale gas services' revenues and losses.
recovery. Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, recoverablegas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from the natural gas distribution operations.utilities.
Revenues from gas marketing services increased for year-to-date 2022 compared to the corresponding period in 2021 due to higher commodity prices and higher sales to commercial customers.
The changes in year-to-date 2022 revenues related to Southern Company Gas' wholesale gas services were due to the sale of Sequent on July 1, 2021. See "Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Other Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $24 | | 15.6 | | $6 | | 1.2 |
In the third quarter 2022, other revenues were $178 million compared to $154 million for the corresponding period in 2021. The increase was primarily due to a $15 million increase in unregulated sales at the traditional electric operating companies primarily associated with power delivery construction and maintenance projects, energy conservation projects, and lighting. Also contributing to the increase was a $9 million increase primarily related to distributed infrastructure projects at PowerSecure.
For year-to-date 2022, other revenues were $519 million compared to $513 million for the corresponding period in 2021. The increase was primarily due to increases of $10 million in unregulated sales associated with power delivery construction and maintenance projects at Mississippi Power, $9 million in unregulated energy conservation projects at Georgia Power, $8 million in unregulated lighting sales at Alabama Power, and $5 million primarily related to distribution infrastructure projects at PowerSecure, partially offset by a $28 million decrease associated with the timing of revenue recognition for a large, ongoing power delivery construction and maintenance contract at Georgia Power.
Fuel and Purchased Power Expenses
| | | | | | | | | | | | | | | | | | | | | | | |
| | Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | 1,189 | | | 96.4 | | $ | 2,319 | | | 79.1 |
| Purchased power | 357 | | | 124.0 | | 573 | | | 80.5 |
| Total fuel and purchased power expenses | $ | 1,546 | | | | | $ | 2,892 | | | |
In the third quarter 2022, total fuel and purchased power expenses were $3.1 billion compared to $1.5 billion for the corresponding period in 2021. The increase was primarily the result of a $1.2 billion increase in the average cost of fuel and purchased power and a $310 million increase in the volume of KWHs generated and purchased.
For year-to-date 2022, total fuel and purchased power expenses were $6.5 billion compared to $3.6 billion for the corresponding period in 2021. The increase was primarily the result of a $2.4 billion increase in the average cost of fuel and purchased power and a $523 million increase in the volume of KWHs generated and purchased.
Fuel and purchased power energy transactions at the traditional electric operating companies are generally offset by fuel revenues and do not have a significant impact on net income. See Note 2 to the financial statements in Item 8 of the Form 10-K for additional information. Fuel expenses incurred under Southern Power's PPAs are generally the responsibility of the counterparties and do not significantly impact net income.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of the Southern Company system's generation and purchased power were as follows:
| | | | | | | | | | | | | | |
| Third Quarter 2022 | Third Quarter 2021 | Year-To-Date 2022 | Year-To-Date 2021 |
Total generation (in billions of KWHs)(a) | 50 | 50 | 141 | 136 |
Total purchased power (in billions of KWHs) | 9 | 5 | 20 | 13 |
Sources of generation (percent)(a) — | | | | |
| Gas | 54 | 48 | 50 | 47 |
| Coal | 21 | 26 | 22 | 24 |
| Nuclear | 16 | 16 | 16 | 17 |
| Hydro | 2 | 3 | 4 | 4 |
| Wind, Solar, and Other | 7 | 7 | 8 | 8 |
Cost of fuel, generated (in cents per net KWH)— | | | | |
Gas(a) | 6.75 | 3.38 | 5.42 | 2.87 |
| Coal | 4.12 | 2.82 | 3.58 | 2.84 |
| Nuclear | 0.71 | 0.78 | 0.72 | 0.76 |
Average cost of fuel, generated (in cents per net KWH)(a) | 5.05 | 2.75 | 4.07 | 2.45 |
Average cost of purchased power (in cents per net KWH)(b) | 8.94 | 6.45 | 7.84 | 5.77 |
(a)Excludes Central Alabama Generating Station KWHs and associated cost of fuel through July 12, 2022 as its fuel was previously provided by the purchaser under a power sales agreement. See Note 15 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.
(b)Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider.
Fuel
In the third quarter 2022, fuel expense was $2.4 billion compared to $1.2 billion for the corresponding period in 2021. The increase was primarily due to a 99.7% increase in the average cost of natural gas per KWH generated, a 52.7% decrease in the volume of KWHs generated by hydro, a 46.1% increase in the average cost of coal per KWH generated, and a 13.0% increase in the volume of KWHs generated by natural gas, partially offset by a 19.0% decrease in the volume of KWHs generated by coal.
For year-to-date 2022, fuel expense was $5.2 billion compared to $2.9 billion for the corresponding period in 2021. The increase was primarily due to an 88.9% increase in the average cost of natural gas per KWH generated, a 26.1% increase in the average cost of coal per KWH generated, a 9.6% increase in the volume of KWHs generated by natural gas, and an 8.7% decrease in the volume of KWHs generated by hydro, partially offset by a 4.1% decrease in the volume of KWHs generated by coal.
Purchased Power
In the third quarter 2022, purchased power expense was $645 million compared to $288 million for the corresponding period in 2021. The increase was primarily due to a 38.6% increase in the average cost per KWH purchased primarily due to higher natural gas and coal prices and an 87.2% increase in the volume of KWHs purchased.
For year-to-date 2022, purchased power expense was $1.3 billion compared to $712 million for the corresponding period in 2021. The increase was primarily due to a 35.9% increase in the average cost per KWH purchased primarily due to higher natural gas and coal prices and a 50.9% increase in the volume of KWHs purchased.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Energy purchases will vary depending on demand for energy within the Southern Company system's electric service territory, the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, and the availability of the Southern Company system's generation.
Cost of Natural Gas
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $165 | | N/M | | $897 | | 95.1 |
Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from the natural gas distribution utilities. Cost of natural gas at the natural gas distribution utilities represented 78% and 87% of the total cost of natural gas in the third quarter and year-to-date 2022, respectively.
In the third quarter 2022, cost of natural gas was $294 million compared to $129 million for the corresponding period in 2021. For year-to-date 2022, cost of natural gas was $1.8 billion compared to $943 million for the corresponding period in 2021. The increases reflect higher gas cost recovery as a result of increases of 104% and 113% in natural gas prices in the third quarter and year-to-date 2022, respectively, compared to the corresponding periods in 2021.
Cost of Other Sales
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $21 | | 29.6 | | $20 | | 7.8 |
In the third quarter 2022, cost of other sales was $92 million compared to $71 million for the corresponding period in 2021. The increase was primarily related to distributed infrastructure projects at PowerSecure.
For year-to-date 2022, cost of other sales was $275 million compared to $255 million for the corresponding period in 2021. The increase was primarily due to increases of $32 million related to distributed infrastructure projects at PowerSecure, $9 million related to unregulated power delivery construction and maintenance projects at Mississippi Power, and $9 million primarily associated with unregulated merchandising and energy services expenses at Alabama Power, partially offset by a decrease of $32 million associated with unregulated power delivery construction and maintenance projects at Georgia Power.
Other Operations and Maintenance Expenses
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $101 | | 7.0 | | $364 | | 8.6 |
In the third quarter 2022, other operations and maintenance expenses were $1.5 billion compared to $1.4 billion for the corresponding period in 2021. The increase was primarily due to increases of $49 million in transmission and distribution expenses primarily related to line maintenance, $18 million in customer accounts, customer service, and sales expenses primarily related to bad debt expenses, payment convenience fees, and labor, $12 million in compensation and benefit expenses, and $10 million in generation expenses primarily related to scheduled outage and maintenance costs.
For year-to-date 2022, other operations and maintenance expenses were $4.6 billion compared to $4.3 billion for the corresponding period in 2021. Excluding $53 million of expenses related to Sequent in 2021, other operations and
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
maintenance expenses increased $417 million. The increase was primarily due to increases of $135 million in transmission and distribution expenses primarily related to line maintenance, $90 million in generation expenses primarily related to scheduled outage and maintenance costs, $38 million in compensation and benefit expenses, $30 million in expenses at Southern Company Gas passed through directly to customers primarily related to bad debt, and $21 million in customer accounts, customer service, and sales expenses primarily related to bad debt expenses, payment convenience fees, and labor.
Depreciation and Amortization
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $26 | | 2.9 | | $70 | | 2.6 |
In the third quarter 2022, depreciation and amortization was $922 million compared to $896 million for the corresponding period in 2021. For year-to-date 2022, depreciation and amortization was $2.73 billion compared to $2.66 billion for the corresponding period in 2021. The increases were primarily due to additional plant in service, including continued infrastructure investments at the natural gas distribution utilities.
Taxes Other Than Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $40 | | 12.8 | | $104 | | 10.7 |
In the third quarter 2022, taxes other than income taxes were $352 million compared to $312 million for the corresponding period in 2021. For year-to-date 2022, taxes other than income taxes were $1.1 billion compared to $969 million for the corresponding period in 2021. The increases primarily reflect an increase in municipal franchise fees at Georgia Power and an increase in revenue tax expenses at Southern Company Gas.
Estimated Loss on Plant Vogtle Units 3 and 4
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(334) | | N/M | | $(790) | | N/M |
Georgia Power recorded pre-tax charges (credits) to income for the estimated probable loss on Plant Vogtle Units 3 and 4 totaling $(70) million and $264 million in the third quarter 2022 and 2021, respectively, and $(18) million and $772 million for year-to-date 2022 and 2021, respectively. The charges (credits) reflect revisions to the total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements herein and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.
Gain on Dispositions, Net
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(105) | | (84.0) | | $(126) | | (70.4) |
In the third quarter 2022, gain on dispositions, net was $20 million compared to $125 million for the corresponding period in 2021. For year-to-date 2022, gain on dispositions, net was $53 million compared to $179 million for the corresponding period in 2021. The decreases primarily reflect a $121 million gain at Southern Company Gas related to the sale of Sequent in the third quarter 2021, partially offset by a $14 million gain recorded in the third quarter
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
2022 as a result of the early termination of the transition services agreement related to the 2019 sale of Gulf Power. The year-to-date 2022 decrease also reflects a $39 million gain at Southern Power primarily from contributions of wind turbine equipment to various equity method investments in 2021, partially offset by a $17 million gain from sales of integrated transmission system assets at Georgia Power in 2022. See Note 15 to the financial statements under "Southern Power – Development Projects" and "Southern Company Gas – Sale of Sequent" in Item 8 of the Form 10-K for additional information.
Allowance for Equity Funds Used During Construction
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $10 | | 20.4 | | $23 | | 16.4 |
In the third quarter 2022, allowance for equity funds used during construction was $59 million compared to $49 million for the corresponding period in 2021. For year-to-date 2022, allowance for equity funds used during construction was $163 million compared to $140 million for the corresponding period in 2021. The increases were primarily associated with an increase in capital expenditures related to Plant Barry Unit 8 construction at Alabama Power and transmission and distribution projects related to grid modernization at Georgia Power.
Earnings from Equity Method Investments
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(2) | | (6.7) | | $74 | | N/M |
For year-to-date 2022, earnings from equity method investments were $109 million compared to $35 million for the corresponding period in 2021. The increase was primarily due to pre-tax impairment charges in 2021 totaling $84 million related to the PennEast Pipeline project at Southern Company Gas, partially offset by a $16 million decrease at Southern Holdings primarily due to a decrease in investment income. See Note 7 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements herein under "Southern Company Gas" for additional information.
Interest Expense, Net of Amounts Capitalized
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $60 | | 13.3 | | $109 | | 8.1 |
In the third quarter 2022, interest expense, net of amounts capitalized was $511 million compared to $451 million for the corresponding period in 2021. The increase was primarily due to increases of approximately $28 million due to higher average outstanding borrowings and $28 million due to higher interest rates.
For year-to-date 2022, interest expense, net of amounts capitalized was $1.5 billion compared to $1.4 billion for the corresponding period in 2021. The increase was primarily due to higher average outstanding borrowings.
See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Other Income (Expense), Net
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1 | | 0.8 | | $124 | | 42.8 |
For year-to-date 2022, other income (expense), net was $414 million compared to $290 million for the corresponding period in 2021. The increase was primarily due to charitable contributions of $101 million at Southern Company Gas during the first and second quarters of 2021 and a $44 million increase in non-service cost-related retirement benefits income. See Note (H) to the Condensed Financial Statements herein for additional information.
Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $42 | | 11.3 | | $341 | | 62.0 |
In the third quarter 2022, income taxes were $414 million compared to $372 million for the corresponding period in 2021. For year-to-date 2022, income taxes were $891 million compared to $550 million for the corresponding period in 2021. The increases were primarily due to higher pre-tax earnings, partially offset by $113 million of additional tax expense in 2021 resulting from Southern Company Gas' sale of Sequent in the third quarter 2021. The year-to-date 2022 increase was also due to an adjustment in the second quarter 2022 related to a prior year state tax credit carryforward at Georgia Power. See Note (G) to the Condensed Financial Statements herein for additional information.
Net Income (Loss) Attributable to Noncontrolling Interests
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $7 | | N/M | | $(28) | | N/M |
Substantially all noncontrolling interests relate to renewable projects at Southern Power. In the third quarter 2022, net income attributable to noncontrolling interests was $12 million compared to $5 million for the corresponding period in 2021. The increase was primarily due to lower HLBV loss allocations to Southern Power's tax equity partners, including loss allocation impacts associated with the Garland battery energy storage facility being placed in service in the third quarter 2021, and higher income allocations to Southern Power's equity partners.
For year-to-date 2022, net loss attributable to noncontrolling interests was $55 million compared to $27 million for the corresponding period in 2021. The increased loss was primarily due to higher HLBV loss allocations to Southern Power's tax equity partners, partially offset by loss allocation impacts associated with the Garland battery energy storage facility being placed in service in the third quarter 2021 and higher income allocations to Southern Power's equity partners.
See Notes 9 and 15 to the financial statements under "Lessor" and "Southern Power," respectively, in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Alabama Power
Net Income
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $26 | | 5.2 | | $67 | | 5.6 |
Alabama Power's net income after dividends on preferred stock in the third quarter 2022 was $525 million compared to $499 million for the corresponding period in 2021. Alabama Power's net income after dividends on preferred stock for year-to-date 2022 was $1.26 billion compared to $1.19 billion for the corresponding period in 2021. These increases were primarily due to an increase in retail revenues associated with warmer weather in Alabama Power's service territory in 2022 compared to the corresponding periods in 2021 and sales growth, partially offset by higher non-fuel operations and maintenance costs.
Retail Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $357 | | 21.6 | | $658 | | 15.1 |
In the third quarter 2022, retail revenues were $2.01 billion compared to $1.65 billion for the corresponding period in 2021. For year-to-date 2022, retail revenues were $5.02 billion compared to $4.36 billion for the corresponding period in 2021.
Details of the changes in retail revenues were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Third Quarter 2022 | | Year-To-Date 2022 |
| (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | $ | 1,651 | | | | | $ | 4,357 | | | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 3 | | | 0.2 | % | | 7 | | | 0.2 | % |
| Sales growth | 20 | | | 1.2 | | | 53 | | | 1.2 | |
| Weather | 25 | | | 1.5 | | | 88 | | | 2.0 | |
| Fuel and other cost recovery | 309 | | | 18.7 | | | 510 | | | 11.7 | |
| Retail – current year | $ | 2,008 | | | 21.6 | % | | $ | 5,015 | | | 15.1 | % |
Revenues attributable to changes in sales increased inthe third quarter and year-to-date 2022 when compared to the corresponding periods in 2021. Weather-adjusted residential KWH sales decreased 0.4% and 0.3% in the third quarter and year-to-date 2022, respectively, when compared to the corresponding periods in 2021 primarily due to decreased customer usage. Weather-adjusted commercial KWH sales decreased 0.7% in the third quarter 2022 when compared to the corresponding period in 2021 primarily due to decreased customer usage. Weather-adjusted commercial KWH sales were flat for year-to-date 2022 when compared to the corresponding period in 2021. Industrial KWH sales increased 2.9% and 2.3% in the third quarter and year-to-date 2022, respectively, when compared to the corresponding periods in 2021 primarily due to increases in the forest product and pipeline sectors, partially offset by decreases in the chemicals sector.
Fuel and other cost recovery revenues increased in the third quarter and year-to-date 2022 when compared to the corresponding periods in 2021 primarily due to increases in the volume of KWHs generated and the average cost of fuel.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Electric rates include provisions to recognize the recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the NDR. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income. See Note 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.
Wholesale Revenues – Non-Affiliates
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $143 | | N/M | | $237 | | 83.2 |
In the third quarter 2022, wholesale revenues from sales to non-affiliates were $250 million compared to $107 million for the corresponding period in 2021. For year-to-date 2022, wholesale revenues from sales to non-affiliates were $522 million compared to $285 million for the corresponding period in 2021. The increases for the third quarter and year-to-date 2022 were primarily due to increases of 75.9% and 41.8%, respectively, in the price of energy due to higher natural gas prices, as well as increases of 32.3% and 29.3%, respectively, in KWH sales as a result of increased opportunity sales due to warmer weather in the third quarter and year-to-date 2022 compared to the corresponding periods in 2021.
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Alabama Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not 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.
Wholesale Revenues – Affiliates
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $17 | | 32.1 | | $61 | | 56.0 |
In the third quarter 2022, wholesale revenues from sales to affiliates were $70 million compared to $53 million for the corresponding period in 2021. The increase was primarily due to a 142.2% increase in the price of energy due to higher natural gas prices, partially offset by a 45.7% decrease in KWH sales due to the availability of lower cost Southern Company system resources compared to Alabama Power's generation.
For year-to-date 2022, wholesale revenues from sales to affiliates were $170 million compared to $109 million for the corresponding period in 2021. The increase was primarily due to an 84.7% increase in the price of energy due to higher natural gas prices, partially offset by a 15.3% decrease in KWH sales due to the availability of lower cost Southern Company system resources compared to Alabama Power's generation.
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.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Other Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $23 | | 24.7 | | $48 | | 17.9 |
In the third quarter 2022, other revenues were $116 million compared to $93 million for the corresponding period in 2021. For year-to-date 2022, other revenues were $316 million compared to $268 million for the corresponding period in 2021. The third quarter and year-to-date 2022 increases were primarily due to increases of $7 million and $15 million, respectively, in cogeneration steam revenue associated with higher natural gas prices, $6 million and $13 million, respectively, in transmission revenues primarily due to open access transmission tariff sales, and $3 million and $8 million, respectively, in unregulated lighting sales. The year-to-date 2022 increase also included a $5 million increase in energy services revenue.
Fuel and Purchased Power Expenses
| | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | 293 | | | 78.6 | | | $ | 472 | | | 50.9 | |
| Purchased power – non-affiliates | 109 | | | 143.4 | | | 174 | | | 100.6 | |
| Purchased power – affiliates | 68 | | | 151.1 | | | 146 | | | 128.1 | |
| Total fuel and purchased power expenses | $ | 470 | | | | | $ | 792 | | | |
In the third quarter 2022, total fuel and purchased power expenses were $964 million compared to $494 million for the corresponding period in 2021. The increase was primarily due to a $257 million increase in the cost of fuel and purchased power and a $213 million increase related to the volume of KWHs generated and purchased.
For year-to-date 2022, total fuel and purchased power expenses were $2.01 billion compared to $1.21 billion for the corresponding period in 2021. The increase was primarily due to a $518 million increase in the cost of fuel and purchased power and a $274 million increase related to the volume of KWHs generated and purchased.
Fuel and purchased power energy transactions do not have a significant impact on earnings, since energy expenses are generally offset by energy revenues through Alabama Power's energy cost recovery clause. See Note 2 to the financial statements under "Alabama Power – Rate ECR" in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of Alabama Power's generation and purchased power were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 | | Third Quarter 2021 | | Year-To-Date 2022 | | Year-To-Date 2021 |
Total generation (in billions of KWHs)(a) | 16 | | 16 | | 45 | | 45 |
Total purchased power (in billions of KWHs) | 4 | | 2 | | 9 | | 5 |
Sources of generation (percent)(a) — | | | | | | | |
| Coal | 47 | | 50 | | 45 | | 47 |
| Nuclear | 22 | | 24 | | 24 | | 25 |
| Gas | 28 | | 18 | | 23 | | 19 |
| Hydro | 3 | | 8 | | 8 | | 9 |
Cost of fuel, generated (in cents per net KWH) — | | | | | | | |
| Coal | 3.89 | | 2.85 | | 3.40 | | 2.78 |
| Nuclear | 0.67 | | 0.73 | | 0.67 | | 0.71 |
Gas(a) | 6.55 | | 3.03 | | 5.20 | | 2.68 |
Average cost of fuel, generated (in cents per net KWH)(a) | 3.91 | | 2.33 | | 3.13 | | 2.20 |
Average cost of purchased power (in cents per net KWH)(b) | 8.55 | | 7.96 | | 8.33 | | 6.70 |
(a)Excludes Central Alabama Generating Station KWHs and associated cost of fuel through July 12, 2022 as its fuel was previously provided by the purchaser under a power sales agreement. See Note 15 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.
(b)Average cost of purchased power includes fuel, energy, and transmission purchased by Alabama Power for tolling agreements where power is generated by the provider.
Fuel
In the third quarter 2022, fuel expense was $666 million compared to $373 million for the corresponding period in 2021. The increase was primarily due to a 116.2% increase in the average cost of natural gas per KWH generated, which excludes tolling agreements, a 36.5% increase in the average cost of coal per KWH generated, a 56.8% decrease in the volume of KWHs generated by hydro facilities as a result of less rainfall in the third quarter 2022 compared to the corresponding period in 2021, and a 46.9% increase in the volume of KWHs generated by natural gas.
For year-to-date 2022, fuel expense was $1.4 billion compared to $0.9 billion for the corresponding period in 2021. The increase was primarily due to a 94.0% increase in the average cost of natural gas per KWH generated, which excludes tolling agreements, a 22.3% increase in the average cost of coal per KWH generated, an 18.3% increase in the volume of KWHs generated by natural gas, and an 8.5% decrease in the volume of KWHs generated by hydro facilities as a result of less rainfall for year-to-date 2022 compared to the corresponding period in 2021.
Purchased Power – Non-Affiliates
In the third quarter 2022, purchased power expense from non-affiliates was $185 million compared to $76 million for the corresponding period in 2021. The increase was primarily due to a 193.7% increase in the volume of KWHs purchased as a result of warmer weather in the third quarter 2022 compared to the corresponding period in 2021, partially offset by an 11.2% decrease in the average cost per KWH purchased due to fixed capacity costs allocated across a higher level of generation.
For year-to-date 2022, purchased power expense from non-affiliates was $347 million compared to $173 million for the corresponding period in 2021. The increase was primarily due to a 100.5% increase in the volume of KWHs purchased as a result of warmer weather for year-to-date 2022 compared to the corresponding period in 2021, as well as an 8.2% increase in the average cost per KWH purchased due to higher natural gas and coal prices.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the third quarter 2022, purchased power expense from affiliates was $113 million compared to $45 million for the corresponding period in 2021. The increase was primarily due to an 84.5% increase in the average cost per KWH purchased due to higher natural gas and coal prices and a 36.4% increase in the volume of KWHs purchased as a result of warmer weather in the third quarter 2022 compared to the corresponding period in 2021.
For year-to-date 2022, purchased power expense from affiliates was $260 million compared to $114 million for the corresponding period in 2021. The increase was primarily due to a 71.0% increase in the average cost per KWH purchased due to higher natural gas and coal prices and a 33.6% increase in the volume of KWHs purchased as a result of warmer weather for year-to-date 2022 compared to the corresponding period in 2021.
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 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $17 | | 4.2 | | $95 | | 8.1 |
In the third quarter 2022, other operations and maintenance expenses were $418 million compared to $401 million for the corresponding period in 2021. For year-to-date 2022, other operations and maintenance expenses were $1.27 billion compared to $1.18 billion for the corresponding period in 2021. The increases for the third quarter and year-to-date 2022 were primarily due to increases of $18 million and $41 million, respectively, in transmission and distribution expenses primarily associated with line maintenance and $6 million and $12 million, respectively, in customer accounts, customer service, and sales expenses primarily associated with labor and bad debt expense. The increase for the third quarter 2022 was partially offset by a $15 million decrease in generation expenses primarily associated with scheduled outages and maintenance. The year-to-date 2022 increase also included a $24 million increase in generation expenses primarily associated with scheduled outages and maintenance and Rate CNP Compliance-related expenses. See Note 2 to the financial statements under "Alabama Power – Rate CNP Compliance" in Item 8 of the Form 10-K for additional information.
Allowance for Equity Funds Used During Construction
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $4 | | 28.6 | | $13 | | 34.2 |
For year-to-date 2022, allowance for equity funds used during construction was $51 million compared to $38 million for the corresponding period in 2021. The increase for year-to-date 2022 was primarily due to an increase in capital expenditures related to Plant Barry Unit 8 construction.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Interest Expense, Net of Amounts Capitalized
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $14 | | 16.7 | | $26 | | 10.3 |
In the third quarter 2022, interest expense, net of amounts capitalized was $98 million compared to $84 million for the corresponding period in 2021. For year-to-date 2022, interest expense, net of amounts capitalized was $278 million compared to $252 million for the corresponding period in 2021. The increases were primarily due to higher average outstanding borrowings. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings.
Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $14 | | 9.2 | | $28 | | 7.7 |
In the third quarter 2022, income taxes were $166 million compared to $152 million for the corresponding period in 2021. For year-to-date 2022, income taxes were $394 million compared to $366 million for the corresponding period in 2021. The increases were primarily due to higher pre-tax earnings.
Georgia Power
Net Income
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $322 | | 60.1 | | $821 | | 79.7 |
Georgia Power's net income in the third quarter 2022 was $858 million compared to $536 million for the corresponding period in 2021. For year-to-date 2022 net income was $1.85 billion compared to $1.03 billion for the corresponding period in 2021. The increases were primarily due to decreases of $249 million and $589 million in the third quarter and year-to-date 2022, respectively, in after-tax charges related to the construction of Plant Vogtle Units 3 and 4 and increases in retail revenues associated with rates and pricing and sales growth, partially offset by higher non-fuel operations and maintenance costs. The increase for year-to-date 2022 was also due to warmer weather in Georgia Power's service territory compared to the corresponding period in 2021.
See Note (B) to the Condensed Financial Statements herein and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.
Retail Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1,051 | | 39.6 | | $2,164 | | 33.5 |
In the third quarter 2022, retail revenues were $3.70 billion compared to $2.65 billion for the corresponding period in 2021. For year-to-date 2022, retail revenues were $8.63 billion compared to $6.47 billion for the corresponding period in 2021.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of the changes in retail revenues were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Third Quarter 2022 | | Year-To-Date 2022 |
| (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | $ | 2,652 | | | | | $ | 6,465 | | | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 157 | | | 5.9 | % | | 442 | | | 6.8 | % |
| Sales growth | 54 | | | 2.0 | | | 101 | | | 1.6 | |
| Weather | (1) | | | — | | | 89 | | | 1.4 | |
| Fuel cost recovery | 841 | | | 31.7 | | | 1,532 | | | 23.7 | |
| Retail – current year | $ | 3,703 | | | 39.6 | % | | $ | 8,629 | | | 33.5 | % |
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2022 when compared to the corresponding periods in 2021. The increases were primarily due to higher contributions from commercial and industrial customers with variable demand-driven pricing, base tariff increases in accordance with the 2019 ARP, and pricing effects associated with customer usage. See Note 2 to the financial statements under "Georgia Power – Rate Plans" in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales increased in the third quarter and year-to-date 2022 when compared to the corresponding periods in 2021. Weather-adjusted residential KWH sales increased 2.7% and 1.0% in the third quarter and year-to-date 2022, respectively, when compared to the corresponding periods in 2021 primarily due to customer growth. The increase for the third quarter 2022 also reflects increased customer usage. Weather-adjusted commercial KWH sales increased 3.2% and 2.9% in the third quarter and year-to-date 2022, respectively, when compared to the corresponding periods in 2021 primarily due to impacts on customer usage from increased activity outside the home as customers return to pre-pandemic levels of activity, as well as customer growth. Weather-adjusted industrial KWH sales increased 1.8% and 2.8% in the third quarter and year-to-date 2022, respectively, when compared to the corresponding periods in 2021 primarily due to increases in the pipeline, electronic, and paper sectors, partially offset by decreases in the chemicals and textiles sectors.
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 2022 when compared to the corresponding periods in 2021 due to higher fuel and purchased power costs. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See Note 2 to the financial statements under "Georgia Power – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.
Wholesale Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(7) | | (11.1) | | $43 | | 30.1 |
In the third quarter 2022, wholesale revenues were $56 million compared to $63 million for the corresponding period in 2021. The decrease was primarily due to a $22 million decrease in KWH sales associated with lower market demand and a $3 million decrease in capacity revenues due to the expiration of a non-affiliate PPA in 2021, largely offset by an increase of $20 million related to the average cost of fuel primarily due to higher natural gas and coal prices.
For year-to-date 2022, wholesale revenues were $186 million compared to $143 million for the corresponding period in 2021. The increase was primarily due to an increase of $60 million related to the average cost of fuel primarily due to higher natural gas and coal prices, partially offset by a $10 million decrease in KWH sales
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
associated with lower market demand and an $8 million decrease in capacity revenues due to the expiration of a non-affiliate PPA in 2021.
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 in amounts billable under the contract terms and provide for recovery of fixed costs and a return on investment. Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Georgia Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above Georgia Power's variable cost of energy.
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.
Other Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(11) | | (7.8) | | $(39) | | (8.8) |
In the third quarter 2022, other revenues were $130 million compared to $141 million for the corresponding period in 2021. For year-to-date 2022, other revenues were $403 million compared to $442 million for the corresponding period in 2021. The decreases for the third quarter and year-to-date 2022 were primarily due to increases of $14 million and $21 million, respectively, in realized losses associated with price stability products for retail customers on variable demand-driven pricing tariffs, decreases of $9 million and $12 million, respectively, from retail solar programs as a result of higher avoided cost credits to customers, and $6 million and $26 million, respectively, resulting from the termination of a transmission service contract. These reductions were partially offset by increases of $8 million and $22 million, respectively, associated with unregulated outdoor lighting sales and energy conservation projects and $6 million and $16 million, respectively, in open access transmission tariff sales. Also contributing to the decrease for year-to-date 2022 was a decrease of $28 million associated with the timing of revenue recognition for a large, ongoing power delivery construction and maintenance contract.
Fuel and Purchased Power Expenses
| | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-to-Date 2022 vs. Year-to-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | 409 | | | 94.7 | | | $ | 799 | | | 73.4 | |
| Purchased power – non-affiliates | 131 | | | 75.7 | | | 239 | | | 51.8 | |
| Purchased power – affiliates | 283 | | | 98.3 | | | 527 | | | 92.0 | |
| Total fuel and purchased power expenses | $ | 823 | | | | | $ | 1,565 | | | |
In the third quarter 2022, total fuel and purchased power expenses were $1.7 billion compared to $0.9 billion for the corresponding period in 2021. For year-to-date 2022, total fuel and purchased power expenses were $3.7 billion compared to $2.1 billion for the corresponding period in 2021. The increases for the third quarter and year-to-date 2022 were primarily due to increases of $0.8 billion and $1.4 billion, respectively, related to the average cost of fuel
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
and purchased power and net increases of $30 million and $158 million, respectively, related to 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 Note 2 to the financial statements under "Georgia Power – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.
Details of Georgia Power's generation and purchased power were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 | | Third Quarter 2021 | | Year-To-Date 2022 | | Year-To-Date 2021 |
Total generation (in billions of KWHs) | 15 | | 16 | | 45 | | 46 |
Total purchased power (in billions of KWHs) | 11 | | 10 | | 27 | | 23 |
Sources of generation (percent) — | | | | | | | |
| Gas | 53 | | 45 | | 48 | | 46 |
| | | | | | | |
| Nuclear | 28 | | 24 | | 26 | | 26 |
| Coal | 16 | | 28 | | 22 | | 24 |
| Hydro and other | 3 | | 3 | | 4 | | 4 |
Cost of fuel, generated (in cents per net KWH) — | | | | | | | |
| Gas | 6.10 | | 3.28 | | 4.99 | | 2.84 |
| Coal | 4.73 | | 2.73 | | 3.84 | | 2.89 |
| Nuclear | 0.75 | | 0.83 | | 0.76 | | 0.80 |
| | | | | | | |
Average cost of fuel, generated (in cents per net KWH) | 4.32 | | 2.51 | | 3.56 | | 2.30 |
Average cost of purchased power (in cents per net KWH)(*) | 10.14 | | 5.24 | | 8.00 | | 4.80 |
(*)Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider.
Fuel
In the third quarter 2022, fuel expense was $841 million compared to $432 million for the corresponding period in 2021. The increase was primarily due to increases of 86.0% and 73.3% in the average cost per KWH generated by natural gas and coal, respectively, and an 11.1% increase in the volume of KWHs generated by natural gas, partially offset by a 44.2% decrease in the volume of KWHs generated by coal.
For year-to-date 2022, fuel expense was $1.89 billion compared to $1.09 billion for the corresponding period in 2021. The increase was primarily due to increases of 75.7% and 32.9% in the average cost per KWH generated by natural gas and coal, respectively, partially offset by a 9.1% decrease in the volume of KWHs generated by coal.
Purchased Power – Non-Affiliates
In the third quarter 2022, purchased power expense from non-affiliates was $304 million compared to $173 million for the corresponding period in 2021. For year-to-date 2022, purchased power expense from non-affiliates was $700 million compared to $461 million for the corresponding period in 2021. The increases for the third quarter and year-to-date 2022 were primarily due to increases of 50.5% and 39.4%, respectively, in the volume of KWHs purchased primarily due to less available Georgia Power-owned coal generation and increases of 53.1% and 31.6%, respectively, in the average cost per KWH purchased primarily due to higher natural gas and coal 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.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Purchased Power – Affiliates
In the third quarter 2022, purchased power expense from affiliates was $571 million compared to $288 million for the corresponding period in 2021. For year-to-date 2022, purchased power expense from affiliates was $1.1 billion compared to $573 million for the corresponding period in 2021. The increases for the third quarter and year-to-date 2022 were primarily due to increases of 120.3% and 93.3%, respectively, in the average cost per KWH purchased primarily due to higher natural gas and coal prices.
Energy purchases from affiliates will vary depending on the 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 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $51 | | 9.4 | | $128 | | 8.2 |
In the third quarter 2022, other operations and maintenance expenses were $595 million compared to $544 million for the corresponding period in 2021. The increase was primarily due to increases of $35 million in distribution expenses primarily associated with line maintenance, $10 million in generation expenses primarily related to non-outage maintenance costs, and $9 million in certain compensation and benefit expenses, partially offset by a decrease of $6 million related to unregulated power delivery construction and maintenance projects.
For year-to-date 2022, other operations and maintenance expenses were $1.69 billion compared to $1.56 billion for the corresponding period in 2021. The increase was primarily due to increases of $80 million in distribution expenses primarily associated with line maintenance, $37 million in generation expenses primarily related to non-outage maintenance costs, $20 million in certain compensation and benefit expenses, $11 million in legal and regulatory expenses, and $8 million in amortization of cloud software, partially offset by a net decrease of $19 million related to unregulated products and services and $17 million in gains from sales of integrated transmission system assets.
Depreciation and Amortization
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $14 | | 4.1 | | $41 | | 4.0 |
In the third quarter 2022, depreciation and amortization was $359 million compared to $345 million for the corresponding period in 2021. For year-to-date 2022, depreciation and amortization was $1.07 billion compared to $1.03 billion for the corresponding period in 2021. The increases for the third quarter and year-to-date 2022 were primarily due to additional plant in service and increases of $3 million and $9 million, respectively, in amortization of regulatory assets related to CCR AROs under the terms of the 2019 ARP. See Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Rate Plans – 2019 ARP" for additional information on recovery of CCR AROs.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Taxes Other Than Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $25 | | 19.2 | | $55 | | 15.1 |
In the third quarter 2022, taxes other than income taxes were $155 million compared to $130 million for the corresponding period in 2021. For year-to-date 2022, taxes other than income taxes were $420 million compared to $365 million for the corresponding period in 2021. The increases were primarily due to increases in municipal franchise fees resulting from higher retail revenues.
Estimated Loss on Plant Vogtle Units 3 and 4
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(334) | | N/M | | $(790) | | N/M |
Georgia Power recorded pre-tax charges (credits) to income for the estimated probable loss on Plant Vogtle Units 3 and 4 totaling $(70) million and $264 million in the third quarter 2022 and 2021, respectively, and $(18) million and $772 million for year-to-date 2022 and 2021, respectively. The charges (credits) reflect revisions to the total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements herein and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.
Interest Expense, Net of Amounts Capitalized
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $17 | | 16.0 | | $32 | | 10.2 |
In the third quarter 2022, interest expense, net of amounts capitalized was $123 million compared to $106 million for the corresponding period in 2021. For year-to-date 2022, interest expense, net of amounts capitalized was $347 million compared to $315 million for the corresponding period in 2021. The increases for the third quarter and year-to-date 2022 were primarily associated with increases of approximately $11 million and $23 million, respectively, related to higher average outstanding borrowings and $10 million and $12 million, respectively, related to higher interest rates. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings.
Other Income (Expense), Net
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(6) | | (14.3) | | $16 | | 12.9 |
For year-to-date 2022, other income (expense), net was $140 million compared to $124 million for the corresponding period in 2021. The increase was primarily due to an increase of $11 million in non-service cost-related retirement benefits income. See Note (H) to the Condensed Financial Statements herein for additional information on retirement benefits.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $113 | | 100.0 | | $340 | | N/M |
In the third quarter 2022, income taxes were $226 million compared to $113 million for the corresponding period in 2021. For year-to-date 2022, income taxes were $421 million compared to $81 million for the corresponding period in 2021. The increases were primarily due to higher pre-tax earnings largely resulting from lower charges associated with the construction of Plant Vogtle Units 3 and 4. The year-to-date increase also reflects an adjustment in the second quarter 2022 related to a prior year state tax credit carryforward. See Note (B) to the Condensed Financial Statements herein and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" and Note (G) to the Condensed Financial Statements herein for additional information.
Mississippi Power
Net Income
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $12 | | 24.0 | | $17 | | 12.8 |
Mississippi Power's net income in the third quarter 2022 was $62 million compared to $50 million for the corresponding period in 2021. For year-to-date 2022, net income was $150 million compared to $133 million for the corresponding period in 2021. The increases were primarily due to an increase in revenues, partially offset by an increase in income taxes. The year-to-date 2022 increase was also partially offset by higher non-fuel operations and maintenance costs.
Retail Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $2 | | 0.8 | | $48 | | 7.2 |
In the third quarter 2022, retail revenues were$250 million compared to $248 million for the corresponding period in 2021. For year-to-date 2022, retail revenues were $718 million compared to $670 million for the corresponding period in 2021.
Details of the changes in retail revenues were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Third Quarter 2022 | | Year-To-Date 2022 |
| | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | $ | 248 | | | | | $ | 670 | | | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 4 | | | 1.6 | % | | 9 | | | 1.3 | % |
| Sales growth (decline) | — | | | — | | | 3 | | | 0.5 | |
| Weather | 3 | | | 1.2 | | | 10 | | | 1.5 | |
| Fuel and other cost recovery | (5) | | | (2.0) | | | 26 | | | 3.9 | |
| Retail – current year | $ | 250 | | | 0.8 | % | | $ | 718 | | | 7.2 | % |
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2022 when compared to the corresponding periods in 2021 primarily due to new PEP rates that became effective for the first billing cycle of April 2022, partially offset by a decrease in revenues associated with a tolling arrangement. See Note (B) to the Condensed Financial Statements under "Mississippi Power – Performance Evaluation Plan" herein for additional information.
Revenues attributable to changes in salesdecreased in the third quarter 2022 when compared to the corresponding period in 2021. Revenues attributable to changes in sales increased for year-to-date 2022 when compared to the corresponding period in 2021. Weather-adjusted residential KWH sales decreased 3.3% and 1.2% in the third quarter and year-to-date 2022, respectively, when compared to the corresponding periods in 2021 due to a decrease in customer usage resulting from increased activity outside the home as customers return to pre-pandemic levels of activity. Weather-adjusted commercial KWH sales increased 0.3% and 1.3% in the third quarter and year-to-date 2022, respectively, when compared to the corresponding periods in 2021 due to customer growth. Industrial KWH sales increased 1.9% and 1.8% in the third quarter and year-to-date 2022, respectively, when compared to the corresponding periods in 2021 primarily due to increases in the petroleum, pipeline, and transportation sectors.
Fuel and other cost recovery revenues decreased in the third quarter 2022 when compared to the corresponding period in 2021 primarily as a result of lower recoverable fuel costs. Fuel and other cost recovery revenues increased for year-to-date 2022 when compared to the corresponding period in 2021 primarily as a result of higher 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. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Mississippi Power" for additional information.
Wholesale Revenues – Non-Affiliates
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $— | | — | | $13 | | 7.3 |
For year-to-date 2022, wholesale revenues from sales to non-affiliates were $191 million compared to $178 million for the corresponding period in 2021. The increase was primarily due to higher fuel costs and an increase in base revenue from MRA customers primarily due to increased demand as a result of weather impacts in 2022.
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 Note 2 to the financial statements under "Mississippi Power" in Item 8 of the Form 10-K for additional information. See Note (B) to the Condensed Financial Statements under "Mississippi Power – Municipal and Rural Associations Tariff" herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Wholesale Revenues – Affiliates
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $125 | | N/M | | $216 | | N/M |
In the third quarter 2022, wholesale revenues from sales to affiliates were $187 million compared to $62 million for the corresponding period in 2021. For year-to-date 2022, wholesale revenues from sales to affiliates were $336 million compared to $120 million for the corresponding period in 2021. Theincreases were primarily due toincreases of $111 million and $197 million, respectively, associated with higher fuel prices, primarily for natural gas, and $14 million and $19 million, respectively, associated with higher KWH sales due to lower cost available Mississippi Power resources as compared to the available affiliate company generation.
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.
Other Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $5 | | 62.5 | | $14 | | 70.0 |
In the third quarter 2022, other revenues were $13 million compared to $8 million for the corresponding period in 2021. For year-to-date 2022, other revenues were $34 million compared to $20 million for the corresponding period in 2021. The increases for the third quarter and year-to-date 2022 were primarily due to increases of $5 million and $10 million, respectively, in unregulated sales associated with power delivery construction and maintenance projects.
Fuel and Purchased Power Expenses
| | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-to-Date 2022 vs. Year-to-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | 103 | | | 74.2 | | $ | 235 | | | 71.1 |
| Purchased power | 14 | | | 250.0 | | 15 | | | 70.6 |
| Total fuel and purchased power expenses | $ | 117 | | | | | $ | 250 | | | |
In the third quarter 2022, total fuel and purchased power expenses were $262 millioncompared to $145 million for the corresponding period in 2021. Theincrease was due to a $106 millionincrease related to the average cost of fuel and purchased power and an $11 million increase related to the volume of KWHs generated and purchased.
For year-to-date 2022, total fuel and purchased power expenses were $601 millioncompared to $351 million for the corresponding period in 2021. Theincreasewas primarily due to a $233 millionincrease related to the average cost of fuel and purchased power and a $17 millionincrease related to the volume of KWHs generated.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Mississippi Power's fuel cost recovery clause.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of Mississippi Power's generation and purchased power were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 | | Third Quarter 2021 | | Year-To-Date 2022 | | Year-To-Date 2021 |
Total generation (in millions of KWHs) | 5,093 | | 4,878 | | 13,650 | | 13,016 |
Total purchased power (in millions of KWHs) | 241 | | 124 | | 527 | | 562 |
Sources of generation (percent) – | | | | | | | |
| Gas | 89 | | 93 | | 89 | | 91 |
| Coal | 11 | | 7 | | 11 | | 9 |
Cost of fuel, generated (in cents per net KWH) – | | | | | | | |
| Gas | 5.10 | | 2.99 | | 4.43 | | 2.66 |
| Coal | 4.50 | | 3.16 | | 4.12 | | 3.13 |
Average cost of fuel, generated (in cents per net KWH) | 5.02 | | 3.00 | | 4.40 | | 2.70 |
Average cost of purchased power (in cents per net KWH) | 8.15 | | 4.51 | | 6.83 | | 3.78 |
Fuel
In the third quarter 2022, fuel expense was $242 million compared to $139 million for the corresponding period in 2021. The increasewas due to a 70.6%increase in the average cost of natural gas per KWH generated, a 42.4%increase in the average cost of coal per KWHs generated, and a 61.3%increase in the volume of KWHs generated by coal.
For year-to-date 2022, fuel expense was $565 million compared to $330 million for the corresponding period in 2021. Theincreasewas due to a 66.5%increase in the average cost of natural gas per KWH generated, a 31.6%increase in the average cost of coal per KWHs generated, a 30.2%increase in the volume of KWHs generated by coal, and a 2.4%increase in the volume of KWHs generated by natural gas.
Purchased Power
In the third quarter 2022, purchased power expense was $20 million compared to $6 million for the corresponding period in 2021. The increasewas due to a 93.6% increase in the volume of KWHs purchased and an 80.7% increase in the average cost per KWH purchased.
For year-to-date 2022, purchased power expense was $36 million compared to $21 million for the corresponding period in 2021. The increasewas primarily due to an 80.6% increase in the average cost per KWH purchased, partially offset by a 6.3% decrease in the volume of KWHs purchased.
Energy purchases will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Other Operations and Maintenance Expenses
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1 | | 1.2 | | $22 | | 9.6 |
For year-to-date 2022, other operations and maintenance expenses were $252 million compared to $230 million for the corresponding period in 2021. The increase was primarily due to increases of $9 million related to unregulated power delivery construction and maintenance projects, $6 million associated with storm reserve accruals, $4 million in transmission and distribution line maintenance, and $4 million in sales and use taxes associated with the Kemper County energy facility. See Note 2 to the financial statements under "Mississippi Power – System Restoration Rider" in Item 8 of the Form 10-K and Note (C) to the Condensed Financial Statements under "Other Matters – Mississippi Power" herein for additional information.
Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $7 | | 70.0 | | $16 | | 72.7 |
In the third quarter 2022, income taxes were $17 million compared to $10 million for the corresponding period in 2021. For year-to-date 2022, income taxes were $38 million compared to $22 million for the corresponding period in 2021. The third quarter and year-to-date 2022 increases primarily relate to a reduction of $3 million and $8 million, respectively, in the flowback of excess deferred income taxes associated with new PEP rates that became effective in April 2022, as well as increases of $4 million and $8 million, respectively, due to higher pre-tax earnings. See Note (G) to the Condensed Financial Statements herein for additional information.
Southern Power
Net Income Attributable to Southern Power
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $17 | | 21.8 | | $54 | | 25.6 |
Net income attributable to Southern Power in the third quarter 2022 was $95 million compared to $78 million for the corresponding period in 2021. Net income attributable to Southern Power for year-to-date 2022 was $265 million compared to $211 million for the corresponding period in 2021. The increases were primarily due to higher revenues driven by higher market prices of energy, partially offset by higher other operations and maintenance expenses. Also contributing to the year-to-date 2022 increase were higher revenues from new natural gas PPAs and higher income associated with tax equity partnerships. The year-to-date 2022 increase was partially offset by gains from contributions of wind turbine equipment to various equity method investments in the first quarter 2021 and a tax benefit due to a change in state apportionment methodology resulting from tax legislation enacted by the State of Alabama in the first quarter 2021.
See Note 15 to the financial statements under "Southern Power – Development Projects" in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Operating Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $501 | | 73.8 | | $1,008 | | 62.6 |
Total operating revenues include PPA capacity revenues, which are derived primarily from long-term contracts involving natural gas facilities, and PPA energy revenues from Southern Power's generation facilities. To the extent Southern Power has capacity not contracted under a PPA, it may sell power into an accessible wholesale market, or, to the extent those generation assets are part of the FERC-approved IIC, it may sell power into the Southern Company power pool.
Natural Gas Capacity and Energy Revenue
Capacity revenues generally represent the greatest contribution to operating income and are designed to provide recovery of fixed costs plus a return on investment.
Energy is generally sold at variable cost or is indexed to published natural gas indices. Energy revenues will vary depending on the energy demand of Southern Power's customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Power's energy. Energy revenues also include fees for support services, fuel storage, and unit start charges. Increases and decreases in energy revenues under PPAs that are driven by fuel or purchased power prices are accompanied by an increase or decrease in fuel and purchased power costs and do not have a significant impact on net income.
Solar and Wind Energy Revenue
Southern Power's energy sales from solar and wind generating facilities are predominantly through long-term PPAs that do not have capacity revenue. Customers either purchase the energy output of a dedicated renewable facility through an energy charge or pay a fixed price related to the energy generated from the respective facility and sold to the grid. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors.
See FUTURE EARNINGS POTENTIAL – "Southern Power's Power Sales Agreements" in Item 7 of the Form 10-K for additional information regarding Southern Power's PPAs.
Operating Revenues Details
Details of Southern Power's operating revenues were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 | | Third Quarter 2021 | | Year-To-Date 2022 | | Year-To-Date 2021 |
| (in millions) |
| PPA capacity revenues | $ | 131 | | | $ | 118 | | | $ | 344 | | | $ | 311 | |
| PPA energy revenues | 736 | | | 413 | | | 1,657 | | | 954 | |
| Total PPA revenues | 867 | | | 531 | | | 2,001 | | | 1,265 | |
| Non-PPA revenues | 304 | | | 139 | | | 590 | | | 327 | |
| Other revenues | 9 | | | 9 | | | 27 | | | 18 | |
| Total operating revenues | $ | 1,180 | | | $ | 679 | | | $ | 2,618 | | | $ | 1,610 | |
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
In the third quarter 2022, total operating revenues were $1.2 billion, reflecting a $501 million, or 74%, increase from the corresponding period in 2021. The increase in operating revenues was primarily due to the following:
•PPA capacity revenues increased $13 million, or 11%, primarily due to increased capacity sales under existing natural gas PPAs.
•PPA energy revenues increased $323 million, or 78%, primarily due to a $333 million increase in sales under existing natural gas PPAs resulting from a $287 million increase in the price of fuel and purchased power and a $45 million increase in the volume of KWHs sold.
•Non-PPA revenues increased $165 million, or 119%, due to a $172 million increase in the market price of energy, partially offset by a $7 million decrease in the volume of KWHs sold through short-term sales.
For year-to-date 2022, total operating revenues were $2.6 billion, reflecting a $1.0 billion, or 63%, increase from the corresponding period in 2021. The increase in operating revenues was primarily due to the following:
•PPA capacity revenues increased $33 million, or 11%, primarily due to new natural gas PPAs and increased capacity sales under existing natural gas PPAs, partially offset by the contractual expiration of natural gas PPAs.
•PPA energy revenues increased $703 million, or 74%, primarily due to a $540 million increase in sales under existing natural gas PPAs resulting from a $442 million increase in the price of fuel and purchased power and a $98 million increase in the volume of KWHs sold. Also contributing to the increase was a $186 million increase in sales associated with new natural gas PPAs, partially offset by a $17 million decrease due to the contractual expiration of natural gas PPAs.
•Non-PPA revenues increased $263 million, or 80%, due to a $299 million increase in the market price of energy, partially offset by a $35 million decrease in the volume of KWHs sold through short-term sales.
Fuel and Purchased Power Expenses
Details of Southern Power's generation and purchased power were as follows:
| | | | | | | | | | | | | | | | | |
| | Third Quarter 2022 | Third Quarter 2021 | | Year-To-Date 2022 | Year-To-Date 2021 |
| (in billions of KWHs) |
| Generation | 12.8 | 12.1 | | 36.7 | 31.8 |
| Purchased power | 1.2 | 0.8 | | 2.3 | 2.0 |
| Total generation and purchased power | 14.0 | 12.9 | | 39.0 | 33.8 |
| | | | | |
Total generation and purchased power (excluding solar, wind, fuel cells, and tolling agreements) | 8.8 | 7.7 | | 23.2 | 20.2 |
Southern Power's PPAs for natural gas generation generally provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing Southern Power for substantially all of the cost of fuel relating to the energy delivered under such PPAs. Consequently, changes in such fuel costs are generally accompanied by a corresponding change in related fuel revenues and do not have a significant impact on net income. Southern Power is responsible for the cost of fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the wholesale market or into the Southern Company power pool for capacity owned directly by Southern Power.
Purchased power expenses will vary depending on demand, availability, and the cost of generating resources throughout the Southern Company system and other contract resources. Load requirements are submitted to the Southern Company power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power, an affiliate company, or external parties. Such purchased power costs are generally recovered through PPA revenues.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of Southern Power's fuel and purchased power expenses were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Third Quarter 2022 vs. Third Quarter 2021 | | Year-to-Date 2022 vs. Year-to-Date 2021 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | 346 | | | 133.6 | | $ | 734 | | | 135.9 |
| Purchased power | 103 | | | 251.2 | | 147 | | | 170.9 |
| Total fuel and purchased power expenses | $ | 449 | | | | | $ | 881 | | | |
In the third quarter 2022, total fuel and purchased power expenses increased $449 million, or 150%, compared to the corresponding period in 2021. Fuel expense increased $346 million due to a $323 million increase associated with the average cost of fuel and a $23 million increase associated with the volume of KWHs generated. Purchased power expense increased $103 million due to a $79 million increase associated with the average cost of purchased power and a $24 million increase associated with the volume of KWHs purchased.
For year-to-date 2022, total fuel and purchased power expenses increased $881 million, or 141%, compared to the corresponding period in 2021. Fuel expense increased $734 million due to a $651 million increase associated with the average cost of fuel and an $83 million increase associated with the volume of KWHs generated. Purchased power expense increased $147 million due to a $134 million increase associated with the average cost of purchased power and a $13 million increase associated with the volume of KWHs purchased.
Other Operations and Maintenance Expenses
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $19 | | 20.1 | | $23 | | 7.4 |
In the third quarter 2022, other operations and maintenance expenses were $113 million compared to $94 million for the corresponding period in 2021. For year-to-date 2022, other operations and maintenance expenses were $331 million compared to $308 million for the corresponding period in 2021. The increases for the third quarter and year-to-date 2022 were primarily due to increases of $11 million and $13 million, respectively, related to the timing of non-outage generation maintenance expenses. Also contributing to the year-to-date 2022 increase was an increase of $11 million in transmission expenses to serve new natural gas PPAs, partially offset by $6 million related to the allocation in 2021 of uncollected settlements by the Energy Reliability Council of Texas market as a result of Winter Storm Uri.
Loss on Sales-Type Lease
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(15) | | (100.0) | | $(14) | | (93.4) |
In the third quarter 2021, a $15 million loss on sales-type lease was recorded upon commencement of the Garland battery energy storage facility PPA, $10 million of which was allocated through noncontrolling interests to Southern Power's partners in the project. See Notes 9 and 15 to the financial statements under "Lessor" and "Southern Power," respectively, in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Gain on Dispositions, Net
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $— | | N/M | | $(37) | | (94.9) |
For year-to-date 2022, gain on dispositions, net was $2 million compared to $39 million for the corresponding period in 2021. The decrease primarily resulted from gains associated with contributions of wind turbine equipment to various equity method investments in the first quarter 2021. See Note 15 to the financial statements under "Southern Power – Development Projects" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Southern Power" herein for additional information.
Income Taxes (Benefit)
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $27 | | N/M | | $52 | | N/M |
In the third quarter 2022, income tax expense was $36 million compared to $9 million for the corresponding period in 2021. The change was primarily due to higher pre-tax earnings, partially offset by higher wind PTCs.
For year-to-date 2022, income tax expense was $49 million compared to a benefit of $3 million for the corresponding period in 2021. The change was primarily due to higher pre-tax earnings for year-to-date 2022 and a change in state apportionment methodology resulting from tax legislation enacted by the State of Alabama in the first quarter 2021, partially offset by higher wind PTCs for year-to-date 2022.
Net Income (Loss) Attributable to Noncontrolling Interests
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $7 | | N/M | | $(28) | | N/M |
In the third quarter 2022, net income attributable to noncontrolling interests was $12 million compared to $5 million for the corresponding period in 2021. The increase was primarily due to lower HLBV loss allocations to tax equity partners, including loss allocation impacts associated with the Garland battery energy storage facility being placed in service in the third quarter 2021, and higher income allocations to equity partners.
For year-to-date 2022, net loss attributable to noncontrolling interests was $55 million compared to $27 million for the corresponding period in 2021. The increased loss was primarily due to higher HLBV loss allocations to tax equity partners, partially offset by loss allocation impacts associated with the Garland battery energy storage facility being placed in service in the third quarter 2021 and higher income allocations to equity partners.
See Notes 9 and 15 to the financial statements under "Lessor" and "Southern Power," respectively, in Item 8 of the Form 10-K for additional information.
Southern Company Gas
Operating Metrics
Southern Company Gas continues to focus on several operating metrics, including Heating Degree Days, customer count, and volumes of natural gas sold.
Southern Company Gas measures weather and the effect on its business using Heating Degree Days. Generally, increased Heating Degree Days result in higher demand for natural gas on Southern Company Gas' distribution system. Southern Company Gas has various regulatory mechanisms, such as weather and revenue normalization and straight-fixed-variable rate design, which limit its exposure to weather changes within typical ranges in each of its
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
utility's respective service territory. Southern Company Gas also utilizes weather hedges to limit the negative income impacts in the event of warmer-than-normal weather.
The number of customers served by gas distribution operations and gas marketing services can be impacted by natural gas prices, economic conditions, and competition from alternative fuels. Gas distribution operations and gas marketing services' customers are primarily located in Georgia and Illinois.
Southern Company Gas' natural gas volume metrics for gas distribution operations and gas marketing services illustrate the effects of weather and customer demand for natural gas.
Seasonality of Results
During the Heating Season, natural gas usage and operating revenues are generally higher as more customers are connected to the gas distribution systems and natural gas usage is higher in periods of colder weather. Southern Company Gas' base operating expenses, excluding cost of natural gas, bad debt expense, and certain incentive compensation costs, are incurred relatively evenly throughout the year. Seasonality also affects the comparison of certain balance sheet items across quarters, including receivables, unbilled revenues, natural gas for sale, and notes payable. However, these items are comparable when reviewing Southern Company Gas' annual results. Thus, Southern Company Gas' operating results for the interim periods presented are not necessarily indicative of annual results and can vary significantly from quarter to quarter.
Net Income
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $27 | | 48.2 | | $127 | | 32.6 |
In the third quarter 2022, net income was $83 million compared to $56 million for the corresponding period in 2021. Net income increased $14 million at gas distribution operations primarily due to base rate increases and continued investment in infrastructure replacement and $14 million at gas pipeline investments primarily as a result of higher earnings at SNG and lower income taxes related to the PennEast Pipeline project. The third quarter 2021 results also included a $93 million after-tax gain and $85 million of additional tax expense as a result of the July 1, 2021 sale of Sequent.
For year-to-date 2022, net income was $516 million compared to $389 million for the corresponding period in 2021. Net income increased $73 million at gas pipeline investments primarily as a result of a 2021 impairment charge related to the PennEast Pipeline project and $57 million at gas distribution operations primarily due to base rate increases and continued investment in infrastructure replacement. The year-to-date 2021 results also included $108 million of net income from Sequent, including the $93 million after-tax gain, and $85 million of additional tax expense as a result of the July 1, 2021 sale of Sequent.
See Notes 2, 7, and 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Natural Gas Revenues, including Alternative Revenue Programs
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $234 | | 37.6 | | $1,004 | | 33.5 |
In the third quarter 2022, natural gas revenues, including alternative revenue programs, were $857 million compared to $623 million for the corresponding period in 2021. For year-to-date 2022, natural gas revenues, including alternative revenue programs, were $4.0 billion compared to $3.0 billion for the corresponding period in 2021.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of the changes in natural gas revenues, including alternative revenue programs, were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 | | Year-To-Date 2022 |
| (in millions) | | (% change) | | (in millions) | | (% change) |
| Natural gas revenues – prior year | $ | 623 | | | | | $ | 2,994 | | | |
| Estimated change resulting from – | | | | | | | |
| Infrastructure replacement programs and base rate changes | 54 | | | 8.7 | % | | 186 | | | 6.2 | % |
| Gas costs and other cost recovery | 172 | | | 27.6 | | | 955 | | | 31.9 | |
| Gas marketing services | 1 | | | 0.2 | | | 14 | | | 0.5 | |
| Wholesale gas services | — | | | — | | | (187) | | | (6.2) | |
| | | | | | | |
| Other | 7 | | | 1.1 | | | 36 | | | 1.1 | |
| Natural gas revenues – current year | $ | 857 | | | 37.6 | % | | $ | 3,998 | | | 33.5 | % |
Revenues from infrastructure replacement programs and base rate changes increased in the third quarter and year-to-date 2022 compared to the corresponding periods in 2021 primarily due to rate increases at Nicor Gas, Atlanta Gas Light, and Chattanooga Gas and continued investment in infrastructure replacement. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" in Item 8 of the Form 10-K for additional information.
Revenues associated with gas costs and other cost recovery increased in the third quarter and year-to-date 2022 compared to the corresponding periods in 2021 primarily due to higher natural gas cost recovery. See "Cost of Natural Gas" herein for additional information. Revenue impacts from weather and customer growth are described further below.
During Heating SeasonRevenues from gas marketing services increased for year-to-date 2022 compared to the corresponding period in 2021 due to higher commodity prices and higher sales to commercial customers.
The changes in year-to-date 2022 revenues related to wholesale gas services were due to the sale of Sequent on July 1, 2021. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Southern Company Gas' natural gas usagedistribution utilities have various regulatory mechanisms that limit their exposure to weather changes. Southern Company Gas also uses hedges for the majority of any remaining exposure to warmer-than-normal weather in Illinois for gas distribution operations and operating revenues are generally higher. Weatherin Illinois and Georgia for gas marketing services; therefore, weather typically does not have a significant net income impact during the non-Heating Season.impact. 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.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter | | 2022 vs. normal | 2022 vs. 2021 | | Year-to-Date | | 2022 vs. normal | 2022 vs. 2021 |
| Normal(*) | 2022 | 2021 | | colder (warmer) | colder (warmer) | | Normal(*) | 2022 | 2021 | | colder (warmer) | colder (warmer) |
| (in thousands) | | | | | (in thousands) | | | |
| Illinois | 42 | | 56 | | 14 | | | 33.3 | % | 300.0 | % | | 3,686 | | 3,683 | | 3,594 | | | (0.1) | % | 2.5 | % |
| Georgia | 3 | | — | | 3 | | | — | % | — | % | | 1,431 | | 1,361 | | 1,396 | | | (4.9) | % | (2.5) | % |
|
| | | | | | | | | | | | | | | |
| | | Year-to-Date | | 2017
vs.
2016 | | 2017
vs.
normal |
| | | Normal(a) | | 2017 | | 2016 | | (warmer) | | (warmer) |
Illinois(b) | | 3,817 |
| | 3,146 |
| | 3,353 |
| | (6.2 | )% | | (17.6 | )% |
| Georgia | | 1,631 |
| | 1,008 |
| | 1,449 |
| | (30.4 | )% | | (38.2 | )% |
| |
(a) | (*)Normal represents the 10-year average from January 1, 2007 through September 30, 2016 for Illinois at Chicago Midway International Airport and for Georgia at Atlanta Hartsfield-Jackson International Airport, based on information obtained from the National Oceanic and Atmospheric Administration, National Climatic Data Center. |
| |
(b) | The 10-year average Heating Degree Days established by the Illinois Commission in Nicor Gas' 2009 rate case is 3,580 for the first nine months from 1998 through 2007. |
For the third quarters 201710-year average from January 1, 2012 through September 30, 2021 for Illinois at Chicago Midway International Airport and 2016,for Georgia at Atlanta Hartsfield-Jackson International Airport, based on information obtained from the weather-related pre-tax income impact was immaterial.
Southern Company Gas hedged its exposure to warmer-than-normal weather at Nicor Gas in Illinois; therefore, the weather-related negative pre-tax income impact on gas distribution operations was limited to $6 million ($3 million after tax)National Oceanic and $7 million ($5 million after tax) for year-to-date 2017 and 2016, respectively. Southern Company Gas also hedged its exposure at gas marketing services to warmer-than-normal weather in Georgia and Illinois;
Atmospheric Administration, National Climatic Data Center.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
therefore, the weather-related negative pre-tax income impact on gas marketing services was limited to $10 million ($6 million after tax) for year-to-date 2017 and there was no impact for year-to-date 2016.
The following table provides the number of customers served by Southern Company Gas at September 30, 20172022 and 2016:2021:
| | | | | | | | | | | | | | | | | |
| September 30, | | |
| 2022 | | 2021 | | 2022 vs. 2021 |
| (in thousands, except market share %) | | (% change) |
| Gas distribution operations | 4,300 | | | 4,283 | | | 0.4 | % |
| Gas marketing services | | | | | |
Energy customers(*) | 598 | | | 603 | | | (0.8) | % |
| Market share of energy customers in Georgia | 28.3 | % | | 28.9 | % | | |
| | | | | |
| | | | | |
|
| | | | | | | | |
| | September 30, | | |
| | 2017 | | 2016 | | 2017 vs. 2016 |
| | (in thousands, except market share %) | | (% change) |
| Gas distribution operations | 4,555 |
| | 4,522 |
| | 0.7 | % |
| Gas marketing services | | | | | |
Energy customers(*) | 756 |
| | 626 |
| | 20.8 | % |
| Market share of energy customers in Georgia | 28.8 | % | | 29.4 | % | | |
| Service contracts | 1,183 |
| | 1,189 |
| | (0.5 | )% |
| |
(*) | Includes approximately 140,000 customers as of September 30, 2017 that were contracted to serve beginning April 1, 2017. |
Southern Company Gas anticipates overall customer growth trends at gas distribution operationsand uses a variety of targeted marketing programs to continue as it expects continued improvement in theattract new housing market and low natural gas prices.
Gas marketing services' market share in Georgia decreased at September 30, 2017 compared to the corresponding period in 2016 as a result of a highly competitive marketing environment, which Southern Company Gas expects to continue for the foreseeable future. Southern Company Gas will continue efforts at gas marketing services to enter into targeted markets and expand its energy customers and service contracts.to retain existing customers.
Cost of Natural Gas
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $165 | | N/M | | $897 | | 95.1 |
|
| | |
| Successor |
| Third Quarter 2017 vs. Third Quarter 2016 |
| (change in millions) | | (% change) |
| $1 | | 0.8 |
In the third quarter 2017, cost ofExcluding Atlanta Gas Light, which does not sell natural gas was $134 million compared to $133 million for the corresponding period in 2016. This increase reflected 7% higherend-use customers, natural gas prices during the third quarter 2017 compared to the corresponding period in 2016, partially offset by lower demand for natural gas.
|
| | | | | | | | | | | | | |
| | | Successor | | | Predecessor |
| | | Year-to-Date 2017 | | July 1, 2016 through September 30, 2016 | | | January 1, 2016 through June 30, 2016 |
| | | (in millions) | | (in millions) | | | (in millions) |
| Cost of natural gas | | $ | 1,085 |
| | $ | 133 |
| | | $ | 755 |
|
Cost of natural gas primarily reflected an increase of 38% in natural gas prices during the year-to-date 2017 compared to the corresponding period in 2016, partially offset by lower demand for natural gas driven by warmer-than-normal weather.
Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, recoverablegas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations. Cost of natural gas at gas distribution operations represented approximately 79%78% and 87% of the total cost of natural gas forin the third quarter and year-to-date 2017 and will be recovered in this manner. For additional information, see2022, respectively. See MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – "Cost"Southern Company Gas – Cost of Natural Gas" of Southern Company Gas in Item 7 of the Form 10-K and "Natural"Natural Gas Revenues," herein. including Alternative Revenue Programs" herein for additional information.
In the third quarter 2022, cost of natural gas was $294 million compared to $129 million for the corresponding period in 2021. For year-to-date 2022, cost of natural gas was $1.8 billion compared to $943 million for the corresponding period in 2021. The increases reflect higher gas cost recovery as a result of increases of 104% and 113% in natural gas prices in the third quarter and year-to-date 2022, respectively, compared to the corresponding periods in 2021.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
The following table details the volumes of natural gas sold during all periods presented.
| | | | Third Quarter | | 2017
vs.
2016 | | Year-to-Date | | 2017
vs.
2016 | | Third Quarter | 2022 vs. 2021 | | Year-to-Date | 2022 vs. 2021 |
| | 2017 | | 2016 | | % Change | | 2017 | | 2016 | | % Change | | 2022 | 2021 | | 2022 | 2021 |
Gas distribution operations
(mmBtu in millions) | | | | | | | | | | | | Gas distribution operations (mmBtu in millions) | |
| Firm | 73 |
| | 71 |
| | 2.8 | % | | 438 |
| | 467 |
| | (6.2 | )% | Firm | 70 | | 74 | | (5.4) | % | | 485 | | 465 | | 4.3 | % |
| Interruptible | 22 |
| | 22 |
| | — | % | | 71 |
| | 71 |
| | — | % | Interruptible | 22 | | 23 | | (4.3) | | | 69 | | 73 | | (5.5) | |
| Total | 95 |
| | 93 |
| | 2.2 | % | | 509 |
| | 538 |
| | (5.4 | )% | Total | 92 | | 97 | | (5.2) | % | | 554 | | 538 | | 3.0 | % |
| | Gas marketing services
(mmBtu in millions) | | | | | | | | | | | | Gas marketing services (mmBtu in millions) | |
| Firm: | | | | | | | | | | | | Firm: | |
| Georgia | 3 |
| | 3 |
| | — | % | | 11 |
| | 25 |
| | (56.0 | )% | Georgia | 3 | | 3 | | — | % | | 24 | | 26 | | (7.7) | % |
| Illinois | 1 |
| | 1 |
| | — | % | | 4 |
| | 8 |
| | (50.0 | )% | Illinois | — | | — | | — | | | 4 | | 5 | | (20.0) | |
| Other emerging markets | 2 |
| | 2 |
| | — | % | | 7 |
| | 9 |
| | (22.2 | )% | |
| Interruptible: | | | | | | | | | | | | |
| Large commercial and industrial | 3 |
| | 3 |
| | — | % | | 8 |
| | 10 |
| | (20.0 | )% | |
| | Other | | Other | 2 | | 2 | | — | | | 8 | | 10 | | (20.0) | |
| Interruptible large commercial and industrial | | Interruptible large commercial and industrial | 3 | | 3 | | — | | | 11 | | 10 | | 10.0 | |
| Total | 9 |
| | 9 |
| | — | % | | 30 |
| | 52 |
| | (42.3 | )% | Total | 8 | | 8 | | — | % | | 47 | | 51 | | (7.8) | % |
Wholesale gas services
(mmBtu in millions/day) | | | | | | | | | | | | |
| Daily physical sales | 6.3 |
| | 7.6 |
| | (17.1 | )% | | 6.4 |
| | 7.6 |
| | (15.8 | )% | |
Other Operations and Maintenance Expenses
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $14 | | 5.9 | | $53 | | 6.8 |
|
| | |
| Successor |
| Third Quarter 2017 vs. Third Quarter 2016 |
| (change in millions) | | (% change) |
| $(11) | | (5.1) |
In the third quarter 2017,2022, other operations and maintenance expenses were $205$252 million compared to $216$238 million for the corresponding period in 2016. The decrease was primarily related to $8 million of expenses associated with certain benefit arrangements recorded in 2016, $2 million lower marketing expenses at gas marketing services, and a $3 million decrease in other employee benefit and incentive costs. |
| | | | | | | | | | | | | |
| | | Successor | | | Predecessor |
| | | Year-to-Date 2017 | | July 1, 2016 through September 30, 2016 | | | January 1, 2016 through June 30, 2016 |
| | | (in millions) | | (in millions) | | | (in millions) |
| Other operations and maintenance | | $ | 671 |
| | $ | 216 |
| | | $ | 454 |
|
Other operations and maintenance expenses for the successor year-to-date 2017 reflected increased compensation expenses due to timing, partially offset by low bad debt expense. For all periods presented, other operations and maintenance expenses primarily includes professional services, including pipeline compliance and maintenance and legal services, as well as compensation and benefit costs.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Depreciation and Amortization
|
| | |
| Successor |
| Third Quarter 2017 vs. Third Quarter 2016 |
| (change in millions) | | (% change) |
| $9 | | 7.8 |
In the third quarter 2017, depreciation and amortization was $125 million compared to $116 million for the corresponding period in 2016. The increase was primarily due to $7 million in additional depreciation at gas distribution operations associated with additional plant in service primarily related to continued investment in infrastructure replacement programs.
|
| | | | | | | | | | | | | |
| | | Successor | | | Predecessor |
| | | Year-to-Date 2017 | | July 1, 2016 through September 30, 2016 | | | January 1, 2016 through June 30, 2016 |
| | | (in millions) | | (in millions) | | | (in millions) |
| Depreciation and amortization | | $ | 370 |
| | $ | 116 |
| | | $ | 206 |
|
Depreciation and amortization for the successor year-to-date 2017 included $29 million of additional amortization of intangible assets established in the application of acquisition accounting primarily at gas marketing services, $21 million in additional depreciation at gas distribution operations due to additional assets placed in service primarily related to continued investment in infrastructure replacement programs, and $7 million from the acceleration of depreciation relating to certain assets.
Taxes Other Than Income Taxes
|
| | |
| Successor |
| Third Quarter 2017 vs. Third Quarter 2016 |
| (change in millions) | | (% change) |
| $(3) | | (10.3) |
In the third quarter 2017, taxes other than income taxes were $26 million compared to $29 million for the corresponding period in 2016. The decrease primarily reflects establishing a regulatory asset related to Nicor Gas' invested capital tax. For additional information, see FUTURE EARNINGS POTENTIAL– "Regulatory Matters – Riders" herein.
|
| | | | | | | | | | | | | |
| | | Successor | | | Predecessor |
| | | Year-to-Date 2017 | | July 1, 2016 through September 30, 2016 | | | January 1, 2016 through June 30, 2016 |
| | | (in millions) | | (in millions) | | | (in millions) |
| Taxes other than income taxes | | $ | 140 |
| | $ | 29 |
| | | $ | 99 |
|
Taxes other than income taxes in the successor periods reflected increased revenue-based taxes due to higher revenues at gas distribution operations during the successor periods.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Earnings from Equity Method Investments
|
| | |
| Successor |
| Third Quarter 2017 vs. Third Quarter 2016 |
| (change in millions) | | (% change) |
| $3 | | 10.3 |
In the third quarter 2017, earnings from equity method investments were $32 million compared to $29 million for the corresponding period in 2016.2021. The increase was primarily due to higher earningscompensation and benefit expenses and higher expenses passed through directly to customers primarily related to bad debt at gas distribution operations.
For year-to-date 2022, other operations and maintenance expenses were $829 million compared to $776 million for the corresponding period in 2021. Excluding $53 million of expenses related to Sequent for year-to-date 2021, other operations and maintenance expenses increased approximately $106 million. The increase was primarily due to increases of $47 million in compensation and benefit expenses, $30 million in expenses passed through directly to customers primarily related to bad debt at gas distribution operations, $18 million in customer accounts expenses, and $15 million in technology-related costs.
Depreciation and Amortization
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $7 | | 5.3 | | $18 | | 4.5 |
In the third quarter 2022, depreciation and amortization was $140 million compared to $133 million for the corresponding period in 2021. For year-to-date 2022, depreciation and amortization was $414 million compared to $396 million for the corresponding period in 2021. The increases were primarily due to continued infrastructure investments at the natural gas distribution utilities.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Taxes Other Than Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $9 | | 25.0 | | $42 | | 25.3 |
In the third quarter 2022, taxes other than income taxes were $45 million compared to $36 million for the corresponding period in 2021. For year-to-date 2022, taxes other than income taxes were $208 million compared to $166 million for the corresponding period in 2021. The increases primarily reflect an increase in revenue tax expenses as a result of higher natural gas revenues and an increase in invested capital tax expense at Nicor Gas. Revenue tax expenses are passed through directly to customers and have no impact on net income.
Gain on Dispositions, Net
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(121) | | (100.0) | | $(122) | | (96.1) |
The sale of Sequent in the third quarter 2021 resulted in a gain on dispositions, net of $121 million. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Earnings from SNG, PennEast Pipeline, and Horizon Pipeline.Equity Method Investments
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $9 | | 36.0 | | $91 | | N/M |
|
| | | | | | | | | | | | | |
| | | Successor | | | Predecessor |
| | | Year-to-Date 2017 | | July 1, 2016 through September 30, 2016 | | | January 1, 2016 through June 30, 2016 |
| | | (in millions) | | (in millions) | | | (in millions) |
| Earnings from equity method investments | | $ | 100 |
| | $ | 29 |
| | | $ | 2 |
|
EarningsIn the third quarter 2022, earnings from equity method investments were $34 million compared to $25 million for the corresponding period in 2021. The increase was primarily due to higher earnings at SNG resulting from higher revenues primarily due to increased demand.
For year-to-date 2022, earnings from equity method investments were $105 million compared to $14 million for the successor year-to-date 2017 consisted of $86corresponding period in 2021. The increase was primarily due to pre-tax impairment charges totaling $84 million in 2021 related to the PennEast Pipeline project and higher earnings at SNG resulting from SNG and $14 million in earnings from all other investments.higher revenues primarily due to increased demand.
See Notes 4 and 11Note 7 to the financial statements of Southernunder "Southern Company Gas under "Equity Method Investments – SNG" and "Investment in SNG," respectively,Gas" in Item 8 of the Form 10-K and Note (J)(E) to the Condensed Financial Statements herein under "Southern"Southern Company Gas – Equity Method Investments" hereinGas" for additional information.
Other Income (Expense), Net
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $2 | | 15.4 | | $113 | | N/M |
|
| | |
| Successor |
| Third Quarter 2017 vs. Third Quarter 2016 |
| (change in millions) | | (% change) |
| $9 | | 100.0 |
In the third quarter 2017,For year-to-date 2022, other income (expense), net was $18$47 million of income compared to $9$66 million of expense for the correspondingcorresponding period in 2016.2021. The increasechange was primarilylargely due to a $14charitable contributions totaling $101 million gain from the settlement of contractor litigation claims.
|
| | | | | | | | | | | | | |
| | | Successor | | | Predecessor |
| | | Year-to-Date 2017 | | July 1, 2016 through September 30, 2016 | | | January 1, 2016 through June 30, 2016 |
| | | (in millions) | | (in millions) | | | (in millions) |
| Other income (expense), net | | $ | 26 |
| | $ | 9 |
| | | $ | 5 |
|
The successor year-to-date 2017 reflects a $16 million gain from the settlement of contractor litigation claims. The successor period of July 1, 2016 through September 30, 2016 and the predecessor period of January 1, 2016 through June 30, 2016 primarily represent the tax gross-up on contributions in aid of construction and AFUDC.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Interest Expense, Net of Amounts Capitalized
|
| | |
| Successor |
| Third Quarter 2017 vs. Third Quarter 2016 |
| (change in millions) | | (% change) |
| $12 | | 30.8 |
In the third quarter 2017, interest expense, net of amounts capitalized was $51 million compared to $39 million for the corresponding period in 2016. The increase was primarily due to additional interest expense on new debt issuances.
|
| | | | | | | | | | | | | |
| | | Successor | | | Predecessor |
| | | Year-to-Date 2017 | | July 1, 2016 through September 30, 2016 | | | January 1, 2016 through June 30, 2016 |
| | | (in millions) | | (in millions) | | | (in millions) |
| Interest expense, net of amounts capitalized | | $ | 145 |
| | $ | 39 |
| | | $ | 96 |
|
The successor year-to-date 2017 and the period of July 1, 2016 through September 30, 2016 reflect additional interest expense on new debt issuances, partially offset by reductions of $29 million and $9 million, respectively, resulting from the fair value adjustment of long-term debt in acquisition accounting.
Income Taxes
|
| | |
Successor |
Third Quarter 2017 vs. Third Quarter 2016 |
(change in millions) | | (% change) |
$45 | | N/M |
N/M - Not meaningful
In the third quarter 2017, income taxes were $52 million compared to $7 million for the corresponding period in 2016. The increase reflects $23 million of additional deferred income tax expense associated with State of Illinois tax legislation enacted during the third quarter 2017first and the allocationsecond quarters of new tax apportionment factors in several states for the inclusion2021 and an increase of Southern Company Gas into the consolidated Southern Company state tax filings, as well as higher pre-tax earnings. See FUTURE EARNINGS POTENTIAL herein for additional information.
|
| | | | | | | | | | | | | |
| | | Successor | | | Predecessor |
| | | Year-to-Date 2017 | | July 1, 2016 through September 30, 2016 | | | January 1, 2016 through June 30, 2016 |
| | | (in millions) | | (in millions) | | | (in millions) |
| Income taxes | | $ | 233 |
| | $ | 7 |
| | | $ | 87 |
|
The successor year-to-date 2017 income taxes reflect $23$12 million of additional deferred income tax expense associated with State of Illinois tax legislation and the allocation of new tax apportionment factors, as well as increased income taxes from higher pre-tax earnings. See FUTURE EARNINGS POTENTIAL herein for additional information.
Performance and Non-GAAP Measures
Prior to the Merger, Southern Company Gas evaluated segment performance using earnings before interest and taxes (EBIT), which includes operating income, earnings from equity method investments, and other income
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(expense), net. EBIT excludes interest expense, net of amounts capitalized and income taxes (benefit), which were evaluated on a consolidated basis for those periods. EBIT is used herein to discuss the results of Southern Company Gas' segments for the predecessor period, as EBIT was the primary measure of segment profit or loss for that period. Subsequent to the Merger, Southern Company Gas changed its segment performance measure from EBIT to net income to better align with the performance measure utilized by Southern Company. EBIT for the successor third quarters 2017 and 2016 and the successor year-to-date 2017 presented herein is considered a non-GAAP measure. Southern Company Gas also discusses consolidated EBIT, which is considered a non-GAAP measure for all periods presented. The presentation of consolidated EBIT is believed to provide useful supplemental information regarding a consolidated measure of profit or loss. Southern Company Gas further believes that the presentation of segment EBIT for the successor third quarters 2017 and 2016 and the successor year-to-date 2017 is useful as it allows for a measure of comparability to other companies with different capital and legal structures, which accordingly may be subject to different interest rates and effective tax rates. The applicable reconciliations of net income to consolidated EBIT and segment EBIT are provided herein.
Adjusted operating margin is a non-GAAP measure that is calculated as operating revenues minus cost of natural gas, cost of other sales, and revenue tax expense. Adjusted operating margin excludes other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, and Merger-related expenses, which are included in the calculation of operating income as calculated in accordance with GAAP and reflected in the consolidated statements of income. The presentation of adjusted operating margin is believed to provide useful information regarding the contribution resulting from customer growth at gas distribution operations since the cost of natural gas and revenue tax expense can vary significantly and are generally billed directlyprimarily related to customers. Southern Company Gas further believes that utilizing adjusted operating margin at gas marketing services, wholesale gas services, and gas midstream operations allows it to focus on a direct measure of adjusted operating margin before overhead costs. The applicable reconciliation of operating income to adjusted operating margin is provided herein.
EBIT and adjusted operating margin should not be considered alternatives to, or more meaningful indicators of, Southern Company Gas' operating performance than consolidated net income attributable to Southern Company Gas or operating income as determinedan increase in accordance with GAAP. In addition, Southern Company Gas' adjusted operating margin may not be comparable to similarly titled measures of other companies. |
| | | | | | | | | | | | | | | | | | | | | |
| | | Successor | | | Predecessor |
| | | Third Quarter 2017 | | Third Quarter 2016 | | Year-to-Date 2017 | | July 1, 2016 through September 30, 2016 | | | January 1, 2016 through
June 30,
2016 |
| | | (in millions) | | | (in millions) |
| Operating Income | | $ | 68 |
| | $ | 12 |
| | $ | 555 |
| | $ | 12 |
| | | $ | 321 |
|
Other operating expenses(a) | | 356 |
| | 396 |
| | 1,181 |
| | 396 |
| | | 815 |
|
Revenue taxes(b) | | (8 | ) | | (8 | ) | | (74 | ) | | (8 | ) | | | (56 | ) |
| Adjusted Operating Margin | | $ | 416 |
| | $ | 400 |
| | $ | 1,662 |
| | $ | 400 |
| | | $ | 1,080 |
|
| |
(a) | Includes other operations and maintenance, depreciation and amortization, taxes other than income taxes, and Merger-related expenses. |
| |
(b) | Nicor Gas' revenue tax expenses, which are passed through directly to customers. |
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
| | | | | | | | | | | | | | | | | | | | | |
| | | Successor | | | Predecessor |
| | | Third Quarter 2017 | | Third Quarter 2016 | | Year-to-Date 2017 | | July 1, 2016 through September 30, 2016 | | | January 1, 2016
through
June 30,
2016 |
| | | (in millions) | | | (in millions) |
Consolidated Net Income Attributable
to Southern Company Gas | | $ | 15 |
| | $ | 4 |
| | $ | 303 |
| | $ | 4 |
| | | $ | 131 |
|
Net income attributable to
noncontrolling interest (*) | | | | — |
| | — |
| | — |
| | | 14 |
|
| Income taxes | | 52 |
| | 7 |
| | 233 |
| | 7 |
| | | 87 |
|
Interest expense, net of amounts
capitalized | | 51 |
| | 39 |
| | 145 |
| | 39 |
| | | 96 |
|
| EBIT | | $ | 118 |
| | $ | 50 |
| | $ | 681 |
| | $ | 50 |
| | | $ | 328 |
|
| |
(*) | See Note 4 to the financial statements of Southern Company Gas under "Variable Interest Entities" in Item 8 of the Form 10-K for additional information. |
Segment Information
Adjusted operating margin, operating expenses, and Southern Company Gas' primary performance metric for each segment is illustrated in the tables below.non-service cost-related retirement benefits income. See Note (K)(H) to the Condensed Financial Statements herein for additional information.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Successor |
| | Third Quarter 2017 |
| Third Quarter 2016 |
| Adjusted Operating |
| Operating |
| Net Income |
| Adjusted Operating |
| Operating |
| Net Income |
| Margin(*) |
| Expenses(*) |
| (Loss) |
| Margin(*) |
| Expenses(*) |
| (Loss) |
| (in millions) |
| (in millions) |
| Gas distribution operations | $ | 379 |
|
| $ | 271 |
|
| $ | 52 |
|
| $ | 353 |
|
| $ | 284 |
|
| $ | 27 |
|
| Gas marketing services | 51 |
|
| 48 |
|
| 1 |
|
| 45 |
|
| 51 |
|
| (4 | ) |
| Wholesale gas services | (25 | ) |
| 11 |
|
| (23 | ) |
| (8 | ) |
| 10 |
|
| (11 | ) |
| Gas midstream operations | 12 |
|
| 13 |
|
| 14 |
|
| 9 |
|
| 13 |
|
| 14 |
|
| All other | 2 |
|
| 8 |
|
| (29 | ) |
| 2 |
|
| 31 |
|
| (22 | ) |
| Intercompany eliminations | (3 | ) |
| (3 | ) |
| — |
|
| (1 | ) |
| (1 | ) |
| — |
|
| Consolidated | $ | 416 |
|
| $ | 348 |
|
| $ | 15 |
|
| $ | 400 |
|
| $ | 388 |
|
| $ | 4 |
|
| |
(*) | Operating margin and operating expenses are adjusted for Nicor Gas' revenue tax expenses, which are passed through directly to customers. |
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
(Continued)
Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(106) | | (79.7) | | $(63) | | (28.1) |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Year-to-Date 2017 | | July 1, 2016 through
September 30, 2016 | | | January 1, 2016 through
June 30, 2016 |
| | Adjusted Operating | | Operating | | Net Income | | Adjusted Operating | | Operating | | Net Income | | | Adjusted Operating | | Operating | | |
| | Margin(*) | | Expenses(*) | | (Loss) | | Margin(*) | | Expenses(*) | | (Loss) | | | Margin(*) | | Expenses(*) | | EBIT |
| | (in millions) | | | (in millions) |
Gas distribution
operations | $ | 1,329 |
| | $ | 866 |
| | $ | 223 |
| | $ | 353 |
| | $ | 284 |
| | $ | 27 |
| | | $ | 911 |
| | $ | 560 |
| | $ | 353 |
|
Gas marketing
services | 213 |
| | 149 |
| | 36 |
| | 45 |
| | 51 |
| | (4 | ) | | | 190 |
| | 81 |
| | 109 |
|
Wholesale gas
services | 93 |
| | 40 |
| | 28 |
| | (8 | ) | | 10 |
| | (11 | ) | | | (36 | ) | | 33 |
| | (68 | ) |
Gas midstream
operations | 28 |
| | 38 |
| | 38 |
| | 9 |
| | 13 |
| | 14 |
| | | 15 |
| | 24 |
| | (6 | ) |
| All other | 7 |
| | 22 |
| | (22 | ) | | 2 |
| | 31 |
| | (22 | ) | | | 4 |
| | 65 |
| | (60 | ) |
Intercompany
eliminations | (8 | ) | | (8 | ) | | — |
| | (1 | ) | | (1 | ) | | — |
| | | (4 | ) | | (4 | ) | | — |
|
| Consolidated | $ | 1,662 |
| | $ | 1,107 |
| | $ | 303 |
| | $ | 400 |
| | $ | 388 |
| | $ | 4 |
| | | $ | 1,080 |
| | $ | 759 |
| | $ | 328 |
|
| |
(*) | Operating margin and operating expenses are adjusted for Nicor Gas' revenue tax expenses, which are passed through directly to customers. |
Segment Information
Operating revenues, operating expenses, and net income (loss) for each segment are provided in the table below. See Note (L) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2022 | | 2021 |
| Operating Revenues | | Operating Expenses | | Net Income (Loss) | | Operating Revenues | | Operating Expenses | | Net Income (Loss) |
| (in millions) | | (in millions) |
| Third Quarter |
| Gas distribution operations | $ | 751 | | | $ | 629 | | | $ | 59 | | | $ | 556 | | | $ | 459 | | | $ | 45 | |
| Gas pipeline investments | 8 | | | 3 | | | 24 | | | 8 | | | 3 | | | 10 | |
Wholesale gas services(*) | — | | | — | | | — | | | — | | | (120) | | | 94 | |
| Gas marketing services | 85 | | | 87 | | | (2) | | | 52 | | | 52 | | | (2) | |
| All other | 16 | | | 12 | | | 2 | | | 11 | | | 25 | | | (91) | |
| Intercompany eliminations | (3) | | | — | | | — | | | (4) | | | (4) | | | — | |
| Consolidated | $ | 857 | | | $ | 731 | | | $ | 83 | | | $ | 623 | | | $ | 415 | | | $ | 56 | |
| | | | | | | | | | | |
| Year-to-Date |
| Gas distribution operations | $ | 3,533 | | | $ | 2,922 | | | $ | 365 | | | $ | 2,466 | | | $ | 1,936 | | | $ | 308 | |
| Gas pipeline investments | 24 | | | 8 | | | 76 | | | 24 | | | 9 | | | 3 | |
Wholesale gas services(*) | — | | | — | | | — | | | 188 | | | (53) | | | 108 | |
| Gas marketing services | 420 | | | 327 | | | 65 | | | 311 | | | 226 | | | 60 | |
| All other | 43 | | | 48 | | | 10 | | | 29 | | | 60 | | | (90) | |
| Intercompany eliminations | (22) | | | (19) | | | — | | | (24) | | | (24) | | | — | |
| Consolidated | $ | 3,998 | | | $ | 3,286 | | | $ | 516 | | | $ | 2,994 | | | $ | 2,154 | | | $ | 389 | |
(*)As a result of the sale of Sequent, wholesale gas services is no longer a reportable segment for the third quarter and year-to-date 2022. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K 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 regulatory 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
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
gas delivered to its customers and its fixed and variable costs, including depreciation, interest expense, operations and maintenance, taxes, and overhead costs, and to earn a reasonable return on its investments.
With the exception of Atlanta Gas Light, Southern Company Gas' second largest utility that operates in a deregulated natural gas market and has a straight-fixed-variable rate design that minimizes the variability of its revenues based on consumption, the earnings of the natural gas distribution utilities can be affected by customer consumption patterns that are a function of weather conditions, price levels for natural gas, and general economic conditions that may impact customers' ability to pay for natural gas consumed. Southern Company Gas has various weatherregulatory and other mechanisms, such as weather and revenue normalization mechanisms and weather derivative instruments, that limit its exposure to changes in customer consumption, including weather changes within typical ranges in its natural gas distribution utilities' service territories.
Successor Third Quarter 2017 vs. Third Quarter 2016 See Note 2 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
In the third quarter 2017,and year-to-date 2022, net income was $52increased $14 million, or 31.1%, and $57 million, or 18.5%, respectively, when compared to $27 million for the corresponding periodperiods in 2016.2021, as described further below:
•Operating revenues increased $195 million and $1.07 billion, respectively, when compared to the corresponding periods in 2021 primarily due to higher gas cost recovery, rate increases, and continued investment in infrastructure replacement. Gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas.
•Operating expenses increased $170 million and $986 million, respectively, when compared to the corresponding periods in 2021 primarily due to increases of $129 million and $802 million, respectively, in the cost of gas as a result of higher natural gas prices compared to 2021, higher compensation and benefit expenses, and higher depreciation resulting from additional assets placed in service. The increase in netoperating expenses also includes higher costs passed through directly to customers, primarily related to bad debt expenses and revenue taxes.
•Other income relatesand (expense) increased $3 million and $12 million, respectively, when compared to the corresponding periods in 2021, primarily due to an increase of $26 million in adjusted operating margin, a decrease of $13 million in operating expenses, and an increase of $11 million in other income (expense), net. The change in net income also includes an increase of $7 million in interestnon-service cost-related retirement benefits income. See Note (H) to the Condensed Financial Statements herein for additional information.
•Interest expense, net of amounts capitalized increased $5 million and an increase of $18$11 million, respectively, when compared to the corresponding periods in income tax expense. The increase in adjusted operating margin2021 primarily reflects $24 million in additional revenue from the continued investment in infrastructure replacement programs and base rate increases, primarily at Atlanta Gas Light effective March 1, 2017. The decrease in operating expenses primarily reflects $18 million in rate credits provided to customers of Elizabethtown Gas in 2016 as a condition of the Merger, partially offset by $7 million in additional depreciation due to additional debt issued to finance continued investmentinvestments. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings.
•Income taxes increased $9 million and $25 million, respectively, when compared to the corresponding periods in infrastructure programs. The increase in other income (expense), net2021 primarily reflects a $14 million gain from the settlement of contractor litigation claims in 2017. The increase in interest expense includes the impact of intercompany promissory notes executed in December 2016 and the issuance of first mortgage bonds at Nicor Gas on August 10, 2017. The increase in income tax expense relates primarilydue to higher pre-tax earnings.
Successor Year-to-Date 2017Gas Pipeline Investments
NetGas pipeline investments consists primarily of joint ventures in natural gas pipeline investments including SNG, Dalton Pipeline, and PennEast Pipeline. See Note (E) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
In the third quarter 2022, net income increased $14 million when compared to the corresponding period in 2021 primarily due to higher earnings at SNG resulting from higher revenues primarily due to increased demand and lower income taxes related to the PennEast Pipeline project.
For year-to-date 2022, net income increased $73 million when compared to the corresponding period in 2021 primarily due to pre-tax impairment charges totaling $84 million ($67 million after tax) in 2021 related to the equity method investment in the PennEast Pipeline project and higher earnings at SNG resulting from higher revenues primarily due to increased demand. See Note 7 to the financial statements under "Southern Company Gas" in Item 8 of $223 million includes $1.3 billion in adjusted operating margin, $866 million in operating expenses, and $23 million in other income (expense), net, which resulted in EBIT of $486 million. Net income also includes
the Form 10-K for additional information.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
$119 million in interest expense, net of amounts capitalized and $144 million in income tax expense. Adjusted operating margin reflects $69 million in additional revenue from continued investment in infrastructure replacement programs and base rate increases, primarily at Atlanta Gas Light effective March 1, 2017. Also included in adjusted operating margin was increased customer growth, partially offset by a $6 million negative impact of warmer-than-normal weather, net of hedging. Operating expenses reflect a $21 million increase in depreciation associated with additional assets placed in service, as well as increased compensation expense, legal expenses, and pipeline compliance and maintenance activities. Other income (expense), net reflects a $16 million gain from the settlement of contractor litigation claims. Interest expense reflects the impact of intercompany promissory notes executed in December 2016 and the issuance of first mortgage bonds at Nicor Gas on August 10, 2017.
Successor Period of July 1, 2016 through September 30, 2016
Net income of $27 million includes $353 million in adjusted operating margin, $284 million in operating expenses, including $18 million in rate credits provided to customers, and $6 million in other income (expense), net, which resulted in EBIT of $75 million. Net income also includes $32 million in interest expense and $16 million in income tax expense.
Predecessor Period of January 1, 2016 through June 30, 2016
EBIT of $353 million includes $911 million in adjusted operating margin, $560 million in operating expenses, and $2 million in other income (expense), net. Adjusted operating margin reflects revenue from continued investment in infrastructure replacement programs and increased usage and customer growth, partially offset by a $7 million negative impact of warmer-than-normal weather, net of hedging. Operating expenses reflect depreciation associated with additional assets placed in service.
Gas Marketing Services
Gas marketing services consists of several businesses that provideprovides energy-related products and services to natural gas markets including warranty sales.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. Operating expenses primarily reflect employee costs, marketing, and bad debt expenses.
Successor Third Quarter 2017 vs. Third Quarter 2016
In the third quarter 2017,2022, net income was $1 millionflat when compared to a net loss of $4 million for the corresponding period in 2016. The2021 primarily due to an increase in net income primarily relates to a $6 million increase in adjusted operating margin and a $3 million decrease in operating expenses. The change in net income also includes increases of $1 million and $3 million in interest expense and income tax expense, respectively. Adjusted operating margin primarily reflects a $3 million decrease in unrealized hedge losses, net of recoveries, and a $4 million increase from the elimination of deferred revenue in the third quarter 2016 from the application of acquisition accounting. Operating expenses reflect decreased amortization of intangible assets established in the application of acquisition accounting.
Successor Year-to-Date 2017
Net income of $36 million includes $213 million in adjusted operating margin and $149$35 million in operating expenses which resulted in EBITprimarily due to higher cost of $64 million. Net income also includes $4 million in interest expense and $24 million in income tax expense. Adjusted operating margin reflectsgas, largely offset by a $10 million negative impactrelated increase of warmer-than-normal weather, net of hedging, and $7 million in unrealized hedge losses, net of recoveries. Operating expenses include $30 million in additional amortization of intangible assets established in the application of acquisition accounting.
Successor Period of July 1, 2016 through September 30, 2016
Net loss of $4 million includes $45 million in adjusted operating margin and $51$33 million in operating expenses, which resulted in a loss before interest and taxes of $6 million. Also included inrevenues.
For year-to-date 2022, net loss is $2income increased $5 million, in income tax benefit.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Predecessor Period of January 1, 2016 through June 30, 2016
EBIT of $109 million includes $190 million in adjusted operating margin and $81 million in operating expenses. Adjusted operating margin reflects $9 million in unrealized hedge gains. Earnings in the predecessor period include $14 million attributable to noncontrolling interest.
Wholesale Gas Services
Wholesale gas services is involved in asset management and optimization, storage, transportation, producer and peaking services, natural gas supply, natural gas services, and wholesale gas marketing. Southern Company Gas has positioned the business to generate positive economic earnings on an annual basis even under low volatility market conditions that can result from a number of factors. When market price volatility increases, wholesale gas services is well positioned to capture significant value and generate stronger results. Operating expenses primarily reflect employee compensation and benefits.
Successor Third Quarter 2017 vs. Third Quarter 2016
In the third quarter 2017, net loss was $23 millionor 8.3%, when compared to a net loss of $11 million for the corresponding period in 2016. The2021 primarily due to a $109 million increase in net loss relates primarilyoperating revenues as a result of higher commodity prices and higher sales to a $17 million decrease in adjusted operating margin, partially offset by an increase of $8 million in income tax benefit due to higher losses. The decrease in adjusted gross margin includes $22 million in additional mark-to-market losses and a $7 million decrease in gains from commercial activity,customers, partially offset by a $12$101 million positive impact from the amortization of liabilities recorded in the application of acquisition accounting.
Successor Year-to-Date 2017
Net income of $28 million includes $93 million in adjusted operating margin and $40 millionincrease in operating expenses which resulted in EBIT of $53 million. Net income also includes $5primarily due to $95 million in interest expensehigher cost of natural gas and $20an increase of $4 million in income tax expense.
Successor Period of July 1, 2016 through September 30, 2016
Net loss of $11 million includes $(8) million in adjusted operating margin and $10 million in operating expenses, which resulted intaxes as a loss before interest and taxes of $17 million. Also included in net loss is $1 million in interest expense and $7 million in income tax benefit.
Predecessor Period of January 1, 2016 through June 30, 2016
Loss before interest and taxes of $68 million includes $(36) million in adjusted operating margin, $33 million in operating expenses, and $1 million in other income (expense), net.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following table illustrates the components of wholesale gas services' adjusted operating margin for the periods presented.
|
| | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Third Quarter 2017 | | Third Quarter 2016 | | Year-to-Date 2017 | | July 1, 2016 through September 30, 2016 | | | January 1, 2016
through
June 30,
2016 |
| | (in millions) | | | (in millions) |
| Commercial activity recognized | $ | 3 |
| | $ | 10 |
| | $ | 80 |
| | 10 |
| | | $ | 34 |
|
| Gain (loss) on storage derivatives | 4 |
| | 11 |
| | 13 |
| | 11 |
| | | (38 | ) |
Gain (loss) on transportation and forward
commodity derivatives | (22 | ) | | (7 | ) | | 14 |
| | (7 | ) | | | (31 | ) |
LOCOM adjustments, net of current period
recoveries | — |
| | — |
| | — |
| | — |
| | | (1 | ) |
| Purchase accounting adjustments | (10 | ) | | (22 | ) | | (14 | ) | | (22 | ) | | | — |
|
| Adjusted Operating Margin | $ | (25 | ) | | $ | (8 | ) | | $ | 93 |
| | $ | (8 | ) | | | $ | (36 | ) |
Change in Commercial Activity
The commercial activity at wholesale gas services includes recognition of storage and transportation values that were generated in prior periods, which reflect the impact of prior period hedge gains and losses as associated physical transactions occur. Warmer-than-normal weather during the 2016/2017 Heating Season, lower power generation volumes, and build-out of new U.S. pipeline infrastructure, along with increases in natural gas supply, caused low volatility and a tightening of locational or transportation spreads in 2017, negatively impacting the amount of commercial activity revenues generated relative to demand fees for contracted pipeline transportation and storage capacity, and minimum sharing under asset management agreements. However, as natural gas prices and forward storage or time spreads increased, wholesale gas services was able to capture higher storage values that it expects to recognize as commercial activity revenues when natural gas is physically withdrawn from storage. Southern Company Gas anticipates continued low volatility in certain areas of wholesale gas services' portfolio.
Change in Storage and Transportation Derivatives
Volatility in the natural gas market arises from a number of factors, such as weather fluctuations or changes in supply or demand for natural gas in different regions of the U.S. The volatility of natural gas commodity prices has a significant impact on Southern Company Gas' customer rates, long-term competitive position against other energy sources, and the ability of wholesale gas services to capture value from locational and seasonal spreads. In 2017 and 2016, there was little price volatility; however, the potential exists for market fundamentals indicating some level of increased volatility that would benefit Southern Company Gas' portfolio of pipeline transportation capacity. Additionally, during the first nine months of 2017, forward storage or time spreads applicable to the locations of wholesale gas services' specific storage positions resulted in storage derivative gains. Transportation and forward commodity derivative gains are primarily the result of narrowing transportation basis spreads due to some reduction in supply constraints resulting from new U.S. pipeline infrastructure and increases in natural gas supply and warmer-than-normal weather, which impacted forward prices at natural gas receipt and delivery points, primarily in the Northeast and Midwest regions.
Withdrawal Schedule and Physical Transportation Transactions
The expected natural gas withdrawals from storage and expected offset to prior hedge losses/gains associated with the transportation portfolio of wholesale gas services are presented in the following table, along with the net operating revenues expected at the time of withdrawal from storage and the physical flow of natural gas between contracted transportation receipt and delivery points. Wholesale gas services' expected net operating revenues exclude storage and transportation demand charges, as well as other variable fuel, withdrawal, receipt, and delivery
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
charges, but are net of the estimated impact of profit sharing under its asset management agreements. Further, the amounts that are realizable in future periods are based on the inventory withdrawal schedule, planned physical flow of natural gas between the transportation receipt and delivery points, and forward natural gas prices at September 30, 2017. A portion of wholesale gas services' storage inventory and transportation capacity is economically hedged with futures contracts, which results in the realization of substantially fixed net operating revenues.
|
| | | | | | | | | | |
| | Storage withdrawal schedule | | |
| | Total storage
(WACOG $2.67) | | Expected net operating gains(a) | | Physical transportation transactions – expected net operating gains (losses)(b) |
| | (in mmBtu in millions) | | (in millions) | | (in millions) |
| 2017 | 22.0 |
| | $ | 4 |
| | $ | (13 | ) |
| 2018 and thereafter | 40.0 |
| | 17 |
| | 28 |
|
| Total at September 30, 2017 | 62.0 |
| | $ | 21 |
| | $ | 15 |
|
| |
(a) | Represents expected operating gains from planned storage withdrawals associated with existing inventory positions and could change as wholesale gas services adjusts its daily injection and withdrawal plans in response to changes in future market conditions and forward NYMEX price fluctuations. |
| |
(b) | Represents the periods associated with the transportation derivative gains during which the derivatives will be settled and the physical transportation transactions will occur that offset the derivative gains and losses that were previously recognized. |
The unrealized storage and transportation derivative gains do not change the underlying economic value of wholesale gas services' storage and transportation positions and will be reversed when the related transactions occur and are recognized. For more information on wholesale gas services' energy marketing and risk management activities, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company Gas in Item 7 of the Form 10-K.
Gas Midstream Operations
Gas midstream operations consists primarily of gas pipeline investments, with storage and fuels also aggregated into this segment. Gas pipeline investments include SNG, Horizon Pipeline, Atlantic Coast Pipeline, PennEast Pipeline, Dalton Pipeline, and Magnolia Enterprise Holdings, Inc. See Note (J) to the Condensed Financial Statements herein and Notes 4 and 11 to the financial statements of Southern Company Gas under "Equity Method Investments – SNG" and "Investment in SNG," respectively, in Item 8 of the Form 10-K for additional information.
Successor Third Quarter 2017 vs. Third Quarter 2016
In both the third quarter 2017 and the corresponding period in 2016 net income was $14 million. Net income reflects a $3 million increase in adjusted operating margin and a $4 million increase in earnings from equity method investments at SNG, PennEast Pipeline, and Horizon Pipeline. The change in net income also includes a $9 million increase in interest expense, net of amounts capitalized and a $2 million decrease in income taxes. The increase in interest expense includes the impact of intercompany promissory notes executed in December 2016.
Successor Year-to-Date 2017
Net income of $38 million includes $28 million in adjusted operating margin, $38 million in operating expenses, $97 million in earnings from equity method investments, consisting primarily of earnings from equity method investments at SNG, and $3 million in other income (expense), net, which resulted in EBIT of $90 million. Also included in net income are $25 million in interest expense and $27 million in income tax expense.
Successor Period of July 1, 2016 through September 30, 2016
Net income of $14 million includes $9 million in adjusted operating margin, $13 million in operating expenses, $28 million in earnings from equity method investments, consisting primarily of earnings from equity method
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
investments at SNG, and $1 million in other income (expense), net, which resulted in EBIT of $25 million. Also included in net income is $11 million in income tax expense.
Predecessor Period of January 1, 2016 through June 30, 2016
Loss before interest and taxes of $6 million includes $15 million in adjusted operating margin, $24 million in operating expenses, and $3 million of other income (expense), net.higher pre-tax earnings.
All Other
All other includes Southern Company Gas' investment in Triton,natural gas storage businesses, a renewable natural gas business, AGL Services Company, and Southern Company Gas Capital, as well as various corporate operating expenses that are not allocated to the reportable segments and interest income (expense) associated with affiliate financing arrangements.
Successor Third Quarter 2017 vs. Third Quarter 2016
In the third quarter 2017, net loss was $29 million compared to $22 million in the corresponding period in 2016. The increase in net loss reflects a $23 million decrease in operating expenses and a decrease of $2 million in other income (expense), net. Net loss also reflected a $6 million increase in interest expense, net of amounts capitalized and an increase of $34 million in income taxes. The decrease in operating expenses reflects a $35 million decrease in Merger-related expenses, partially offset by a $10 million increase in other operations and maintenance expenses and a $3 million increase from the acceleration of depreciation relating to certain assets. Interest expense decreased as a result of intercompany promissory notes executed in December 2016. The increase in income taxes primarily reflects additional deferred income tax expenses associated with State of Illinois tax legislation enacted during the third quarter 2017, as well as the allocation of new tax apportionment factors in several states for the inclusion of Southern Company Gas into the consolidated Southern Company state tax filings.
Successor Year-to-Date 2017, Successor Period of July 1, 2016 through September 30, 2016, and Predecessor Period of January 1, 2016 through June 30, 2016
For the successor period of July 1, 2016 through September 30, 2016 and the predecessor period of January 1, 2016 through June 30, 2016, Merger-related expenses were $35 million and $56 million, respectively. There were no Merger-related expenses during the successor year-to-date 2017. In the successor year-to-date 2017, depreciation and amortization includes $7 million from the acceleration of depreciation relating to certain assets. Interest expense, net of amounts capitalized was $8 million, $6 million, and $34 million, respectively, in the successor year-to-date 2017, the successor period of July 1, 2016 through September 30, 2016, and the predecessor period of January 1, 2016 through June 30, 2016. Income taxes were $18 million in the successor year-to-date 2017 and income tax benefit was $11 million and $35 million, respectively, in the successor period of July 1, 2016 through September 30, 2016 and the predecessor period of January 1, 2016 through June 30, 2016. In the successor year-to-date 2017, income taxes reflect $23 million of additional deferred income tax expense associated with State of Illinois tax legislation enacted during the third quarter 2017 and the allocation of new tax apportionment factors in several states for the inclusion of Southern Company Gas into the consolidated Southern Company state tax filings.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Segment Reconciliations
Reconciliations of consolidated net income attributable to Southern Company Gas to EBIT for the successor third quarter and year-to-date 2017, and operating income to adjusted operating margin for all periods presented, are in the following tables. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for information regarding agreements by certain affiliates of Southern Company Gas to sell two natural gas storage facilities.
In the third quarter 2022, net income increased $93 million when compared to the corresponding period in 2021. The change primarily relates to additional information.tax expense as a result of the sale of Sequent in 2021 and a decrease of $13 million in operating expenses related to lower depreciation in 2022 and transaction costs in 2021 related to the sale of Sequent.
For year-to-date 2022, net income increased $100 million when compared to the corresponding period in 2021. The change primarily relates to additional tax expense as a result of the sale of Sequent in 2021 and an increase in operating revenues of $14 million primarily related to higher demand fees and favorable hedge gains at the natural gas storage businesses, higher sales from the renewable natural gas business, and lower depreciation in 2022.
|
| | | | | | | | | | | | | | | | | | | | | |
| Successor |
| Third Quarter 2017 |
| Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services | Gas Midstream Operations | All Other | Intercompany Elimination | Consolidated |
| (in millions) |
Consolidated Net Income
(Loss) | $ | 52 |
| $ | 1 |
| $ | (23 | ) | $ | 14 |
| $ | (29 | ) | $ | — |
| $ | 15 |
|
| Income taxes (benefit) | 34 |
| 1 |
| (15 | ) | 9 |
| 23 |
| — |
| 52 |
|
Interest expense, net of
amounts capitalized | 39 |
| 1 |
| 2 |
| 9 |
| — |
| — |
| 51 |
|
| EBIT | $ | 125 |
| $ | 3 |
| $ | (36 | ) | $ | 32 |
| $ | (6 | ) | $ | — |
| $ | 118 |
|
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | Successor |
| | | Third Quarter 2016 |
| | | Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services | Gas Midstream Operations | All Other | Intercompany Elimination | Consolidated |
| | | (in millions) |
Consolidated Net Income
(Loss) | | $ | 27 |
| $ | (4 | ) | $ | (11 | ) | $ | 14 |
| $ | (22 | ) | $ | — |
| $ | 4 |
|
| Income taxes (benefit) | | 16 |
| (2 | ) | (7 | ) | 11 |
| (11 | ) | — |
| 7 |
|
Interest expense, net of
amounts capitalized | | 32 |
| — |
| 1 |
| — |
| 6 |
| — |
| 39 |
|
| EBIT | | $ | 75 |
| $ | (6 | ) | $ | (17 | ) | $ | 25 |
| $ | (27 | ) | $ | — |
| $ | 50 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| | Successor |
| | Year-to-Date 2017 |
| | Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services | Gas Midstream Operations | All Other | Intercompany Elimination | Consolidated |
| | (in millions) |
Consolidated Net Income
(Loss) | $ | 223 |
| $ | 36 |
| $ | 28 |
| $ | 38 |
| $ | (22 | ) | $ | — |
| $ | 303 |
|
| Income taxes | 144 |
| 24 |
| 20 |
| 27 |
| 18 |
| — |
| 233 |
|
Interest expense, net of
amounts capitalized | 119 |
| 4 |
| 5 |
| 25 |
| (8 | ) | — |
| 145 |
|
| EBIT | $ | 486 |
| $ | 64 |
| $ | 53 |
| $ | 90 |
| $ | (12 | ) | $ | — |
| $ | 681 |
|
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
| | | | | | | | | | | | | | | | | | | | | |
| Successor |
| Third Quarter 2017 |
| Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services | Gas Midstream Operations | All Other | Intercompany Elimination | Consolidated |
| (in millions) |
| Operating Income (Loss) | $ | 108 |
| $ | 3 |
| $ | (36 | ) | $ | (1 | ) | $ | (6 | ) | $ | — |
| $ | 68 |
|
Other operating expenses(a) | 279 |
| 48 |
| 11 |
| 13 |
| 8 |
| (3 | ) | 356 |
|
Revenue tax expense(b) | (8 | ) | — |
| — |
| — |
| — |
| — |
| (8 | ) |
Adjusted Operating
Margin | $ | 379 |
| $ | 51 |
| $ | (25 | ) | $ | 12 |
| $ | 2 |
| $ | (3 | ) | $ | 416 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| | Successor |
| | Third Quarter 2016 |
| | Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services | Gas Midstream Operations | All Other | Intercompany Elimination | Consolidated |
| | (in millions) |
| Operating Income (Loss) | $ | 69 |
| $ | (6 | ) | $ | (18 | ) | $ | (4 | ) | $ | (29 | ) | $ | — |
| $ | 12 |
|
Other operating expenses(a) | 292 |
| 51 |
| 10 |
| 13 |
| 31 |
| (1 | ) | 396 |
|
Revenue tax expense(b) | (8 | ) | — |
| — |
| — |
| — |
| — |
| (8 | ) |
Adjusted Operating
Margin | $ | 353 |
| $ | 45 |
| $ | (8 | ) | $ | 9 |
| $ | 2 |
| $ | (1 | ) | $ | 400 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| | Successor |
| | Year-to-Date 2017 |
| | Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services | Gas Midstream Operations | All Other | Intercompany Elimination | Consolidated |
| | (in millions) |
| Operating Income (Loss) | $ | 463 |
| $ | 64 |
| $ | 53 |
| $ | (10 | ) | $ | (15 | ) | $ | — |
| $ | 555 |
|
Other operating expenses(a) | 940 |
| 149 |
| 40 |
| 38 |
| 22 |
| (8 | ) | 1,181 |
|
Revenue tax expense(b) | (74 | ) | — |
| — |
| — |
| — |
| — |
| (74 | ) |
Adjusted Operating
Margin | $ | 1,329 |
| $ | 213 |
| $ | 93 |
| $ | 28 |
| $ | 7 |
| $ | (8 | ) | $ | 1,662 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| | Predecessor |
| | January 1, 2016 through June 30, 2016 |
| | Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services | Gas Midstream Operations | All Other | Intercompany Elimination | Consolidated |
| | (in millions) |
| Operating Income (Loss) | $ | 351 |
| $ | 109 |
| $ | (69 | ) | $ | (9 | ) | $ | (61 | ) | $ | — |
| $ | 321 |
|
Other operating expenses(a) | 616 |
| 81 |
| 33 |
| 24 |
| 65 |
| (4 | ) | 815 |
|
Revenue tax expense(b) | (56 | ) | — |
| — |
| — |
| — |
| — |
| (56 | ) |
| Adjusted Operating Margin | $ | 911 |
| $ | 190 |
| $ | (36 | ) | $ | 15 |
| $ | 4 |
| $ | (4 | ) | $ | 1,080 |
|
| |
(a) | Includes other operations and maintenance, depreciation and amortization, taxes other than income taxes, and Merger-related expenses. |
| |
(b) | Nicor Gas' revenue tax expenses, which are passed through directly to customers. |
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FUTURE EARNINGS POTENTIAL
TheEach Registrant's results of operations discussed above are not necessarily indicative of Southern Company Gas'its future earnings potential. The level of Southern Company Gas'the Registrants' future earnings depends on numerous factors that affect the opportunities, challenges, and risks of itsthe Registrants' primary businessbusinesses of selling electricity and/or distributing natural gas, distribution and complementary businesses inas described further herein.
For the gas marketing services, wholesale gas services, and gas midstream operations sectors. Thesetraditional electric operating companies, these factors include Southern Company Gas'the ability to maintain a constructive regulatory environmentenvironments that allowsallow for the timely recovery of prudently-incurred costs during a time of increasing costs, including those related to projected long-term demand growth, stringent environmental standards, including CCR rules, safety, system reliability and resiliency, fuel, restoration following major storms, and capital expenditures, including constructing new electric generating plants and expanding and improving the transmission and distribution systems; continued customer growth; and the trends of higher inflation and reduced electricity usage per customer, especially in residential and commercial markets. For Georgia Power, completing construction of Plant Vogtle Units 3 and 4 and the related cost recovery proceedings is another major factor.
Earnings in the electricity business will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions, which could contribute to a net reduction in customer usage.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Global and U.S. economic conditions have been significantly affected by a series of demand and supply shocks that caused a global and national economic recession in 2020. The drivers, speed, and depth of the 2020 economic contraction were unprecedented and continue to reduce energy demand across the Southern Company system's service territory, primarily in the commercial class. Retail electric revenues attributable to changes in sales increased in the first nine months of 2022 when compared to the corresponding period in 2021 primarily due to the normalization of economic activity; however, total retail electric sales for the Southern Company system continued to be negatively impacted by the COVID-19 pandemic when compared to pre-pandemic trends. Most prominently, the COVID-19 pandemic has negatively impacted global supply chains and business operations as suppliers continue to experience difficulties keeping up with strong demand for factory goods, which is being driven by low business inventories. In addition, rising inflation in 2021 and 2022 has resulted in increasing costs for many goods and services. As a result of persistently high inflation, interest rates have been on the rise and are expected to continue rising in the near term, which has impacted, and may continue to impact, the Registrants' borrowing costs. Based on these factors, the probability of the U.S. economy falling into a recession has heightened. The impacts of new COVID-19 variants, responses to the COVID-19 pandemic by both customers and governments, ongoing geopolitical threats, such as the escalation of the Russia-Ukraine war, and the potential of future COVID-19-related lockdowns in Asia or elsewhere could further disrupt global supply chains and increase the severity of a possible economic downturn in the Southern Company system's service territory. See RESULTS OF OPERATIONS herein for information on COVID-19-related impacts on energy demand in the Southern Company system's service territory during the first nine months of 2022.
The level of future earnings for Southern Power's competitive wholesale electric business depends on numerous factors including the parameters of the wholesale market and the efficient operation of its wholesale generating assets; Southern Power's ability to execute its growth strategy through the development or acquisition of renewable facilities and other energy projects while containing costs; regulatory matters; customer creditworthiness; total electric generating capacity available in Southern Power's market areas; Southern Power's ability to successfully remarket capacity as current contracts expire; renewable portfolio standards; availability of federal and state ITCs and PTCs, which could be impacted by future tax legislation; transmission constraints; cost of generation from units within the Southern Company power pool; and operational limitations. See "Income Tax Matters" herein for additional information on recent tax legislation expanding the availability of federal ITCs and PTCs.
The level of future earnings for Southern Company Gas' primary business of distributing natural gas and its complementary businesses in the gas pipeline investments and gas marketing services sectors depends on numerous factors. These factors include the natural gas distribution utilities' ability to maintain constructive regulatory environments that allow for the timely recovery of prudently-incurred costs, including those related to projected long-term demand growth, safety, system reliability and resiliency, natural gas, and capital expenditures, including expanding and improving the natural gas distribution systems; the completion and subsequent operation of ongoing infrastructure and other construction projects, creditworthiness of customers, Southern Company Gas' abilityprojects; customer creditworthiness; and certain policies to optimize its transportation and storage positions, and its ability to re-contract storage rates at favorable prices. Future earnings in the near term will depend, in part, upon maintaining and growing sales and customers which are subject to a number of factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers,limit the use of alternative energy sources by customers,natural gas, such as the pricepotential across certain parts of the U.S. for state or municipal bans on the use of natural gas, the price elasticity of demand, and the rate of economic growth or decline in Southern Company Gas' service territories. Demand for natural gas is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings.
Current proposals related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction.gas. The ultimate impact of any tax reform proposals is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Southern Company Gas' financial statements.
On July 6, 2017, the State of Illinois enacted tax legislation that repealed its non-combination tax rule and increased the effective corporate income tax rate from 5.25% to 7.0% (making the total corporate tax rate 9.5% when combined with the 2.5% personal property replacement tax) effective July 1, 2017. In addition to increasing taxes on future earnings, this legislation required Southern Company Gas to increase accumulated deferred income tax liabilities by $24 million during the third quarter 2017 to reflect these changes, $15 million of which was expensed and $9 million was recorded as a regulatory asset. In addition, during the third quarter 2017, Southern Company calculated new apportionment factors in several states to include Southern Company Gas in its consolidated tax filings, which resulted in $8 million of additional deferred income tax expenses.
On October 15, 2017, Southern Company Gas subsidiary, Pivotal Utility Holdings, entered into agreements for the sale of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. The execution of the asset purchase agreements triggered an interim assessment of goodwill, which is currently being performed with the assistance of a third-party valuation specialist. The preliminary results of this valuation indicate that the estimated fair values of the reporting units with goodwill exceed their carrying amounts and are not at risk of impairment. See OVERVIEW – "Merger, Acquisition, and Disposition Activities" and Note (I) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information on the sales.
Volatilityvolatility of natural gas prices has a significantan impact on Southern Company Gas' customer rates, its long-term competitive position against other energy sources, and the ability of itsSouthern Company Gas' gas marketing services and wholesale gas services segmentsbusiness to capture value from locational and seasonal spreads. Additionally, changes in commodity prices, primarily driven by tight gas supplies, geopolitical events, and diminished gas production, subject a significant portion of Southern Company Gas' operations to earnings variability. Over the longer-term, volatility is expected to be low to moderatevariability and locational and/or transportation spreads are expected to decrease as new pipelines are built to reduce the existing supply constraintshave recently resulted in the shale areas of the Northeast U.S. To the extent these pipelines are delayed or not built, volatility could increase.higher natural gas prices. 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, theenvironment. 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. Alternatively, a significant drop in oil and natural gas prices could lead to a consolidation of natural gas producers or reduced levels of natural gas production.
Earnings for both the electricity and natural gas businesses are subject to a variety of other factors. These factors include weather; competition; developing new and maintaining existing energy contracts and associated load requirements with wholesale customers; energy conservation practiced by customers; the use of alternative energy sources by customers; government incentives to reduce overall energy usage; the prices of electricity and natural
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
(Continued)
gas; costs and availability of labor and materials in a time of rising costs, impacted by heightened inflation caused by unprecedented shocks to the broader economy, and supply chain disruptions; and the price elasticity of demand. Demand for electricity and natural gas in the Registrants' service territories is primarily driven by the pace of economic growth or decline that may be affected by changes in regional and global economic conditions, which may impact future earnings.
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, or the sale of interests in, certain assets or businesses, internal restructuring, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations, risks, and financial condition of Southern Company. In addition, Southern Power and Southern Company Gas regularly consider and evaluate joint development arrangements as well as acquisitions and dispositions of businesses and assets as part of their business strategies. See Note 15 to the financial statements in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements herein for additional information.
For additional information relating to these issues, see "Risk Factors" of Southern Company GasRISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL in Item 7 of the Form 10-K.
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis or through market-based contracts. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for natural gas, which could negatively affect results of operations, cash flows, and financial condition. See Note (B) under "Environmental Matters –Environmental Remediation" to the Condensed Financial Statements herein and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company Gas in Item 7 and Note 3 to the financial statements of Southern Company Gas under "Environmental Matters"Remediation" in Item 8 of the Form 10-K, as well as Note (C) to the Condensed Financial Statements under "General Litigation Matters" and "Environmental Remediation" herein, for additional information.
Natural Gas StorageEnvironmental Laws and Regulations
A wholly-owned subsidiaryAir Quality
On August 30, 2022, the EPA found that 15 states, including Alabama and Mississippi, failed to submit regional haze state implementation plans for the second 10-year planning period (2018 through 2028) by July 31, 2021. The finding of Southern Company Gas ownsfailure to submit establishes a two-year deadline for the EPA to promulgate a Federal Implementation Plan (FIP) to address these requirements for each applicable state unless, before the EPA promulgates a FIP, the state submits, and operatesthe EPA approves, a natural gas storage facility consisting of two salt dome caverns in Louisiana. Periodic integrity tests are required in accordance with rules ofstate implementation plan that meets the Louisiana Department of Natural Resources (LDNR). In August 2017, in connection with an ongoing integrity project, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. At September 30, 2017, the facility's property, plant, and equipment had a net book value of $111 million, of which the cavern itself represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including the results of ongoing third-party technical engineering reviews, testing, and compliance with an order from the LDNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining a core sample to determine the composition of the sheath surrounding the edge of the salt dome. Early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility.requirements. The ultimate outcome of this matter, including any potential impacts to Alabama Power, Mississippi Power, and Southern Power, cannot be determined at this time, but could havetime.
Global Climate Issues
On June 30, 2022, the U.S. Supreme Court issued an opinion limiting the EPA's authority to regulate greenhouse gas emissions under the Clean Air Act. The Court's review in the case focused on whether the EPA's authority under the Clean Air Act allows the EPA to regulate the electric industry in a materialmanner as broad as the Clean Power Plan (CPP), which was repealed and replaced by the Affordable Clean Energy rule (ACE Rule). The Court held that the generation shifting to lower carbon emitting sources approach in the CPP is not authorized by the Clean Air Act. However, the Court did not decide whether the EPA may adopt measures only applied at the individual electric generating source, which is the basis for the ACE Rule. The EPA has announced its intent to propose a rule for existing power plants pursuant to the Clean Air Act by March 2023. The ultimate impact on Southern Company Gas' financial statements.of the Court's decision cannot be determined at this time.
See
MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Southern Company Gas in Item 7 andOF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Regulatory Matters
See Note 42 to the financial statements of Southern Company Gas in Item 8 of the Form 10-K, for additional information regarding the Dalton Pipeline project.
On August 1, 2017, the Dalton Pipeline was placed in service as authorized by the FERC and transportation service for customers commenced.
On October 13, 2017, the Atlantic Coast Pipeline project received FERC approval.
Regulatory Matters
See Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Southern Company Gas" herein for additional information regarding Southern Company Gas' regulatory matters.
Riders
Nicor Gas has established a variable tax cost adjustment rider, which was approved by the Illinois Commission effective July 16, 2017. This rider provides for recovery of the invested capital tax imposed on Nicor Gas through an annual true-up and reconciliation mechanism based on amounts approved in prior rate cases. Accordingly, this rider will not have a significant effect on Southern Company Gas' net income.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Natural Gas Cost Recovery
Southern Company Gas has established natural gas cost recovery rates approved by the relevant state regulatory agencies in the states in which it serves. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on Southern Company Gas' revenues or net income, but will affect cash flows.
Base Rate Cases
Settled Base Rate Cases
On February 21, 2017, the Georgia PSC approved the Georgia Rate Adjustment Mechanism (GRAM) and a $20 million increase in annual base rate revenues for Atlanta Gas Light, effective March 1, 2017. GRAM adjusts base rates annually, up or down, based on the previously approved ROE of 10.75% and does not collect revenue through special riders and surcharges. Various infrastructure programs previously authorized by the Georgia PSC under Atlanta Gas Light's STRIDE program, which include the Integrated Vintage Plastic Replacement Program and Integrated System Reinforcement Program, will continue under GRAM and the recovery of and return on the infrastructure program investments will be included in annual base rate adjustments. The Georgia PSC will review Atlanta Gas Light's performance annually under GRAM.
Pursuant to the GRAM approval, Atlanta Gas Light and the staff of the Georgia PSC agreed to a variation to the Integrated Customer Growth Program that was formerly part of Atlanta Gas Light's STRIDE program. As a result, a new tariff was created, effective October 10, 2017, to provide $15 million annually for Atlanta Gas Light to commit to strategic economic development projects.
Beginning with the next rate adjustment in June 2018, Atlanta Gas Light's recovery of the previously unrecovered Pipeline Replacement Program revenue through 2014, as well as the mitigation costs associated with the Pipeline Replacement Program that were not previously included in its rates, will also be included in GRAM. In connection with the GRAM approval, the last monthly Pipeline Replacement Program surcharge increase became effective March 1, 2017.
In September 2016, Elizabethtown Gas filed a general base rate case with the New Jersey BPU requesting a $19 million increase in annual base rate revenues. The requested increase was based on a projected 12-month test year ending March 31, 2017 and a ROE of 10.25%. On June 30, 2017, the New Jersey BPU approved a settlement that provides for a $13 million increase in annual base rate revenues, effective July 1, 2017, based on a ROE of 9.6%. Also included in the settlement was a new composite depreciation rate that is expected to result in a $3 million annual reduction of depreciation. See OVERVIEW – "Merger, Acquisition,"Recent Developments" herein, and Disposition Activities" and Note (I) to the Condensed Financial Statements under "Southern Company Gas" herein for information on the proposed sale of Elizabethtown Gas.
Pending Base Rate Cases
On March 10, 2017, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $208 million increase in annual base rate revenues. The requested increase is based on a 2018 projected test year and a ROE of 10.7%. The Illinois Commission is expected to rule on the requested increase in December 2017, after which rate adjustments will be effective.
On March 31, 2017, Virginia Natural Gas filed a general base rate case with the Virginia Commission requesting a $44 million increase in annual base rate revenues. The requested increase was based on a projected 12-month test year beginning September 1, 2017 and a ROE of 10.25%. The requested increase included $13 million related to the recovery of investments under the Steps to Advance Virginia's Energy (SAVE) program. On October 3, 2017, Virginia Natural Gas entered into a proposed stipulation with the Staff of the Virginia Commission, the Office of the Attorney General, Division of Consumer Counsel, and the Virginia Industrial Gas Users' Association resolving all related issues. The proposed stipulation includes a $34 million increase in annual base rate revenues, including $13 million related to the recovery of investments under the SAVE program. An authorized ROE range of 9.0% to 10.0% with a midpoint of 9.5% will be used to determine the revenue requirement in any filing, other than for a
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
change in base rates. The Virginia Commission is expected to rule on the proposed stipulation in the fourth quarter 2017. Rate adjustments based on the proposed stipulation became effective September 1, 2017, subject to refund.
On October 23, 2017, Florida City Gas filed a general base rate case with the Florida PSC requesting a $19 million increase in annual base rate revenues. The requested increase is based on a 2018 projected test year and a ROE of 11.25%. The requested increase includes $3 million related to the recovery of investments under the Safety, Access, and Facility Enhancement (SAFE) program. Additionally, Florida City Gas requested interim rates of $5 million to be effective in January 2018, subject to refund. The Florida PSC is expected to rule on the requested increase in mid-2018.
The ultimate outcome of these pending base rate cases cannot be determined at this time.
Regulatory Infrastructure Programs
Southern Company Gas is engaged in various infrastructure programs that update or expand its gas distribution systems to improve reliability and ensure the safety of its utility infrastructure, and recovers in rates its investment and a return associated with these infrastructure programs.
Nicor Gas
In 2014, the Illinois Commission approved Nicor Gas' nine-year regulatory infrastructure program, Investing in Illinois. Under this program, Nicor Gas placed into service $178 million of qualifying assets during the first nine months of 2017.
Atlanta Gas Light
Atlanta Gas Light's STRIDE program, which started in 2009, consists of three individual programs that update and expand gas distribution systems and LNG facilities as well as improve system reliability to meet operational flexibility and customer growth. Through the programs under STRIDE, Atlanta Gas Light invested $127 million during the first nine months of 2017. The recovery of and return on current and future capital investments under the STRIDE program are included in the annual base rate revenue adjustment under GRAM.
In August 2016, Atlanta Gas Light filed a petition with the Georgia PSC for approval of a four-year extension of its Integrated System Reinforcement Program (i-SRP) seeking approval to invest an additional $177 million to improve and upgrade its core gas distribution system in years 2017 through 2020. Subsequently, the proposed capital investments associated with the extension of i-SRP were included in the 2017 annual base rate revenue under GRAM approved by the Georgia PSC on February 21, 2017.
See "Base Rate Cases" herein for additional information.
Elizabethtown Gas
In 2013, the New Jersey BPU approved the extension of Elizabethtown Gas' Aging Infrastructure Replacement program, under which Elizabethtown Gas invested $16 million during the first nine months of 2017. Effective July 1, 2017, investments under this program are being recovered through base rate revenues.
Virginia Natural Gas
In March 2016, the Virginia Commission approved an extension to the SAVE program, under which Virginia Natural Gas invested $21 million during the first nine months of 2017.
Florida City Gas
The Florida PSC approved Florida City Gas' SAFE program in 2015. Under the program, Florida City Gas invested $9 million during the first nine months of 2017.
Other Matters
Southern Company Gas is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company Gas is subject to certain claims and legal actions arising in the
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ordinary course of business. The ultimate outcome of such pending or potential litigation or regulatory matters 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 related to Alabama Power, Georgia Power, Mississippi Power, and other matters being litigated which may affect future earnings potential.
Nicor Gas and Nicor Energy Services Company, wholly-owned subsidiaries of Southern Company Gas, including items that could impact the applicable Registrants' future earnings, cash flows, and/or financial condition.
Alabama Power
On September 23, 2022, the FERC authorized Alabama Power to use updated depreciation rates from its 2021 depreciation study effective January 1, 2023. The study was also provided to the Alabama PSC, and Nicor Inc. were defendantsthe new depreciation rates will be reflected in a putative class action initially filedAlabama Power's future rate filings. The updated depreciation rates are expected to result in 2011an approximately $500 million increase in the state court in Cook County, Illinois. The plaintiffs purported to represent a class of the customers who purchased the Gas Line Comfort Guard product from Nicor Energy Services Companyannual depreciation expense. See Notes 2 and variously alleged that the marketing, sale, and billing of the Gas Line Comfort Guard product violated the Illinois Consumer Fraud and Deceptive Business Practices Act, constituting common law fraud and resulting in unjust enrichment of these entities. The plaintiffs sought, on behalf of the classes they purported to represent, actual and punitive damages, interest, costs, attorney fees, and injunctive relief. On February 8, 2017, the judge denied the plaintiffs' motion for class certification and Southern Company Gas' motion for summary judgment. On March 7, 2017, the parties reached a settlement, which was finalized and effective on April 3, 2017. The settlement did not have a material impact on Southern Company Gas' financial statements.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company Gas prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 15 to the financial statements of Southern Company Gasunder "Alabama Power" and "Depreciation and Amortization," respectively, in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Company Gas' results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Company Gas in Item 7 of the Form 10-K for a complete discussion of Southern Company Gas' critical accounting policies and estimates related to Utility Regulation, Pushdown of Acquisition Accounting, Assessment of Assets, Derivatives and Hedging Activities, Pension and Other Postretirement Benefits, and Contingent Obligations.
Recently Issued Accounting Standards
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Southern Company Gas in Item 7 of the Form 10-K for additional information.
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the
Construction Programs
The Subsidiary Registrants are engaged in continuous construction programs to accommodate existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers.estimated future loads on their respective systems. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
While Southern Company Gas expects most of its revenuesystem strategy continues to include developing and constructing new electric generating facilities, expanding and improving the electric transmission and electric and natural gas distribution systems, and undertaking projects to comply with environmental laws and regulations.
For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements.retail rates. The majority oflargest construction project currently underway in the Southern Company Gas' revenue, including energy provided to customers,system is from tariff offerings that provide natural gas without a defined contractual term, as well as longer-term contractual agreements, including non-derivative natural gas asset managementPlant Vogtle Units 3 and optimization arrangements. Southern Company Gas expects that the revenue from contracts with these customers will not result in a significant shift in the timing of revenue recognition for such sales.
Southern Company Gas' ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements, such as energy-related derivatives and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Southern Company Gas' financial statements. In addition, the power
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Southern Company Gas expects CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Southern Company Gas intends to use the modified retrospective method of adoption effective January 1, 2018. Southern Company Gas has also elected to utilize practical expedients which allow it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Southern Company Gas' financial statements, Southern Company Gas will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.
On January 26, 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for annual and interim periods beginning on or after December 15, 2019, and early adoption is permitted on testing dates after January 1, 2017. Southern Company Gas is evaluating the standard and expects to early adopt ASU 2017-04 effective January 1, 2018.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company Gas' operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Southern Company Gas' financial statements.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with early adoption permitted. Southern Company Gas is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on Southern Company Gas' financial statements.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FINANCIAL CONDITION AND LIQUIDITY
Overview
4. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company Gas in Item 7 of the Form 10-K for additional information. As a result of the Merger that closed on July 1, 2016, the results reported herein include disclosure of the successor third quarter and year-to-date 2017, the successor period of July 1, 2016 through September 30, 2016, and the predecessor period of January 1, 2016 through June 30, 2016. See OVERVIEW – "Merger, Acquisition, and Disposition Activities" and Note (I)(B) to the Condensed Financial Statements under "Southern Company"Georgia Power – Merger with Southern Company Gas"Nuclear Construction" herein for additional information.
Southern Company Gas' financial condition remained stable at September 30, 2017. Southern Company Gas intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
By regulation, Nicor Gas is restricted, Also see Note 2 to the extentfinancial statements under "Alabama Power – Certificates of its retained earnings balance, in the amount it can dividend or loan to affiliatesConvenience and is not permitted to make money pool loans to affiliates. Due to the increased working capital requirements associated with Nicor Gas' Investing in Illinois infrastructure replacement program, since 2015, Nicor Gas has temporarily ceased distributing dividends to Southern Company Gas. Elizabethtown Gas is restricted by its dividend policy as established by the New Jersey BPU in the amount it can dividend to its parent company to the extent of 70% of its quarterly net income. Additionally, as stipulated in the New Jersey BPU's order approving the Merger, Southern Company Gas is prohibited from paying dividends to its parent company, Southern Company, if Southern Company Gas' senior unsecured debt rating falls below investment grade. As of September 30, 2017, the amount of subsidiary retained earnings and net income available to dividend totaled $752 million. These restrictions did not have any impact on Southern Company Gas' ability to meet its cash obligations, nor does management expect such restrictions to materially impact Southern Company Gas' ability to meet its currently anticipated cash obligations.
Net cash provided from (used for) operating activities totaled $1.1 billion for the successor first nine months of 2017, $(342) million for the successor period of July 1, 2016 through September 30, 2016, and $1.1 billion for the predecessor period of January 1, 2016 through June 30, 2016. These cash flows were primarily driven by the sale of natural gas inventory during the respective periods.
Net cash used for investing activities totaled $1.2 billion for the successor first nine months of 2017, primarily due to gross property additions related to capital expenditures for infrastructure replacement programs at gas distribution operations and capital contributed to equity method investments in pipelines. Net cash used for investing activities totaled $1.7 billion for the successor period of July 1, 2016 through September 30, 2016 and $559 million for the predecessor period of January 1, 2016 through June 30, 2016 primarily due to gross property additions related to capital expenditures for infrastructure replacement programs at gas distribution operations and the acquisition of Southern Company Gas' ownership interest in SNG in September 2016.
Net cash provided from financing activities totaled $45 million for the successor first nine months of 2017, primarily due to proceeds from debt issuances and capital contributions from Southern Company, partially offset by net repayments of commercial paper borrowings and common stock dividend payments to Southern Company. Net cash provided from (used for) financing activities totaled $2.1 billion for the successor period of July 1, 2016 through September 30, 2016 and $(558) million for the predecessor period of January 1, 2016 through June 30, 2016 primarily due to net repayments of commercial paper borrowings, the redemption of long-term debt, and common stock dividend payments to shareholders, partially offset by proceeds from debt issuances. The successor period of July 1, 2016 through September 30, 2016 also includes capital contributions from Southern Company to fund the investment in SNG. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Significant balance sheet changes at September 30, 2017 include an increase of $847 million in total property, plant, and equipment primarily due to capital expenditures for infrastructure replacement programs, an increase in long-term debt of $603 million primarily due to $450 million of senior notes and $200 million of first mortgage bonds at Nicor Gas issued in May 2017 and August 2017, respectively, and a decrease of $323 million in notes payable related primarily to net repayments of commercial paper borrowings at Nicor Gas. Other significant balance sheet changes include an increase of $239 million in accumulated deferred income taxes, primarily as a result of tax depreciation related to infrastructure assets placed in service as well as the impact of State of Illinois tax legislation, and decreases of $196 million and $146 million in energy marketing receivables and payables, respectively, due to lower natural gas prices.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company GasNecessity" in Item 78 of the Form 10-K for a descriptioninformation regarding Alabama Power's construction of Southern Company Gas' capital requirements for its infrastructure programs, scheduled maturities of long-term debt and the related interest, as well as pipeline charges, storage capacity, and gas supply, operating leases, asset management agreements, standby letters of credit and performance/surety bonds, financial derivative obligations, pension and other postretirement benefit plans, and other purchase commitments, primarily related to environmental remediation liabilities. There are no scheduled maturities of long-term debt through September 30, 2018. See "Sources of Capital" herein for additional information.Plant Barry Unit 8.
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 315 to the consolidated financial statements in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements herein under "Southern Power" for information about costs relating to Southern Power's construction of renewable energy facilities.
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, reduce emissions, 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 Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Southern Company Gas" for additional information regarding additional factors that may impact infrastructure investment expenditures.
Sources of Capital
on Southern Company Gas plans to obtain the funds to meet its future capital needs through operating cash flows, short-term debt borrowings under its commercial paper programs, external securities issuances, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, depend upon regulatory approval, prevailing market conditions, and other factors. Gas' construction program.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Company Gas in Item 7 of the Form 10-K for additional information.
At September 30, 2017, Southern Company Gas' current liabilities exceeded current assets by $645 million primarily as a result of $934 million in notes payable. Southern Company Gas' current liabilities frequently exceed current assets because of commercial paper borrowings used to fund daily operations, scheduled maturities of long-term debt, and significant seasonal fluctuations in cash needs. Southern Company Gas intends to utilize operating cash flows, commercial paper, and debt securities issuances, as market conditions permit, as well as equity contributions from Southern Company to fund its short-term capital needs. Southern Company Gas has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet liquidity needs.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
At September 30, 2017, Southern Company Gas had approximately $21 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2017 were as follows:
|
| | | | | | | | |
| Company | | Expires 2022 | | Unused |
| | | (millions) |
| Southern Company Gas Capital | | $ | 1,200 |
| | $ | 1,161 |
|
| Nicor Gas | | 700 |
| | 700 |
|
| Total | | $ | 1,900 |
| | $ | 1,861 |
|
Additionally, Pivotal Utility Holdings is party to a series of loan agreements with the New Jersey Economic Development Authority and Brevard County, Florida under which five series of gas facility revenue bonds totaling $200 million have been issued.
See Note 6 to the consolidated financial statements of Southern Company Gas under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements""Cash Requirements" herein for additional information.
In May 2017, Southern Company Gas Capital and Nicor Gas terminated their existing credit arrangements for $1.3 billion and $700 million, respectively, which were to mature in 2017 and 2018, and entered into a new multi-year credit arrangement (Facility) currently allocated for $1.2 billion and $700 million, respectively, with a maturity date of 2022, as reflected in the table above. Pursuant to the Facility, the allocations may be adjusted.
The Facility contains a covenant that limits the ratio of debt to capitalization (as defined in each facility) to a maximum of 70% for each of Southern Company Gas and Nicor Gas and contains a cross-acceleration provision to other indebtedness (including guarantee obligations) of the applicable company. Such cross-acceleration provision to other indebtedness would trigger an event of default of the applicable company if Southern Company Gas or Nicor Gas defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2017, both companies were in compliance with such covenant. The Facility does not contain a material adverse change clause at the time of borrowings.
Subject to applicable market conditions, the applicable company expects to renew or replace the Facility as needed, prior to expiration. In connection therewith, the applicable company may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
Southern Company Gas makes short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Commercial paper borrowings are included in notes payable in the balance sheets.
Details of commercial paper borrowings were as follows:
|
| | | | | | | | | | | | | | | | | |
| | Commercial Paper at September 30, 2017 | | Commercial Paper During the Period(*) |
| | Amount
Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| Commercial paper: | (in millions) | | | | (in millions) | | | | (in millions) |
| Southern Company Gas Capital | $ | 836 |
| | 1.5 | % | | $ | 680 |
| | 1.5 | % | | $ | 838 |
|
| Nicor Gas | 98 |
| | 1.3 |
| | 40 |
| | 1.3 |
| | 120 |
|
| Total | $ | 934 |
| | 1.5 | % | | $ | 720 |
| | 1.5 | % | | |
| |
(*) | Average and maximum amounts are based upon daily balances during the successor three-month period ended September 30, 2017. |
Southern Company Gas believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and operating cash flows.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Credit Rating Risk
Southern Company Gas does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change below BBB- and/or Baa3. These contracts are for physical gas purchases and sales and energy price risk management. The maximum potential collateral requirements under these contracts at September 30, 2017 were $12 million.
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Company Gas to access capital markets, and would be likely to impact the cost at which it does so.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including Southern Company Gas, Southern Company Gas Capital, and Nicor Gas) from stable to negative.
Financing Activities
The long-term debt on Southern Company Gas' consolidated balance sheets includes both principal and non-principal components. As of September 30, 2017, the non-principal components totaled $523 million, which consisted of the unamortized portions of the fair value adjustment recorded in purchase accounting, debt premiums, debt discounts, and debt issuance costs.
In December 2016, Southern Company Gas executed intercompany promissory notes to further allocate interest expense to its reportable segments that previously remained in the "all other" segment. These intercompany promissory notes allow Southern Company Gas to calculate net income, which is its performance measure subsequent to the Merger, at the segment level that incorporates the full impact of interest costs.
In May 2017, Southern Company Gas Capital issued $450 million aggregate principal amount of Series 2017A 4.40% Senior Notes due May 30, 2047. The proceeds were used to repay Southern Company Gas' short-term indebtedness and for general corporate purposes.
In July 2017, Atlanta Gas Light Company repaid at maturity $22 million of Series C medium-term notes.
In July 2017, Nicor Gas agreed to issue $400 million aggregate principal amount of first mortgage bonds in a private placement. On August 10, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.03% Series due August 10, 2027 and $100 million aggregate principal amount of First Mortgage Bonds 3.62% Series due August 10, 2037. The proceeds were used to repay short-term indebtedness incurred under the Nicor Gas commercial paper program and for other working capital needs. The remaining $200 million is expected to be issued in November 2017.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company Gas plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
Market Price Risk
Other than the items discussed below, there were no material changes to Southern Company Gas' disclosures about market price risk during the successor third quarter and year-to-date 2017. For an in-depth discussion of Southern Company Gas' market price risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company Gas in Item 7 of the Form 10-K. Also see Notes (C) and (H) to the Condensed Financial Statements herein for information relating to derivative instruments.
Southern Company Gas is exposed to market risks, primarily commodity price risk, interest rate risk, and weather risk. Due to various cost recovery mechanisms, the natural gas distribution utilities of Southern Company Gas that sell natural gas directly to end-use customers have limited exposure to market volatility of natural gas prices.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Certain natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs implemented per the guidelines of their respective state regulatory agencies to hedge the impact of market fluctuations in natural gas prices for customers. For the weather risk associated with Nicor Gas, Southern Company Gas has a corporate weather hedging program that utilizes weather derivatives to reduce the risk of lower operating margins potentially resulting from significantly warmer-than-normal weather. In addition, certain non-regulated operations routinely utilize various types of derivative instruments to economically hedge certain commodity price and weather risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and over-the-counter energy contracts, such as forward contracts, futures contracts, options contracts, and swap agreements. Some of these economic hedge activities may not qualify, or are not designated, for hedge accounting treatment. The following table illustrates the change in the net fair value of Southern Company Gas' derivative instruments during all periods presented, and provides details of the net fair value of contracts outstanding as of the dates presented.
|
| | | | | | | | | | | | | | | | | | | | | |
| | | Successor | | | Predecessor |
| | | Third Quarter | | Third Quarter | | Year-to-Date | | July 1, 2016 through September 30, 2016 | | | January 1, 2016
through
June 30,
2016 |
| | | 2017 | | 2016 | | 2017 | | | |
| | | (in millions) | | | (in millions) |
Contracts outstanding at beginning of period,
assets (liabilities), net | | $ | 51 |
| | $ | (54 | ) | | $ | 12 |
| | $ | (54 | ) | | | $ | 75 |
|
| Contracts realized or otherwise settled | | (6 | ) | | (3 | ) | | (22 | ) | | (3 | ) | | | (77 | ) |
Current period changes(a) | | (16 | ) | | — |
| | 39 |
| | — |
| | | (82 | ) |
Contracts outstanding at the end of period,
assets (liabilities), net | | 29 |
| | (57 | ) | | 29 |
| | (57 | ) | | | (84 | ) |
| Netting of cash collateral | | 76 |
| | 111 |
| | 76 |
| | 111 |
| | | 120 |
|
Cash collateral and net fair value of contracts
outstanding at end of period(b) | | $ | 105 |
| | $ | 54 |
| | $ | 105 |
| | $ | 54 |
| | | $ | 36 |
|
| |
(a) | Current period changes also include the fair value of new contracts entered into during the period, if any. |
| |
(b) | Net fair value of derivative instruments outstanding includes premiums and the intrinsic values associated with weather derivatives of $13 million at September 30, 2017 and $7 million at September 30, 2016. |
The maturities of Southern Company Gas' energy-related derivative contracts at September 30, 2017 were as follows:
|
| | | | | | | | | | | | | | | |
| | | | Fair Value Measurements |
| | | | Successor – September 30, 2017 |
| | Total
Fair Value | | Maturity |
| | | Year 1 | | Years 2 & 3 | | Years 4 and thereafter |
| | (in millions) |
Level 1(a) | $ | (35 | ) | | $ | (10 | ) | | $ | (20 | ) | | $ | (5 | ) |
Level 2(b) | 64 |
| | 12 |
| | 45 |
| | 7 |
|
Fair value of contracts outstanding at end of period(c) | $ | 29 |
| | $ | 2 |
| | $ | 25 |
| | $ | 2 |
|
| |
(a) | Valued using NYMEX futures prices. |
| |
(b) | Valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers. |
| |
(c) | Excludes cash collateral of $76 million at September 30, 2017. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS
FOR
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA POWER COMPANY
GULF POWER COMPANY
MISSISSIPPI POWER COMPANY
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
(UNAUDITED)
INDEX TO THE NOTES TO THE CONDENSED FINANCIAL STATEMENTS
|
| | |
Note | | Page Number |
A | | |
B | | |
C | | |
D | | |
E | | |
F | | |
G | | |
H | | |
I | | |
J | | |
K | | |
INDEX TO APPLICABLE NOTES TO FINANCIAL STATEMENTS BY REGISTRANT
The following unaudited notes to the condensed financial statements are a combined presentation. The list below indicates the registrants to which each footnote applies.
|
| |
Registrant | Applicable Notes |
Southern Company | A, B, C, D, E, F, G, H, I, J, K |
Alabama Power | A, B, C, E, F, G, H |
Georgia Power | A, B, C, E, F, G, H |
Gulf Power | A, B, C, E, F, G, H |
Mississippi Power | A, B, C, E, F, G, H |
Southern Power | A, B, C, D, E, G, H, I |
Southern Company Gas | A, B, C, E, F, G, H, I, J, K |
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA POWER COMPANY
GULF POWER COMPANY
MISSISSIPPI POWER COMPANY
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
NOTES TO THE CONDENSED FINANCIAL STATEMENTS:
(UNAUDITED)
The condensed quarterly financial statements of each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 2016 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended September 30, 2017 and 2016. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each registrant believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q unless specifically required by GAAP. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.
Southern Company's financial statements reflect its investments in its subsidiaries, including Southern Company Gas as a result of the Merger, on a consolidated basis. Southern Company Gas' results of operations and cash flows for the three and nine months ended September 30, 2017 and the three months ended September 30, 2016, as well as its financial condition as of September 30, 2017 and December 31, 2016, are reflected within Southern Company's consolidated amounts in these accompanying notes herein. The equity method is used for entities in which Southern Company has significant influence but does not control, including Southern Company Gas' investment in SNG, and for variable interest entities where Southern Company has an equity investment but is not the primary beneficiary. See Note (I) under "Southern Company– Merger with Southern Company Gas" for additional information regarding the Merger.
Pursuant to the Merger, Southern Company pushed down the application of the acquisition method of accounting to the consolidated financial statements of Southern Company Gas such that the assets and liabilities are recorded at their respective fair values, and goodwill has been established for the excess of the purchase price over the fair value of net identifiable assets. Accordingly, the consolidated financial statements of Southern Company Gas for periods before and after July 1, 2016 (acquisition date) reflect different bases of accounting, and the financial positions and results of operations of those periods are not comparable. Throughout Southern Company Gas' condensed consolidated financial statements and the accompanying notes herein, periods prior to July 1, 2016 are identified as "predecessor," while periods after the acquisition date are identified as "successor."
Certain prior year data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on the results of operations, financial position, or cash flows of any registrant.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Recently Issued Accounting Standards
See Note 1 to the financial statements of the registrants under "Recently Issued Accounting Standards" in Item 8 of the Form 10-K for additional information.
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
While the registrants expect most of their revenue to be included in the scope of ASC 606, they have not fully completed the evaluation of all revenue arrangements. The majority of Southern Company's, the traditional electric operating companies', and Southern Company Gas' revenue, including energy provided to customers, is from tariff offerings that provide electricity or natural gas without a defined contractual term, as well as longer-term contractual commitments, including PPAs and non-derivative natural gas asset management and optimization arrangements. The majority of Southern Power's revenues includes longer-term PPAs for generation capacity and energy. The registrants expect the adoption of ASC 606 will not result in a significant shift from the current timing of revenue recognition for such transactions.
The registrants' ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements, such as certain PPAs, energy-related derivatives, and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on the registrants' financial statements. In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Southern Company, the traditional electric operating companies, and Southern Company Gas expect CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. The registrants intend to use the modified retrospective method of adoption effective January 1, 2018. The registrants have also elected to utilize practical expedients which allow them to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in the registrants' financial statements, the registrants will continue to evaluate theRegistrants' capital requirements as well as any additional clarifying guidance that may be issued.
On January 26, 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for annual and interim periods beginning on or after December 15, 2019, and early adoption is permitted on testing dates after January 1, 2017. Southern Company and Southern Company Gas are evaluating the standard and expect to early adopt ASU 2017-04 effective January 1, 2018.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company's, the traditional electric operating companies', and Southern Company Gas' operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Southern Company's, the traditional electric operating companies', or Southern Company Gas' financial statements.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with early adoption permitted. The registrants are evaluating the standard and expect to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on the registrants' financial statements.
Affiliate Transactions
Prior to the completion of Southern Company Gas' acquisition of its 50% equity interest in SNG, SCS (as agent for Alabama Power, Georgia Power, and Southern Power) and Southern Company Gas had entered into long-term interstate natural gas transportation agreements with SNG. The interstate transportation service provided to Alabama Power, Georgia Power, Southern Power, and Southern Company Gas by SNG pursuant to these agreements is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. For the nine months ended September 30, 2017, transportation costs under these agreements for Alabama Power, Georgia Power, Southern Power, and Southern Company Gas were approximately $8 million, $77 million, $19 million, and $24 million, respectively. For the period subsequent to Southern Company Gas' investment in SNG through September 30, 2016, transportation costs under these agreements for Alabama Power, Georgia Power, Southern Power, and Southern Company Gas were approximately $1 million, $8 million, $2 million, and $4 million, respectively.
SCS, as agent for Georgia Power and Southern Power, has agreements with certain subsidiaries of Southern Company Gas to purchase natural gas. For the nine months ended September 30, 2017, natural gas purchases made by Georgia Power and Southern Power from Southern Company Gas' subsidiaries were approximately $18 million and $94 million, respectively. For the period subsequent to Southern Company's acquisition of Southern Company Gas through September 30, 2016, natural gas purchases made by Georgia Power and Southern Power from Southern Company Gas' subsidiaries were approximately $7 million and $2 million, respectively.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Goodwill and Other Intangible Assets
At September 30, 2017 and December 31, 2016, goodwill was as follows:
|
| | | | | | |
| | Goodwill |
| | At September 30, 2017 | At December 31, 2016 |
| | (in millions) |
| Southern Company | $ | 6,267 |
| $ | 6,251 |
|
| Southern Power | $ | 2 |
| $ | 2 |
|
| Southern Company Gas | | |
| Gas distribution operations | $ | 4,702 |
| $ | 4,702 |
|
| Gas marketing services | 1,265 |
| 1,265 |
|
| Southern Company Gas total | $ | 5,967 |
| $ | 5,967 |
|
Goodwill is not amortized, but is subject to an annual impairment test during the fourth quarter of each year, or more frequently if impairment indicators arise.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Other intangible assets were as follows:
|
| | | | | | | | | | | | | | | | | | | |
| | At September 30, 2017 | | At December 31, 2016 |
| | Gross Carrying Amount | Accumulated Amortization | Other Intangible Assets, Net | | Gross Carrying Amount | Accumulated Amortization | Other
Intangible Assets, Net |
| | (in millions) | | (in millions) |
| Southern Company | | | | | | | |
| Other intangible assets subject to amortization: | | | | | | | |
| Customer relationships | $ | 288 |
| $ | (70 | ) | $ | 218 |
| | $ | 268 |
| $ | (32 | ) | $ | 236 |
|
| Trade names | 159 |
| (15 | ) | 144 |
| | 158 |
| (5 | ) | 153 |
|
| Storage and transportation contracts | 64 |
| (27 | ) | 37 |
| | 64 |
| (2 | ) | 62 |
|
| PPA fair value adjustments | 456 |
| (41 | ) | 415 |
| | 456 |
| (22 | ) | 434 |
|
| Other | 16 |
| (3 | ) | 13 |
| | 11 |
| (1 | ) | 10 |
|
| Total other intangible assets subject to amortization | $ | 983 |
| $ | (156 | ) | $ | 827 |
|
| $ | 957 |
| $ | (62 | ) | $ | 895 |
|
| Other intangible assets not subject to amortization: | | | | | | | |
| Federal Communications Commission licenses | $ | 75 |
| $ | — |
| $ | 75 |
| | $ | 75 |
| $ | — |
| $ | 75 |
|
| Total other intangible assets | $ | 1,058 |
| $ | (156 | ) | $ | 902 |
| | $ | 1,032 |
| $ | (62 | ) | $ | 970 |
|
| | | | | | | | |
| Southern Power | | | | | | | |
| Other intangible assets subject to amortization: | | | | | | | |
| PPA fair value adjustments | $ | 456 |
| $ | (41 | ) | $ | 415 |
| | $ | 456 |
| $ | (22 | ) | $ | 434 |
|
| | | | | | | | |
| Southern Company Gas | | | | | | | |
| Other intangible assets subject to amortization: | | | | | | | |
| Gas marketing services | | | | | | | |
| Customer relationships | $ | 221 |
| $ | (65 | ) | $ | 156 |
| | $ | 221 |
| $ | (30 | ) | $ | 191 |
|
| Trade names | 115 |
| (8 | ) | 107 |
| | 115 |
| (2 | ) | 113 |
|
| Wholesale gas services | | | | | | | |
| Storage and transportation contracts | 64 |
| (27 | ) | 37 |
| | 64 |
| (2 | ) | 62 |
|
| Total other intangible assets subject to amortization | $ | 400 |
| $ | (100 | ) | $ | 300 |
| | $ | 400 |
| $ | (34 | ) | $ | 366 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Amortization associated with other intangible assets was as follows:
|
| | | | | | |
| | Three Months Ended | Nine Months Ended |
| | September 30, 2017 |
| | (in millions) |
| Southern Company | $ | 29 |
| $ | 94 |
|
| Southern Power | $ | 6 |
| $ | 19 |
|
| Southern Company Gas | $ | 20 |
| $ | 66 |
|
See Note 12 to the financial statements of Southern Company under "Southern Power" and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information regarding Southern Power's PPA fair value adjustments related to its business acquisitions. Also see Note (I) under "Southern Company– Acquisition of PowerSecure" and " –Merger with Southern Company Gas" for additional information.
Property Damage Reserve
See Note 1 to the financial statements of Gulf Power under "Property Damage Reserve" in Item 8 of the Form 10-K for additional information.
Gulf Power's cost of repairing damages from major storms and other uninsured property damages, including uninsured damages to transmission and distribution facilities, generation facilities, and other property is charged to Gulf Power's property damage reserve. In accordance with a settlement agreement approved by the Florida PSC on April 4, 2017 (2017 Rate Case Settlement Agreement), Gulf Power suspended further property damage reserve accruals effective April 2017. Gulf Power may make discretionary accruals and is required to resume accruals of $3.5 million annually if the reserve balance falls below zero. In addition, Gulf Power may initiate a storm surcharge to recover costs associated with any tropical systems named by the National Hurricane Center or other catastrophic storm events that reduce the property damage reserve in the aggregate by approximately $31 million (75% of the April 1, 2017 balance) or more. The storm surcharge would begin, on an interim basis, 60 days following the filing of a cost recovery petition, would be limited to $4.00/month for a 1,000 KWH residential customer unless Gulf Power incurs in excess of $100 million in qualified storm recovery costs in a calendar year, and would replenish the property damage reserve to approximately $40 million. As of September 30, 2017, Gulf Power's property damage reserve totaled approximately $39 million. See Note (B) under "Regulatory Matters–Gulf Power– Retail Base Rate Cases" for additional details regarding the 2017 Rate Case Settlement Agreement.
Natural Gas for Sale
Southern Company Gas' natural gas distribution utilities, with the exception of Nicor Gas, carry natural gas inventory on a WACOG basis.
Nicor Gas' natural gas inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated. Southern Company Gas had no inventory decrement at September 30, 2017. The cost of natural gas, including inventory costs, is recovered from customers under a purchased gas recovery mechanism adjusted for differences between actual costs and amounts billed; therefore, LIFO liquidations have no impact on Southern Company's or Southern Company Gas' net income.
Natural gas inventories for Southern Company Gas' non-utility businesses are carried at the lower of weighted average cost or current market price, with cost determined on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value. Southern Company Gas had no material LOCOM adjustment in any period presented.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| |
(B) | CONTINGENCIES AND REGULATORY MATTERS |
See Note 3 to the financial statements of the registrants in Item 8 of the Form 10-K for information relating to various lawsuits, other contingencies, and regulatory matters.
General Litigation Matters
Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation against each registrant and any subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such registrant's financial statements.
Southern Company
On January 20, 2017, a purported securities class action complaint was filed against Southern Company, certain of its officers, and certain former Mississippi Power officers in the U.S. District Court for the Northern District of Georgia, Atlanta Division, by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint alleges that Southern Company, certain of its officers, and certain former Mississippi Power officers made materially false and misleading statements regarding the Kemper IGCC in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. On June 12, 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. On July 27, 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition on September 11, 2017.
On February 27, 2017, Jean Vineyard filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the defendants caused Southern Company to make false or misleading statements regarding the Kemper IGCC cost and schedule. Further, the complaint alleges that the defendants were unjustly enriched and caused the waste of corporate assets. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on her own behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. On March 27, 2017, the court deferred this lawsuit until 30 days after certain further action in the purported securities class action complaint discussed above.
On May 15, 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia and, on May 31, 2017, Judy Mesirov filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. Each complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper IGCC. Each complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper IGCC schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. On August 15, 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia and the court deferred the consolidated case until 30 days after certain further action in the purported securities class action complaint discussed above.
Southern Company believes these legal challenges have no merit; however, an adverse outcome in any of these proceedings could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, the ultimate outcome of which cannot be determined at this time.
Georgia Power
In 2011, plaintiffs filed a putative class action against Georgia Power in the Superior Court of Fulton County, Georgia alleging that Georgia Power's collection in rates of municipal franchise fees (all of which are remitted to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state tort law claims. In November 2016, the Georgia Court of Appeals reversed the trial court's previous dismissal of the case and remanded the case to the trial court for further proceedings. Georgia Power filed a petition for writ of certiorari with the Georgia Supreme Court, which was granted on August 28, 2017. A decision from the Georgia Supreme Court is not expected until 2018. Georgia Power believes the plaintiffs' claims have no merit and intends to vigorously defend itself in this matter. The ultimate outcome of this matter cannot be determined at this time.
Southern Power
During 2015, Southern Power indirectly acquired a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock facility in Pecos County, Texas, which was under construction by Recurrent Energy, LLC and was subsequently placed in service in November 2016. Prior to placing the facility in service, certain solar panels were damaged during installation. While the facility currently is generating energy consistent with operational expectations and PPA obligations, Southern Power is pursuing remedies under its insurance policies and other contracts to repair or replace these solar panels. In connection therewith, Southern Power is withholding payments of approximately $26 million from the construction contractor, who has placed a lien on the Roserock facility for the same amount. The amounts withheld are included in other accounts and notes payable and other current liabilities on Southern Company's consolidated balance sheets and other accounts payable and other current liabilities on Southern Power's consolidated balance sheets. On May 18, 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas, against X.L. America, Inc. (XL) and North American Elite Insurance Company (North American Elite) seeking recovery from an insurance policy for damages resulting from a hail storm and certain installation practices by the construction contractor, McCarthy Building Companies, Inc. (McCarthy). On May 19, 2017, Roserock filed a separate lawsuit against McCarthy in the state district court in Travis County, Texas alleging breach of contract and breach of warranty for the damages sustained at the Roserock facility, which has since been moved to the U.S. District Court for the Western District of Texas. On May 22, 2017, McCarthy filed a counter lawsuit against Roserock, Array Technologies, Inc., Canadian Solar (USA), Inc., XL, and North American Elite in the U.S. District Court for the Western District of Texas alleging, among other things, breach of contract, and requesting foreclosure of mechanic's liens against Roserock. On July 18, 2017, the U.S. District Court for the Western District of Texas consolidated the two pending lawsuits. Southern Power intends to vigorously pursue and defend these matters, the ultimate outcome of which cannot be determined at this time.
Southern Company Gas
Nicor Gas and Nicor Energy Services Company, wholly-owned subsidiaries of Southern Company Gas, and Nicor Inc. were defendants in a putative class action initially filed in 2011 in the state court in Cook County, Illinois. The plaintiffs purported to represent a class of the customers who purchased the Gas Line Comfort Guard product from Nicor Energy Services Company and variously alleged that the marketing, sale, and billing of the Gas Line Comfort Guard product violated the Illinois Consumer Fraud and Deceptive Business Practices Act, constituting common law fraud and resulting in unjust enrichment of these entities. The plaintiffs sought, on behalf of the classes they
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
purported to represent, actual and punitive damages, interest, costs, attorney fees, and injunctive relief. On February 8, 2017, the judge denied the plaintiffs' motion for class certification and Southern Company Gas' motion for summary judgment. On March 7, 2017, the parties reached a settlement, which was finalized and effective on April 3, 2017. The settlement did not have a material impact on Southern Company's or Southern Company Gas' financial statements.
Environmental Matters
Environmental Remediation
The Southern Company system must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companies and the natural gas distribution utilities in Illinois, New Jersey, Georgia, and Florida have each received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies.
Georgia Power's environmental remediation liability was $26 million and $17 million as of September 30, 2017 and December 31, 2016, respectively. Georgia Power has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected.
Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $53 million and $44 million as of September 30, 2017 and December 31, 2016, respectively. These estimated costs primarily relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf Power's substations. The schedule for completion of the remediation projects is subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power's environmental cost recovery clause; therefore, these liabilities have no impact on net income.
Southern Company Gas' environmental remediation liability was $399 million and $426 million as of September 30, 2017 and December 31, 2016, respectively, based on the estimated cost of environmental investigation and remediation associated with known current and former manufactured gas plant operating sites. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies of the natural gas distribution utilities, with the exception of one site representing $5 million of the total accrued remediation costs.
The final outcome of these matters cannot be determined at this time. However, the final disposition of these matters is not expected to have a material impact on the financial statements of Southern Company, Georgia Power, Gulf Power, or Southern Company Gas.
Natural Gas Storage
A wholly-owned subsidiary of Southern Company Gas owns and operates a natural gas storage facility consisting of two salt dome caverns in Louisiana. Periodic integrity tests are required in accordance with rules of the Louisiana Department of Natural Resources (LDNR). In August 2017, in connection with an ongoing integrity project, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. At September 30, 2017, the facility's property, plant, and equipment had a net book value of $111 million, of which the cavern itself represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including the results of ongoing third-party technical engineering reviews, testing, and compliance with an order from the LDNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining a core sample to determine the composition of the sheath surrounding the edge of the salt dome. Early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
facility. The ultimate outcome of this matter cannot be determined at this time, but could have a significant impact on Southern Company's financial statements and a material impact on Southern Company Gas' financial statements.
Nuclear Fuel Disposal Costs
See Note 3 to the financial statements of Southern Company, Alabama Power, and Georgia Power under "Nuclear Fuel Disposal Costs" in Item 8 of the Form 10-K for additional information regarding legal remedies pursued by Alabama Power and Georgia Power against the U.S. government for its partial breach of contract relating to the disposal of spent nuclear fuel and high level radioactive waste generated at each company's nuclear plants.
On October 10, 2017, Alabama Power and Georgia Power filed additional lawsuits against the U.S. government in the Court of Federal Claims for the costs of continuing to store spent nuclear fuel at Plant Farley, Plant Hatch, and Plant Vogtle Units 1 and 2 for the period from January 1, 2015 through December 31, 2017. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of September 30, 2017 for any potential recoveries from the additional lawsuits. The final outcome of these matters cannot be determined at this time; however, no material impact on Southern Company's, Alabama Power's, or Georgia Power's net income is expected.
FERC Matters
Municipal and Rural Associations Tariff
See Note 3 to the financial statements of Mississippi Power under "FERC Matters" in Item 8 of the Form 10-K for additional information regarding a settlement agreement entered into by Mississippi Power regarding the establishment of a regulatory asset for Kemper IGCC-related costs. See "Integrated Coal Gasification Combined Cycle" herein for information regarding the Kemper IGCC.
In March 2016, Mississippi Power reached a settlement agreement with its wholesale customers, which was subsequently approved by the FERC, for an increase in wholesale base revenues under the MRA cost-based electric tariff, primarily as a result of placing scrubbers for Plant Daniel Units 1 and 2 in service in 2015. The settlement agreement became effective for services rendered beginning May 1, 2016, resulting in an estimated annual revenue increase of $7 million under the MRA cost-based electric tariff. Additionally, under the settlement agreement, the tariff customers agreed to similar regulatory treatment for MRA tariff ratemaking as the treatment approved for retail ratemaking through an order issued by the Mississippi PSC in December 2015 (In-Service Asset Rate Order). This regulatory treatment primarily includes (i) recovery of the Kemper IGCC assets currently operational and providing service to customers and other related costs, (ii) amortization of the Kemper IGCC-related regulatory assets included in rates under the settlement agreement over the 36 months ending April 30, 2019, (iii) Kemper IGCC-related expenses included in rates under the settlement agreement no longer being deferred and charged to expense, and (iv) removing all of the Kemper IGCC CWIP from rate base with a corresponding increase in accrual of AFUDC. The additional resulting AFUDC totaled approximately $22 million through the suspension of Kemper IGCC start-up activities.
See "Integrated Coal Gasification Combined Cycle" herein for additional information.
Fuel Cost Recovery
Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At September 30, 2017, the amount of over-recovered wholesale MRA fuel costs included in the balance sheets was $3 million compared to $13 million at December 31, 2016. Over-recovered wholesale MB fuel costs included in the balance sheets were immaterial at September 30, 2017 and December 31, 2016.
See Note 3 to the financial statements of Mississippi Power under "FERC Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Market-Based Rate Authority
See Note 3 to the financial statements of Southern Company and Mississippi Power under "FERC Matters – Market-Based Rate Authority" and Note 3 to the financial statements of Alabama Power, Georgia Power, Gulf Power, and Southern Power under "FERC Matters" in Item 8 of the Form 10-K for additional information regarding the traditional electric operating companies' and Southern Power's market power proceeding and amendment to their market-rate tariff.
On May 17, 2017, the FERC accepted the traditional electric operating companies' and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' and Southern Power's market power proceeding related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' and Southern Power's June 30, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order, or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and Southern Power expect to make a filing within the specified 60 days responding to the FERC's order.
The ultimate outcome of these matters cannot be determined at this time.
Regulatory Matters
Alabama Power
See Note 3 to the financial statements of Southern Company and Alabama Power under "Regulatory Matters – Alabama Power" and "Retail Regulatory Matters," respectively, in Item 8 of the Form 10-K for additional information regarding Alabama Power's recovery of retail costs through various regulatory clauses and accounting orders. The balance of each regulatory clause recovery on the balance sheet follows:
|
| | | | | | | |
| Regulatory Clause | Balance Sheet Line Item | September 30,
2017 | December 31,
2016 |
|
| (in millions) |
| Rate CNP Compliance | Deferred over recovered regulatory clause revenues | $ | 9 |
| $ | — |
|
Rate CNP Compliance(*) | Deferred under recovered regulatory clause revenues | — |
| 9 |
|
| Rate CNP PPA | Deferred under recovered regulatory clause revenues | 17 |
| 142 |
|
Retail Energy Cost Recovery(*) | Other regulatory liabilities, current | — |
| 76 |
|
| Natural Disaster Reserve | Other regulatory liabilities, deferred | 51 |
| 69 |
|
| |
(*) | In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power reclassified $36 million of its under recovered balance for Rate CNP Compliance and $11 million of its under recovered balance for Retail Energy Cost Recovery to a deferred regulatory asset account. |
Georgia Power
Rate Plans
See Note 3 to the financial statements of Southern Company and Georgia Power under "Regulatory Matters – Georgia Power – Rate Plans" and "Retail Regulatory Matters – Rate Plans," respectively, in Item 8 of the Form 10-K for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, Environmental Compliance Cost Recovery tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to the construction of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a separate fuel cost recovery tariff. See "Nuclear Construction" herein and Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Nuclear Construction" and Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the NCCR tariff. Also see "Fuel Cost Recovery" herein and Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Fuel Cost Recovery" and Georgia Power under "Retail Regulatory Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding fuel cost recovery.
Integrated Resource Plan
See Note 3 to the financial statements of Southern Company and Georgia Power under "Regulatory Matters – Georgia Power – Integrated Resource Plan" and "Retail Regulatory Matters – Integrated Resource Plan," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's triennial Integrated Resource Plan.
On March 7, 2017, the Georgia PSC approved Georgia Power's decision to suspend work at a future generation site in Stewart County, Georgia, due to changing economics, including load forecasts and lower fuel costs. The timing of recovery for costs incurred of approximately $50 million will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time.
Fuel Cost Recovery
See Note 3 to the financial statements of Southern Company and Georgia Power under "Regulatory Matters – Georgia Power – Fuel Cost Recovery" and "Retail Regulatory Matters – Fuel Cost Recovery," respectively, in Item 8 of the Form 10-K for additional information.
As of September 30, 2017, Georgia Power's under recovered fuel balance totaled $100 million and is included in current assets and other deferred charges and assets on Southern Company's and Georgia Power's condensed balance sheets. As of December 31, 2016, Georgia Power's over recovered fuel balance totaled $84 million and is included in other current liabilities on Southern Company's and Georgia Power's condensed balance sheets.
Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's or Georgia Power's revenues or net income, but will affect cash flow.
Storm Damage Recovery
Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, for incremental operating and maintenance costs of damage from major storms to its transmission and distribution facilities. During September 2017, Hurricane Irma caused significant damage to Georgia Power's transmission and distribution facilities. The total amount of incremental restoration costs related to this hurricane is estimated to be approximately $150 million. As of September 30, 2017, Georgia Power had deferred approximately $145 million in a regulatory asset related to storm damage. As of September 30, 2017, the total balance in Georgia Power's regulatory asset related to storm damage was $360 million. The rate of storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case required to be filed by July 1, 2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's or Georgia Power's financial statements. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Storm Damage Recovery" and Note 1 to the financial statements of Georgia Power under "Storm Damage Recovery" in Item 8 of the Form 10-K for additional information regarding Georgia Power's storm damage reserve.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Nuclear Construction
See Note 3 to the financial statements of Southern Company and Georgia Power under "Regulatory Matters – Georgia Power – Nuclear Construction" and "Retail Regulatory Matters – Nuclear Construction," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's construction of Plant Vogtle Units 3 and 4, Vogtle Construction Monitoring (VCM) reports, the NCCR tariff, and the Contractor Settlement Agreement.
Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcy
In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Vogtle 3 and 4 Agreement, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4. Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. Georgia Power's proportionate share of Plant Vogtle Units 3 and 4 is 45.7%.
The Vogtle 3 and 4 Agreement also provided for liquidated damages upon the EPC Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to an aggregate cap of 10% of the contract price, or approximately $920 million (approximately $420 million based on Georgia Power's ownership interest). Under the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. In January 2016, Westinghouse delivered to the Vogtle Owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020 and require 60 days' written notice to Georgia Power in the event the Westinghouse Letters of Credit will not be renewed.
Under the terms of the Vogtle 3 and 4 Agreement, the EPC Contractor did not have the right to terminate the Vogtle 3 and 4 Agreement for convenience. In the event of an abandonment of work by the EPC Contractor, the maximum liability of the EPC Contractor under the Vogtle 3 and 4 Agreement was 40% of the contract price (approximately $1.7 billion based on Georgia Power's ownership interest).
On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. To provide for a continuation of work at Plant Vogtle Units 3 and 4, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an interim assessment agreement with the EPC Contractor (Interim Assessment Agreement), which the bankruptcy court approved on March 30, 2017.
The Interim Assessment Agreement provided, among other items, that during the term of the Interim Assessment Agreement Georgia Power was obligated to pay, on behalf of the Vogtle Owners, all costs accrued by the EPC Contractor for subcontractors and vendors for services performed or goods provided. The Interim Assessment Agreement, as amended, expired on July 27, 2017.
Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor, including Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken, and continues to take, actions to remove liens filed by these subcontractors through the posting of surety bonds. Georgia Power estimates the aggregate liability, through September 30, 2017, of the Vogtle Owners for the removal of subcontractor liens and payment of other EPC Contractor pre-petition accounts payable to total approximately $386 million, of which $340 million had been paid or accrued as of September 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $176 million.
On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion (Guarantee Obligations), of which Georgia Power's proportionate share is approximately $1.7 billion, and that the Guarantee Obligations exist regardless of whether Plant Vogtle Units 3 and 4 are completed. The Guarantee
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations, which will reduce CWIP, beginning in October 2017 and continuing through January 2021. In the event Toshiba receives certain payments, including sale proceeds, from or related to Westinghouse (or its subsidiaries) or Toshiba Nuclear Energy Holdings (UK) Limited (or its subsidiaries), it will hold a portion of such payments in trust for the Vogtle Owners and promptly pay them as offsets against any remaining Guarantee Obligations. Under the Guarantee Settlement Agreement, the Vogtle Owners will forbear from exercising certain remedies, including drawing on the Westinghouse Letters of Credit, until June 30, 2020, unless certain events of nonpayment, insolvency, or other material breach of the Guarantee Settlement Agreement by Toshiba occur. If such an event occurs, the balance of the Guarantee Obligations will become immediately due and payable, and the Vogtle Owners may exercise any and all rights and remedies, including drawing on the Westinghouse Letters of Credit without restriction. In addition, the Guarantee Settlement Agreement does not restrict the Vogtle Owners from fully drawing on the Westinghouse Letters of Credit in the event they are not renewed or replaced prior to the expiration date. On October 2, 2017, Georgia Power received the first installment of the Guarantee Obligations of $300 million from Toshiba, of which Georgia Power's proportionate share was $137 million. Georgia Power is considering potential options with respect to its right to future payments under the Guarantee Settlement Agreement and its claims against the EPC Contractor in the EPC Contractor's bankruptcy proceeding, including a potential sale of those payment rights and bankruptcy claims. Any such transaction cannot be assured and would be subject to DOE consents and related approvals under the Loan Guarantee Agreement and related agreements.
On August 10, 2017, Toshiba released its financial results for the quarter ended June 30, 2017, which reflected a negative shareholders' equity balance of approximately $4.5 billion as of June 30, 2017. Toshiba previously announced the existence of material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern. As a result, substantial risk regarding the Vogtle Owners' ability to fully collect the Guarantee Obligations continues to exist. An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Southern Company's and Georgia Power's financial statements.
Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into a services agreement (Services Agreement), which was amended and restated on July 20, 2017, for the EPC Contractor to transition construction management of Plant Vogtle Units 3 and 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Services Agreement, (ii) assume and assign to the Vogtle Owners certain project-related contracts, (iii) join the Vogtle Owners as counterparties to certain assumed project-related contracts, and (iv) reject the Vogtle 3 and 4 Agreement. The Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE on July 27, 2017. The Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.
Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement (Bechtel Agreement) with Bechtel Power Corporation (Bechtel), whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4. Facility design and engineering remains the responsibility of the EPC Contractor under the Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. Pursuant to the Loan Guarantee Agreement, Georgia Power is required to obtain the DOE's approval of the Bechtel Agreement prior to obtaining any further advances under the Loan Guarantee Agreement.
In connection with the recommendation to continue with construction of Plant Vogtle Units 3 and 4 (described below), the Vogtle Owners agreed on a term sheet to amend the existing joint ownership agreements to provide for additional Vogtle Owner approval requirements. Under the term sheet, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including (i) the bankruptcy of Toshiba or a material breach by Toshiba of the Guarantee Settlement Agreement; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report by more than $1 billion or extension of the project schedule contained in the seventeenth VCM report by more than one year. In addition, under the term sheet, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Services Agreement or agreements with the primary construction contractor or Southern Nuclear.
The term sheet also confirms that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.
The ultimate outcome of these matters cannot be determined at this time.
Regulatory Matters
In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by including the related CWIP accounts in rate base during the construction period. As of September 30, 2017, Georgia Power had recovered approximately $1.5 billion of financing costs. Georgia Power expects to file on November 1, 2017 to increase the NCCR tariff by approximately $90 million, effective January 1, 2018, pending Georgia PSC approval.
On December 20, 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving the following prudence matters: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report will be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement is reasonable and prudent and none of the amounts paid or to be paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) financing costs on verified and approved capital costs will be deemed prudent provided they are incurred prior to December 31, 2019 and December 31, 2020 for Plant Vogtle Units 3 and 4, respectively; and (iv) (a) the in-service capital cost forecast will be adjusted to $5.680 billion (Revised Forecast), which includes a contingency of $240 million above Georgia Power's then current forecast of $5.440 billion, (b) capital costs incurred up to the Revised Forecast will be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, and (c) Georgia Power would have the burden to show that any capital costs above the Revised Forecast are reasonable and prudent. Under the terms of the Vogtle Cost Settlement Agreement, the certified in-service capital cost for purposes of calculating the NCCR tariff will remain at $4.418 billion. Construction capital costs above $4.418 billion will accrue AFUDC through the date each unit is placed in service. The ROE used to calculate the NCCR tariff was reduced from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016. For purposes of the AFUDC calculation, the ROE on costs between $4.418 billion and $5.440 billion will also be 10.00% and the ROE on any amounts above $5.440 billion would be Georgia Power's average cost of long-term debt. If the Georgia PSC adjusts Georgia
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Power's ROE rate setting point in a rate case prior to Plant Vogtle Units 3 and 4 being placed into retail rate base, then the ROE for purposes of calculating both the NCCR tariff and AFUDC will likewise be 95 basis points lower than the revised ROE rate setting point. If Plant Vogtle Units 3 and 4 are not placed in service by December 31, 2020, then (i) the ROE for purposes of calculating the NCCR tariff will be reduced an additional 300 basis points, or $8 million per month, and may, at the Georgia PSC's discretion, be accrued to be used for the benefit of customers, until such time as the units are placed in service and (ii) the ROE used to calculate AFUDC will be Georgia Power's average cost of long-term debt.
The Georgia PSC has approved sixteen VCM reports covering the periods through December 31, 2016, including construction capital costs incurred, which through that date totaled $3.9 billion. Georgia Power filed its seventeenth VCM report, covering the period from January 1 through June 30, 2017, requesting approval of $542 million of construction capital costs incurred during that period, with the Georgia PSC on August 31, 2017.
In the seventeenth VCM report, Georgia Power recommended that construction of Plant Vogtle Units 3 and 4 be continued, with Southern Nuclear serving as project manager. Georgia Power believes that the most reasonable schedule for completing Plant Vogtle Units 3 and 4 is by November 2021 for Unit 3 and by November 2022 for Unit 4. Georgia Power's recommendation to go forward with completion of Vogtle Units 3 and 4 is based on the following assumptions about the regulatory treatment of this recommendation, if the recommendation to go forward is adopted by the Georgia PSC: (i) that pursuant to Georgia law, the Georgia PSC in the seventeenth VCM proceeding approves the new cost and schedule forecast and finds that it is a reasonable basis for going forward, and that if the Georgia PSC disapproves all or part of the proposed cost and schedule revisions, Georgia Power may cancel Plant Vogtle Units 3 and 4 and recover its actual investment in Plant Vogtle Units 3 and 4; (ii) that the Vogtle Cost Settlement Agreement remains in full force and effect, including Georgia Power retaining the burden of proving all capital costs above $5.680 billion were prudent; (iii) that while the Georgia PSC will make no prudence finding in the seventeenth VCM proceeding, nor will the certified amount be amended consistent with the Vogtle Cost Settlement Agreement, the Georgia PSC recognizes that the certified amount is not a cap, and all costs that are approved and presumed or shown to be prudently incurred will be recoverable by Georgia Power; (iv) that Georgia Power is not a guarantor of the Toshiba Guarantee, and the failure of Toshiba to pay the Toshiba Guarantee, the failure of the U.S. Congress to extend the PTCs for Plant Vogtle Units 3 and 4, or the failure of the DOE to extend the Loan Guarantee Agreement with Georgia Power to reflect the increased capital amounts, will not reduce the amount of investment Georgia Power is otherwise allowed to collect; and (v) that as conditions change and assumptions are either proven or disproven, Georgia Power and the Georgia PSC may reconsider the decision to go forward. The Georgia PSC is expected to make a decision on these matters by February 6, 2018.
The ultimate outcome of these matters cannot be determined at this time.
Revised Cost and Schedule
Georgia Power's approximate proportionate share of the remaining estimated cost to complete Plant Vogtle Units 3 and 4 is as follows:
|
| | | |
| | (in billions) |
| Estimated cost to complete | $ | 4.2 |
|
| CWIP as of September 30, 2017 | 4.6 |
|
| Guarantee Obligations | (1.7 | ) |
| Estimated capital costs | $ | 7.1 |
|
| Vogtle Cost Settlement Agreement Revised Forecast | (5.7 | ) |
| Estimated net additional capital costs | $ | 1.4 |
|
Georgia Power's estimated financing costs during the construction period total approximately $3.4 billion, of which approximately $1.5 billion had been incurred through September 30, 2017.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Georgia Power's cancellation cost estimate results indicate that its proportionate share of the estimated costs to cancel both units is approximately $350 million. As a result, as of September 30, 2017, total estimated costs subject to evaluation by Georgia Power and the Georgia PSC in the event of a cancellation decision are as follows:
|
| | | |
| | Cancellation Cost Estimate |
| | (in billions) |
| CWIP as of September 30, 2017 | $ | 4.6 |
|
| Financing costs collected, net of tax | 1.5 |
|
Cancellation costs(*) | 0.4 |
|
| Guarantee Obligations | (1.7 | ) |
| Estimated net cancellation cost | $ | 4.8 |
|
| |
(*) | The estimate for cancellation costs includes, but is not limited to, costs to terminate contracts for construction and other services, as well as costs to secure the Plant Vogtle Units 3 and 4 construction site. |
The Guarantee Obligations continue to exist in the event of cancellation. In addition, under Georgia law, prudently incurred costs related to certificated projects cancelled by the Georgia PSC are allowed recovery, including carrying costs, in future retail rates. Georgia Power will continue working with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4, including, but not limited to, the status of construction and rate recovery.
The ultimate outcome of these matters cannot be determined at this time.
Other Matters
As of September 30, 2017, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through the Loan Guarantee Agreement and a multi-advance credit facility among Georgia Power, the DOE, and the FFB, which provides for borrowings of up to $3.46 billion, subject to the satisfaction of certain conditions. On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to the financial statements of Southern Company and Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (E) under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
The IRS has allocated PTCs to Plant Vogtle Units 3 and 4 which require that the applicable unit be placed in service prior to 2021. The net present value of Georgia Power's PTCs is estimated at approximately $400 million per unit.
There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise while construction proceeds. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise while construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
While construction continues, the risk remains that challenges with management of contractors, subcontractors, and vendors, labor productivity, fabrication, delivery, assembly, and installation of plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost.
The ultimate outcome of these matters cannot be determined at this time.
Gulf Power
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information regarding Gulf Power's rates and charges for service to retail customers.
Retail Base Rate Cases
See Note 3 to the financial statements of Southern Company and Gulf Power under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" and "Retail Regulatory Matters – Retail Base Rate Cases," respectively, in Item 8 of the Form 10-K for additional information.
In 2013, the Florida PSC approved a settlement agreement that authorized Gulf Power to reduce depreciation and record a regulatory asset up to $62.5 million from January 2014 through June 2017. In any given month, such depreciation reduction could not exceed the amount necessary for the retail ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. For 2014 and 2015, Gulf Power recognized reductions in depreciation of $8.4 million and $20.1 million, respectively. No net reduction in depreciation was recorded in 2016. Through June 2017, Gulf Power recognized the remaining allowable reductions in depreciation totaling $34.0 million.
On April 4, 2017, the Florida PSC approved the 2017 Rate Case Settlement Agreement among Gulf Power and three intervenors with respect to Gulf Power's request to increase retail base rates. Among the terms of the 2017 Rate Case Settlement Agreement, Gulf Power increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consisted of a $62.0 million increase in annual base revenues less an annual equivalent credit of approximately $7.7 million for 2017 for certain wholesale revenues to be provided through December 2019 through the purchased power capacity cost recovery clause. In addition, Gulf Power continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%), is deemed to have an equity ratio of 52.5% for all retail regulatory purposes, and implemented new dismantlement accruals effective July 1, 2017. Gulf Power will also begin amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 (357 MWs) over 15 years effective January 1, 2018 and will implement new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs), which was recorded in the first quarter 2017. The remaining issues related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause rate approved by the Florida PSC in November 2016.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Cost Recovery Clauses
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K for additional information regarding Gulf Power's recovery of retail costs through various regulatory clauses and accounting orders. Gulf Power has four regulatory clauses which are approved by the Florida PSC. The balance of each regulatory clause recovery on the balance sheet follows:
|
| | | | | | | |
| Regulatory Clause | Balance Sheet Line Item | September 30,
2017 | December 31,
2016 |
|
| (in millions) |
| Fuel Cost Recovery | Under recovered regulatory clause revenues | $ | 13 |
| $ | — |
|
| Fuel Cost Recovery | Other regulatory liabilities, current | — |
| 15 |
|
| Purchased Power Capacity Recovery | Under recovered regulatory clause revenues | 1 |
| — |
|
| Environmental Cost Recovery | Other regulatory liabilities, current | 1 |
| — |
|
| Environmental Cost Recovery | Under recovered regulatory clause revenues | — |
| 13 |
|
| Energy Conservation Cost Recovery | Under recovered regulatory clause revenues | 1 |
| 4 |
|
As discussed previously, the 2017 Rate Case Settlement Agreement resolved the remaining issues related to Gulf Power's inclusion of certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 in the environmental cost recovery clause and no adjustment to the environmental cost recovery clause rate approved by the Florida PSC in November 2016 was made.
On October 25, 2017, the Florida PSC approved Gulf Power's annual rate clause request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2018. The net effect of the approved changes is a $63 million increase in annual revenues effective in January 2018, the majority of which will be offset by related expense increases.
Mississippi Power
Performance Evaluation Plan
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Performance Evaluation Plan" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's base rates.
On March 15, 2017, Mississippi Power submitted its annual PEP lookback filing for 2016, which reflected the need for a $5 million surcharge to be recovered from customers. The filing has been suspended for review by the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time.
Energy Efficiency
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Energy Efficiency" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's energy efficiency programs.
On July 6, 2017, the Mississippi PSC issued an order approving Mississippi Power's Energy Efficiency Cost Rider compliance filing, which increased annual retail revenues by approximately $2 million effective with the first billing cycle for August 2017.
Environmental Compliance Overview Plan
On May 4, 2017, the Mississippi PSC approved Mississippi Power's ECO Plan filing for 2017, which requested the maximum 2% annual increase in revenues, approximately $18 million, primarily related to the Plant Daniel Units 1
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
and 2 scrubbers placed in service in 2015. The rates became effective with the first billing cycle for June 2017. Approximately $26 million of related revenue requirements in excess of the 2% maximum was deferred for inclusion in the 2018 filing.
Fuel Cost Recovery
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's retail fuel cost recovery.
At September 30, 2017, the amount of over-recovered retail fuel costs included on Mississippi Power's condensed balance sheet was $2 million compared to $37 million at December 31, 2016.
Ad Valorem Tax Adjustment
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Ad Valorem Tax Adjustment" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's ad valorem tax adjustments.
On July 6, 2017, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment factor filing for 2017, which included an annual rate increase of 0.85%, or $8 million in annual retail revenues, primarily due to increased assessments.
Southern Company Gas
Riders
Nicor Gas has established a variable tax cost adjustment rider, which was approved by the Illinois Commission effective July 16, 2017. This rider provides for recovery of the invested capital tax imposed on Nicor Gas through an annual true-up and reconciliation mechanism based on amounts approved in prior rate cases. Accordingly, this rider will not have a significant effect on Southern Company Gas' net income.
Natural Gas Cost Recovery
Southern Company Gas has established natural gas cost recovery rates approved by the relevant state regulatory agencies in the states in which it serves. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on Southern Company's or Southern Company Gas' revenues or net income, but will affect cash flows.
Base Rate Cases
See Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters – Base Rate Cases" in Item 8 of the Form 10-K for additional information.
Settled Base Rate Cases
On February 21, 2017, the Georgia PSC approved the Georgia Rate Adjustment Mechanism (GRAM) and a $20 million increase in annual base rate revenues for Atlanta Gas Light, effective March 1, 2017. GRAM adjusts base rates annually, up or down, based on the previously approved ROE of 10.75% and does not collect revenue through special riders and surcharges. Various infrastructure programs previously authorized by the Georgia PSC under Atlanta Gas Light's STRIDE program, which include the Integrated Vintage Plastic Replacement Program and Integrated System Reinforcement Program, will continue under GRAM and the recovery of and return on the infrastructure program investments will be included in annual base rate adjustments. The Georgia PSC will review Atlanta Gas Light's performance annually under GRAM.
Pursuant to the GRAM approval, Atlanta Gas Light and the staff of the Georgia PSC agreed to a variation to the Integrated Customer Growth Program that was formerly part of Atlanta Gas Light's STRIDE program. As a result, a
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
new tariff was created, effective October 10, 2017, to provide $15 million annually for Atlanta Gas Light to commit to strategic economic development projects.
Beginning with the next rate adjustment in June 2018, Atlanta Gas Light's recovery of the previously unrecovered Pipeline Replacement Program revenue through 2014, as well as the mitigation costs associated with the Pipeline Replacement Program that were not previously included in its rates, will also be included in GRAM. In connection with the GRAM approval, the last monthly Pipeline Replacement Program surcharge increase became effective March 1, 2017.
In September 2016, Elizabethtown Gas filed a general base rate case with the New Jersey BPU requesting a $19 million increase in annual base rate revenues. The requested increase was based on a projected 12-month test year ending March 31, 2017 and a ROE of 10.25%. On June 30, 2017, the New Jersey BPU approved a settlement that provides for a $13 million increase in annual base rate revenues, effective July 1, 2017, based on a ROE of 9.6%. Also included in the settlement was a new composite depreciation rate that is expected to result in a $3 million annual reduction of depreciation. See Note (I) under "Southern Company Gas" for information on the proposed sale of Elizabethtown Gas.
Pending Base Rate Cases
On March 10, 2017, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $208 million increase in annual base rate revenues. The requested increase is based on a 2018 projected test year and a ROE of 10.7%. The Illinois Commission is expected to rule on the requested increase in December 2017, after which rate adjustments will be effective.
On March 31, 2017, Virginia Natural Gas filed a general base rate case with the Virginia Commission requesting a $44 million increase in annual base rate revenues. The requested increase was based on a projected 12-month test year beginning September 1, 2017 and a ROE of 10.25%. The requested increase included $13 million related to the recovery of investments under the Steps to Advance Virginia's Energy (SAVE) program. On October 3, 2017, Virginia Natural Gas entered into a proposed stipulation with the Staff of the Virginia Commission, the Office of the Attorney General, Division of Consumer Counsel, and the Virginia Industrial Gas Users' Association resolving all related issues. The proposed stipulation includes a $34 million increase in annual base rate revenues, including $13 million related to the recovery of investments under the SAVE program. An authorized ROE range of 9.0% to 10.0% with a midpoint of 9.5% will be used to determine the revenue requirement in any filing, other than for a change in base rates. The Virginia Commission is expected to rule on the proposed stipulation in the fourth quarter 2017. Rate adjustments based on the proposed stipulation became effective September 1, 2017, subject to refund.
On October 23, 2017, Florida City Gas filed a general base rate case with the Florida PSC requesting a $19 million increase in annual base rate revenues. The requested increase is based on a 2018 projected test year and a ROE of 11.25%. The requested increase includes $3 million related to the recovery of investments under the Safety, Access, and Facility Enhancement (SAFE) program. Additionally, Florida City Gas requested interim rates of $5 million to be effective in January 2018, subject to refund. The Florida PSC is expected to rule on the requested increase in mid-2018.
The ultimate outcome of these pending base rate cases cannot be determined at this time.
Regulatory Infrastructure Programs
Southern Company Gas is engaged in various infrastructure programs that update or expand its gas distribution systems to improve reliability and ensure the safety of its utility infrastructure, and recovers in rates its investment and a return associated with these infrastructure programs. See Note 3 to the financial statements of Southern Company and Southern Company Gas under "Regulatory Matters – Southern Company Gas – Regulatory Infrastructure Programs" and "Regulatory Matters – Regulatory Infrastructure Programs," respectively, in Item 8 of the Form 10-K for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Nicor Gas
In 2014, the Illinois Commission approved Nicor Gas' nine-year regulatory infrastructure program, Investing in Illinois. Under this program, Nicor Gas placed into service $178 million of qualifying assets during the first nine months of 2017.
Atlanta Gas Light
Atlanta Gas Light's STRIDE program, which started in 2009, consists of three individual programs that update and expand gas distribution systems and LNG facilities as well as improve system reliability to meet operational flexibility and customer growth. Through the programs under STRIDE, Atlanta Gas Light invested $127 million during the first nine months of 2017. The recovery of and return on current and future capital investments under the STRIDE program are included in the annual base rate revenue adjustment under GRAM.
In August 2016, Atlanta Gas Light filed a petition with the Georgia PSC for approval of a four-year extension of its Integrated System Reinforcement Program (i-SRP) seeking approval to invest an additional $177 million to improve and upgrade its core gas distribution system in years 2017 through 2020. Subsequently, the proposed capital investments associated with the extension of i-SRP were included in the 2017 annual base rate revenue under GRAM approved by the Georgia PSC on February 21, 2017.
See "Base Rate Cases" herein for additional information.
Elizabethtown Gas
In 2013, the New Jersey BPU approved the extension of Elizabethtown Gas' Aging Infrastructure Replacement program, under which Elizabethtown Gas invested $16 million during the first nine months of 2017. Effective July 1, 2017, investments under this program are being recovered through base rate revenues.
Virginia Natural Gas
In March 2016, the Virginia Commission approved an extension to the SAVE program, under which Virginia Natural Gas invested $21 million during the first nine months of 2017.
Florida City Gas
The Florida PSC approved Florida City Gas' SAFE program in 2015. Under the program, Florida City Gas invested $9 million during the first nine months of 2017.
Integrated Coal Gasification Combined Cycle
See Note 3 to the financial statements of Southern Company and Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding Mississippi Power's construction of the Kemper IGCC.
Kemper IGCC Overview
The Kemper IGCC was designed to utilize IGCC technology with an expected output capacity of 582 MWs and to be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper IGCC, Mississippi Power constructed approximately 61 miles of CO2 pipeline infrastructure for the transport of captured CO2 for use in enhanced oil recovery.
Kemper IGCC Schedule and Cost Estimate
In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of grants awarded to the Kemper IGCC project by the DOE under the Clean Coal Power
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Initiative Round 2 (Initial DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014.
The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO2, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast has decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations has increased significantly since certification.
On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC (Kemper Settlement Order). The Kemper Settlement Order established a new docket for the purposes of pursuing a global settlement of costs of the Kemper IGCC (Kemper IGCC Settlement Docket). On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014.
Mississippi Power's Kemper IGCC 2010 project estimate totaled $2.97 billion, which included capped costs of $2.4 billion. At the time of project suspension in June 2017, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in additional grants from the DOE for the Kemper IGCC (Additional DOE Grants).
Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate above the cost cap for the Kemper IGCC of $196 million ($121 million after tax) in the second quarter through May 31, 2017 and a total of $305 million ($188 million after tax) for year-to-date through May 31, 2017. In the aggregate, Mississippi Power incurred charges of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017. The May 31, 2017 cost estimate included approximately $175 million of estimated costs to be incurred beyond the then-estimated in-service date of June 30, 2017 that were expected to be subject to the $2.88 billion cost cap.
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred. In the aggregate, Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC totaling $34 million ($21 million after tax) for the third quarter 2017 and $3.2 billion ($2.2 billion after tax) for the nine months ended September 30, 2017.
As of September 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC. The Kemper combined cycle balances as presented in the condensed balance sheet at September 30, 2017 include $1.1 billion in property, plant, and equipment, net of $80 million in accumulated depreciation; $15 million in materials and supplies; $10 million in other deferred charges and assets; and $113 million in regulatory assets, net of accumulated amortization of $63 million, of which $21 million is included in other regulatory assets, current and $92 million in other regulatory assets, deferred.
Rate Recovery of Kemper IGCC Costs
Given the variety of potential scenarios and the uncertainty of the outcome of future regulatory proceedings with the Mississippi PSC (and any subsequent related legal challenges), the ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, cannot now be determined but could result in further material charges that could have a material impact on Southern Company's and Mississippi Power's results of operations, financial condition, and liquidity.
Kemper IGCC Settlement Docket
On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC. The Kemper Settlement Order established the Kemper IGCC Settlement Docket. The Mississippi PSC requested any such proposed settlement agreement reflect: (i) at a minimum, no rate increase to Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and related assets; and (iii) modification or amendment of the CPCN for the Kemper IGCC to allow only for ownership and operation of a natural gas facility.
On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014. At the time of project suspension, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants.
Mississippi Power reached and filed a settlement agreement on August 21, 2017 with certain parties (not including the Mississippi Public Utilities Staff (MPUS)), which it believes met the conditions of the Kemper Settlement Order. The settlement agreement provides for an annual revenue requirement of $126 million for Kemper IGCC-related costs, which would (i) be effective January 1, 2018, (ii) represent no rate increase for customers, and (iii) include no recovery for the costs associated with the gasifier portion of the Kemper IGCC in 2018 or at any future date. In addition, under the settlement agreement, the CPCN for the Kemper IGCC would be modified to limit the Kemper County energy facility to natural gas combined cycle operation and Mississippi Power would, in the future, file a reserve margin plan with the Mississippi PSC. The Mississippi PSC issued a scheduling order, as amended on October 5, 2017, noting Mississippi Power and the MPUS had failed to reach a joint stipulation and ordering a full hearing. The Mississippi PSC is expected to rule on an order resolving this matter in January 2018.
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
associated with the gasification portions of the plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred.
As of September 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which $0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility, as well as the 15% that was previously contracted to Cooperative Energy. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.
Prudence
On August 17, 2016, the Mississippi PSC issued an order establishing a discovery docket to manage all filings related to the prudence of the Kemper IGCC. On October 3, 2016, Mississippi Power made a required compliance filing, which included a review and explanation of differences between the Kemper IGCC project estimate set forth in the 2010 CPCN proceedings and the most recent Kemper IGCC project estimate, as well as comparisons of current cost estimates and current expected plant operational parameters to the estimates presented in the 2010 CPCN proceedings for the first five years after the Kemper IGCC was to be placed in service. Compared to amounts presented in the 2010 CPCN proceedings, operations and maintenance expenses have increased an average of $105 million annually and maintenance capital has increased an average of $44 million annually for the first full five years of operations for the Kemper IGCC. Additionally, while the current estimated operational availability estimates reflect ultimate results similar to those presented in the 2010 CPCN proceedings, the ramp up period for the current estimates reflects a lower starting point and a slower escalation rate. On November 17, 2016, Mississippi Power submitted a supplemental filing to the October 3, 2016 compliance filing to present revised non-fuel operations and maintenance expense projections for the first year after the Kemper IGCC was to be placed in service. This supplemental filing included approximately $68 million in additional estimated operations and maintenance costs expected to be required to support the operations of the Kemper IGCC during that period.
Mississippi Power responded to numerous requests for information from interested parties in the discovery docket, which is now complete. Mississippi Power expects the Mississippi PSC to utilize this information in connection with the ultimate resolution of Kemper IGCC cost recovery.
Economic Viability Analysis
In the fourth quarter 2016, as a part of its Integrated Resource Plan process, the Southern Company system completed its regular annual updated fuel forecast, the 2017 Annual Fuel Forecast. This updated fuel forecast reflected significantly lower long-term estimated costs for natural gas than were previously projected. As a result of the updated long-term natural gas forecast, as well as the revised operating expense projections reflected in the discovery docket filings discussed above, on February 21, 2017, Mississippi Power filed an updated project economic viability analysis of the Kemper IGCC as required under the 2012 MPSC CPCN Order confirming authorization of the Kemper IGCC. The project economic viability analysis measures the life cycle economics of the Kemper IGCC compared to feasible alternatives, natural gas combined cycle generating units, under a variety of scenarios and considering fuel, operating and capital costs, and operating characteristics, as well as federal and state taxes and incentives. The reduction in the projected long-term natural gas prices in the 2017 Annual Fuel Forecast
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
and, to a lesser extent, the increase in the estimated Kemper IGCC operating costs, negatively impact the updated project economic viability analysis.
Mississippi Power expects the Mississippi PSC to address this matter in connection with the Kemper IGCC Settlement Docket.
2015 Rate Case
On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order adopting in full a stipulation entered into between Mississippi Power and the MPUS regarding the Kemper IGCC assets that were commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The In-Service Asset Rate Order also included a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets. The stipulated revenue requirement excluded the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by Cooperative Energy but reserved Mississippi Power's right to seek recovery in a future proceeding. See "Termination of Proposed Sale of Undivided Interest" herein for additional information.
In 2011, the Mississippi PSC authorized Mississippi Power to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date. In connection with the implementation of the In-Service Asset Order and wholesale rates, Mississippi Power began expensing certain ongoing project costs and certain retail debt carrying costs that previously were deferred and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees. The amortization periods for these regulatory assets vary from two years to 10 years as set forth in the In-Service Asset Rate Order and the settlement agreement with wholesale customers. As of September 30, 2017, the balance associated with these regulatory assets was $113 million, of which $21 million is included in current assets. See "FERC Matters" herein for additional information related to the 2016 settlement agreement with wholesale customers.
The In-Service Asset Rate Order requires Mississippi Power to submit an annual true-up calculation of its actual cost of capital, compared to the stipulated total cost of capital, for the May 31, 2016 and 2017 calculations. At September 30, 2017, Mississippi Power's related regulatory liability totaled approximately $10 million.
As required by the In-Service Asset Rate Order, on June 5, 2017, Mississippi Power made a rate filing requesting to adjust the amortization schedules of the regulatory assets reviewed and determined prudent in the In-Service Asset Order in a manner that would not change customer rates or annual revenues. On June 28, 2017, the Mississippi PSC suspended this filing. On July 6, 2017, the Mississippi PSC issued an order requiring Mississippi Power to establish a regulatory liability account to maintain current rates related to the Kemper IGCC following the July 2017 completion of the amortization period for certain regulatory assets approved in the In-Service Asset Rate Order that would allow for subsequent refund if the Mississippi PSC deems the rates unjust and unreasonable. At September 30, 2017, the related regulatory liability totaled $7 million.
2013 MPSC Rate Order
In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that was intended to establish the process for resolving matters regarding cost recovery related to the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (construction cost increase demonstrated to produce efficiencies that result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions), but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. In March 2013, the Mississippi PSC issued a rate
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
order approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designed to collect $156 million annually beginning in 2014 (2013 MPSC Rate Order) to be used to mitigate customer rate impacts after the Kemper IGCC was placed in service, based on a mirror CWIP methodology (Mirror CWIP rate).
On February 12, 2015, the Mississippi Supreme Court reversed the 2013 MPSC Rate Order and, on July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015 and required the fourth quarter 2015 refund of the $342 million previously collected, along with associated carrying costs of $29 million.
Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continued to record AFUDC on the Kemper IGCC. Between the original May 2014 estimated in-service date and the June 2017 project suspension date, Mississippi Power recorded $494 million of AFUDC on the Kemper IGCC subject to the $2.88 billion cost cap and Cost Cap Exception amounts, of which $460 million related to the gasification portions of the Kemper IGCC.
Mississippi Power expects the Mississippi PSC to address this matter in connection with the Kemper IGCC Settlement Docket.
Lignite Mine and CO2 Pipeline Facilities
In conjunction with the Kemper IGCC, Mississippi Power owns the lignite mine and equipment and mineral reserves located around the Kemper IGCC site. The mine started commercial operation in June 2013.
In 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is responsible for the mining operations through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. In addition to the obligation to fund the reclamation activities, Mississippi Power provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. During the suspension period, these costs are approximately $2 million per month and are being recognized in income as incurred. See Note 1 to the financial statements of Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" and "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.
In addition, Mississippi Power constructed the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery. Mississippi Power entered into agreements with Denbury Onshore (Denbury) and Treetop Midstream Services, LLC (Treetop), pursuant to which Denbury would purchase 70% of the CO2 captured from the Kemper IGCC and Treetop would purchase 30% of the CO2 captured from the Kemper IGCC. On June 3, 2016, Mississippi Power cancelled its contract with Treetop and amended its contract with Denbury to reflect, among other things, Denbury's agreement to purchase 100% of the CO2 captured from the Kemper IGCC and an initial contract term of 16 years. Denbury has the right to terminate the contract at any time because Mississippi Power did not place the Kemper IGCC in service by July 1, 2017.
The ultimate outcome of these matters cannot be determined at this time.
Termination of Proposed Sale of Undivided Interest
In 2010 and as amended in 2012, Mississippi Power and Cooperative Energy (formerly known as SMEPA) entered into an agreement whereby Cooperative Energy agreed to purchase a 15% undivided interest in the Kemper IGCC. On May 20, 2015, Cooperative Energy notified Mississippi Power of its termination of the agreement. Mississippi Power previously received a total of $275 million of deposits from Cooperative Energy that were required to be returned to Cooperative Energy with interest. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to Cooperative Energy. Subsequently, Mississippi Power issued a promissory note in the aggregate principal amount of approximately $301 million to Southern Company, which was repaid in June 2017.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Litigation
On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff alleges that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper IGCC and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper IGCC; ask the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper IGCC in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper IGCC costs from being charged to customers through electric rates. On June 23, 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the plaintiffs filed notice of an appeal.
On June 9, 2016, Treetop, Greenleaf CO2 Solutions, LLC (Greenleaf), Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint relates to the cancelled CO2 contract with Treetop and alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and seeks compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS moved to compel arbitration pursuant to the terms of the CO2 contract, which the court granted on May 4, 2017. On June 28, 2017, Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a claim for arbitration requesting $500 million in damages.
Southern Company and Mississippi Power believe these legal challenges have no merit; however, an adverse outcome in these proceedings could have a material impact on Southern Company's and Mississippi Power's results of operations, financial condition, and liquidity. Southern Company and Mississippi Power will vigorously defend themselves in these matters, and the ultimate outcome of these matters cannot be determined at this time.
Baseload Act
In 2008, the Baseload Act was signed by the Governor of Mississippi. The Baseload Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism that includes in retail base rates, prior to and during construction, all or a portion of the prudently-incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passage of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews by the Mississippi PSC and prohibits the cancellation of any such generating plant without the approval of the Mississippi PSC. In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery or implement credits, refunds, or rebates to customers for costs incurred in connection with such cancelled generating plant.
Income Tax MattersValuation 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 3(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 of Southern Company and Mississippi Power under "Integrated Coal Gasification Combined Cycle – Bonus Depreciation," " – Investment Tax Credits," and " – Section 174 Research and Experimental Deduction""Nuclear Decommissioning" in Item 8 of the Form 10-K and Note (G) under "Section 174 Research and Experimental Deduction" for additional information on bonus depreciation, investment tax credits, and the Section 174 research and experimental deduction.information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS:STATEMENTS (Continued)
(UNAUDITED)
Southern Power has contingent payment obligations related to certain acquisitions whereby it 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 obligations are 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.
Bonus DepreciationSouthern Power also has payment obligations through 2040 whereby it must reimburse the transmission owners for interconnection facilities and network upgrades constructed to support connection of a Southern Power generating facility to the transmission system. The obligations are categorized as Level 2 under Fair Value Measurements as the fair value is determined using observable inputs for the contracted amounts and reimbursement period, as well as a discount rate. The fair value of the obligations reflects the net present value of expected payments.
All projected tax benefits previously received for bonus depreciation"Other investments" include investments traded in the open market that have maturities greater than 90 days, which are categorized as Level 2 under Fair Value Measurements and are comprised of corporate bonds, bank certificates of deposit, treasury bonds, and/or agency bonds.
At September 30, 2022, 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 $156 million and unfunded commitments related to the Kemper IGCCprivate equity investments totaled $84 million. Private equity investments include high-quality private equity funds across several market sectors and funds that invest in real estate assets. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated.
At September 30, 2022, other financial instruments for which the carrying amount did not equal fair value were repaidas follows:
| | | | | | | | | | | | | | | | | | | | |
| Southern
Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas(*) |
| (in billions) |
| Long-term debt, including securities due within one year: | | | | |
| Carrying amount | $ | 53.4 | | $ | 10.8 | | $ | 14.5 | | $ | 1.5 | | $ | 2.9 | | $ | 7.4 | |
| Fair value | 46.4 | | 9.3 | | 12.6 | | 1.2 | | 2.7 | | 6.3 | |
(*)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 remaining lives of the respective bonds, the latest being through 2043.
The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to the Registrants.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
(J) DERIVATIVES
The Registrants are exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Prior to the sale of Sequent on July 1, 2021, Southern Company Gas' wholesale gas operations used various contracts in its commercial activities that generally met the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note (I) for additional fair value information. In the statements of cash flows, any cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Any cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with the classification of the hedged interest or principal, respectively. See Note 1 to the financial statements under "Financial Instruments" in Item 8 of the Form 10-K for additional information. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information regarding the sale of Sequent.
Energy-Related Derivatives
The Subsidiary Registrants enter into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies and the natural gas distribution utilities have limited exposure to market volatility in energy-related commodity prices. Each of the traditional electric operating companies and certain of the natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs, implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies, through the use of financial derivative contracts, which are expected to continue to mitigate price volatility. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in energy-related commodity prices because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted capacity is used to sell electricity. Southern Company Gas retains exposure to price changes that can, in a volatile energy market, be material and can adversely affect its results of operations.
Southern Company Gas also enters into weather derivative contracts as economic hedges in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in operating revenues.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Energy-related derivative contracts are accounted for under one of three methods:
•Regulatory Hedges – Energy-related derivative contracts designated as regulatory hedges relate primarily to the traditional electric operating companies' and the natural gas distribution utilities' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through an approved cost recovery mechanism.
•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 September 30, 2022, the net volume of energy-related derivative contracts for natural gas positions, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows:
| | | | | | | | | | | | | | | | | |
| Net
Purchased
mmBtu | | Longest
Hedge
Date | | Longest
Non-Hedge
Date |
| (in millions) | | | | |
Southern Company(*) | 399 | | 2030 | | 2025 |
| Alabama Power | 105 | | 2026 | | — |
| Georgia Power | 116 | | 2025 | | — |
| Mississippi Power | 82 | | 2027 | | — |
| Southern Power | 11 | | 2030 | | 2023 |
Southern Company Gas(*) | 85 | | 2025 | | 2025 |
(*)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 95.7 million mmBtu and short natural gas positions of 10.6 million mmBtu at September 30, 2022, 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 15 million mmBtu for Southern Company, which includes 4 million mmBtu for Alabama Power, 5 million mmBtu for Georgia Power, 2 million mmBtu for Mississippi Power, and 4 million mmBtu for Southern Power.
For cash flow hedges of energy-related derivatives, the estimated pre-tax gains (losses) expected to be reclassified from accumulated OCI to earnings for the 12-month period ending September 30, 2023 are $17 million for Southern Company, $26 million for Southern Company Gas, and immaterial for the other Registrants.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Interest Rate Derivatives
Southern Company and certain subsidiaries may enter into interest rate derivatives to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and presented on the same income statement line item as the earnings effect of the hedged transactions. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
At September 30, 2022, 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, 2022 |
| | (in millions) | | | | | | (in millions) |
| Cash Flow Hedges of Existing Debt | | | | | | |
| Southern Company parent | $ | 175 | | | — | 4.25% | September 2025 | | $ | — | |
| Southern Company parent | 175 | | | — | 3.83% | August 2032 | | — | |
| Fair Value Hedges of Existing Debt | | | | | | |
| Southern Company parent | 400 | | | 1.75% | 1-month LIBOR + 0.68% | March 2028 | | (57) | |
| Southern Company parent | 1,000 | | | 3.70% | 1-month LIBOR + 2.36% | April
2030 | | (167) | |
| Southern Company Gas | 500 | | | 1.75% | 1-month LIBOR + 0.38% | January 2031 | | (87) | |
| Southern Company | $ | 2,250 | | | | | | | $ | (311) | |
For cash flow hedges of interest rate derivatives, the estimated pre-tax gains (losses) expected to be reclassified from accumulated OCI to interest expense for the 12-month period ending September 30, 2023 are $(17) million for Southern Company and immaterial for the other Registrants. Deferred gains and losses related to interest rate derivatives are expected to be amortized into earnings through 2052 for Southern Company, Alabama Power, and Georgia Power, 2028 for Mississippi Power, and 2046 for Southern Company Gas.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Foreign Currency Derivatives
Southern Company and certain subsidiaries, including Southern Power, may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and on the same income statement line as the earnings effect of the hedged transactions, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. 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, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Southern Company has elected to exclude the cross-currency basis spread from the assessment of effectiveness in the fair value hedges of its foreign currency risk and record any difference between the change in the fair value of the excluded components and the amounts recognized in earnings as a component of OCI.
At September 30, 2022, the following foreign currency derivatives were outstanding:
| | | | | | | | | | | | | | | | | | | | |
| Pay Notional | Pay
Rate | Receive Notional | Receive
Rate | Hedge
Maturity Date | Fair Value Gain (Loss) at September 30, 2022 |
| (in millions) | | (in millions) | | | (in millions) |
| Cash Flow Hedges of Existing Debt | | | | | |
| Southern Power | $ | 564 | | 3.78% | € | 500 | | 1.85% | June 2026 | $ | (80) | |
| | | | | | |
| Fair Value Hedges of Existing Debt | | | | | |
| | | | | | |
| Southern Company parent | 1,476 | | 3.39% | 1,250 | | 1.88% | September 2027 | (243) | |
| | | | | | |
| | | | | | |
| Southern Company | $ | 2,040 | | | € | 1,750 | | | | $ | (323) | |
For cash flow hedges of foreign currency derivatives, the estimated pre-tax losses expected to be reclassified from accumulated OCI to earnings for the 12-month period ending September 30, 2023 are $12 million for Southern Power.
Derivative Financial Statement Presentation and Amounts
The Registrants 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 sheets 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:
| | | | | | | | | | | | | | |
| At September 30, 2022 | At December 31, 2021 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| (in millions) | (in millions) |
| Southern Company | | | | |
| Energy-related derivatives designated as hedging instruments for regulatory purposes | | | | |
| | | | |
| Assets from risk management activities/Other current liabilities | $ | 299 | | $ | 70 | | $ | 129 | | $ | 30 | |
| Other deferred charges and assets/Other deferred credits and liabilities | 150 | | 59 | | 72 | | 6 | |
| | | | |
| | | | |
| Total derivatives designated as hedging instruments for regulatory purposes | 449 | | 129 | | 201 | | 36 | |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Energy-related derivatives: | | | | |
| Assets from risk management activities/Other current liabilities | 27 | | 13 | | 7 | | 5 | |
| Other deferred charges and assets/Other deferred credits and liabilities | 7 | | 1 | | 1 | | — | |
| Interest rate derivatives: | | | | |
| Assets from risk management activities/Other current liabilities | — | | 44 | | 19 | | — | |
| Other deferred charges and assets/Other deferred credits and liabilities | — | | 266 | | — | | 29 | |
| Foreign currency derivatives: | | | | |
| Assets from risk management activities/Other current liabilities | — | | 37 | | — | | 39 | |
| Other deferred charges and assets/Other deferred credits and liabilities | — | | 285 | | — | | 40 | |
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | 34 | | 646 | | 27 | | 113 | |
| Energy-related derivatives not designated as hedging instruments | | | | |
| | | | |
| Assets from risk management activities/Other current liabilities | 19 | | 18 | | 9 | | 4 | |
| Other deferred charges and assets/Other deferred credits and liabilities | 2 | | 1 | | 1 | | — | |
| | | | |
| Total derivatives not designated as hedging instruments | 21 | | 19 | | 10 | | 4 | |
| Gross amounts recognized | 504 | | 794 | | 238 | | 153 | |
Gross amounts offset(a) | (113) | | (128) | | (25) | | (28) | |
Net amounts recognized in the Balance Sheets(b) | $ | 391 | | $ | 666 | | $ | 213 | | $ | 125 | |
| | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | |
| At September 30, 2022 | At December 31, 2021 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| (in millions) | (in millions) |
| Alabama Power | | | | |
| Energy-related derivatives designated as hedging instruments for regulatory purposes | | | | |
| | | | |
| Other current assets/Other current liabilities | $ | 90 | | $ | 12 | | $ | 30 | | $ | 9 | |
| Other deferred charges and assets/Other deferred credits and liabilities | 57 | | 23 | | 25 | | 2 | |
| Total derivatives designated as hedging instruments for regulatory purposes | 147 | | 35 | | 55 | | 11 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| Gross amounts offset | (31) | | (31) | | (5) | | (5) | |
| Net amounts recognized in the Balance Sheets | $ | 116 | | $ | 4 | | $ | 50 | | $ | 6 | |
| | | | |
| Georgia Power | | | | |
| Energy-related derivatives designated as hedging instruments for regulatory purposes | | | | |
| | | | |
| Assets from risk management activities/Other current liabilities | $ | 107 | | $ | 28 | | $ | 54 | | $ | 6 | |
| Other deferred charges and assets/Other deferred credits and liabilities | 38 | | 23 | | 21 | | 2 | |
| Total derivatives designated as hedging instruments for regulatory purposes | 145 | | 51 | | 75 | | 8 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| Energy-related derivatives not designated as hedging instruments | | | | |
| | | | |
| Other current assets/Other current liabilities | 1 | | — | | — | | — | |
| | | | |
| Gross amounts recognized | 146 | | 51 | | 75 | | 8 | |
| Gross amounts offset | (41) | | (41) | | (8) | | (8) | |
| Net amounts recognized in the Balance Sheets | $ | 105 | | $ | 10 | | $ | 67 | | $ | — | |
| | | | |
| Mississippi Power | | | | |
| Energy-related derivatives designated as hedging instruments for regulatory purposes | | | | |
| | | | |
| Assets from risk management activities/Other current liabilities | $ | 78 | | $ | 12 | | $ | 30 | | $ | 3 | |
| Other deferred charges and assets/Other deferred credits and liabilities | 55 | | 12 | | 26 | | 2 | |
| Total derivatives designated as hedging instruments for regulatory purposes | 133 | | 24 | | 56 | | 5 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| Gross amounts offset | (20) | | (20) | | (4) | | (4) | |
| Net amounts recognized in the Balance Sheets | $ | 113 | | $ | 4 | | $ | 52 | | $ | 1 | |
| | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | |
| At September 30, 2022 | At December 31, 2021 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| (in millions) | (in millions) |
| Southern Power | | | | |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | — | | $ | 10 | | $ | 2 | | $ | — | |
| Other deferred charges and assets/Other deferred credits and liabilities | 5 | | 1 | | 1 | | — | |
| Foreign currency derivatives: | | | | |
| Other current assets/Other current liabilities | — | | 12 | | — | | 16 | |
| Other deferred charges and assets/Other deferred credits and liabilities | — | | 68 | | — | | — | |
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | 5 | | 91 | | 3 | | 16 | |
| Energy-related derivatives not designated as hedging instruments | | | | |
| | | | |
| Other current assets/Other current liabilities | 2 | | 2 | | 1 | | — | |
| | | | |
| | | | |
| | | | |
| | | | |
| Gross amounts recognized | 7 | | 93 | | 4 | | 16 | |
| Gross amounts offset | (3) | | (3) | | — | | — | |
| Net amounts recognized in the Balance Sheets | $ | 4 | | $ | 90 | | $ | 4 | | $ | 16 | |
| | | | |
| Southern Company Gas | | | | |
| Energy-related derivatives designated as hedging instruments for regulatory purposes | | | | |
| | | | |
| Other current assets/Other current liabilities | $ | 24 | | $ | 17 | | $ | 15 | | $ | 12 | |
| | | | |
| | | | |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | 26 | | 3 | | 5 | | 5 | |
| Other deferred charges and assets/Other deferred credits and liabilities | 3 | | — | | — | | — | |
| Interest rate derivatives: | | | | |
| Other current assets/Other current liabilities | — | | 13 | | 6 | | — | |
| Other deferred charges and assets/Other deferred credits and liabilities | — | | 74 | | — | | 6 | |
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | 29 | | 90 | | 11 | | 11 | |
| Energy-related derivatives not designated as hedging instruments | | | | |
| | | | |
| Other current assets/Other current liabilities | 16 | | 16 | | 8 | | 4 | |
| Other deferred charges and assets/Other deferred credits and liabilities | 2 | | 1 | | 1 | | — | |
| | | | |
| Total derivatives not designated as hedging instruments | 18 | | 17 | | 9 | | 4 | |
| Gross amounts recognized | 71 | | 124 | | 35 | | 27 | |
Gross amounts offset(a) | (18) | | (33) | | (8) | | (11) | |
Net amounts recognized in the Balance Sheets(b) | $ | 53 | | $ | 91 | | $ | 27 | | $ | 16 | |
(a)Gross amounts offset includes cash collateral held on deposit in broker margin accounts of $15 million and $3 million at September 30, 2022 and December 31, 2021, respectively.
(b)Net amounts of derivative instruments outstanding exclude immaterial premium and intrinsic value associated with weather derivatives for all periods presented.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Energy-related derivatives not designated as hedging instruments were immaterial for Alabama Power and Mississippi Power at September 30, 2022. There were no such instruments for the traditional electric operating companies at December 31, 2021.
At September 30, 2022 and December 31, 2021, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:
| | | | | | | | | | | | | | | | | |
| Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet |
Derivative Category and Balance Sheet
Location | Southern
Company | Alabama
Power | Georgia
Power | Mississippi
Power | Southern Company Gas |
| | (in millions) |
| At September 30, 2022: | | | | | |
| Energy-related derivatives: | | | | | |
| Other regulatory assets, current | $ | (17) | | $ | (2) | | $ | (8) | | $ | (3) | | $ | (4) | |
| Other regulatory assets, deferred | (6) | | (2) | | (3) | | (1) | | — | |
| | | | | |
| | | | | |
| Other regulatory liabilities, current | 246 | | 80 | | 87 | | 69 | | 10 | |
| Other regulatory liabilities, deferred | 98 | | 36 | | 18 | | 44 | | — | |
| Total energy-related derivative gains (losses) | $ | 321 | | $ | 112 | | $ | 94 | | $ | 109 | | $ | 6 | |
| | | | | |
| At December 31, 2021: | | | | | |
| Energy-related derivatives: | | | | | |
| Other regulatory assets, current | $ | (17) | | $ | (6) | | $ | — | | $ | — | | $ | (11) | |
| | | | | |
| Other regulatory liabilities, current | 107 | | 28 | | 48 | | 27 | | 4 | |
| Other regulatory liabilities, deferred | 65 | | 22 | | 19 | | 24 | | — | |
| Total energy-related derivative gains (losses) | $ | 155 | | $ | 44 | | $ | 67 | | $ | 51 | | $ | (7) | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
For the three and nine months ended September 30, 2022 and 2021, the pre-tax effects of cash flow and fair value 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, |
| 2022 | 2021 | 2022 | 2021 |
| (in millions) | (in millions) |
| Southern Company | | | | |
| Cash flow hedges: | | | | |
| Energy-related derivatives | $ | 11 | | $ | 38 | | $ | 51 | | $ | 59 | |
| Interest rate derivatives | 6 | | 5 | | 36 | | 7 | |
| Foreign currency derivatives | (35) | | (36) | | (137) | | (79) | |
Fair value hedges(*): | | | | |
| Foreign currency derivatives | 20 | | (4) | | 18 | | (4) | |
| Total | $ | 2 | | $ | 3 | | $ | (32) | | $ | (17) | |
| | | | |
| | | | |
| Georgia Power | | | | |
| | | | |
| Interest rate derivatives | $ | — | | $ | — | | $ | 31 | | $ | — | |
| | | | |
| | | | |
| | | | |
| Southern Power | | | | |
| Cash flow hedges: | | | | |
| Energy-related derivatives | $ | (11) | | $ | 8 | | $ | (4) | | $ | 16 | |
| | | | |
| Foreign currency derivatives | (35) | | (36) | | (137) | | (79) | |
| Total | $ | (46) | | $ | (28) | | $ | (141) | | $ | (63) | |
| Southern Company Gas | | | | |
| Cash flow hedges: | | | | |
| Energy-related derivatives | $ | 22 | | $ | 30 | | $ | 55 | | $ | 43 | |
| Interest rate derivatives | 5 | | — | | — | | — | |
| Total | $ | 27 | | $ | 30 | | $ | 55 | | $ | 43 | |
(*)Represents amounts excluded from the assessment of effectiveness for which the difference between changes in fair value and periodic amortization is recorded in OCI.
For the three and nine months ended September 30, 2022 and 2021, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments on accumulated OCI were immaterial for the other Registrants.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
For the three and nine months ended September 30, 2022 and 2021, 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, |
|
| 2022 | 2021 | 2022 | 2021 |
| (in millions) | (in millions) |
| Southern Company | | | | |
| Total cost of natural gas | $ | 294 | | $ | 129 | | $ | 1,840 | | $ | 943 | |
Gain (loss) on energy-related cash flow hedges(a) | 9 | | 2 | | 28 | | — | |
| Total depreciation and amortization | 922 | | 896 | | 2,728 | | 2,658 | |
Gain (loss) on energy-related cash flow hedges(a) | (1) | | 3 | | 5 | | 6 | |
| Total interest expense, net of amounts capitalized | (511) | | (451) | | (1,461) | | (1,352) | |
Gain (loss) on interest rate cash flow hedges(a) | (7) | | (7) | | (19) | | (20) | |
Gain (loss) on foreign currency cash flow hedges(a) | (3) | | (6) | | (16) | | (18) | |
Gain (loss) on interest rate fair value hedges(b) | (102) | | (4) | | (300) | | (16) | |
| Total other income (expense), net | 132 | | 131 | | 414 | | 290 | |
Gain (loss) on foreign currency cash flow hedges(a)(c) | (32) | | (34) | | (129) | | (76) | |
| Gain (loss) on foreign currency fair value hedges | (59) | | (32) | | (180) | | (32) | |
| Amount excluded from effectiveness testing recognized in earnings | (21) | | 4 | | (17) | | 4 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| Southern Power | | | | |
| Total depreciation and amortization | $ | 133 | | $ | 132 | | $ | 384 | | $ | 383 | |
Gain (loss) on energy-related cash flow hedges(a) | (1) | | 3 | | 5 | | 6 | |
| Total interest expense, net of amounts capitalized | (32) | | (36) | | (105) | | (111) | |
Gain (loss) on foreign currency cash flow hedges(a) | (3) | | (6) | | (16) | | (18) | |
| Total other income (expense), net | 3 | | 2 | | 5 | | 10 | |
Gain (loss) on foreign currency cash flow hedges(a)(c) | (32) | | (34) | | (129) | | (76) | |
| Southern Company Gas | | | | |
| Total cost of natural gas | $ | 294 | | $ | 129 | | $ | 1,840 | | $ | 943 | |
Gain (loss) on energy-related cash flow hedges(a) | 9 | | 2 | | 28 | | — | |
| Total interest expense, net of amounts capitalized | (65) | | (57) | | (187) | | (175) | |
Gain (loss) on interest rate cash flow hedges(a) | (2) | | (1) | | (3) | | (2) | |
Gain (loss) on interest rate fair value hedges(b) | (30) | | — | | (87) | | 2 | |
(a)Reclassified from accumulated OCI into earnings.
(b)For fair value hedges, changes in the fair value of the derivative contracts are generally equal to changes in the fair value of the underlying debt and have no material impact on income.
(c)The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes.
For the three and nine months ended September 30, 2022 and 2021, the pre-tax effects of cash flow hedge accounting on income for interest rate derivatives were immaterial for Alabama Power, Georgia Power, and Mississippi Power.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
At September 30, 2022 and December 31, 2021, 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 | At September 30, 2022 | At December 31, 2021 | | At September 30, 2022 | At December 31, 2021 |
| (in millions) | | (in millions) |
| Southern Company | | | | | |
| | | | | |
| Long-term debt | $ | (2,788) | | $ | (3,280) | | | $ | 306 | | $ | 9 | |
| | | | | |
| Southern Company Gas | | | | | |
| | | | | |
| Long-term debt | $ | (411) | | $ | (493) | | | $ | 86 | | $ | 2 | |
For the three and nine months ended September 30, 2022 and 2021, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income of Southern Company and Southern Company Gas were as follows:
| | | | | | | | | | | | | | | | | | | | |
| | Gain (Loss) |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| Derivatives in Non-Designated Hedging Relationships | Statements of Income Location | 2022 | 2021 | | 2022 | 2021 |
| | (in millions) | | (in millions) |
| | | | | | |
| Energy-related derivatives: | Natural gas revenues(*) | $ | 3 | | $ | (2) | | | $ | (10) | | $ | (122) | |
| Cost of natural gas | (2) | | 20 | | | (7) | | 36 | |
| | | | | | |
| Total derivatives in non-designated hedging relationships | $ | 1 | | $ | 18 | | | $ | (17) | | $ | (86) | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | |
(*)Excludes immaterial gains (losses) recorded in natural gas revenues associated with weather derivatives for all periods presented.
For the three and nine months ended September 30, 2022 and 2021, the pre-tax effects of energy-related derivatives not designated as hedging instruments were immaterial for the other Registrants.
Contingent Features
The Registrants 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. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. At September 30, 2022, the Registrants had no collateral posted with derivative counterparties to satisfy these arrangements.
For Southern Company and Southern Power, 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, were $156 million and $38 million, respectively at September 30, 2022. For the traditional electric operating companies and Southern Power, 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 at September 30, 2022. 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, Inc., Gulf Power continued participating in the Southern Company power pool through July 13, 2022.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Alabama Power and Southern Power maintain accounts with certain regional transmission organizations to facilitate financial derivative transactions and they may be required to post collateral based on the value of the positions in these accounts and the associated margin requirements. At September 30, 2022, cash collateral posted in these accounts was immaterial. Southern Company Gas maintains accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Southern Company Gas may be required to deposit cash into these accounts. At September 30, 2022, cash collateral held on deposit in broker margin accounts was $15 million.
The Registrants are exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Registrants only enter into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Registrants have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate their exposure to counterparty credit risk.
Southern Company Gas uses established credit policies to determine and monitor the creditworthiness of counterparties, including requirements to post collateral or other credit security, as well as the quality of pledged collateral. Collateral or credit security is most often in the form of cash or letters of credit from an investment-grade financial institution, but may also include cash or U.S. government securities held by a trustee. Prior to entering a physical transaction, Southern Company Gas assigns its counterparties an internal credit rating and credit limit based on the counterparties' Moody's, S&P, and Fitch ratings, commercially available credit reports, and audited financial statements. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.
Southern Company Gas utilizes netting agreements whenever possible to mitigate exposure to counterparty credit risk. Netting agreements enable Southern Company Gas to net certain assets and liabilities by counterparty across product lines and against cash collateral, provided the netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, counterparties are settled net, they are recorded on a gross basis on the balance sheet as energy marketing receivables and energy marketing payables.
The Registrants do not anticipate a material adverse effect on their respective financial statements as a result of counterparty nonperformance.
(K) ACQUISITIONS AND DISPOSITIONS
See Note 15 to the financial statements in Item 8 of the Form 10-K for additional information.
Alabama Power
On September 30, 2022, Alabama Power completed its acquisition of the Calhoun Generating Station, which was accounted for as an asset acquisition. The total purchase price was $179 million, of which $171 million was related to net assets recorded within property, plant, and equipment on the balance sheet and the remainder primarily related to fossil fuel stock and materials and supplies. See Note (B) and Note 15 to the financial statements in Item 8 of the Form 10-K under "Alabama Power" for additional information.
Southern Power
Construction Projects
During the nine months ended September 30, 2022, Southern Power completed construction of and placed in service the remaining 40 MWs of the Tranquillity battery energy storage facility and the remaining 15 MWs of the Garland battery energy storage facility.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | | | | |
| Project Facility | Resource | Approximate Nameplate Capacity (MW) | Location | COD | PPA Contract Period |
| Projects Completed During the Nine Months Ended September 30, 2022 |
Garland Solar Storage(a) | Battery energy storage system | 88 | Kern County, CA | September 2021 through February 2022(b) | 20 years |
Tranquillity Solar Storage(a) | Battery energy storage system | 72 | Fresno County, CA | November 2021 through March 2022(c) | 20 years |
(a)Southern Power consolidates each project's operating results in its financial statements and the tax equity partner and two other partners each own a noncontrolling interest.
(b)The facility has a total capacity of 88 MWs, of which 73 MWs were placed in service in 2021 and 15 MWs were placed in service in February 2022.
(c)The facility has a total capacity of 72 MWs, of which 32 MWs were placed in service in 2021 and 40 MWs were placed in service in March 2022.
Southern Company Gas
Sale of Natural Gas Storage Facilities
On September 7, 2022, certain affiliates of Southern Company Gas entered into agreements to sell two natural gas storage facilities located in California and Texas for an aggregate purchase price of $186 million, plus working capital and certain other adjustments. Completion of the sales is subject to material closing conditions, including, among others, release of a Southern Company Gas parent guarantee, approval from the California Public Utility Commission without a material burdensome condition, and the expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. The parent guarantee release was executed on October 20, 2022, which resolved a material closing condition. As a result, Southern Company Gas expects to record pre-tax impairment charges totaling approximately $125 million ($95 million after tax) in the fourth quarter 2022. The sale of the Texas facility is expected to be completed later in the fourth quarter 2022, and the sale of the California facility is expected to be completed during 2023; however, the ultimate outcome of these matters cannot be determined at this time.
Sale of Pivotal LNG
On May 20, 2022, Southern Company Gas received the final $5 million contingent payment from Dominion Modular LNG Holdings, Inc. in connection with third quarter 2017 estimated tax payments. If the suspensionits 2020 sale of Pivotal LNG, Inc.
(L) SEGMENT AND RELATED INFORMATION
Southern Company
The primary businesses of the Kemper IGCC start-up activities ultimately resultsSouthern 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 traditional electric operating companies are vertically integrated utilities providing electric service in an abandonment for income tax purposes, the related deduction would be claimedthree Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy and battery energy storage projects, and sells electricity at market-based rates in the yearwholesale market. Southern Company Gas distributes natural gas through its natural gas distribution utilities and is involved in several other complementary businesses including gas pipeline investments and gas marketing services. Prior to the sale of Sequent on July 1, 2021, Southern Company Gas' other businesses also included wholesale gas services.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Southern Company's reportable business segments are the sale of electricity by the traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Company Gas. Revenues from sales by Southern Power to the traditional electric operating companies were $336 million and $673 million for the three and nine months ended September 30, 2022, respectively, and $167 million and $361 million for the three and nine months ended September 30, 2021, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies were immaterial for all periods presented. Revenues from sales of natural gas from Southern Company Gas (prior to its sale of Sequent) to Southern Power were $18 million for the nine months ended September 30, 2021. 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 distributed energy and resilience solutions and deploying microgrids for commercial, industrial, governmental, and utility customers, as well as investments in telecommunications and, for the three and nine months ended September 30, 2021, leveraged lease projects. All other inter-segment revenues are not material.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Financial data for business segments and products and services for the three and nine months ended September 30, 2022 and 2021 was as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Electric Utilities | | | | |
| Traditional
Electric Operating
Companies | Southern
Power | Eliminations | Total | Southern Company Gas | All
Other | Eliminations | Consolidated |
| (in millions) |
| Three Months Ended September 30, 2022 | | | | | | | |
| Operating revenues | $ | 6,938 | | $ | 1,180 | | $ | (691) | | $ | 7,427 | | $ | 857 | | $ | 135 | | $ | (41) | | $ | 8,378 | |
Segment net income (loss)(a)(b) | 1,445 | | 95 | | — | | 1,540 | | 83 | | (152) | | 1 | | 1,472 | |
| Nine Months Ended September 30, 2022 | | | | | | | |
| Operating revenues | $ | 16,716 | | $ | 2,618 | | $ | (1,391) | | $ | 17,943 | | $ | 3,998 | | $ | 418 | | $ | (127) | | $ | 22,232 | |
Segment net income (loss)(a)(b) | 3,256 | | 265 | | — | | 3,521 | | 516 | | (415) | | (11) | | 3,611 | |
| At September 30, 2022 | | | | | | | | |
| Goodwill | $ | — | | $ | 2 | | $ | — | | $ | 2 | | $ | 5,015 | | $ | 263 | | $ | — | | $ | 5,280 | |
| Total assets | 95,659 | | 13,283 | | (748) | | 108,194 | | 24,097 | | 2,372 | | (658) | | 134,005 | |
| Three Months Ended September 30, 2021 | | | | | | | |
| Operating revenues | $ | 5,018 | | $ | 679 | | $ | (170) | | $ | 5,527 | | $ | 623 | | $ | 124 | | $ | (36) | | $ | 6,238 | |
Segment net income (loss)(a)(b)(c) | 1,085 | | 78 | | — | | 1,163 | | 56 | | (121) | | 3 | | 1,101 | |
| Nine Months Ended September 30, 2021 | | | | | | | |
| Operating revenues | $ | 12,813 | | $ | 1,610 | | $ | (372) | | $ | 14,051 | | $ | 2,994 | | $ | 412 | | $ | (111) | | $ | 17,346 | |
Segment net income (loss)(a)(b)(c)(d)(e) | 2,352 | | 211 | | — | | 2,563 | | 389 | | (338) | | (6) | | 2,608 | |
| At December 31, 2021 | | | | | | | | |
| Goodwill | $ | — | | $ | 2 | | $ | — | | $ | 2 | | $ | 5,015 | | $ | 263 | | $ | — | | $ | 5,280 | |
| Total assets | 89,051 | | 13,390 | | (667) | | 101,774 | | 23,560 | | 2,975 | | (775) | | 127,534 | |
(a)Attributable to Southern Company.
(b)For the traditional electric operating companies, includes pre-tax charges (credits) to income at Georgia Power for the estimated probable loss associated with the construction of Plant Vogtle Units 3 and 4 of $(70) million ($(52) million after tax) and $(18) million ($(13) million after tax) for the three and nine months ended September 30, 2022, respectively, and $264 million ($197 million after tax) and $772 million ($576 million after tax) for the three and nine months ended September 30, 2021, respectively. See Note (B) and Note 2 to the financial statements in Item 8 of the abandonment. See Note (G)Form 10-K under "Georgia Power – Nuclear Construction" for additional information.
(c)For Southern Company Gas, includes a pre-tax gain of $121 million ($93 million after tax) related to its sale of Sequent, as well as the resulting $85 million of additional tax expense as a result of the sale. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
(d)For Southern Power, includes gains on wind turbine equipment contributed to various equity method investments totaling approximately $37 million pre-tax ($28 million after tax). See Note 15 to the financial statements under "Southern Power – Development Projects" in Item 8 of the Form 10-K for additional information.
(e)For Southern Company Gas, includes pre-tax impairment charges totaling $84 million ($67 million after tax) related to its equity method investment in the PennEast Pipeline project. See Note 7 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Products and Services
| | | | | | | | | | | | | | |
| | Electric Utilities' Revenues |
| Retail | Wholesale | Other | Total |
| (in millions) |
| Three Months Ended September 30, 2022 | $ | 5,961 | | $ | 1,197 | | $ | 269 | | $ | 7,427 | |
| Three Months Ended September 30, 2021 | 4,551 | | 731 | | 245 | | 5,527 | |
| Nine Months Ended September 30, 2022 | $ | 14,363 | | $ | 2,798 | | $ | 782 | | $ | 17,943 | |
| Nine Months Ended September 30, 2021 | 11,492 | | 1,822 | | 737 | | 14,051 | |
| | | | | | | | | | | | | | | | | |
| | Southern Company Gas' Revenues |
| Gas
Distribution
Operations | Wholesale Gas Services(*) | Gas
Marketing
Services | Other | Total |
| (in millions) |
| Three Months Ended September 30, 2022 | $ | 748 | | $ | — | | $ | 85 | | $ | 24 | | $ | 857 | |
| Three Months Ended September 30, 2021 | 553 | | — | | 52 | | 18 | | 623 | |
| Nine Months Ended September 30, 2022 | $ | 3,513 | | $ | — | | $ | 420 | | $ | 65 | | $ | 3,998 | |
| Nine Months Ended September 30, 2021 | 2,451 | | 188 | | 311 | | 44 | | 2,994 | |
(*)Prior to the sale of Sequent, the revenues for wholesale gas services were netted with costs associated with its energy and risk management activities. See "Southern Company Gas" herein and Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Southern Company Gas
Southern Company Gas manages its business through three reportable segments – gas distribution operations, gas pipeline investments, and gas marketing services. Prior to the sale of Sequent on July 1, 2021, Southern Company Gas' reportable segments also included wholesale gas services. The non-reportable segments are combined and presented as all other. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information on the sale of Sequent.
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 four states.
Gas pipeline investments consists of joint ventures in natural gas pipeline investments including a 50% interest in SNG 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. Gas pipeline investments also includes a 20% ownership interest in the PennEast Pipeline project, which was cancelled in September 2021. See Note 7 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Through July 1, 2021, wholesale gas services provided 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 engaged in natural gas storage and gas pipeline arbitrage and related activities.
Gas marketing services provides natural gas marketing to end-use customers primarily in Georgia and Illinois through SouthStar.
The all other column includes segments and subsidiaries that fall below the quantitative threshold for separate disclosure, including storage and fuels operations. See Note (K) under "Southern Company Gas" for information regarding agreements by certain affiliates of Southern Company Gas to sell two natural gas storage facilities.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Business segment financial data for the three and nine months ended September 30, 2022 and 2021 was as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Gas Distribution Operations | Gas Pipeline Investments | Wholesale Gas Services(a) | Gas Marketing Services | Total | All Other | Eliminations | Consolidated |
| (in millions) |
| Three Months Ended September 30, 2022 | | | | | | |
| Operating revenues | $ | 751 | | $ | 8 | | $ | — | | $ | 85 | | $ | 844 | | $ | 16 | | $ | (3) | | $ | 857 | |
| Segment net income (loss) | 59 | | 24 | | — | | (2) | | 81 | | 2 | | — | | 83 | |
| Nine Months Ended September 30, 2022 | | | | | | |
| Operating revenues | $ | 3,533 | | $ | 24 | | $ | — | | $ | 420 | | $ | 3,977 | | $ | 43 | | $ | (22) | | $ | 3,998 | |
| Segment net income (loss) | 365 | | 76 | | — | | 65 | | 506 | | 10 | | — | | 516 | |
| Total assets at September 30, 2022 | 21,605 | | 1,425 | | — | | 1,595 | | 24,625 | | 9,100 | | (9,628) | | 24,097 | |
| Three Months Ended September 30, 2021 | | | | | | |
| Operating revenues | $ | 556 | | $ | 8 | | $ | — | | $ | 52 | | $ | 616 | | $ | 11 | | $ | (4) | | $ | 623 | |
Segment net income (loss)(b)(c) | 45 | | 10 | | 94 | | (2) | | 147 | | (91) | | — | | 56 | |
| Nine Months Ended September 30, 2021 | | | | | | | |
| Operating revenues | $ | 2,466 | | $ | 24 | | $ | 188 | | $ | 311 | | $ | 2,989 | | $ | 29 | | $ | (24) | | $ | 2,994 | |
Segment net income (loss)(b)(c)(d) | 308 | | 3 | | 108 | | 60 | | 479 | | (90) | | — | | 389 | |
| Total assets at December 31, 2021 | 20,917 | | 1,467 | | 31 | | 1,556 | | 23,971 | | 12,114 | | (12,525) | | 23,560 | |
(a)As a result of the sale of Sequent, wholesale gas services is no longer a reportable segment for the three and nine months ended September 30, 2022. Prior to the sale of Sequent, the revenues for wholesale gas services were 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) |
| | | | | |
| | | | | |
| | | | | |
| Nine Months Ended September 30, 2021 | $ | 3,881 | | $ | 90 | | $ | 3,971 | | $ | 3,783 | | $ | 188 | |
(b)For wholesale gas services, includes a pre-tax gain of $121 million ($93 million after tax) related to the sale of Sequent. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
(c)For the "All Other" column, includes $85 million of additional tax expense as a result of the sale. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
(d)For gas pipeline investments, includes pre-tax impairment charges totaling $84 million ($67 million after tax) related to the equity method investment in the PennEast Pipeline project. See Note 7 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.
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| Combined Management's Discussion and Analysis of Financial Condition and Results of Operations | |
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The following Management's Discussion and Analysis of Financial Condition and Results of Operations is a combined presentation; however, information contained herein relating to any individual Registrant is filed by such Registrant on its own behalf and each Registrant makes no representation as to information related to the other Registrants.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
OVERVIEW
Southern Company is a holding company that owns all of the common stock of three traditional electric operating companies (Alabama Power, Georgia Power, and Mississippi Power), Southern Power, and Southern Company Gas and owns other direct and indirect subsidiaries. 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. Southern Company's reportable segments are the sale of electricity by the traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Company Gas. Southern Company Gas' reportable segments are gas distribution operations, gas pipeline investments, and gas marketing services. Prior to the sale of Sequent on July 1, 2021, Southern Company Gas' reportable segments also included wholesale gas services. See Note (L) to the Condensed Financial Statements herein for additional information on segment reporting. For additional information on the Registrants' primary business activities and the sale of Sequent, see BUSINESS – "The Southern Company System" in Item 1 of the Form 10-K and Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K, respectively.
The Registrants continue to focus on several key performance indicators. For the traditional electric operating companies and Southern Company Gas, these indicators include, but are not limited to, customer satisfaction, plant availability, electric and natural gas system reliability, and execution of major construction projects. For Southern Power, these indicators include, but are not limited to, the equivalent forced outage rate and contract availability to evaluate operating results and help ensure its ability to meet its contractual commitments to customers. In addition, Southern Company and the Subsidiary Registrants focus on earnings per share and net income, respectively, as a key performance indicator.
Recent Developments
Alabama Power
On July 12, 2022, the Alabama PSC approved the following items:
•Alabama Power's petition for a certificate of convenience and necessity authorizing Alabama Power to complete the acquisition of the Calhoun Generating Station. The transaction closed on September 30, 2022 and, on October 3, 2022, Alabama Power filed Rate CNP New Plant with the Alabama PSC to recover the related costs. The filing reflected an increase in annual revenues of $34 million, or 0.6%, effective with the billing month of November 2022.
•An increase to Rate ECR effective with August 2022 billings, which is expected to result in an increase of approximately $310 million annually. The approved increase in the Rate ECR factor has no significant effect on Alabama Power's net income, but does increase operating cash flows related to fuel cost recovery.
•Modifications to Rate NDR.
•An accounting order authorizing Alabama Power to create a reliability reserve separate from the NDR and transition the previous Rate NDR authority related to reliability expenditures to the reliability reserve. Alabama Power may make accruals to the reliability reserve if the NDR balance exceeds $35 million.
See Note (B) to the Condensed Financial Statements under "Alabama Power" herein for additional information.
On September 23, 2022, the FERC authorized Alabama Power to use updated depreciation rates from its 2021 depreciation study effective January 1, 2023. The study was also provided to the Alabama PSC, and the new depreciation rates will be reflected in Alabama Power's future rate filings. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Alabama Power" herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Georgia Power
Plant Vogtle Units 3 and 4 Construction and Start-Up Status
Construction continues on Plant Vogtle Units 3 and 4 (with electric generating capacity of approximately 1,100 MWs each), in which Georgia Power currently holds a 45.7% ownership interest. Georgia Power's share of the total project capital cost forecast to complete Plant Vogtle Units 3 and 4, including contingency, through the end of the first quarter 2023 and the fourth quarter 2023, respectively, is $10.4 billion.
On July 29, 2022, Southern Nuclear announced that all Unit 3 ITAACs had been submitted to the NRC. On August 3, 2022, the NRC published its 103(g) finding that the acceptance criteria in the combined license for Unit 3 had been met, which allowed nuclear fuel to be loaded and allows start-up testing to begin. Fuel load for Unit 3 was completed on October 17, 2022, and the unit is projected to be placed in service by the end of the first quarter 2023. The projected schedule for Unit 3 primarily depends on the pace of system and area transitions to operations, including the completion of closure documentation necessary to support start-up testing, and the progression of start-up, final component, and pre-operational testing, which may be impacted by equipment or other operational failures. Unit 4 is projected to be placed in service by the end of the fourth quarter 2023. The projected schedule for Unit 4 primarily depends on Unit 3 progress through start-up and testing; overall construction productivity and production levels improving, particularly in electrical installation, including terminations; and appropriate levels of craft laborers, particularly electricians, being added and maintained. Any further delays could result in later in-service dates and cost increases.
During the first nine months of 2022, established construction contingency totaling $170 million was assigned to the base capital cost forecast for costs primarily associated with construction productivity, the pace of system turnovers, additional craft and support resources, and procurement for Units 3 and 4. Georgia Power also increased its total project capital cost forecast by adding $36 million and $32 million to replenish construction contingency in the second quarter 2022 and the third quarter 2022, respectively. After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded pre-tax charges to income in the second quarter 2022 and the third quarter 2022 of $36 million ($27 million after tax) and $32 million ($24 million after tax), respectively, for the increases in the total project capital cost forecast. Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery during the prudence review following the Unit 4 fuel load pursuant to the twenty-fourth VCM stipulation described in Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction – Regulatory Matters" herein.
Georgia Power and the other Vogtle Owners do not agree on the starting dollar amount for the determination of cost increases subject to the cost-sharing and tender provisions of the Global Amendments (as defined in Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction – Joint Owner Contracts" herein). The other Vogtle Owners have notified Georgia Power that they believe the current capital cost expenditures have already exceeded the cost-sharing thresholds and the current project capital cost forecast triggers the tender provisions under the Global Amendments.
On June 17, 2022 and July 26, 2022, OPC and Dalton, respectively, notified Georgia Power of their purported exercises of their tender options. On June 18, 2022, OPC and MEAG Power each filed a separate lawsuit against Georgia Power in the Superior Court of Fulton County, Georgia seeking a declaratory judgment that the starting dollar amount is $17.1 billion and that the cost-sharing and tender provisions have been triggered. On July 25, 2022 and July 28, 2022, Georgia Power filed its answers in the lawsuits filed by MEAG Power and OPC, respectively, and included counterclaims seeking a declaratory judgment that the starting dollar amount is $18.38 billion and that costs related to force majeure events are excluded prior to calculating the cost-sharing and tender provisions and when calculating Georgia Power's related financial obligations. On September 26, 2022, Dalton filed complaints in each of these lawsuits.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
On September 29, 2022, Georgia Power and MEAG Power reached an agreement to resolve their dispute regarding the proper interpretation of the cost-sharing and tender provisions of the Global Amendments. Under the terms of the agreement, among other items, (i) MEAG Power will not exercise its tender option and will retain its full ownership interest in Plant Vogtle Units 3 and 4; (ii) Georgia Power will pay a portion of MEAG Power's costs of construction for Plant Vogtle Units 3 and 4 as such costs are incurred and with no further adjustment for force majeure costs, which payments will total approximately $79 million based on the current project capital cost forecast; and (iii) Georgia Power will pay 20% of MEAG Power's costs of construction with respect to any amounts over the current project capital cost forecast, with no further adjustment for force majeure costs. On October 4, 2022, MEAG Power and Georgia Power filed a notice of settlement and voluntary dismissal of the pending litigation described above, including Georgia Power's counterclaim, and, on October 6, 2022, Dalton dismissed its related complaint. Georgia Power recorded pre-tax charges (credits) to income in the fourth quarter 2021, the second quarter 2022, and the third quarter 2022 of approximately $440 million ($328 million after tax), $16 million ($12 million after tax), and $(102) million ($(76) million after tax), respectively, associated with the cost-sharing and tender provisions of the Global Amendments, including the settlement with MEAG Power, which are included in the total project capital cost forecast. The settlement with MEAG Power does not resolve the separate pending litigation with OPC, including Dalton's associated complaint. Georgia Power may be required to record further pre-tax charges to income of up to approximately $300 million associated with the cost-sharing and tender provisions of the Global Amendments for OPC and Dalton based on the current project capital cost forecast.
The ultimate impact of these matters on the construction schedule and project capital cost forecast for Plant Vogtle Units 3 and 4 cannot be determined at this time. See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information.
2022 Base Rate Case
On June 24, 2022, Georgia Power filed a base rate case (Georgia Power 2022 Base Rate Case) with the Georgia PSC. The filing, as modified on August 22, 2022, proposes a three-year alternate rate plan with requested rate increases totaling $889 million, $107 million, and $45 million effective January 1, 2023, January 1, 2024, and January 1, 2025, respectively. Georgia Power expects the Georgia PSC to render a final decision in this matter on December 20, 2022. The ultimate outcome of this matter cannot be determined at this time.
Section 174 Research and Experimental Deduction
Southern Company, on behalf of Mississippi Power, has reflected deductions for research and experimental (R&E) expenditures related See Note (B) to the Kemper IGCC in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation, resolving a methodology for these deductions. See Note (G)Condensed Financial Statements under "Georgia Power – Rate Plans – 2022 Base Rate Case" herein for additional information.
Integrated Resource Plan
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)On July 21, 2022, the Georgia PSC approved Georgia Power's triennial IRP (2022 IRP), as modified by a stipulated agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors and as further modified by the Georgia PSC. In the 2022 IRP decision, the Georgia PSC approved several requests, including the following:
(UNAUDITED)•Decertification and retirement of Plant Wansley Units 1 and 2 (926 MWs based on 53.5% ownership), which occurred on August 31, 2022, and Plant Scherer Unit 3 (614 MWs based on 75% ownership) by December 31, 2028, as well as the reclassification to regulatory asset accounts of the remaining net book values of these units and any remaining unusable materials and supplies inventories upon retirement.
•Decertification and retirement of Plant Gaston Units 1 through 4 (500 MWs based on 50% ownership through SEGCO) by December 31, 2028. See Note 7 to the financial statements under "SEGCO" in Item 8 of the Form 10-K for additional information.
•Georgia Power's environmental compliance strategy, including approval of Georgia Power's plans to address CCR at its ash ponds and landfills.
The Georgia PSC deferred a decision on the requested decertification and retirement of Plant Bowen Units 1 and 2 (1,400 MWs) to the 2025 IRP.
See Note (B) to the Condensed Financial Statements under "Georgia Power – Integrated Resource Plans" herein for additional information.
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(C) | FAIR VALUE MEASUREMENTS |
As
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Mississippi Power
On June 7, 2022, the Mississippi PSC approved Mississippi Power's annual retail PEP filing for 2022, resulting in an annual increase in revenues of approximately $18 million, or 1.9%. The rate increase became effective with the first billing cycle of April 2022 in accordance with the PEP rate schedule.
On August 26, 2022, the FERC accepted an amended shared service agreement (SSA) between Mississippi Power and Cooperative Energy, effective July 1, 2022, under which Cooperative Energy will continue to decrease its use of Mississippi Power's generation services under the MRA tariff up to 2.5% annually through 2035. At September 30, 2017, assets and liabilities measured2022, Mississippi Power is serving approximately 400 MWs of Cooperative Energy's annual demand.Beginning in 2036, Cooperative Energy will provide 100% of its electricity requirements at fair value on a recurring basis during the period, together with their associated level ofMRA delivery points under the fair value hierarchy, were as follows:
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| | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using: | | |
| As of September 30, 2017: | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Net Asset Value as a Practical Expedient (NAV) | | Total |
| | (in millions) |
| Southern Company | | | | | | | | | |
| Assets: | | | | | | | | | |
Energy-related derivatives(a)(b) | $ | 231 |
| | $ | 184 |
| | $ | — |
| | $ | — |
| | $ | 415 |
|
| Interest rate derivatives | — |
| | 5 |
| | — |
| | — |
| | 5 |
|
| Foreign currency derivatives | — |
| | 103 |
| | — |
| | — |
| | 103 |
|
Nuclear decommissioning trusts(c) | 752 |
| | 1,004 |
| | — |
| | 26 |
| | 1,782 |
|
| Cash equivalents | 1,271 |
| | — |
| | — |
| | — |
| | 1,271 |
|
| Other investments | 9 |
| | — |
| | 1 |
| | — |
| | 10 |
|
| Total | $ | 2,263 |
| | $ | 1,296 |
| | $ | 1 |
| | $ | 26 |
| | $ | 3,586 |
|
| Liabilities: | | | | | | | | | |
Energy-related derivatives(a)(b) | $ | 265 |
| | $ | 146 |
| | $ | — |
| | $ | — |
| | $ | 411 |
|
| Interest rate derivatives | — |
| | 24 |
| | — |
| | — |
| | 24 |
|
| Foreign currency derivatives | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
| Contingent consideration | — |
| | — |
| | 20 |
| | — |
| | 20 |
|
| Total | $ | 265 |
| | $ | 193 |
| | $ | 20 |
| | $ | — |
| | $ | 478 |
|
| | | | | | | | | | |
| Alabama Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 9 |
| | $ | — |
| | $ | — |
| | $ | 9 |
|
Nuclear decommissioning trusts:(d) | | | | | | | | |
|
|
| Domestic equity | 422 |
| | 81 |
| | — |
| | — |
| | 503 |
|
| Foreign equity | 60 |
| | 57 |
| | — |
| | — |
| | 117 |
|
| U.S. Treasury and government agency securities | — |
| | 27 |
| | — |
| | — |
| | 27 |
|
| Corporate bonds | 19 |
| | 150 |
| | — |
| | — |
| | 169 |
|
| Mortgage and asset backed securities | — |
| | 18 |
| | — |
| | — |
| | 18 |
|
| Private Equity | — |
| | — |
| | — |
| | 26 |
| | 26 |
|
| Other | — |
| | 8 |
| | — |
| | — |
| | 8 |
|
| Cash equivalents | 808 |
| | — |
| | — |
| | — |
| | 808 |
|
| Total | $ | 1,309 |
| | $ | 350 |
| | $ | — |
| | $ | 26 |
| | $ | 1,685 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 7 |
| | $ | — |
| | $ | — |
| | $ | 7 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using: | | |
| As of September 30, 2017: | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Net Asset Value as a Practical Expedient (NAV) | | Total |
| | (in millions) |
| Georgia Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 18 |
| | $ | — |
| | $ | — |
| | $ | 18 |
|
| Interest rate derivatives | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Nuclear decommissioning trusts:(d) (e) | | | | | | | | | |
| Domestic equity | 235 |
| | 1 |
| | — |
| | — |
| | 236 |
|
| Foreign equity | — |
| | 156 |
| | — |
| | — |
| | 156 |
|
| U.S. Treasury and government agency securities | — |
| | 225 |
| | — |
| | — |
| | 225 |
|
| Municipal bonds | — |
| | 64 |
| | — |
| | — |
| | 64 |
|
| Corporate bonds | — |
| | 160 |
| | — |
| | — |
| | 160 |
|
| Mortgage and asset backed securities | — |
| | 38 |
| | — |
| | — |
| | 38 |
|
| Other | 16 |
| | 19 |
| | — |
| | — |
| | 35 |
|
| Cash equivalents | 112 |
| | — |
| | — |
| | — |
| | 112 |
|
| Total | $ | 363 |
| | $ | 682 |
| | $ | — |
| | $ | — |
| | $ | 1,045 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 11 |
| | $ | — |
| | $ | — |
| | $ | 11 |
|
| Interest rate derivatives | — |
| | 3 |
| | — |
| | — |
| | 3 |
|
| Total | $ | — |
| | $ | 14 |
| | $ | — |
| | $ | — |
| | $ | 14 |
|
| | | | | | | | | | |
| Gulf Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Cash equivalents | $ | 21 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 21 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 22 |
| | $ | — |
| | $ | — |
| | $ | 22 |
|
| | | | | | | | | | |
| Mississippi Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 3 |
|
| Interest rate derivatives | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
| Cash equivalents | 209 |
| | — |
| | — |
| | — |
| | 209 |
|
| Total | $ | 209 |
| | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | 214 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 7 |
| | $ | — |
| | $ | — |
| | $ | 7 |
|
| | | | | | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using: | | |
| As of September 30, 2017: | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Net Asset Value as a Practical Expedient (NAV) | | Total |
| | (in millions) |
| Southern Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 9 |
| | $ | — |
| | $ | — |
| | $ | 9 |
|
| Foreign currency derivatives | — |
| | 103 |
| | — |
| | — |
| | 103 |
|
| Cash equivalents | 90 |
| | — |
| | — |
| | — |
| | 90 |
|
| Total | $ | 90 |
| | $ | 112 |
| | $ | — |
| | $ | — |
| | $ | 202 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | 4 |
|
| Foreign currency derivatives | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
| Contingent consideration | — |
| | — |
| | 20 |
| | — |
| | 20 |
|
| Total | $ | — |
|
| $ | 27 |
|
| $ | 20 |
|
| $ | — |
|
| $ | 47 |
|
| | | | | | | | | | |
| Southern Company Gas | | | | | | | | | |
| Assets: | | | | | | | | | |
Energy-related derivatives(a)(b) | $ | 231 |
| | $ | 145 |
| | $ | — |
| | $ | — |
| | $ | 376 |
|
| Liabilities: | | | | | | | | | |
Energy-related derivatives(a)(b) | $ | 265 |
| | $ | 95 |
| | $ | — |
| | $ | — |
| | $ | 360 |
|
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(a) | Excludes $13 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value. |
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(b) | Excludes cash collateral of $76 million. |
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(c) | For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table. |
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(d) | Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. |
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(e) | Includes the investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of September 30, 2017, approximately $66 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan to creditors under the funds' managers' securities lending program. |
Southern Company, Alabama Power, and Georgia Power continue to electtariff. Neither party has the option to fair value investment securities heldcancel the amended SSA. Mississippi Power expects to remarket this capacity, including the potential development of future arrangements with Cooperative Energy.
On July 15, 2022, Mississippi Power filed a request with the FERC for a $23 million increase in annual wholesale base revenues under the nuclear decommissioning trust funds.MRA tariff and requested an effective date of July 15, 2022. Cooperative Energy has filed a complaint with FERC challenging the new rates. On September 13, 2022, the FERC issued an order accepting Mississippi Power's request effective September 14, 2022, subject to refund, and establishing hearing and settlement judge procedures. The fair valueultimate outcome of this matter cannot be determined at this time.
See Note (B) to the funds at Condensed Financial Statements under "Mississippi Power" herein for additional information.
Southern Company, including reinvested interest and dividends and excludingPower
During the funds' expenses, increased by $50 million and $168 million, respectively, for the three and nine months ended September 30, 2017,2022, Southern Power completed construction of and placed in service the remaining 40 MWs of the Tranquillity battery energy storage facility and the remaining 15 MWs of the Garland battery energy storage facility. See Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information.
At September 30, 2022, Southern Power's average investment coverage ratio for its generating assets, including those owned with various partners, based on the ratio of investment under contract to total investment using the respective facilities' net book value (or expected in-service value for facilities under construction) as the investment amount was 95% through 2026 and 92% through 2031, with an average remaining contract duration of approximately 13 years.
Southern Company Gas
On July 1, 2022, Atlanta Gas Light filed its annual GRAM update with the Georgia PSC. The filing requests an annual base rate increase of $53 million based on the projected 12-month period beginning January 1, 2023. Resolution of the GRAM filing is expected by December 28, 2022, with the new rates effective January 1, 2023.
On August 1, 2022, Virginia Natural Gas filed a general base rate case with the Virginia Commission seeking an increase in annual base rate revenues of $69 million, including $15 million related to the recovery of investments under the SAVE program, primarily to recover investments and increased costs associated with infrastructure, technology, and workforce development. The requested increase is based on a projected 12-month period beginning January 1, 2023, a ROE of 10.35%, and an equity ratio of 53.2%. Rate adjustments are expected to be effective January 1, 2023, subject to refund. The Virginia Commission is expected to rule on the requested increase in the third quarter 2023.
On September 7, 2022, certain affiliates of Southern Company Gas entered into agreements to sell two natural gas storage facilities located in California and Texas for an aggregate purchase price of $186 million, plus working capital and certain other adjustments. On October 20, 2022, the release of a Southern Company Gas parent guarantee was executed, which resolved a material closing condition. As a result, Southern Company Gas expects to record pre-tax impairment charges totaling approximately $125 million ($95 million after tax) in the fourth quarter
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
2022. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
The ultimate outcome of these matters cannot be determined at this time.
RESULTS OF OPERATIONS
Southern Company
Net Income
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $371 | | 33.7 | | $1,003 | | 38.5 |
Consolidated net income attributable to Southern Company was $1.5 billion ($1.36 per share) in the third quarter 2022 compared to $1.1 billion ($1.04 per share) for the corresponding period in 2021. Consolidated net income attributable to Southern Company was $3.6 billion ($3.38 per share) for year-to-date 2022 compared to $2.6 billion ($2.46 per share) for the corresponding period in 2021. The increases were primarily due to decreases of $249 million and $589 million in the third quarter and year-to-date 2022, respectively, in after-tax charges related to the construction of Plant Vogtle Units 3 and 4, increases in retail electric revenues associated with rates and pricing, warmer weather, and sales growth, and increases in natural gas revenues from base rate increases and continued infrastructure replacement, partially offset by higher non-fuel operations and maintenance costs. The increase for year-to-date 2022 also reflects after-tax charges totaling $67 million in 2021 related to the PennEast Pipeline project at Southern Company Gas.
See Note (B) to the Condensed Financial Statements herein and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4 and Note 7 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information on the PennEast Pipeline project.
Retail Electric Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1,410 | | 31.0 | | $2,871 | | 25.0 |
In the third quarter 2022, retail electric revenues were $6.0 billion compared to $4.6 billion for the corresponding period in 2021. For year-to-date 2022, retail electric revenues were $14.4 billion compared to $11.5 billion for the corresponding period in 2021.
Details of the changes in retail electric revenues were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Third Quarter 2022 | | Year-To-Date 2022 |
| (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail electric – prior year | $ | 4,551 | | | | | $ | 11,492 | | | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 165 | | | 3.6 | % | | 458 | | | 4.0 | % |
| Sales growth | 73 | | | 1.6 | | | 158 | | | 1.4 | |
| Weather | 26 | | | 0.6 | | | 188 | | | 1.6 | |
| Fuel and other cost recovery | 1,146 | | | 25.2 | | | 2,067 | | | 18.0 | |
| Retail electric – current year | $ | 5,961 | | | 31.0 | % | | $ | 14,363 | | | 25.0 | % |
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2022 when compared to the corresponding periods in 2021. The increases were primarily due to higher contributions from commercial and industrial customers with variable demand-driven pricing, base tariff increases in accordance with Georgia Power's 2019 ARP, and pricing effects associated with customer usage. See Note 2 to the financial statements under "Georgia Power – Rate Plans" in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales increased in the third quarter and year-to-date 2022 when compared to the corresponding periods in 2021. Weather-adjusted residential KWH sales increased 1.3% and 0.4% in the third quarter and year-to-date 2022, respectively, and weather-adjusted commercial KWH sales increased 2.0% in both the third quarter and year-to-date 2022 when compared to the corresponding periods in 2021 primarily due to customer growth. In addition, commercial customer usage increased in the third quarter and year-to-date 2022 and residential customer usage decreased for year-to-date 2022 when compared to the corresponding periods in 2021 as customers return to pre-pandemic levels of activity outside the home. Industrial KWH sales increased 2.2% and 2.6% in the third quarter and year-to-date 2022, respectively, when compared to the corresponding periods in 2021 primarily due to increases in the pipeline and paper sectors, partially offset by a decrease in the chemicals sector.
Fuel and other cost recovery revenues increased $1.1 billion and $2.1 billion in the third quarter and year-to-date 2022, respectively, compared to the corresponding periods in 2021 primarily due to higher fuel and purchased power costs and an increase in the volume of KWHs generated. 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. 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.
Wholesale Electric Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $466 | | 63.7 | | $976 | | 53.6 |
In the third quarter 2022, wholesale electric revenues were $1.2 billion compared to $731 million for the corresponding period in 2021. For year-to-date 2022, wholesale electric revenues were $2.8 billion compared to $1.8 billion for the corresponding period in 2021. The increases were primarily due to increases of $437 million and $930 million in the third quarter and year-to-date 2022, respectively, in energy revenues as a result of fuel and purchased power price increases when compared to the corresponding periods in 2021, an increase in the volume of KWHs sold primarily associated with natural gas PPAs at Southern Power, and increased opportunity sales at Alabama Power due to warmer weather.
Wholesale electric revenues consist of revenues from PPAs and short-term opportunity sales. Wholesale electric revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues generally represent the greatest contribution to net income and are designed to provide recovery of fixed costs plus a return on investment. Energy revenues will vary depending on fuel prices, the market prices of wholesale energy compared to the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Energy sales from solar and wind PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or through a fixed price related to the energy. As a result, the ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors. Wholesale electric revenues at Mississippi Power include FERC-regulated municipal and rural association sales
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
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.
Other Electric Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $6 | | 3.4 | | $29 | | 5.5 |
In the third quarter 2022, other electric revenues were $185 million compared to $179 million for the corresponding period in 2021. The increase was primarily due to increases of $14 million in transmission revenues primarily associated with open access transmission tariff sales and $7 million in cogeneration steam revenues associated with higher natural gas prices at Alabama Power, partially offset by a $14 million increase in realized losses associated with price stability products for retail customers on variable demand-driven pricing tariffs at Georgia Power.
For year-to-date 2022, other electric revenues were $554 million compared to $525 million for the corresponding period in 2021. The increase was primarily due to increases of $41 million in transmission revenues primarily associated with open access transmission tariff sales, $15 million in cogeneration steam revenues associated with higher natural gas prices at Alabama Power, and $13 million in outdoor lighting sales at Georgia Power, partially offset by a decrease of $26 million resulting from the termination of a transmission service contract and an increase of $21 million in realized losses associated with price stability products for retail customers on variable demand-driven pricing tariffs, both at Georgia Power.
Natural Gas Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $234 | | 37.6 | | $1,004 | | 33.5 |
In the third quarter 2022, natural gas revenues were $857 million compared to $623 million for the corresponding period in 2021. For year-to-date 2022, natural gas revenues were $4.0 billion compared to $3.0 billion for the corresponding period in 2021.
Details of the changes in natural gas revenues were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 | | Year-To-Date 2022 |
| (in millions) | | (% change) | | (in millions) | | (% change) |
| Natural gas revenues – prior year | $ | 623 | | | | | $ | 2,994 | | | |
| Estimated change resulting from – | | | | | | | |
| Infrastructure replacement programs and base rate changes | 54 | | | 8.7 | % | | 186 | | | 6.2 | % |
| Gas costs and other cost recovery | 172 | | | 27.6 | | | 955 | | | 31.9 | |
| Gas marketing services | 1 | | | 0.2 | | | 14 | | | 0.5 | |
| Wholesale gas services | — | | | — | | | (187) | | | (6.2) | |
| Other | 7 | | | 1.1 | | | 36 | | | 1.1 | |
| Natural gas revenues – current year | $ | 857 | | | 37.6 | % | | $ | 3,998 | | | 33.5 | % |
Revenues from infrastructure replacement programs and base rate changes at the natural gas distribution utilities increased in the third quarter and year-to-date 2022 compared to the corresponding periods in 2021 primarily due to rate increases at Nicor Gas, Atlanta Gas Light, and Chattanooga Gas and continued investment in infrastructure replacement. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Revenues associated with gas costs and other cost recovery increased in the third quarter and year-to-date 2022 compared to the corresponding periods in 2021 primarily due to higher natural gas cost recovery. Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from the natural gas distribution utilities.
Revenues from gas marketing services increased for year-to-date 2022 compared to the corresponding period in 2021 due to higher commodity prices and higher sales to commercial customers.
The changes in year-to-date 2022 revenues related to Southern Company Gas' wholesale gas services were due to the sale of Sequent on July 1, 2021. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Other Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $24 | | 15.6 | | $6 | | 1.2 |
In the third quarter 2022, other revenues were $178 million compared to $154 million for the corresponding period in 2021. The increase was primarily due to a $15 million increase in unregulated sales at the traditional electric operating companies primarily associated with power delivery construction and maintenance projects, energy conservation projects, and lighting. Also contributing to the increase was a $9 million increase primarily related to distributed infrastructure projects at PowerSecure.
For year-to-date 2022, other revenues were $519 million compared to $513 million for the corresponding period in 2021. The increase was primarily due to increases of $10 million in unregulated sales associated with power delivery construction and maintenance projects at Mississippi Power, $9 million in unregulated energy conservation projects at Georgia Power, $8 million in unregulated lighting sales at Alabama Power, and $5 million primarily related to distribution infrastructure projects at PowerSecure, partially offset by a $28 million decrease associated with the timing of revenue recognition for a large, ongoing power delivery construction and maintenance contract at Georgia Power.
Fuel and Purchased Power Expenses
| | | | | | | | | | | | | | | | | | | | | | | |
| | Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | 1,189 | | | 96.4 | | $ | 2,319 | | | 79.1 |
| Purchased power | 357 | | | 124.0 | | 573 | | | 80.5 |
| Total fuel and purchased power expenses | $ | 1,546 | | | | | $ | 2,892 | | | |
In the third quarter 2022, total fuel and purchased power expenses were $3.1 billion compared to $1.5 billion for the corresponding period in 2021. The increase was primarily the result of a $1.2 billion increase in the average cost of fuel and purchased power and a $310 million increase in the volume of KWHs generated and purchased.
For year-to-date 2022, total fuel and purchased power expenses were $6.5 billion compared to $3.6 billion for the corresponding period in 2021. The increase was primarily the result of a $2.4 billion increase in the average cost of fuel and purchased power and a $523 million increase in the volume of KWHs generated and purchased.
Fuel and purchased power energy transactions at the traditional electric operating companies are generally offset by fuel revenues and do not have a significant impact on net income. See Note 2 to the financial statements in Item 8 of the Form 10-K for additional information. Fuel expenses incurred under Southern Power's PPAs are generally the responsibility of the counterparties and do not significantly impact net income.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of the Southern Company system's generation and purchased power were as follows:
| | | | | | | | | | | | | | |
| Third Quarter 2022 | Third Quarter 2021 | Year-To-Date 2022 | Year-To-Date 2021 |
Total generation (in billions of KWHs)(a) | 50 | 50 | 141 | 136 |
Total purchased power (in billions of KWHs) | 9 | 5 | 20 | 13 |
Sources of generation (percent)(a) — | | | | |
| Gas | 54 | 48 | 50 | 47 |
| Coal | 21 | 26 | 22 | 24 |
| Nuclear | 16 | 16 | 16 | 17 |
| Hydro | 2 | 3 | 4 | 4 |
| Wind, Solar, and Other | 7 | 7 | 8 | 8 |
Cost of fuel, generated (in cents per net KWH)— | | | | |
Gas(a) | 6.75 | 3.38 | 5.42 | 2.87 |
| Coal | 4.12 | 2.82 | 3.58 | 2.84 |
| Nuclear | 0.71 | 0.78 | 0.72 | 0.76 |
Average cost of fuel, generated (in cents per net KWH)(a) | 5.05 | 2.75 | 4.07 | 2.45 |
Average cost of purchased power (in cents per net KWH)(b) | 8.94 | 6.45 | 7.84 | 5.77 |
(a)Excludes Central Alabama Generating Station KWHs and associated cost of fuel through July 12, 2022 as its fuel was previously provided by the purchaser under a power sales agreement. See Note 15 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.
(b)Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider.
Fuel
In the third quarter 2022, fuel expense was $2.4 billion compared to $1.2 billion for the corresponding period in 2021. The increase was primarily due to a 99.7% increase in the average cost of natural gas per KWH generated, a 52.7% decrease in the volume of KWHs generated by hydro, a 46.1% increase in the average cost of coal per KWH generated, and a 13.0% increase in the volume of KWHs generated by natural gas, partially offset by a 19.0% decrease in the volume of KWHs generated by coal.
For year-to-date 2022, fuel expense was $5.2 billion compared to $2.9 billion for the corresponding period in 2021. The increase was primarily due to an 88.9% increase in the average cost of natural gas per KWH generated, a 26.1% increase in the average cost of coal per KWH generated, a 9.6% increase in the volume of KWHs generated by natural gas, and an 8.7% decrease in the volume of KWHs generated by hydro, partially offset by a 4.1% decrease in the volume of KWHs generated by coal.
Purchased Power
In the third quarter 2022, purchased power expense was $645 million compared to $288 million for the corresponding period in 2021. The increase was primarily due to a 38.6% increase in the average cost per KWH purchased primarily due to higher natural gas and coal prices and an 87.2% increase in the volume of KWHs purchased.
For year-to-date 2022, purchased power expense was $1.3 billion compared to $712 million for the corresponding period in 2021. The increase was primarily due to a 35.9% increase in the average cost per KWH purchased primarily due to higher natural gas and coal prices and a 50.9% increase in the volume of KWHs purchased.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Energy purchases will vary depending on demand for energy within the Southern Company system's electric service territory, the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, and the availability of the Southern Company system's generation.
Cost of Natural Gas
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $165 | | N/M | | $897 | | 95.1 |
Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from the natural gas distribution utilities. Cost of natural gas at the natural gas distribution utilities represented 78% and 87% of the total cost of natural gas in the third quarter and year-to-date 2022, respectively.
In the third quarter 2022, cost of natural gas was $294 million compared to $129 million for the corresponding period in 2021. For year-to-date 2022, cost of natural gas was $1.8 billion compared to $943 million for the corresponding period in 2021. The increases reflect higher gas cost recovery as a result of increases of 104% and 113% in natural gas prices in the third quarter and year-to-date 2022, respectively, compared to the corresponding periods in 2021.
Cost of Other Sales
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $21 | | 29.6 | | $20 | | 7.8 |
In the third quarter 2022, cost of other sales was $92 million compared to $71 million for the corresponding period in 2021. The increase was primarily related to distributed infrastructure projects at PowerSecure.
For year-to-date 2022, cost of other sales was $275 million compared to $255 million for the corresponding period in 2021. The increase was primarily due to increases of $32 million related to distributed infrastructure projects at PowerSecure, $9 million related to unregulated power delivery construction and maintenance projects at Mississippi Power, and $9 million primarily associated with unregulated merchandising and energy services expenses at Alabama Power, partially offset by a decrease of $32 million associated with unregulated power delivery construction and maintenance projects at Georgia Power.
Other Operations and Maintenance Expenses
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $101 | | 7.0 | | $364 | | 8.6 |
In the third quarter 2022, other operations and maintenance expenses were $1.5 billion compared to $1.4 billion for the corresponding period in 2021. The increase was primarily due to increases of $49 million in transmission and distribution expenses primarily related to line maintenance, $18 million in customer accounts, customer service, and sales expenses primarily related to bad debt expenses, payment convenience fees, and labor, $12 million in compensation and benefit expenses, and $10 million in generation expenses primarily related to scheduled outage and maintenance costs.
For year-to-date 2022, other operations and maintenance expenses were $4.6 billion compared to $4.3 billion for the corresponding period in 2021. Excluding $53 million of expenses related to Sequent in 2021, other operations and
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
maintenance expenses increased $417 million. The increase was primarily due to increases of $135 million in transmission and distribution expenses primarily related to line maintenance, $90 million in generation expenses primarily related to scheduled outage and maintenance costs, $38 million in compensation and benefit expenses, $30 million in expenses at Southern Company Gas passed through directly to customers primarily related to bad debt, and $21 million in customer accounts, customer service, and sales expenses primarily related to bad debt expenses, payment convenience fees, and labor.
Depreciation and Amortization
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $26 | | 2.9 | | $70 | | 2.6 |
In the third quarter 2022, depreciation and amortization was $922 million compared to $896 million for the corresponding period in 2021. For year-to-date 2022, depreciation and amortization was $2.73 billion compared to $2.66 billion for the corresponding period in 2021. The increases were primarily due to additional plant in service, including continued infrastructure investments at the natural gas distribution utilities.
Taxes Other Than Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $40 | | 12.8 | | $104 | | 10.7 |
In the third quarter 2022, taxes other than income taxes were $352 million compared to $312 million for the corresponding period in 2021. For year-to-date 2022, taxes other than income taxes were $1.1 billion compared to $969 million for the corresponding period in 2021. The increases primarily reflect an increase in municipal franchise fees at Georgia Power and an increase in revenue tax expenses at Southern Company Gas.
Estimated Loss on Plant Vogtle Units 3 and 4
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(334) | | N/M | | $(790) | | N/M |
Georgia Power recorded pre-tax charges (credits) to income for the estimated probable loss on Plant Vogtle Units 3 and 4 totaling $(70) million and $264 million in the third quarter 2022 and 2021, respectively, and $(18) million and $772 million for year-to-date 2022 and 2021, respectively. The charges (credits) reflect revisions to the total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements herein and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.
Gain on Dispositions, Net
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(105) | | (84.0) | | $(126) | | (70.4) |
In the third quarter 2022, gain on dispositions, net was $20 million compared to $125 million for the corresponding period in 2021. For year-to-date 2022, gain on dispositions, net was $53 million compared to $179 million for the corresponding period in 2021. The decreases primarily reflect a $121 million gain at Southern Company Gas related to the sale of Sequent in the third quarter 2021, partially offset by a $14 million gain recorded in the third quarter
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
2022 as a result of the early termination of the transition services agreement related to the 2019 sale of Gulf Power. The year-to-date 2022 decrease also reflects a $39 million gain at Southern Power primarily from contributions of wind turbine equipment to various equity method investments in 2021, partially offset by a $17 million gain from sales of integrated transmission system assets at Georgia Power in 2022. See Note 15 to the financial statements under "Southern Power – Development Projects" and "Southern Company Gas – Sale of Sequent" in Item 8 of the Form 10-K for additional information.
Allowance for Equity Funds Used During Construction
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $10 | | 20.4 | | $23 | | 16.4 |
In the third quarter 2022, allowance for equity funds used during construction was $59 million compared to $49 million for the corresponding period in 2021. For year-to-date 2022, allowance for equity funds used during construction was $163 million compared to $140 million for the corresponding period in 2021. The increases were primarily associated with an increase in capital expenditures related to Plant Barry Unit 8 construction at Alabama Power and transmission and distribution projects related to grid modernization at Georgia Power.
Earnings from Equity Method Investments
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(2) | | (6.7) | | $74 | | N/M |
For year-to-date 2022, earnings from equity method investments were $109 million compared to $35 million for the corresponding period in 2021. The increase was primarily due to pre-tax impairment charges in 2021 totaling $84 million related to the PennEast Pipeline project at Southern Company Gas, partially offset by a $16 million decrease at Southern Holdings primarily due to a decrease in investment income. See Note 7 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements herein under "Southern Company Gas" for additional information.
Interest Expense, Net of Amounts Capitalized
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $60 | | 13.3 | | $109 | | 8.1 |
In the third quarter 2022, interest expense, net of amounts capitalized was $511 million compared to $451 million for the corresponding period in 2021. The increase was primarily due to increases of approximately $28 million due to higher average outstanding borrowings and $28 million due to higher interest rates.
For year-to-date 2022, interest expense, net of amounts capitalized was $1.5 billion compared to $1.4 billion for the corresponding period in 2021. The increase was primarily due to higher average outstanding borrowings.
See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Other Income (Expense), Net
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1 | | 0.8 | | $124 | | 42.8 |
For year-to-date 2022, other income (expense), net was $414 million compared to $290 million for the corresponding period in 2021. The increase was primarily due to charitable contributions of $101 million at Southern Company Gas during the first and second quarters of 2021 and a $44 million increase in non-service cost-related retirement benefits income. See Note (H) to the Condensed Financial Statements herein for additional information.
Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $42 | | 11.3 | | $341 | | 62.0 |
In the third quarter 2022, income taxes were $414 million compared to $372 million for the corresponding period in 2021. For year-to-date 2022, income taxes were $891 million compared to $550 million for the corresponding period in 2021. The increases were primarily due to higher pre-tax earnings, partially offset by $113 million of additional tax expense in 2021 resulting from Southern Company Gas' sale of Sequent in the third quarter 2021. The year-to-date 2022 increase was also due to an adjustment in the second quarter 2022 related to a prior year state tax credit carryforward at Georgia Power. See Note (G) to the Condensed Financial Statements herein for additional information.
Net Income (Loss) Attributable to Noncontrolling Interests
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $7 | | N/M | | $(28) | | N/M |
Substantially all noncontrolling interests relate to renewable projects at Southern Power. In the third quarter 2022, net income attributable to noncontrolling interests was $12 million compared to $5 million for the corresponding period in 2021. The increase was primarily due to lower HLBV loss allocations to Southern Power's tax equity partners, including loss allocation impacts associated with the Garland battery energy storage facility being placed in service in the third quarter 2021, and higher income allocations to Southern Power's equity partners.
For year-to-date 2022, net loss attributable to noncontrolling interests was $55 million compared to $27 million for the corresponding period in 2021. The increased loss was primarily due to higher HLBV loss allocations to Southern Power's tax equity partners, partially offset by loss allocation impacts associated with the Garland battery energy storage facility being placed in service in the third quarter 2021 and higher income allocations to Southern Power's equity partners.
See Notes 9 and 15 to the financial statements under "Lessor" and "Southern Power," respectively, in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Alabama Power
Net Income
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $26 | | 5.2 | | $67 | | 5.6 |
Alabama Power's net income after dividends on preferred stock in the third quarter 2022 was $525 million compared to $499 million for the corresponding period in 2021. Alabama Power's net income after dividends on preferred stock for year-to-date 2022 was $1.26 billion compared to $1.19 billion for the corresponding period in 2021. These increases were primarily due to an increase in retail revenues associated with warmer weather in Alabama Power's service territory in 2022 compared to the corresponding periods in 2021 and sales growth, partially offset by higher non-fuel operations and maintenance costs.
Retail Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $357 | | 21.6 | | $658 | | 15.1 |
In the third quarter 2022, retail revenues were $2.01 billion compared to $1.65 billion for the corresponding period in 2021. For year-to-date 2022, retail revenues were $5.02 billion compared to $4.36 billion for the corresponding period in 2021.
Details of the changes in retail revenues were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Third Quarter 2022 | | Year-To-Date 2022 |
| (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | $ | 1,651 | | | | | $ | 4,357 | | | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 3 | | | 0.2 | % | | 7 | | | 0.2 | % |
| Sales growth | 20 | | | 1.2 | | | 53 | | | 1.2 | |
| Weather | 25 | | | 1.5 | | | 88 | | | 2.0 | |
| Fuel and other cost recovery | 309 | | | 18.7 | | | 510 | | | 11.7 | |
| Retail – current year | $ | 2,008 | | | 21.6 | % | | $ | 5,015 | | | 15.1 | % |
Revenues attributable to changes in sales increased inthe third quarter and year-to-date 2022 when compared to the corresponding periods in 2021. Weather-adjusted residential KWH sales decreased 0.4% and 0.3% in the third quarter and year-to-date 2022, respectively, when compared to the corresponding periods in 2021 primarily due to decreased customer usage. Weather-adjusted commercial KWH sales decreased 0.7% in the third quarter 2022 when compared to the corresponding period in 2021 primarily due to decreased customer usage. Weather-adjusted commercial KWH sales were flat for year-to-date 2022 when compared to the corresponding period in 2021. Industrial KWH sales increased 2.9% and 2.3% in the third quarter and year-to-date 2022, respectively, when compared to the corresponding periods in 2021 primarily due to increases in the forest product and pipeline sectors, partially offset by decreases in the chemicals sector.
Fuel and other cost recovery revenues increased in the third quarter and year-to-date 2022 when compared to the corresponding periods in 2021 primarily due to increases in the volume of KWHs generated and the average cost of fuel.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Electric rates include provisions to recognize the recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the NDR. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income. See Note 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.
Wholesale Revenues – Non-Affiliates
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $143 | | N/M | | $237 | | 83.2 |
In the third quarter 2022, wholesale revenues from sales to non-affiliates were $250 million compared to $107 million for the corresponding period in 2021. For year-to-date 2022, wholesale revenues from sales to non-affiliates were $522 million compared to $285 million for the corresponding period in 2021. The increases for the third quarter and year-to-date 2022 were primarily due to increases of 75.9% and 41.8%, respectively, in the price of energy due to higher natural gas prices, as well as increases of 32.3% and 29.3%, respectively, in KWH sales as a result of increased opportunity sales due to warmer weather in the third quarter and year-to-date 2022 compared to the corresponding periods in 2021.
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Alabama Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not 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.
Wholesale Revenues – Affiliates
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $17 | | 32.1 | | $61 | | 56.0 |
In the third quarter 2022, wholesale revenues from sales to affiliates were $70 million compared to $53 million for the corresponding period in 2021. The increase was primarily due to a 142.2% increase in the price of energy due to higher natural gas prices, partially offset by a 45.7% decrease in KWH sales due to the availability of lower cost Southern Company system resources compared to Alabama Power's generation.
For year-to-date 2022, wholesale revenues from sales to affiliates were $170 million compared to $109 million for the corresponding period in 2021. The increase was primarily due to an 84.7% increase in the price of energy due to higher natural gas prices, partially offset by a 15.3% decrease in KWH sales due to the availability of lower cost Southern Company system resources compared to Alabama Power's generation.
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.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Other Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $23 | | 24.7 | | $48 | | 17.9 |
In the third quarter 2022, other revenues were $116 million respectively,compared to $93 million for the threecorresponding period in 2021. For year-to-date 2022, other revenues were $316 million compared to $268 million for the corresponding period in 2021. The third quarter and nine months endedyear-to-date 2022 increases were primarily due to increases of $7 million and $15 million, respectively, in cogeneration steam revenue associated with higher natural gas prices, $6 million and $13 million, respectively, in transmission revenues primarily due to open access transmission tariff sales, and $3 million and $8 million, respectively, in unregulated lighting sales. The year-to-date 2022 increase also included a $5 million increase in energy services revenue.
Fuel and Purchased Power Expenses
| | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | 293 | | | 78.6 | | | $ | 472 | | | 50.9 | |
| Purchased power – non-affiliates | 109 | | | 143.4 | | | 174 | | | 100.6 | |
| Purchased power – affiliates | 68 | | | 151.1 | | | 146 | | | 128.1 | |
| Total fuel and purchased power expenses | $ | 470 | | | | | $ | 792 | | | |
In the third quarter 2022, total fuel and purchased power expenses were $964 million compared to $494 million for the corresponding period in 2021. The increase was primarily due to a $257 million increase in the cost of fuel and purchased power and a $213 million increase related to the volume of KWHs generated and purchased.
For year-to-date 2022, total fuel and purchased power expenses were $2.01 billion compared to $1.21 billion for the corresponding period in 2021. The increase was primarily due to a $518 million increase in the cost of fuel and purchased power and a $274 million increase related to the volume of KWHs generated and purchased.
Fuel and purchased power energy transactions do not have a significant impact on earnings, since energy expenses are generally offset by energy revenues through Alabama Power's energy cost recovery clause. See Note 2 to the financial statements under "Alabama Power – Rate ECR" in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of Alabama Power's generation and purchased power were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 | | Third Quarter 2021 | | Year-To-Date 2022 | | Year-To-Date 2021 |
Total generation (in billions of KWHs)(a) | 16 | | 16 | | 45 | | 45 |
Total purchased power (in billions of KWHs) | 4 | | 2 | | 9 | | 5 |
Sources of generation (percent)(a) — | | | | | | | |
| Coal | 47 | | 50 | | 45 | | 47 |
| Nuclear | 22 | | 24 | | 24 | | 25 |
| Gas | 28 | | 18 | | 23 | | 19 |
| Hydro | 3 | | 8 | | 8 | | 9 |
Cost of fuel, generated (in cents per net KWH) — | | | | | | | |
| Coal | 3.89 | | 2.85 | | 3.40 | | 2.78 |
| Nuclear | 0.67 | | 0.73 | | 0.67 | | 0.71 |
Gas(a) | 6.55 | | 3.03 | | 5.20 | | 2.68 |
Average cost of fuel, generated (in cents per net KWH)(a) | 3.91 | | 2.33 | | 3.13 | | 2.20 |
Average cost of purchased power (in cents per net KWH)(b) | 8.55 | | 7.96 | | 8.33 | | 6.70 |
(a)Excludes Central Alabama Generating Station KWHs and associated cost of fuel through July 12, 2022 as its fuel was previously provided by the purchaser under a power sales agreement. See Note 15 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.
(b)Average cost of purchased power includes fuel, energy, and transmission purchased by Alabama Power for tolling agreements where power is generated by the provider.
Fuel
In the third quarter 2022, fuel expense was $666 million compared to $373 million for the corresponding period in 2021. The increase was primarily due to a 116.2% increase in the average cost of natural gas per KWH generated, which excludes tolling agreements, a 36.5% increase in the average cost of coal per KWH generated, a 56.8% decrease in the volume of KWHs generated by hydro facilities as a result of less rainfall in the third quarter 2022 compared to the corresponding period in 2021, and a 46.9% increase in the volume of KWHs generated by natural gas.
For year-to-date 2022, fuel expense was $1.4 billion compared to $0.9 billion for the corresponding period in 2021. The increase was primarily due to a 94.0% increase in the average cost of natural gas per KWH generated, which excludes tolling agreements, a 22.3% increase in the average cost of coal per KWH generated, an 18.3% increase in the volume of KWHs generated by natural gas, and an 8.5% decrease in the volume of KWHs generated by hydro facilities as a result of less rainfall for year-to-date 2022 compared to the corresponding period in 2021.
Purchased Power – Non-Affiliates
In the third quarter 2022, purchased power expense from non-affiliates was $185 million compared to $76 million for the corresponding period in 2021. The increase was primarily due to a 193.7% increase in the volume of KWHs purchased as a result of warmer weather in the third quarter 2022 compared to the corresponding period in 2021, partially offset by an 11.2% decrease in the average cost per KWH purchased due to fixed capacity costs allocated across a higher level of generation.
For year-to-date 2022, purchased power expense from non-affiliates was $347 million compared to $173 million for the corresponding period in 2021. The increase was primarily due to a 100.5% increase in the volume of KWHs purchased as a result of warmer weather for year-to-date 2022 compared to the corresponding period in 2021, as well as an 8.2% increase in the average cost per KWH purchased due to higher natural gas and coal prices.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the third quarter 2022, purchased power expense from affiliates was $113 million compared to $45 million for the corresponding period in 2021. The increase was primarily due to an 84.5% increase in the average cost per KWH purchased due to higher natural gas and coal prices and a 36.4% increase in the volume of KWHs purchased as a result of warmer weather in the third quarter 2022 compared to the corresponding period in 2021.
For year-to-date 2022, purchased power expense from affiliates was $260 million compared to $114 million for the corresponding period in 2021. The increase was primarily due to a 71.0% increase in the average cost per KWH purchased due to higher natural gas and coal prices and a 33.6% increase in the volume of KWHs purchased as a result of warmer weather for year-to-date 2022 compared to the corresponding period in 2021.
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 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $17 | | 4.2 | | $95 | | 8.1 |
In the third quarter 2022, other operations and maintenance expenses were $418 million compared to $401 million for the corresponding period in 2021. For year-to-date 2022, other operations and maintenance expenses were $1.27 billion compared to $1.18 billion for the corresponding period in 2021. The increases for the third quarter and year-to-date 2022 were primarily due to increases of $18 million and $41 million, respectively, in transmission and distribution expenses primarily associated with line maintenance and $6 million and $12 million, respectively, in customer accounts, customer service, and sales expenses primarily associated with labor and bad debt expense. The increase for the third quarter 2022 was partially offset by a $15 million decrease in generation expenses primarily associated with scheduled outages and maintenance. The year-to-date 2022 increase also included a $24 million increase in generation expenses primarily associated with scheduled outages and maintenance and Rate CNP Compliance-related expenses. See Note 2 to the financial statements under "Alabama Power – Rate CNP Compliance" in Item 8 of the Form 10-K for additional information.
Allowance for Equity Funds Used During Construction
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $4 | | 28.6 | | $13 | | 34.2 |
For year-to-date 2022, allowance for equity funds used during construction was $51 million compared to $38 million for the corresponding period in 2021. The increase for year-to-date 2022 was primarily due to an increase in capital expenditures related to Plant Barry Unit 8 construction.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Interest Expense, Net of Amounts Capitalized
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $14 | | 16.7 | | $26 | | 10.3 |
In the third quarter 2022, interest expense, net of amounts capitalized was $98 million compared to $84 million for the corresponding period in 2021. For year-to-date 2022, interest expense, net of amounts capitalized was $278 million compared to $252 million for the corresponding period in 2021. The increases were primarily due to higher average outstanding borrowings. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings.
Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $14 | | 9.2 | | $28 | | 7.7 |
In the third quarter 2022, income taxes were $166 million compared to $152 million for the corresponding period in 2021. For year-to-date 2022, income taxes were $394 million compared to $366 million for the corresponding period in 2021. The increases were primarily due to higher pre-tax earnings.
Georgia Power
Net Income
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $322 | | 60.1 | | $821 | | 79.7 |
Georgia Power's net income in the third quarter 2022 was $858 million compared to $536 million for the corresponding period in 2021. For year-to-date 2022 net income was $1.85 billion compared to $1.03 billion for the corresponding period in 2021. The increases were primarily due to decreases of $249 million and $589 million in the third quarter and year-to-date 2022, respectively, in after-tax charges related to the construction of Plant Vogtle Units 3 and 4 and increases in retail revenues associated with rates and pricing and sales growth, partially offset by higher non-fuel operations and maintenance costs. The increase for year-to-date 2022 was also due to warmer weather in Georgia Power's service territory compared to the corresponding period in 2021.
See Note (B) to the Condensed Financial Statements herein and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.
Retail Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1,051 | | 39.6 | | $2,164 | | 33.5 |
In the third quarter 2022, retail revenues were $3.70 billion compared to $2.65 billion for the corresponding period in 2021. For year-to-date 2022, retail revenues were $8.63 billion compared to $6.47 billion for the corresponding period in 2021.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of the changes in retail revenues were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Third Quarter 2022 | | Year-To-Date 2022 |
| (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | $ | 2,652 | | | | | $ | 6,465 | | | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 157 | | | 5.9 | % | | 442 | | | 6.8 | % |
| Sales growth | 54 | | | 2.0 | | | 101 | | | 1.6 | |
| Weather | (1) | | | — | | | 89 | | | 1.4 | |
| Fuel cost recovery | 841 | | | 31.7 | | | 1,532 | | | 23.7 | |
| Retail – current year | $ | 3,703 | | | 39.6 | % | | $ | 8,629 | | | 33.5 | % |
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2022 when compared to the corresponding periods in 2021. The increases were primarily due to higher contributions from commercial and industrial customers with variable demand-driven pricing, base tariff increases in accordance with the 2019 ARP, and pricing effects associated with customer usage. See Note 2 to the financial statements under "Georgia Power – Rate Plans" in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales increased in the third quarter and year-to-date 2022 when compared to the corresponding periods in 2021. Weather-adjusted residential KWH sales increased 2.7% and 1.0% in the third quarter and year-to-date 2022, respectively, when compared to the corresponding periods in 2021 primarily due to customer growth. The increase for the third quarter 2022 also reflects increased customer usage. Weather-adjusted commercial KWH sales increased 3.2% and 2.9% in the third quarter and year-to-date 2022, respectively, when compared to the corresponding periods in 2021 primarily due to impacts on customer usage from increased activity outside the home as customers return to pre-pandemic levels of activity, as well as customer growth. Weather-adjusted industrial KWH sales increased 1.8% and 2.8% in the third quarter and year-to-date 2022, respectively, when compared to the corresponding periods in 2021 primarily due to increases in the pipeline, electronic, and paper sectors, partially offset by decreases in the chemicals and textiles sectors.
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 2022 when compared to the corresponding periods in 2021 due to higher fuel and purchased power costs. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See Note 2 to the financial statements under "Georgia Power – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.
Wholesale Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(7) | | (11.1) | | $43 | | 30.1 |
In the third quarter 2022, wholesale revenues were $56 million compared to $63 million for the corresponding period in 2021. The decrease was primarily due to a $22 million decrease in KWH sales associated with lower market demand and a $3 million decrease in capacity revenues due to the expiration of a non-affiliate PPA in 2021, largely offset by an increase of $20 million related to the average cost of fuel primarily due to higher natural gas and coal prices.
For year-to-date 2022, wholesale revenues were $186 million compared to $143 million for the corresponding period in 2021. The increase was primarily due to an increase of $60 million related to the average cost of fuel primarily due to higher natural gas and coal prices, partially offset by a $10 million decrease in KWH sales
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
associated with lower market demand and an $8 million decrease in capacity revenues due to the expiration of a non-affiliate PPA in 2021.
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 in amounts billable under the contract terms and provide for recovery of fixed costs and a return on investment. Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Georgia Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above Georgia Power's variable cost of energy.
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.
Other Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(11) | | (7.8) | | $(39) | | (8.8) |
In the third quarter 2022, other revenues were $130 million compared to $141 million for the corresponding period in 2021. For year-to-date 2022, other revenues were $403 million compared to $442 million for the corresponding period in 2021. The decreases for the third quarter and year-to-date 2022 were primarily due to increases of $14 million and $21 million, respectively, in realized losses associated with price stability products for retail customers on variable demand-driven pricing tariffs, decreases of $9 million and $12 million, respectively, from retail solar programs as a result of higher avoided cost credits to customers, and $6 million and $26 million, respectively, resulting from the termination of a transmission service contract. These reductions were partially offset by increases of $8 million and $22 million, respectively, associated with unregulated outdoor lighting sales and energy conservation projects and $6 million and $16 million, respectively, in open access transmission tariff sales. Also contributing to the decrease for year-to-date 2022 was a decrease of $28 million associated with the timing of revenue recognition for a large, ongoing power delivery construction and maintenance contract.
Fuel and Purchased Power Expenses
| | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-to-Date 2022 vs. Year-to-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | 409 | | | 94.7 | | | $ | 799 | | | 73.4 | |
| Purchased power – non-affiliates | 131 | | | 75.7 | | | 239 | | | 51.8 | |
| Purchased power – affiliates | 283 | | | 98.3 | | | 527 | | | 92.0 | |
| Total fuel and purchased power expenses | $ | 823 | | | | | $ | 1,565 | | | |
In the third quarter 2022, total fuel and purchased power expenses were $1.7 billion compared to $0.9 billion for the corresponding period in 2021. For year-to-date 2022, total fuel and purchased power expenses were $3.7 billion compared to $2.1 billion for the corresponding period in 2021. The increases for the third quarter and year-to-date 2022 were primarily due to increases of $0.8 billion and $1.4 billion, respectively, related to the average cost of fuel
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
and purchased power and net increases of $30 million and $158 million, respectively, related to 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 Note 2 to the financial statements under "Georgia Power – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.
Details of Georgia Power's generation and purchased power were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 | | Third Quarter 2021 | | Year-To-Date 2022 | | Year-To-Date 2021 |
Total generation (in billions of KWHs) | 15 | | 16 | | 45 | | 46 |
Total purchased power (in billions of KWHs) | 11 | | 10 | | 27 | | 23 |
Sources of generation (percent) — | | | | | | | |
| Gas | 53 | | 45 | | 48 | | 46 |
| | | | | | | |
| Nuclear | 28 | | 24 | | 26 | | 26 |
| Coal | 16 | | 28 | | 22 | | 24 |
| Hydro and other | 3 | | 3 | | 4 | | 4 |
Cost of fuel, generated (in cents per net KWH) — | | | | | | | |
| Gas | 6.10 | | 3.28 | | 4.99 | | 2.84 |
| Coal | 4.73 | | 2.73 | | 3.84 | | 2.89 |
| Nuclear | 0.75 | | 0.83 | | 0.76 | | 0.80 |
| | | | | | | |
Average cost of fuel, generated (in cents per net KWH) | 4.32 | | 2.51 | | 3.56 | | 2.30 |
Average cost of purchased power (in cents per net KWH)(*) | 10.14 | | 5.24 | | 8.00 | | 4.80 |
(*)Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider.
Fuel
In the third quarter 2022, fuel expense was $841 million compared to $432 million for the corresponding period in 2021. The increase was primarily due to increases of 86.0% and 73.3% in the average cost per KWH generated by natural gas and coal, respectively, and an 11.1% increase in the volume of KWHs generated by natural gas, partially offset by a 44.2% decrease in the volume of KWHs generated by coal.
For year-to-date 2022, fuel expense was $1.89 billion compared to $1.09 billion for the corresponding period in 2021. The increase was primarily due to increases of 75.7% and 32.9% in the average cost per KWH generated by natural gas and coal, respectively, partially offset by a 9.1% decrease in the volume of KWHs generated by coal.
Purchased Power – Non-Affiliates
In the third quarter 2022, purchased power expense from non-affiliates was $304 million compared to $173 million for the corresponding period in 2021. For year-to-date 2022, purchased power expense from non-affiliates was $700 million compared to $461 million for the corresponding period in 2021. The increases for the third quarter and year-to-date 2022 were primarily due to increases of 50.5% and 39.4%, respectively, in the volume of KWHs purchased primarily due to less available Georgia Power-owned coal generation and increases of 53.1% and 31.6%, respectively, in the average cost per KWH purchased primarily due to higher natural gas and coal 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.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Purchased Power – Affiliates
In the third quarter 2022, purchased power expense from affiliates was $571 million compared to $288 million for the corresponding period in 2021. For year-to-date 2022, purchased power expense from affiliates was $1.1 billion compared to $573 million for the corresponding period in 2021. The increases for the third quarter and year-to-date 2022 were primarily due to increases of 120.3% and 93.3%, respectively, in the average cost per KWH purchased primarily due to higher natural gas and coal prices.
Energy purchases from affiliates will vary depending on the 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 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $51 | | 9.4 | | $128 | | 8.2 |
In the third quarter 2022, other operations and maintenance expenses were $595 million compared to $544 million for the corresponding period in 2021. The increase was primarily due to increases of $35 million in distribution expenses primarily associated with line maintenance, $10 million in generation expenses primarily related to non-outage maintenance costs, and $9 million in certain compensation and benefit expenses, partially offset by a decrease of $6 million related to unregulated power delivery construction and maintenance projects.
For year-to-date 2022, other operations and maintenance expenses were $1.69 billion compared to $1.56 billion for the corresponding period in 2021. The increase was primarily due to increases of $80 million in distribution expenses primarily associated with line maintenance, $37 million in generation expenses primarily related to non-outage maintenance costs, $20 million in certain compensation and benefit expenses, $11 million in legal and regulatory expenses, and $8 million in amortization of cloud software, partially offset by a net decrease of $19 million related to unregulated products and services and $17 million in gains from sales of integrated transmission system assets.
Depreciation and Amortization
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $14 | | 4.1 | | $41 | | 4.0 |
In the third quarter 2022, depreciation and amortization was $359 million compared to $345 million for the corresponding period in 2021. For year-to-date 2022, depreciation and amortization was $1.07 billion compared to $1.03 billion for the corresponding period in 2021. The increases for the third quarter and year-to-date 2022 were primarily due to additional plant in service and increases of $3 million and $9 million, respectively, in amortization of regulatory assets related to CCR AROs under the terms of the 2019 ARP. See Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Rate Plans – 2019 ARP" for additional information on recovery of CCR AROs.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Taxes Other Than Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $25 | | 19.2 | | $55 | | 15.1 |
In the third quarter 2022, taxes other than income taxes were $155 million compared to $130 million for the corresponding period in 2021. For year-to-date 2022, taxes other than income taxes were $420 million compared to $365 million for the corresponding period in 2021. The increases were primarily due to increases in municipal franchise fees resulting from higher retail revenues.
Estimated Loss on Plant Vogtle Units 3 and 4
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(334) | | N/M | | $(790) | | N/M |
Georgia Power recorded pre-tax charges (credits) to income for the estimated probable loss on Plant Vogtle Units 3 and 4 totaling $(70) million and $264 million in the third quarter 2022 and 2021, respectively, and $(18) million and $772 million for year-to-date 2022 and 2021, respectively. The charges (credits) reflect revisions to the total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements herein and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.
Interest Expense, Net of Amounts Capitalized
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $17 | | 16.0 | | $32 | | 10.2 |
In the third quarter 2022, interest expense, net of amounts capitalized was $123 million compared to $106 million for the corresponding period in 2021. For year-to-date 2022, interest expense, net of amounts capitalized was $347 million compared to $315 million for the corresponding period in 2021. The increases for the third quarter and year-to-date 2022 were primarily associated with increases of approximately $11 million and $23 million, respectively, related to higher average outstanding borrowings and $10 million and $12 million, respectively, related to higher interest rates. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings.
Other Income (Expense), Net
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(6) | | (14.3) | | $16 | | 12.9 |
For year-to-date 2022, other income (expense), net was $140 million compared to $124 million for the corresponding period in 2021. The increase was primarily due to an increase of $11 million in non-service cost-related retirement benefits income. See Note (H) to the Condensed Financial Statements herein for additional information on retirement benefits.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $113 | | 100.0 | | $340 | | N/M |
In the third quarter 2022, income taxes were $226 million compared to $113 million for the corresponding period in 2021. For year-to-date 2022, income taxes were $421 million compared to $81 million for the corresponding period in 2021. The increases were primarily due to higher pre-tax earnings largely resulting from lower charges associated with the construction of Plant Vogtle Units 3 and 4. The year-to-date increase also reflects an adjustment in the second quarter 2022 related to a prior year state tax credit carryforward. See Note (B) to the Condensed Financial Statements herein and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" and Note (G) to the Condensed Financial Statements herein for additional information.
Mississippi Power
Net Income
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $12 | | 24.0 | | $17 | | 12.8 |
Mississippi Power's net income in the third quarter 2022 was $62 million compared to $50 million for the corresponding period in 2021. For year-to-date 2022, net income was $150 million compared to $133 million for the corresponding period in 2021. The increases were primarily due to an increase in revenues, partially offset by an increase in income taxes. The year-to-date 2022 increase was also partially offset by higher non-fuel operations and maintenance costs.
Retail Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $2 | | 0.8 | | $48 | | 7.2 |
In the third quarter 2022, retail revenues were$250 million compared to $248 million for the corresponding period in 2021. For year-to-date 2022, retail revenues were $718 million compared to $670 million for the corresponding period in 2021.
Details of the changes in retail revenues were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Third Quarter 2022 | | Year-To-Date 2022 |
| | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | $ | 248 | | | | | $ | 670 | | | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 4 | | | 1.6 | % | | 9 | | | 1.3 | % |
| Sales growth (decline) | — | | | — | | | 3 | | | 0.5 | |
| Weather | 3 | | | 1.2 | | | 10 | | | 1.5 | |
| Fuel and other cost recovery | (5) | | | (2.0) | | | 26 | | | 3.9 | |
| Retail – current year | $ | 250 | | | 0.8 | % | | $ | 718 | | | 7.2 | % |
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2022 when compared to the corresponding periods in 2021 primarily due to new PEP rates that became effective for the first billing cycle of April 2022, partially offset by a decrease in revenues associated with a tolling arrangement. See Note (B) to the Condensed Financial Statements under "Mississippi Power – Performance Evaluation Plan" herein for additional information.
Revenues attributable to changes in salesdecreased in the third quarter 2022 when compared to the corresponding period in 2021. Revenues attributable to changes in sales increased for year-to-date 2022 when compared to the corresponding period in 2021. Weather-adjusted residential KWH sales decreased 3.3% and 1.2% in the third quarter and year-to-date 2022, respectively, when compared to the corresponding periods in 2021 due to a decrease in customer usage resulting from increased activity outside the home as customers return to pre-pandemic levels of activity. Weather-adjusted commercial KWH sales increased 0.3% and 1.3% in the third quarter and year-to-date 2022, respectively, when compared to the corresponding periods in 2021 due to customer growth. Industrial KWH sales increased 1.9% and 1.8% in the third quarter and year-to-date 2022, respectively, when compared to the corresponding periods in 2021 primarily due to increases in the petroleum, pipeline, and transportation sectors.
Fuel and other cost recovery revenues decreased in the third quarter 2022 when compared to the corresponding period in 2021 primarily as a result of lower recoverable fuel costs. Fuel and other cost recovery revenues increased for year-to-date 2022 when compared to the corresponding period in 2021 primarily as a result of higher 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. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Mississippi Power" for additional information.
Wholesale Revenues – Non-Affiliates
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $— | | — | | $13 | | 7.3 |
For year-to-date 2022, wholesale revenues from sales to non-affiliates were $191 million compared to $178 million for the corresponding period in 2021. The increase was primarily due to higher fuel costs and an increase in base revenue from MRA customers primarily due to increased demand as a result of weather impacts in 2022.
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 Note 2 to the financial statements under "Mississippi Power" in Item 8 of the Form 10-K for additional information. See Note (B) to the Condensed Financial Statements under "Mississippi Power – Municipal and Rural Associations Tariff" herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Wholesale Revenues – Affiliates
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $125 | | N/M | | $216 | | N/M |
In the third quarter 2022, wholesale revenues from sales to affiliates were $187 million compared to $62 million for the corresponding period in 2021. For year-to-date 2022, wholesale revenues from sales to affiliates were $336 million compared to $120 million for the corresponding period in 2021. Theincreases were primarily due toincreases of $111 million and $197 million, respectively, associated with higher fuel prices, primarily for natural gas, and $14 million and $19 million, respectively, associated with higher KWH sales due to lower cost available Mississippi Power resources as compared to the available affiliate company generation.
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.
Other Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $5 | | 62.5 | | $14 | | 70.0 |
In the third quarter 2022, other revenues were $13 million compared to $8 million for the corresponding period in 2021. For year-to-date 2022, other revenues were $34 million compared to $20 million for the corresponding period in 2021. The increases for the third quarter and year-to-date 2022 were primarily due to increases of $5 million and $10 million, respectively, in unregulated sales associated with power delivery construction and maintenance projects.
Fuel and Purchased Power Expenses
| | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-to-Date 2022 vs. Year-to-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | 103 | | | 74.2 | | $ | 235 | | | 71.1 |
| Purchased power | 14 | | | 250.0 | | 15 | | | 70.6 |
| Total fuel and purchased power expenses | $ | 117 | | | | | $ | 250 | | | |
In the third quarter 2022, total fuel and purchased power expenses were $262 millioncompared to $145 million for the corresponding period in 2021. Theincrease was due to a $106 millionincrease related to the average cost of fuel and purchased power and an $11 million increase related to the volume of KWHs generated and purchased.
For year-to-date 2022, total fuel and purchased power expenses were $601 millioncompared to $351 million for the corresponding period in 2021. Theincreasewas primarily due to a $233 millionincrease related to the average cost of fuel and purchased power and a $17 millionincrease related to the volume of KWHs generated.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Mississippi Power's fuel cost recovery clause.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of Mississippi Power's generation and purchased power were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 | | Third Quarter 2021 | | Year-To-Date 2022 | | Year-To-Date 2021 |
Total generation (in millions of KWHs) | 5,093 | | 4,878 | | 13,650 | | 13,016 |
Total purchased power (in millions of KWHs) | 241 | | 124 | | 527 | | 562 |
Sources of generation (percent) – | | | | | | | |
| Gas | 89 | | 93 | | 89 | | 91 |
| Coal | 11 | | 7 | | 11 | | 9 |
Cost of fuel, generated (in cents per net KWH) – | | | | | | | |
| Gas | 5.10 | | 2.99 | | 4.43 | | 2.66 |
| Coal | 4.50 | | 3.16 | | 4.12 | | 3.13 |
Average cost of fuel, generated (in cents per net KWH) | 5.02 | | 3.00 | | 4.40 | | 2.70 |
Average cost of purchased power (in cents per net KWH) | 8.15 | | 4.51 | | 6.83 | | 3.78 |
Fuel
In the third quarter 2022, fuel expense was $242 million compared to $139 million for the corresponding period in 2021. The increasewas due to a 70.6%increase in the average cost of natural gas per KWH generated, a 42.4%increase in the average cost of coal per KWHs generated, and a 61.3%increase in the volume of KWHs generated by coal.
For year-to-date 2022, fuel expense was $565 million compared to $330 million for the corresponding period in 2021. Theincreasewas due to a 66.5%increase in the average cost of natural gas per KWH generated, a 31.6%increase in the average cost of coal per KWHs generated, a 30.2%increase in the volume of KWHs generated by coal, and a 2.4%increase in the volume of KWHs generated by natural gas.
Purchased Power
In the third quarter 2022, purchased power expense was $20 million compared to $6 million for the corresponding period in 2021. The increasewas due to a 93.6% increase in the volume of KWHs purchased and an 80.7% increase in the average cost per KWH purchased.
For year-to-date 2022, purchased power expense was $36 million compared to $21 million for the corresponding period in 2021. The increasewas primarily due to an 80.6% increase in the average cost per KWH purchased, partially offset by a 6.3% decrease in the volume of KWHs purchased.
Energy purchases will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Other Operations and Maintenance Expenses
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1 | | 1.2 | | $22 | | 9.6 |
For year-to-date 2022, other operations and maintenance expenses were $252 million compared to $230 million for the corresponding period in 2021. The increase was primarily due to increases of $9 million related to unregulated power delivery construction and maintenance projects, $6 million associated with storm reserve accruals, $4 million in transmission and distribution line maintenance, and $4 million in sales and use taxes associated with the Kemper County energy facility. See Note 2 to the financial statements under "Mississippi Power – System Restoration Rider" in Item 8 of the Form 10-K and Note (C) to the Condensed Financial Statements under "Other Matters – Mississippi Power" herein for additional information.
Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $7 | | 70.0 | | $16 | | 72.7 |
In the third quarter 2022, income taxes were $17 million compared to $10 million for the corresponding period in 2021. For year-to-date 2022, income taxes were $38 million compared to $22 million for the corresponding period in 2021. The third quarter and year-to-date 2022 increases primarily relate to a reduction of $3 million and $8 million, respectively, in the flowback of excess deferred income taxes associated with new PEP rates that became effective in April 2022, as well as increases of $4 million and $8 million, respectively, due to higher pre-tax earnings. See Note (G) to the Condensed Financial Statements herein for additional information.
Southern Power
Net Income Attributable to Southern Power
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $17 | | 21.8 | | $54 | | 25.6 |
Net income attributable to Southern Power in the third quarter 2022 was $95 million compared to $78 million for the corresponding period in 2021. Net income attributable to Southern Power for year-to-date 2022 was $265 million compared to $211 million for the corresponding period in 2021. The increases were primarily due to higher revenues driven by higher market prices of energy, partially offset by higher other operations and maintenance expenses. Also contributing to the year-to-date 2022 increase were higher revenues from new natural gas PPAs and higher income associated with tax equity partnerships. The year-to-date 2022 increase was partially offset by gains from contributions of wind turbine equipment to various equity method investments in the first quarter 2021 and a tax benefit due to a change in state apportionment methodology resulting from tax legislation enacted by the State of Alabama in the first quarter 2021.
See Note 15 to the financial statements under "Southern Power – Development Projects" in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Operating Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $501 | | 73.8 | | $1,008 | | 62.6 |
Total operating revenues include PPA capacity revenues, which are derived primarily from long-term contracts involving natural gas facilities, and PPA energy revenues from Southern Power's generation facilities. To the extent Southern Power has capacity not contracted under a PPA, it may sell power into an accessible wholesale market, or, to the extent those generation assets are part of the FERC-approved IIC, it may sell power into the Southern Company power pool.
Natural Gas Capacity and Energy Revenue
Capacity revenues generally represent the greatest contribution to operating income and are designed to provide recovery of fixed costs plus a return on investment.
Energy is generally sold at variable cost or is indexed to published natural gas indices. Energy revenues will vary depending on the energy demand of Southern Power's customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Power's energy. Energy revenues also include fees for support services, fuel storage, and unit start charges. Increases and decreases in energy revenues under PPAs that are driven by fuel or purchased power prices are accompanied by an increase or decrease in fuel and purchased power costs and do not have a significant impact on net income.
Solar and Wind Energy Revenue
Southern Power's energy sales from solar and wind generating facilities are predominantly through long-term PPAs that do not have capacity revenue. Customers either purchase the energy output of a dedicated renewable facility through an energy charge or pay a fixed price related to the energy generated from the respective facility and sold to the grid. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors.
See FUTURE EARNINGS POTENTIAL – "Southern Power's Power Sales Agreements" in Item 7 of the Form 10-K for additional information regarding Southern Power's PPAs.
Operating Revenues Details
Details of Southern Power's operating revenues were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 | | Third Quarter 2021 | | Year-To-Date 2022 | | Year-To-Date 2021 |
| (in millions) |
| PPA capacity revenues | $ | 131 | | | $ | 118 | | | $ | 344 | | | $ | 311 | |
| PPA energy revenues | 736 | | | 413 | | | 1,657 | | | 954 | |
| Total PPA revenues | 867 | | | 531 | | | 2,001 | | | 1,265 | |
| Non-PPA revenues | 304 | | | 139 | | | 590 | | | 327 | |
| Other revenues | 9 | | | 9 | | | 27 | | | 18 | |
| Total operating revenues | $ | 1,180 | | | $ | 679 | | | $ | 2,618 | | | $ | 1,610 | |
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
In the third quarter 2022, total operating revenues were $1.2 billion, reflecting a $501 million, or 74%, increase from the corresponding period in 2021. The increase in operating revenues was primarily due to the following:
•PPA capacity revenues increased $13 million, or 11%, primarily due to increased capacity sales under existing natural gas PPAs.
•PPA energy revenues increased $323 million, or 78%, primarily due to a $333 million increase in sales under existing natural gas PPAs resulting from a $287 million increase in the price of fuel and purchased power and a $45 million increase in the volume of KWHs sold.
•Non-PPA revenues increased $165 million, or 119%, due to a $172 million increase in the market price of energy, partially offset by a $7 million decrease in the volume of KWHs sold through short-term sales.
For year-to-date 2022, total operating revenues were $2.6 billion, reflecting a $1.0 billion, or 63%, increase from the corresponding period in 2021. The increase in operating revenues was primarily due to the following:
•PPA capacity revenues increased $33 million, or 11%, primarily due to new natural gas PPAs and increased capacity sales under existing natural gas PPAs, partially offset by the contractual expiration of natural gas PPAs.
•PPA energy revenues increased $703 million, or 74%, primarily due to a $540 million increase in sales under existing natural gas PPAs resulting from a $442 million increase in the price of fuel and purchased power and a $98 million increase in the volume of KWHs sold. Also contributing to the increase was a $186 million increase in sales associated with new natural gas PPAs, partially offset by a $17 million decrease due to the contractual expiration of natural gas PPAs.
•Non-PPA revenues increased $263 million, or 80%, due to a $299 million increase in the market price of energy, partially offset by a $35 million decrease in the volume of KWHs sold through short-term sales.
Fuel and Purchased Power Expenses
Details of Southern Power's generation and purchased power were as follows:
| | | | | | | | | | | | | | | | | |
| | Third Quarter 2022 | Third Quarter 2021 | | Year-To-Date 2022 | Year-To-Date 2021 |
| (in billions of KWHs) |
| Generation | 12.8 | 12.1 | | 36.7 | 31.8 |
| Purchased power | 1.2 | 0.8 | | 2.3 | 2.0 |
| Total generation and purchased power | 14.0 | 12.9 | | 39.0 | 33.8 |
| | | | | |
Total generation and purchased power (excluding solar, wind, fuel cells, and tolling agreements) | 8.8 | 7.7 | | 23.2 | 20.2 |
Southern Power's PPAs for natural gas generation generally provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing Southern Power for substantially all of the cost of fuel relating to the energy delivered under such PPAs. Consequently, changes in such fuel costs are generally accompanied by a corresponding change in related fuel revenues and do not have a significant impact on net income. Southern Power is responsible for the cost of fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the wholesale market or into the Southern Company power pool for capacity owned directly by Southern Power.
Purchased power expenses will vary depending on demand, availability, and the cost of generating resources throughout the Southern Company system and other contract resources. Load requirements are submitted to the Southern Company power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power, an affiliate company, or external parties. Such purchased power costs are generally recovered through PPA revenues.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of Southern Power's fuel and purchased power expenses were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Third Quarter 2022 vs. Third Quarter 2021 | | Year-to-Date 2022 vs. Year-to-Date 2021 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | 346 | | | 133.6 | | $ | 734 | | | 135.9 |
| Purchased power | 103 | | | 251.2 | | 147 | | | 170.9 |
| Total fuel and purchased power expenses | $ | 449 | | | | | $ | 881 | | | |
In the third quarter 2022, total fuel and purchased power expenses increased $449 million, or 150%, compared to the corresponding period in 2021. Fuel expense increased $346 million due to a $323 million increase associated with the average cost of fuel and a $23 million increase associated with the volume of KWHs generated. Purchased power expense increased $103 million due to a $79 million increase associated with the average cost of purchased power and a $24 million increase associated with the volume of KWHs purchased.
For year-to-date 2022, total fuel and purchased power expenses increased $881 million, or 141%, compared to the corresponding period in 2021. Fuel expense increased $734 million due to a $651 million increase associated with the average cost of fuel and an $83 million increase associated with the volume of KWHs generated. Purchased power expense increased $147 million due to a $134 million increase associated with the average cost of purchased power and a $13 million increase associated with the volume of KWHs purchased.
Other Operations and Maintenance Expenses
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $19 | | 20.1 | | $23 | | 7.4 |
In the third quarter 2022, other operations and maintenance expenses were $113 million compared to $94 million for the corresponding period in 2021. For year-to-date 2022, other operations and maintenance expenses were $331 million compared to $308 million for the corresponding period in 2021. The increases for the third quarter and year-to-date 2022 were primarily due to increases of $11 million and $13 million, respectively, related to the timing of non-outage generation maintenance expenses. Also contributing to the year-to-date 2022 increase was an increase of $11 million in transmission expenses to serve new natural gas PPAs, partially offset by $6 million related to the allocation in 2021 of uncollected settlements by the Energy Reliability Council of Texas market as a result of Winter Storm Uri.
Loss on Sales-Type Lease
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(15) | | (100.0) | | $(14) | | (93.4) |
In the third quarter 2021, a $15 million loss on sales-type lease was recorded upon commencement of the Garland battery energy storage facility PPA, $10 million of which was allocated through noncontrolling interests to Southern Power's partners in the project. See Notes 9 and 15 to the financial statements under "Lessor" and "Southern Power," respectively, in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Gain on Dispositions, Net
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $— | | N/M | | $(37) | | (94.9) |
For year-to-date 2022, gain on dispositions, net was $2 million compared to $39 million for the corresponding period in 2021. The decrease primarily resulted from gains associated with contributions of wind turbine equipment to various equity method investments in the first quarter 2021. See Note 15 to the financial statements under "Southern Power – Development Projects" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Southern Power" herein for additional information.
Income Taxes (Benefit)
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $27 | | N/M | | $52 | | N/M |
In the third quarter 2022, income tax expense was $36 million compared to $9 million for the corresponding period in 2021. The change was primarily due to higher pre-tax earnings, partially offset by higher wind PTCs.
For year-to-date 2022, income tax expense was $49 million compared to a benefit of $3 million for the corresponding period in 2021. The change was primarily due to higher pre-tax earnings for year-to-date 2022 and a change in state apportionment methodology resulting from tax legislation enacted by the State of Alabama in the first quarter 2021, partially offset by higher wind PTCs for year-to-date 2022.
Net Income (Loss) Attributable to Noncontrolling Interests
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $7 | | N/M | | $(28) | | N/M |
In the third quarter 2022, net income attributable to noncontrolling interests was $12 million compared to $5 million for the corresponding period in 2021. The increase was primarily due to lower HLBV loss allocations to tax equity partners, including loss allocation impacts associated with the Garland battery energy storage facility being placed in service in the third quarter 2021, and higher income allocations to equity partners.
For year-to-date 2022, net loss attributable to noncontrolling interests was $55 million compared to $27 million for the corresponding period in 2021. The increased loss was primarily due to higher HLBV loss allocations to tax equity partners, partially offset by loss allocation impacts associated with the Garland battery energy storage facility being placed in service in the third quarter 2021 and higher income allocations to equity partners.
See Notes 9 and 15 to the financial statements under "Lessor" and "Southern Power," respectively, in Item 8 of the Form 10-K for additional information.
Southern Company Gas
Operating Metrics
Southern Company Gas continues to focus on several operating metrics, including Heating Degree Days, customer count, and volumes of natural gas sold.
Southern Company Gas measures weather and the effect on its business using Heating Degree Days. Generally, increased Heating Degree Days result in higher demand for natural gas on Southern Company Gas' distribution system. Southern Company Gas has various regulatory mechanisms, such as weather and revenue normalization and straight-fixed-variable rate design, which limit its exposure to weather changes within typical ranges in each of its
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
utility's respective service territory. Southern Company Gas also utilizes weather hedges to limit the negative income impacts in the event of warmer-than-normal weather.
The number of customers served by gas distribution operations and gas marketing services can be impacted by natural gas prices, economic conditions, and competition from alternative fuels. Gas distribution operations and gas marketing services' customers are primarily located in Georgia and Illinois.
Southern Company Gas' natural gas volume metrics for gas distribution operations and gas marketing services illustrate the effects of weather and customer demand for natural gas.
Seasonality of Results
During the Heating Season, natural gas usage and operating revenues are generally higher as more customers are connected to the gas distribution systems and natural gas usage is higher in periods of colder weather. Southern Company Gas' base operating expenses, excluding cost of natural gas, bad debt expense, and certain incentive compensation costs, are incurred relatively evenly throughout the year. Seasonality also affects the comparison of certain balance sheet items across quarters, including receivables, unbilled revenues, natural gas for sale, and notes payable. However, these items are comparable when reviewing Southern Company Gas' annual results. Thus, Southern Company Gas' operating results for the interim periods presented are not necessarily indicative of annual results and can vary significantly from quarter to quarter.
Net Income
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $27 | | 48.2 | | $127 | | 32.6 |
In the third quarter 2022, net income was $83 million compared to $56 million for the corresponding period in 2021. Net income increased $14 million at gas distribution operations primarily due to base rate increases and continued investment in infrastructure replacement and $14 million at gas pipeline investments primarily as a result of higher earnings at SNG and lower income taxes related to the PennEast Pipeline project. The third quarter 2021 results also included a $93 million after-tax gain and $85 million of additional tax expense as a result of the July 1, 2021 sale of Sequent.
For year-to-date 2022, net income was $516 million compared to $389 million for the corresponding period in 2021. Net income increased $73 million at gas pipeline investments primarily as a result of a 2021 impairment charge related to the PennEast Pipeline project and $57 million at gas distribution operations primarily due to base rate increases and continued investment in infrastructure replacement. The year-to-date 2021 results also included $108 million of net income from Sequent, including the $93 million after-tax gain, and $85 million of additional tax expense as a result of the July 1, 2021 sale of Sequent.
See Notes 2, 7, and 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Natural Gas Revenues, including Alternative Revenue Programs
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $234 | | 37.6 | | $1,004 | | 33.5 |
In the third quarter 2022, natural gas revenues, including alternative revenue programs, were $857 million compared to $623 million for the corresponding period in 2021. For year-to-date 2022, natural gas revenues, including alternative revenue programs, were $4.0 billion compared to $3.0 billion for the corresponding period in 2021.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of the changes in natural gas revenues, including alternative revenue programs, were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 | | Year-To-Date 2022 |
| (in millions) | | (% change) | | (in millions) | | (% change) |
| Natural gas revenues – prior year | $ | 623 | | | | | $ | 2,994 | | | |
| Estimated change resulting from – | | | | | | | |
| Infrastructure replacement programs and base rate changes | 54 | | | 8.7 | % | | 186 | | | 6.2 | % |
| Gas costs and other cost recovery | 172 | | | 27.6 | | | 955 | | | 31.9 | |
| Gas marketing services | 1 | | | 0.2 | | | 14 | | | 0.5 | |
| Wholesale gas services | — | | | — | | | (187) | | | (6.2) | |
| | | | | | | |
| Other | 7 | | | 1.1 | | | 36 | | | 1.1 | |
| Natural gas revenues – current year | $ | 857 | | | 37.6 | % | | $ | 3,998 | | | 33.5 | % |
Revenues from infrastructure replacement programs and base rate changes increased in the third quarter and year-to-date 2022 compared to the corresponding periods in 2021 primarily due to rate increases at Nicor Gas, Atlanta Gas Light, and Chattanooga Gas and continued investment in infrastructure replacement. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" in Item 8 of the Form 10-K for additional information.
Revenues associated with gas costs and other cost recovery increased in the third quarter and year-to-date 2022 compared to the corresponding periods in 2021 primarily due to higher natural gas cost recovery. See "Cost of Natural Gas" herein for additional information. Revenue impacts from weather and customer growth are described further below.
Revenues from gas marketing services increased for year-to-date 2022 compared to the corresponding period in 2021 due to higher commodity prices and higher sales to commercial customers.
The changes in year-to-date 2022 revenues related to wholesale gas services were due to the sale of Sequent on July 1, 2021. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Southern Company Gas' natural gas distribution utilities have various regulatory mechanisms that limit their exposure to weather changes. Southern Company Gas also uses hedges for the majority of any remaining exposure to warmer-than-normal weather in Illinois for gas distribution operations and in Illinois and Georgia for gas marketing services; therefore, weather typically does not have a significant net income impact. The following table presents Heating Degree Days information for Illinois and Georgia, the primary locations where Southern Company Gas' operations are impacted by weather.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter | | 2022 vs. normal | 2022 vs. 2021 | | Year-to-Date | | 2022 vs. normal | 2022 vs. 2021 |
| Normal(*) | 2022 | 2021 | | colder (warmer) | colder (warmer) | | Normal(*) | 2022 | 2021 | | colder (warmer) | colder (warmer) |
| (in thousands) | | | | | (in thousands) | | | |
| Illinois | 42 | | 56 | | 14 | | | 33.3 | % | 300.0 | % | | 3,686 | | 3,683 | | 3,594 | | | (0.1) | % | 2.5 | % |
| Georgia | 3 | | — | | 3 | | | — | % | — | % | | 1,431 | | 1,361 | | 1,396 | | | (4.9) | % | (2.5) | % |
(*)Normal represents the 10-year average from January 1, 2012 through September 30, 2016. Alabama Power recorded2021 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.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
The following table provides the number of customers served by Southern Company Gas at September 30, 2022 and 2021:
| | | | | | | | | | | | | | | | | |
| September 30, | | |
| 2022 | | 2021 | | 2022 vs. 2021 |
| (in thousands, except market share %) | | (% change) |
| Gas distribution operations | 4,300 | | | 4,283 | | | 0.4 | % |
| Gas marketing services | | | | | |
Energy customers(*) | 598 | | | 603 | | | (0.8) | % |
| Market share of energy customers in Georgia | 28.3 | % | | 28.9 | % | | |
| | | | | |
| | | | | |
(*)Gas marketing services' customers are primarily located in Georgia and Illinois.
Southern Company Gas anticipates customer growth and uses a variety of targeted marketing programs to attract new customers and to retain existing customers.
Cost of Natural Gas
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $165 | | N/M | | $897 | | 95.1 |
Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations. Cost of natural gas at gas distribution operations represented 78% and 87% of the total cost of natural gas in the third quarter and year-to-date 2022, respectively. See MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – "Southern Company Gas – Cost of Natural Gas" in Item 7 of the Form 10-K and "Natural Gas Revenues, including Alternative Revenue Programs" herein for additional information.
In the third quarter 2022, cost of natural gas was $294 million compared to $129 million for the corresponding period in 2021. For year-to-date 2022, cost of natural gas was $1.8 billion compared to $943 million for the corresponding period in 2021. The increases reflect higher gas cost recovery as a result of increases of 104% and 113% in natural gas prices in the third quarter and year-to-date 2022, respectively, compared to the corresponding periods in 2021.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
The following table details the volumes of natural gas sold during all periods presented.
| | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter | 2022 vs. 2021 | | Year-to-Date | 2022 vs. 2021 |
| 2022 | 2021 | | 2022 | 2021 |
Gas distribution operations (mmBtu in millions) | | | | | | |
| Firm | 70 | | 74 | | (5.4) | % | | 485 | | 465 | | 4.3 | % |
| Interruptible | 22 | | 23 | | (4.3) | | | 69 | | 73 | | (5.5) | |
| Total | 92 | | 97 | | (5.2) | % | | 554 | | 538 | | 3.0 | % |
| | | | | | |
| | | | | | | |
Gas marketing services (mmBtu in millions) | | | | | | |
| Firm: | | | | | | | |
| Georgia | 3 | | 3 | | — | % | | 24 | | 26 | | (7.7) | % |
| Illinois | — | | — | | — | | | 4 | | 5 | | (20.0) | |
| | | | | | | |
| Other | 2 | | 2 | | — | | | 8 | | 10 | | (20.0) | |
| Interruptible large commercial and industrial | 3 | | 3 | | — | | | 11 | | 10 | | 10.0 | |
| Total | 8 | | 8 | | — | % | | 47 | | 51 | | (7.8) | % |
Other Operations and Maintenance Expenses
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $14 | | 5.9 | | $53 | | 6.8 |
In the third quarter 2022, other operations and maintenance expenses were $252 million compared to $238 million for the corresponding period in 2021. The increase was primarily due to higher compensation and benefit expenses and higher expenses passed through directly to customers primarily related to bad debt at gas distribution operations.
For year-to-date 2022, other operations and maintenance expenses were $829 million compared to $776 million for the corresponding period in 2021. Excluding $53 million of expenses related to Sequent for year-to-date 2021, other operations and maintenance expenses increased approximately $106 million. The increase was primarily due to increases of $47 million in compensation and benefit expenses, $30 million in expenses passed through directly to customers primarily related to bad debt at gas distribution operations, $18 million in customer accounts expenses, and $15 million in technology-related costs.
Depreciation and Amortization
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $7 | | 5.3 | | $18 | | 4.5 |
In the third quarter 2022, depreciation and amortization was $140 million compared to $133 million for the corresponding period in 2021. For year-to-date 2022, depreciation and amortization was $414 million compared to $396 million for the corresponding period in 2021. The increases were primarily due to continued infrastructure investments at the natural gas distribution utilities.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Taxes Other Than Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $9 | | 25.0 | | $42 | | 25.3 |
In the third quarter 2022, taxes other than income taxes were $45 million compared to $36 million for the corresponding period in 2021. For year-to-date 2022, taxes other than income taxes were $208 million compared to $166 million for the corresponding period in 2021. The increases primarily reflect an increase in revenue tax expenses as a result of higher natural gas revenues and an increase in invested capital tax expense at Nicor Gas. Revenue tax expenses are passed through directly to customers and have no impact on net income.
Gain on Dispositions, Net
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(121) | | (100.0) | | $(122) | | (96.1) |
The sale of Sequent in the third quarter 2021 resulted in a gain on dispositions, net of $121 million. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Earnings from Equity Method Investments
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $9 | | 36.0 | | $91 | | N/M |
In the third quarter 2022, earnings from equity method investments were $34 million compared to $25 million for the corresponding period in 2021. The increase was primarily due to higher earnings at SNG resulting from higher revenues primarily due to increased demand.
For year-to-date 2022, earnings from equity method investments were $105 million compared to $14 million for the corresponding period in 2021. The increase was primarily due to pre-tax impairment charges totaling $84 million in 2021 related to the PennEast Pipeline project and higher earnings at SNG resulting from higher revenues primarily due to increased demand.
See Note 7 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements herein under "Southern Company Gas" for additional information.
Other Income (Expense), Net
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $2 | | 15.4 | | $113 | | N/M |
For year-to-date 2022, other income (expense), net was $47 million of income compared to $66 million of expense for the corresponding period in 2021. The change was largely due to charitable contributions totaling $101 million during the first and second quarters of 2021 and an increase of $12 million at gas distribution operations primarily related to an increase in non-service cost-related retirement benefits income. See Note (H) to the Condensed Financial Statements herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(106) | | (79.7) | | $(63) | | (28.1) |
In the third quarter 2022, income taxes were$27 million compared to $133 million for the corresponding period in 2021. For year-to-date 2022, income taxes were $161 million compared to $224 million for the corresponding period in 2021. The decreases were primarily the result of $113 million in additional tax expense in the third quarter 2021 as a result of the sale of Sequent. Partially offsetting the third quarter 2022 decrease was an increase of $9 million in income tax expense at gas distribution operations primarily as a result of higher pre-tax earnings. The year-to-date 2022 decrease was partially offset by increases in fair valueincome tax expense of $25 million at gas distribution operations primarily as a result of higher pre-tax earnings and $87$20 million at gas pipeline investments primarily from $18 million of tax benefits resulting from the impairment charge in the second quarter 2021 related to the PennEast Pipeline project. See Notes 7 and 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Segment Information
Operating revenues, operating expenses, and net income (loss) for each segment are provided in the table below. See Note (L) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2022 | | 2021 |
| Operating Revenues | | Operating Expenses | | Net Income (Loss) | | Operating Revenues | | Operating Expenses | | Net Income (Loss) |
| (in millions) | | (in millions) |
| Third Quarter |
| Gas distribution operations | $ | 751 | | | $ | 629 | | | $ | 59 | | | $ | 556 | | | $ | 459 | | | $ | 45 | |
| Gas pipeline investments | 8 | | | 3 | | | 24 | | | 8 | | | 3 | | | 10 | |
Wholesale gas services(*) | — | | | — | | | — | | | — | | | (120) | | | 94 | |
| Gas marketing services | 85 | | | 87 | | | (2) | | | 52 | | | 52 | | | (2) | |
| All other | 16 | | | 12 | | | 2 | | | 11 | | | 25 | | | (91) | |
| Intercompany eliminations | (3) | | | — | | | — | | | (4) | | | (4) | | | — | |
| Consolidated | $ | 857 | | | $ | 731 | | | $ | 83 | | | $ | 623 | | | $ | 415 | | | $ | 56 | |
| | | | | | | | | | | |
| Year-to-Date |
| Gas distribution operations | $ | 3,533 | | | $ | 2,922 | | | $ | 365 | | | $ | 2,466 | | | $ | 1,936 | | | $ | 308 | |
| Gas pipeline investments | 24 | | | 8 | | | 76 | | | 24 | | | 9 | | | 3 | |
Wholesale gas services(*) | — | | | — | | | — | | | 188 | | | (53) | | | 108 | |
| Gas marketing services | 420 | | | 327 | | | 65 | | | 311 | | | 226 | | | 60 | |
| All other | 43 | | | 48 | | | 10 | | | 29 | | | 60 | | | (90) | |
| Intercompany eliminations | (22) | | | (19) | | | — | | | (24) | | | (24) | | | — | |
| Consolidated | $ | 3,998 | | | $ | 3,286 | | | $ | 516 | | | $ | 2,994 | | | $ | 2,154 | | | $ | 389 | |
(*)As a result of the sale of Sequent, wholesale gas services is no longer a reportable segment for the third quarter and year-to-date 2022. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K 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 regulatory 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
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
gas delivered to its customers and its fixed and variable costs, including depreciation, interest expense, operations and maintenance, taxes, and overhead costs, and to earn a reasonable return on its investments.
With the exception of Atlanta Gas Light, Southern Company Gas' second largest utility that operates in a deregulated natural gas market and has a straight-fixed-variable rate design that minimizes the variability of its revenues based on consumption, the earnings of the natural gas distribution utilities can be affected by customer consumption patterns that are a function of weather conditions, price levels for natural gas, and general economic conditions that may impact customers' ability to pay for natural gas consumed. Southern Company Gas has various regulatory and other mechanisms, such as weather and revenue normalization mechanisms and weather derivative instruments, that limit its exposure to changes in customer consumption, including weather changes within typical ranges in its natural gas distribution utilities' service territories. See Note 2 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
In the third quarter and year-to-date 2022, net income increased $14 million, or 31.1%, and $57 million, or 18.5%, respectively, when compared to the corresponding periods in 2021, as described further below:
•Operating revenues increased $195 million and $1.07 billion, respectively, when compared to the corresponding periods in 2021 primarily due to higher gas cost recovery, rate increases, and continued investment in infrastructure replacement. Gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas.
•Operating expenses increased $170 million and $986 million, respectively, when compared to the corresponding periods in 2021 primarily due to increases of $129 million and $802 million, respectively, in the cost of gas as a result of higher natural gas prices compared to 2021, higher compensation and benefit expenses, and higher depreciation resulting from additional assets placed in service. The increase in operating expenses also includes higher costs passed through directly to customers, primarily related to bad debt expenses and revenue taxes.
•Other income and (expense) increased $3 million and $12 million, respectively, when compared to the corresponding periods in 2021, primarily due to an increase in non-service cost-related retirement benefits income. See Note (H) to the Condensed Financial Statements herein for additional information.
•Interest expense, net of amounts capitalized increased $5 million and $11 million, respectively, when compared to the corresponding periods in 2021 primarily due to additional debt issued to finance continued investments. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings.
•Income taxes increased $9 million and $25 million, respectively, when compared to the corresponding periods in 2021 primarily due to higher pre-tax earnings.
Gas Pipeline Investments
Gas pipeline investments consists primarily of joint ventures in natural gas pipeline investments including SNG, Dalton Pipeline, and PennEast Pipeline. See Note (E) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
In the third quarter 2022, net income increased $14 million when compared to the corresponding period in 2021 primarily due to higher earnings at SNG resulting from higher revenues primarily due to increased demand and lower income taxes related to the PennEast Pipeline project.
For year-to-date 2022, net income increased $73 million when compared to the corresponding period in 2021 primarily due to pre-tax impairment charges totaling $84 million ($67 million after tax) in 2021 related to the equity method investment in the PennEast Pipeline project and higher earnings at SNG resulting from higher revenues primarily due to increased demand. See Note 7 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Gas Marketing Services
Gas marketing services provides energy-related products and services to natural gas markets and participants in customer choice programs that were approved in various states to increase competition. These programs allow customers to choose their natural gas supplier while the local distribution utility continues to provide distribution and transportation services. Gas marketing services is weather sensitive and uses a variety of hedging strategies, such as weather derivative instruments and other risk management tools, to partially mitigate potential weather impacts.
In the third quarter 2022, net income was flat when compared to the corresponding period in 2021 primarily due to an increase of $35 million in operating expenses primarily due to higher cost of gas, largely offset by a related increase of $33 million in operating revenues.
For year-to-date 2022, net income increased $5 million, or 8.3%, when compared to the corresponding period in 2021 primarily due to a $109 million increase in operating revenues as a result of higher commodity prices and higher sales to commercial customers, partially offset by a $101 million increase in operating expenses primarily due to $95 million in higher cost of natural gas and an increase of $4 million in income taxes as a result of higher pre-tax earnings.
All Other
All other includes natural gas storage businesses, a renewable natural gas business, 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. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for information regarding agreements by certain affiliates of Southern Company Gas to sell two natural gas storage facilities.
In the third quarter 2022, net income increased $93 million when compared to the corresponding period in 2021. The change primarily relates to additional tax expense as a result of the sale of Sequent in 2021 and a decrease of $13 million in operating expenses related to lower depreciation in 2022 and transaction costs in 2021 related to the sale of Sequent.
For year-to-date 2022, net income increased $100 million when compared to the corresponding period in 2021. The change primarily relates to additional tax expense as a result of the sale of Sequent in 2021 and an increase in operating revenues of $14 million primarily related to higher demand fees and favorable hedge gains at the natural gas storage businesses, higher sales from the renewable natural gas business, and lower depreciation in 2022.
FUTURE EARNINGS POTENTIAL
Each Registrant's results of operations are not necessarily indicative of its future earnings potential. The level of the Registrants' future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Registrants' primary businesses of selling electricity and/or distributing natural gas, as described further herein.
For the traditional electric operating companies, these factors include the ability to maintain constructive regulatory environments that allow for the threetimely recovery of prudently-incurred costs during a time of increasing costs, including those related to projected long-term demand growth, stringent environmental standards, including CCR rules, safety, system reliability and resiliency, fuel, restoration following major storms, and capital expenditures, including constructing new electric generating plants and expanding and improving the transmission and distribution systems; continued customer growth; and the trends of higher inflation and reduced electricity usage per customer, especially in residential and commercial markets. For Georgia Power, completing construction of Plant Vogtle Units 3 and 4 and the related cost recovery proceedings is another major factor.
Earnings in the electricity business will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions, which could contribute to a net reduction in customer usage.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Global and U.S. economic conditions have been significantly affected by a series of demand and supply shocks that caused a global and national economic recession in 2020. The drivers, speed, and depth of the 2020 economic contraction were unprecedented and continue to reduce energy demand across the Southern Company system's service territory, primarily in the commercial class. Retail electric revenues attributable to changes in sales increased in the first nine months ended September 30, 2017 and $26 million and $66 million, respectively,of 2022 when compared to the corresponding period in 2021 primarily due to the normalization of economic activity; however, total retail electric sales for the threeSouthern Company system continued to be negatively impacted by the COVID-19 pandemic when compared to pre-pandemic trends. Most prominently, the COVID-19 pandemic has negatively impacted global supply chains and business operations as suppliers continue to experience difficulties keeping up with strong demand for factory goods, which is being driven by low business inventories. In addition, rising inflation in 2021 and 2022 has resulted in increasing costs for many goods and services. As a result of persistently high inflation, interest rates have been on the rise and are expected to continue rising in the near term, which has impacted, and may continue to impact, the Registrants' borrowing costs. Based on these factors, the probability of the U.S. economy falling into a recession has heightened. The impacts of new COVID-19 variants, responses to the COVID-19 pandemic by both customers and governments, ongoing geopolitical threats, such as the escalation of the Russia-Ukraine war, and the potential of future COVID-19-related lockdowns in Asia or elsewhere could further disrupt global supply chains and increase the severity of a possible economic downturn in the Southern Company system's service territory. See RESULTS OF OPERATIONS herein for information on COVID-19-related impacts on energy demand in the Southern Company system's service territory during the first nine months ended September 30, 2016of 2022.
The level of future earnings for Southern Power's competitive wholesale electric business depends on numerous factors including the parameters of the wholesale market and the efficient operation of its wholesale generating assets; Southern Power's ability to execute its growth strategy through the development or acquisition of renewable facilities and other energy projects while containing costs; regulatory matters; customer creditworthiness; total electric generating capacity available in Southern Power's market areas; Southern Power's ability to successfully remarket capacity as a changecurrent contracts expire; renewable portfolio standards; availability of federal and state ITCs and PTCs, which could be impacted by future tax legislation; transmission constraints; cost of generation from units within the Southern Company power pool; and operational limitations. See "Income Tax Matters" herein for additional information on recent tax legislation expanding the availability of federal ITCs and PTCs.
The level of future earnings for Southern Company Gas' primary business of distributing natural gas and its complementary businesses in the gas pipeline investments and gas marketing services sectors depends on numerous factors. These factors include the natural gas distribution utilities' ability to maintain constructive regulatory liabilitiesenvironments that allow for the timely recovery of prudently-incurred costs, including those related to projected long-term demand growth, safety, system reliability and resiliency, natural gas, and capital expenditures, including expanding and improving the natural gas distribution systems; the completion and subsequent operation of ongoing infrastructure and other construction projects; customer creditworthiness; and certain policies to limit the use of natural gas, such as the potential across certain parts of the U.S. for state or municipal bans on the use of natural gas. The volatility of natural gas prices has an impact on Southern Company Gas' customer rates, its AROs.long-term competitive position against other energy sources, and the ability of Southern Company Gas' gas marketing services business to capture value from locational and seasonal spreads. Additionally, changes in commodity prices, primarily driven by tight gas supplies, geopolitical events, and diminished gas production, subject a portion of Southern Company Gas' operations to earnings variability and have recently resulted in higher natural gas prices. Additional economic factors may contribute to this environment. 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. Alternatively, a significant drop in oil and natural gas prices could lead to a consolidation of natural gas producers or reduced levels of natural gas production.
Earnings for both the electricity and natural gas businesses are subject to a variety of other factors. These factors include weather; competition; developing new and maintaining existing energy contracts and associated load requirements with wholesale customers; energy conservation practiced by customers; the use of alternative energy sources by customers; government incentives to reduce overall energy usage; the prices of electricity and natural
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
gas; costs and availability of labor and materials in a time of rising costs, impacted by heightened inflation caused by unprecedented shocks to the broader economy, and supply chain disruptions; and the price elasticity of demand. Demand for electricity and natural gas in the Registrants' service territories is primarily driven by the pace of economic growth or decline that may be affected by changes in regional and global economic conditions, which may impact future earnings.
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, or the sale of interests in, certain assets or businesses, internal restructuring, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations, risks, and financial condition of Southern Company. In addition, Southern Power and Southern Company Gas regularly consider and evaluate joint development arrangements as well as acquisitions and dispositions of businesses and assets as part of their business strategies. See Note 15 to the financial statements in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements herein for additional information.
For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL in Item 7 of the Form 10-K.
Environmental Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" in Item 7 and Note 3 to the financial statements under "Environmental Remediation" in Item 8 of the Form 10-K, as well as Note (C) to the Condensed Financial Statements under "General Litigation Matters" and "Environmental Remediation" herein, for additional information.
Environmental Laws and Regulations
Air Quality
On August 30, 2022, the EPA found that 15 states, including Alabama and Mississippi, failed to submit regional haze state implementation plans for the second 10-year planning period (2018 through 2028) by July 31, 2021. The finding of failure to submit establishes a two-year deadline for the EPA to promulgate a Federal Implementation Plan (FIP) to address these requirements for each applicable state unless, before the EPA promulgates a FIP, the state submits, and the EPA approves, a state implementation plan that meets the requirements. The ultimate outcome of this matter, including any potential impacts to Alabama Power, Mississippi Power, and Southern Power, cannot be determined at this time.
Global Climate Issues
On June 30, 2022, the U.S. Supreme Court issued an opinion limiting the EPA's authority to regulate greenhouse gas emissions under the Clean Air Act. The Court's review in the case focused on whether the EPA's authority under the Clean Air Act allows the EPA to regulate the electric industry in a manner as broad as the Clean Power Plan (CPP), which was repealed and replaced by the Affordable Clean Energy rule (ACE Rule). The Court held that the generation shifting to lower carbon emitting sources approach in the CPP is not authorized by the Clean Air Act. However, the Court did not decide whether the EPA may adopt measures only applied at the individual electric generating source, which is the basis for the ACE Rule. The EPA has announced its intent to propose a rule for existing power plants pursuant to the Clean Air Act by March 2023. The ultimate impact of the Court's decision cannot be determined at this time.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Regulatory Matters
See Note 2 to the financial statements in Item 8 of the Form 10-K, OVERVIEW – "Recent Developments" herein, and Note (B) to the Condensed Financial Statements herein for a discussion of regulatory matters related to Alabama Power, Georgia Power, recorded increasesMississippi Power, and Southern Company Gas, including items that could impact the applicable Registrants' future earnings, cash flows, and/or financial condition.
Alabama Power
On September 23, 2022, the FERC authorized Alabama Power to use updated depreciation rates from its 2021 depreciation study effective January 1, 2023. The study was also provided to the Alabama PSC, and the new depreciation rates will be reflected in fair valueAlabama Power's future rate filings. The updated depreciation rates are expected to result in an approximately $500 million increase in annual depreciation expense. See Notes 2 and 5 to the financial statements under "Alabama Power" and "Depreciation and Amortization," respectively, in Item 8 of $25 millionthe Form 10-K for additional information.
Construction Programs
The Subsidiary Registrants are engaged in continuous construction programs to accommodate existing and $81 million, respectively,estimated future loads on their respective systems. The Southern Company system strategy continues to include developing and constructing new electric generating facilities, expanding and improving the electric transmission and electric and natural gas distribution systems, and undertaking projects to comply with environmental laws and regulations.
For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. The largest construction project currently underway in the Southern Company system is Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information. Also see Note 2 to the threefinancial statements under "Alabama Power – Certificates of Convenience and nine months ended September 30, 2017Necessity" in Item 8 of the Form 10-K for information regarding Alabama Power's construction of Plant Barry Unit 8.
See Note 15 to the financial statements in Item 8 of the Form 10-K and $23 millionNote (K) to the Condensed Financial Statements herein under "Southern Power" for information about costs relating to Southern Power's construction of renewable energy facilities.
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, reduce emissions, and $50 million, respectively,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 Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Southern Company Gas" for additional information on Southern Company Gas' construction program.
See FINANCIAL CONDITION AND LIQUIDITY – "Cash Requirements" herein for additional information regarding the three and nine months ended September 30, 2016 as a change in its regulatory asset related to its AROs.Registrants' capital requirements for their construction programs.
Valuation Methodologies
The energy-related derivatives primarily consist of exchange-traded and over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The fair value of cross-currency swaps reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and discount rates. The interest rate derivatives and cross-currency swaps are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note (H)(J) for additional information on how these derivatives are used.
The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. For fair value measurements of the investments within the nuclear decommissioning trusts 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 16 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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Southern Power has contingent payment obligations related to certain acquisitions whereby Southern Powerit is primarily obligated to make generation-based payments to the seller, over a period ranging from 10 to 30 years, beginningwhich commenced at the commercial operation date.of the respective facility and continue through 2026. The obligation isobligations are 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, and is evaluated periodically.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.
Southern Power also has payment obligations through 2040 whereby it must reimburse the transmission owners for interconnection facilities and network upgrades constructed to support connection of a Southern Power generating facility to the transmission system. The obligations are categorized as Level 2 under Fair Value Measurements as the fair value is determined using observable inputs for the contracted amounts and reimbursement period, as well as a discount rate. The fair value of the obligations reflects the net present value of expected payments.
"Other investments" include investments that are not traded in the open market. The fair valuemarket that have maturities greater than 90 days, which are categorized as Level 2 under Fair Value Measurements and are comprised of these investments has been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan executions.corporate bonds, bank certificates of deposit, treasury bonds, and/or agency bonds.
As ofAt September 30, 2017,2022, the fair value measurements of private equity investments held in theAlabama Power's nuclear decommissioning trusttrusts that are calculated at net asset value per share (or its equivalent) as a practical expedient as well astotaled $156 million and unfunded commitments related to the nature and risks of thoseprivate equity investments were as follows:
|
| | | | | | | | | | | |
| As of September 30, 2017: | Fair Value | | Unfunded Commitments | | Redemption Frequency | | Redemption Notice Period |
| | (in millions) | | | | |
| Southern Company | $ | 26 |
| | $ | 24 |
| | Not Applicable | | Not Applicable |
| Alabama Power | $ | 26 |
| | $ | 24 |
| | Not Applicable | | Not Applicable |
totaled $84 million. Private equity fundsinvestments include a fund-of-funds that invests in high-quality private equity funds across several market sectors and funds that invest in real estate assets, and a fund that acquires companies to create resale value.assets. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated. Liquidations are expected to occur at various times over the next 10 years.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
As ofAt September 30, 2017,2022, 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 billions) |
| Long-term debt, including securities due within one year: | | | | |
| Carrying amount | $ | 53.4 | | $ | 10.8 | | $ | 14.5 | | $ | 1.5 | | $ | 2.9 | | $ | 7.4 | |
| Fair value | 46.4 | | 9.3 | | 12.6 | | 1.2 | | 2.7 | | 6.3 | |
|
| | | | | | | |
| | Carrying Amount | | Fair Value |
| | (in millions) |
| Long-term debt, including securities due within one year: | | | |
| Southern Company | $ | 47,269 |
| | $ | 49,348 |
|
| Alabama Power | $ | 7,404 |
| | $ | 8,031 |
|
| Georgia Power | $ | 11,713 |
| | $ | 12,237 |
|
| Gulf Power | $ | 1,292 |
| | $ | 1,352 |
|
| Mississippi Power | $ | 2,123 |
| | $ | 2,117 |
|
| Southern Power | $ | 5,810 |
| | $ | 5,916 |
|
| Southern Company Gas | $ | 5,862 |
| | $ | 6,230 |
|
The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas.
Earnings per Share
For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under the stock option and performance share plans. See Note 8 to the financial statements of Southern Company in Item 8 of the Form 10-K for information on the stock option and performance share plans. The effect of both stock options and performance share award units was determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:Registrants.
|
| | | | | | | | |
| | Three Months Ended September 30, 2017 | Three Months Ended September 30, 2016 | Nine Months Ended September 30, 2017 | Nine Months Ended September 30, 2016 |
| | (in millions) |
| As reported shares | 1,003 |
| 968 |
| 998 |
| 940 |
|
| Effect of options and performance share award units | 7 |
| 7 |
| 7 |
| 5 |
|
| Diluted shares | 1,010 |
| 975 |
| 1,005 |
| 945 |
|
Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were immaterial for the three and nine months ended September 30, 2017 and 2016.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS:STATEMENTS (Continued)
(UNAUDITED)
Changes in Stockholders' Equity(J) DERIVATIVES
The following table presents year-to-date changes in stockholders' equity of Southern Company:
|
| | | | | | | | | | | | | | | | | |
| | Number of Common Shares | | Common
Stockholders'
Equity | Preferred and Preference Stock of Subsidiaries | | Total
Stockholders'
Equity |
| | Issued | Treasury | | Noncontrolling Interests(*) |
| | (in thousands) | | (in millions) |
| Balance at December 31, 2016 | 991,213 |
| (819 | ) | | $ | 24,758 |
| $ | 609 |
| $ | 1,245 |
| $ | 26,612 |
|
| Consolidated net income attributable to Southern Company | — |
| — |
| | 347 |
| — |
| — |
| 347 |
|
| Other comprehensive income (loss) | — |
| — |
| | (2 | ) | — |
| — |
| (2 | ) |
| Stock issued | 13,308 |
| — |
| | 613 |
| — |
| — |
| 613 |
|
| Stock-based compensation | — |
| — |
| | 97 |
| — |
| — |
| 97 |
|
| Cash dividends on common stock | — |
| — |
| | (1,716 | ) | — |
| — |
| (1,716 | ) |
| Preference stock redemption | — |
| — |
| | — |
| (150 | ) | — |
| (150 | ) |
| Contributions from noncontrolling interests | — |
| — |
| | — |
| — |
| 77 |
| 77 |
|
| Distributions to noncontrolling interests | — |
| — |
| | — |
| — |
| (87 | ) | (87 | ) |
| Net income attributable to noncontrolling interests | — |
| — |
| | — |
| — |
| 45 |
| 45 |
|
| Reclassification from redeemable noncontrolling interests | — |
| — |
| | — |
| — |
| 114 |
| 114 |
|
| Other | — |
| (75 | ) | | (15 | ) | 3 |
| 1 |
| (11 | ) |
| Balance at September 30, 2017 | 1,004,521 |
| (894 | ) | | $ | 24,082 |
| $ | 462 |
| $ | 1,395 |
| $ | 25,939 |
|
| | | | | | | | |
| Balance at December 31, 2015 | 915,073 |
| (3,352 | ) | | $ | 20,592 |
| $ | 609 |
| $ | 781 |
| $ | 21,982 |
|
| Consolidated net income attributable to Southern Company | — |
| — |
| | 2,251 |
| — |
| — |
| 2,251 |
|
| Other comprehensive income (loss) | — |
| — |
| | (95 | ) | — |
| — |
| (95 | ) |
| Stock issued | 65,725 |
| 2,599 |
| | 3,265 |
| — |
| — |
| 3,265 |
|
| Stock-based compensation | — |
| — |
| | 94 |
| — |
| — |
| 94 |
|
| Cash dividends on common stock | — |
| — |
| | (1,553 | ) | — |
| — |
| (1,553 | ) |
| Contributions from noncontrolling interests | — |
| — |
| | — |
| — |
| 357 |
| 357 |
|
| Distributions to noncontrolling interests | — |
| — |
| | — |
| — |
| (21 | ) | (21 | ) |
| Purchase of membership interests from noncontrolling interests | — |
| — |
| | — |
| — |
| (129 | ) | (129 | ) |
| Net income attributable to noncontrolling interests | — |
| — |
| | — |
| — |
| 36 |
| 36 |
|
| Other | — |
| (46 | ) | | (7 | ) | — |
| — |
| (7 | ) |
| Balance at September 30, 2016 | 980,798 |
| (799 | ) | | $ | 24,547 |
| $ | 609 |
| $ | 1,024 |
| $ | 26,180 |
|
| |
(*) | Related to Southern Power Company and excludes redeemable noncontrolling interests. In April 2017, approximately $114 million was reclassified from redeemable noncontrolling interests to noncontrolling interests, included in stockholder's equity, due to the expiration of SunPower Corp's option to require Southern Power to purchase its membership interests in one of the solar partnerships. See Note 10 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Going Concern
As of September 30, 2017, Mississippi Power's current liabilities exceeded current assets by approximately $769 million primarily due to approximately $935 million that will be required through September 30, 2018 to fund maturities of long-term debt and $4 million that will be required to fund maturities of short-term debt. In addition, Mississippi Power has $40 million of tax-exempt variable rate demand obligations that are supported by short-term credit facilities and $50 million of fixed rate pollution control revenue bonds that are required to be remarketed over the next 12 months. Mississippi Power intends to utilize operating cash flows, lines of credit, and bank term loans, as market conditions permit, as well as, under certain circumstances, commercial paper and/or equity contributions and/or loans from Southern Company to fund Mississippi Power's short-term capital needs. Specifically, Mississippi Power has been informed by Southern Company that in the event sufficient funds are not available from external sources, Southern Company intends to provide Mississippi Power with loans and/or equity contributions sufficient to fund the remaining indebtedness scheduled to mature and other cash needs over the next 12 months. Therefore, Mississippi Power's financial statement presentation contemplates continuation of Mississippi Power as a going concern as a result of Southern Company's anticipated ongoing financial support of Mississippi Power. For additional information, see Notes 1 and 6 to the financial statements of Mississippi Power under "Recently Issued Accounting Standards" and "Going Concern," respectively, in Item 8 of the Form 10-K and Note (B) under "Integrated Coal Gasification Combined Cycle."
DOE Loan Guarantee Borrowings
See Note 6 to the financial statements of Southern Company and Georgia Power in Item 8 of the Form 10-K for additional information regarding Georgia Power's Loan Guarantee Agreement with the DOE and related multi-advance term loan facility (FFB Credit Facility) with the FFB.
On July 27, 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement (LGA Amendment) in connection with the DOE's consent to Georgia Power's entry into the Services Agreement and the related intellectual property licenses (IP Licenses).
Under the terms of the Loan Guarantee Agreement, upon termination of the Vogtle 3 and 4 Agreement, further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement. Under the terms of the LGA Amendment, Georgia Power will not request any advances unless and until such time as Georgia Power has (i) completed the cost-to-complete and cancellation cost assessments prepared as a result of the bankruptcy of the EPC Contractor (Cost Assessments) and made a determination to continue construction of Plant Vogtle Units 3 and 4, (ii) delivered to the DOE an updated project schedule, construction budget, and other information, (iii) entered into one or more agreements with a construction contractor or contractors that will be primarily responsible for construction of Plant Vogtle Units 3 and 4 and such agreements have been approved by the DOE (together with the Services Agreement and the IP Licenses, the Replacement EPC Arrangements), and (iv) entered into a further amendment to the Loan Guarantee Agreement with the DOE to reflect the Replacement EPC Arrangements.
Upon satisfaction of the conditions described above, advances may be requested under the FFB Credit Facility on a quarterly basis through 2020. The final maturity date for each advance under the FFB Credit Facility is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20, 2020. Borrowings under the FFB Credit Facility will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375%.
In addition to the conditions described above, future advances are subject to satisfaction of customary conditions, as well as certification of compliance with the requirements of the Title XVII Loan Guarantee Program, accuracy of project-related representations and warranties, delivery of updated project-related information, absence of liens on Georgia Power's ownership interest in Plant Vogtle Units 3 and 4 other than permitted liens, evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act of 1931, as amended, and certification from the DOE's consulting engineer that proceeds of the advances are used to reimburse Eligible Project Costs.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Under the Loan Guarantee Agreement, Georgia Power is subject to customary borrower affirmative and negative covenants and events of default. In addition, Georgia Power is subject to project-related reporting requirements and other project-specific covenants and events of default.
In the event certain mandatory prepayment events occur, the FFB's commitment to make further advances under the FFB Credit Facility will terminate and Georgia Power will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facility over a period of five years (with level principal amortization). Among other things, these mandatory prepayment events include (i) the termination of the Services Agreement or rejection of the Services Agreement in bankruptcy if Georgia Power does not maintain access to intellectual property rights under the IP Licenses; (ii) a decision by Georgia Power not to continue construction of Plant Vogtle Units 3 and 4; (iii) a failure by Georgia Power to complete the Cost Assessments or enter into Replacement EPC Arrangements by December 31, 2017; (iv) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC, or by Georgia Power if authorized by the Georgia PSC; and (v) cost disallowances by the Georgia PSC that could have a material adverse effect on completion of Plant Vogtle Units 3 and 4 or Georgia Power's ability to repay the outstanding borrowings under the FFB Credit Facility. Under certain circumstances, insurance proceeds and any proceeds from an event of taking must be applied to immediately prepay outstanding borrowings under the FFB Credit Facility. In addition, under certain circumstances Georgia Power may be required to make additional prepayments in connection with its receipt of payments under the Guarantee Settlement Agreement or from the EPC Contractor under the Vogtle 3 and 4 Agreement. Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facility. Under the FFB Credit Facility, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable.
On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion of additional guaranteed loans under the Loan Guarantee Agreement. Final approval and issuance of these additional loan guarantees by the DOE cannot be 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 (B) under "Regulatory Matters – Georgia Power – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.
Bank Credit Arrangements
Bank credit arrangements provide liquidity support to the registrants' commercial paper borrowings and the traditional electric operating companies' pollution control revenue bonds. The amount of variable rate pollution control revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of September 30, 2017 was approximately $1.5 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia Power, $82 million at Gulf Power, and $40 million at Mississippi Power). In June 2017, Georgia Power remarketed $318 million of variable rate pollution control bonds in index rate modes, reducing the liquidity support utilized under Georgia Power's bank credit arrangement. In addition, at September 30, 2017, the traditional electric operating companies had approximately $699 million (comprised of approximately $509 million at Georgia Power, $140 million at Gulf Power, and $50 million at Mississippi Power) of pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to September 30, 2017, $40 million of these pollution control revenue bonds of Georgia Power which were in an index rate mode were remarketed to the public in a long-term fixed rate mode. See Note 6 to the financial statements of each registrant under "Bank Credit Arrangements" in Item 8 of the Form 10-K and "Financing Activities" herein for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
The following table outlines the committed credit arrangements by company as of September 30, 2017:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Expires | | | | Executable Term Loans | | Expires Within One Year |
| Company | 2017 | 2018 | 2019 | 2020 | 2022 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out |
| | (in millions) |
Southern Company(a) | $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 2,000 |
| | $ | 2,000 |
| | $ | 2,000 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Alabama Power | — |
| 35 |
| — |
| 500 |
| 800 |
| | 1,335 |
| | 1,335 |
| | — |
| | — |
| | — |
| | 35 |
|
| Georgia Power | — |
| — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,732 |
| | — |
| | — |
| | — |
| | — |
|
| Gulf Power | 30 |
| 195 |
| 25 |
| 30 |
| — |
| | 280 |
| | 280 |
| | 45 |
| | — |
| | — |
| | 40 |
|
| Mississippi Power | 100 |
| — |
| — |
| — |
| — |
| | 100 |
| | 100 |
| | — |
| | — |
| | — |
| | 100 |
|
Southern Power Company(b) | — |
| — |
| — |
| — |
| 750 |
| | 750 |
| | 728 |
| | — |
| | — |
| | — |
| | — |
|
Southern Company Gas(c) | — |
| — |
| — |
| — |
| 1,900 |
| | 1,900 |
| | 1,861 |
| | — |
| | — |
| | — |
| | — |
|
| Other | — |
| 30 |
| — |
| — |
| — |
| | 30 |
| | 30 |
| | 20 |
| | — |
| | 20 |
| | 10 |
|
| Southern Company Consolidated | $ | 130 |
| $ | 260 |
| $ | 25 |
| $ | 530 |
| $ | 7,200 |
| | $ | 8,145 |
| | $ | 8,066 |
| | $ | 65 |
| | $ | — |
| | $ | 20 |
| | $ | 185 |
|
| |
(a) | Represents the Southern Company parent entity. |
| |
(b) | Does not include Southern Power's $120 million continuing letter of credit facility for standby letters of credit expiring in 2019, of which $111 million has been used for letters of credit and $9 million remains unused at September 30, 2017.
|
| |
(c) | Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.2 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $700 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas.
|
As reflected in the table above, in May 2017, Southern Company, Alabama Power, Georgia Power, and Southern Power Company each amended certain of their multi-year credit arrangements, which, among other things, extended the maturity dates from 2020 to 2022. Southern Company and Southern Power Company increased their borrowing ability under these arrangements to $2.0 billion from $1.25 billion and to $750 million from $600 million, respectively. Southern Company also terminated its $1.0 billion facility maturing in 2018. Also in May 2017, Southern Company Gas Capital and Nicor Gas terminated their existing credit arrangements for $1.3 billion and $700 million, respectively, which were to mature in 2017 and 2018, and entered into a new multi-year credit arrangement currently allocated for $1.2 billion and $700 million, respectively, with a maturity date of 2022. Pursuant to the new multi-year credit arrangement, the allocations may be adjusted. In September 2017, Alabama Power amended its $500 million multi-year credit arrangement, which, among other things, extended the maturity date from 2018 to 2020.
Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Financing Activities
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first nine months of 2017:
|
| | | | | | | | | | | | | | | | | | | |
| Company | Senior Note Issuances | | Senior Note Maturities and Redemptions | | Revenue Bond
Maturities, Redemptions, and
Repurchases | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(a) |
| | (in millions) |
Southern Company(b) | $ | 300 |
| | $ | 400 |
| | $ | — |
| | $ | 500 |
| | $ | 400 |
|
| Alabama Power | 550 |
| | 200 |
| | 36 |
| | — |
| | — |
|
| Georgia Power | 1,350 |
| | 450 |
| | 65 |
| | 370 |
| | 13 |
|
| Gulf Power | 300 |
| | 85 |
| | — |
| | 6 |
| | — |
|
| Mississippi Power | — |
| | — |
| | — |
| | 40 |
| | 893 |
|
| Southern Power | — |
| | — |
| | — |
| | 43 |
| | 4 |
|
Southern Company Gas(c) | 450 |
| | — |
| | — |
| | 200 |
| | 22 |
|
| Other | — |
| | — |
| | — |
| | — |
| | 12 |
|
Elimination(d) | — |
| | — |
| | — |
| | (40 | ) | | (599 | ) |
| Southern Company Consolidated | $ | 2,950 |
| | $ | 1,135 |
| | $ | 101 |
| | $ | 1,119 |
| | $ | 745 |
|
| |
(a) | Includes reductions in capital lease obligations resulting from cash payments under capital leases. |
| |
(b) | Represents the Southern Company parent entity. |
| |
(c) | The senior notes were issued by Southern Company Gas Capital and guaranteed by the Southern Company Gas parent entity. Other long-term debt issued represents first mortgage bonds issued by Nicor Gas.
|
| |
(d) | Includes intercompany loans from Southern Company to Mississippi Power and reductions in affiliate capital lease obligations at Georgia Power. These transactions are eliminated in Southern Company's Consolidated Financial Statements. |
Southern Company
In June 2017, Southern Company issued $500 million aggregate principal amount of Series 2017A 5.325% Junior Subordinated Notes due June 21, 2057 and $300 million aggregate principal amount of Series 2017A Floating Rate Senior Notes due September 30, 2020, which bear interest at a floating rate based on three-month LIBOR. The proceeds were used to repay short-term indebtedness and for other general corporate purposes.
Also in June 2017, Southern Company entered into two $100 million aggregate principal amount floating rate bank term loan agreements, which mature on June 21, 2018 and June 29, 2018 and bear interest based on one-month LIBOR. The proceeds were used for working capital and other general corporate purposes.
In August 2017, Southern Company borrowed $250 million pursuant to an uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Southern Company and the bank from time to time and is payable on no less than 30 days' demand by the bank. The proceeds were used for working capital and other general corporate purposes.
Alabama Power
In March 2017, Alabama Power issued $550 million aggregate principal amount of Series 2017A 2.45% Senior Notes due March 30, 2022. The proceeds were used to repay Alabama Power's short-term indebtedness and for general corporate purposes, including Alabama Power's continuous construction program.
In September 2017, Alabama Power issued 10 million shares ($250 million aggregate stated capital) of 5.00% Class A Preferred Stock, Cumulative, Par Value $1 Per Share (Stated Capital $25 Per Share). The proceeds were used in
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
October 2017 to redeem all 2 million shares ($50 million aggregate stated capital) of Alabama Power's 6.50% Series Preference Stock, 6 million shares ($150 million aggregate stated capital) of Alabama Power's 6.45% Series Preference Stock, and 1.52 million shares ($38 million aggregate stated capital) of Alabama Power's 5.83% Class A Preferred Stock and for other general corporate purposes, including Alabama Power's continuous construction program.
Georgia Power
In March 2017, Georgia Power issued $450 million aggregate principal amount of Series 2017A 2.00% Senior Notes due March 30, 2020 and $400 million aggregate principal amount of Series 2017B 3.25% Senior Notes due March 30, 2027. The proceeds were used to repay a portion of Georgia Power's short-term indebtedness and for general corporate purposes, including Georgia Power's continuous construction program.
In April 2017, Georgia Power purchased and held $27 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1995. Subsequent to September 30, 2017, Georgia Power remarketed these bonds to the public.
In June 2017, Georgia Power entered into three floating rate bank loans in aggregate principal amounts of $50 million, $150 million, and $100 million, with maturity dates of December 1, 2017, May 31, 2018, and June 28, 2018, respectively, which bear interest based on one-month LIBOR. Also in June 2017, Georgia Power borrowed $500 million pursuant to an uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Georgia Power and the bank from time to time and is payable on no less than 30 days' demand by the bank. The proceeds from these bank loans were used to repay a portion of Georgia Power's existing indebtedness and for working capital and other general corporate purposes, including Georgia Power's continuous construction program.
In August 2017, Georgia Power repaid $250 million of the $500 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement. Also in August 2017, Georgia Power amended its $100 million floating rate bank loan to extend the maturity date from June 28, 2018 to October 26, 2018.
Also in August 2017, Georgia Power issued $500 million aggregate principal amount of Series 2017C 2.00% Senior Notes due September 8, 2020. The proceeds were used to repay Georgia Power's $50 million floating rate bank loan due December 1, 2017 and outstanding commercial paper borrowings and for general corporate purposes.
Also in August 2017, Georgia Power purchased and held $38 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 1997. Subsequent to September 30, 2017, Georgia Power remarketed these bonds to the public.
In September 2017, Georgia Power issued $270 million aggregate principal amount of Series 2017A 5.00% Junior Subordinated Notes due October 1, 2077. The proceeds were used in October 2017 to redeem all 1.8 million shares ($45 million aggregate liquidation amount) of Georgia Power's 6.125% Series Class A Preferred Stock and 2.25 million shares ($225 million aggregate liquidation amount) of Georgia Power's 6.50% Series 2007A Preference Stock.
Gulf Power
In March 2017, Gulf Power extended the maturity of a $100 million short-term floating rate bank loan bearing interest based on one-month LIBOR from April 2017 to October 2017 and subsequently repaid the loan in May 2017.
In May 2017, Gulf Power issued $300 million aggregate principal amount of Series 2017A 3.30% Senior Notes due May 30, 2027. The proceeds, together with other funds, were used to repay at maturity $85 million aggregate principal amount of Series 2007A 5.90% Senior Notes due June 15, 2017; to repay outstanding commercial paper borrowings; to repay a $100 million short-term floating rate bank loan, as discussed above; and to redeem, in June 2017, 550,000 shares ($55 million aggregate liquidation amount) of Gulf Power's 6.00% Series Preference Stock, 450,000 shares ($45 million aggregate liquidation amount) of Gulf Power's Series 2007A 6.45% Preference Stock,
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
and 500,000 shares ($50 million aggregate liquidation amount) of Gulf Power's Series 2013A 5.60% Preference Stock.
Mississippi Power
In March 2017, Mississippi Power issued a $9 million short-term bank note bearing interest at 5% per annum, which was repaid in April 2017.
In February 2017, Mississippi Power amended $551 million in promissory notes to Southern Company extending the maturity dates of the notes from December 1, 2017 to July 31, 2018. In the second quarter 2017, Mississippi Power borrowed an additional $40 million under a promissory note issued to Southern Company.
In June 2017, Southern Company made equity contributions totaling $1.0 billion to Mississippi Power. Mississippi Power used a portion of the proceeds to (i) prepay $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018; (ii) repay all of the $591 million outstanding principal amount of promissory notes to Southern Company; and (iii) repay a $10 million short-term bank loan.
In August 2017, Mississippi Power repaid a $12.5 million short-term bank note.
In September 2017, Mississippi Power issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $150 million bearing interest based on one-month LIBOR. Mississippi Power borrowed $109 million under this promissory note primarily to satisfy its federal income tax obligations for the quarter ending September 30, 2017 and subsequently repaid the promissory note upon receipt of its income tax refund from the U.S. federal government related to the settlement concerning deductible R&E expenditures. See Note (G) under "Section 174 Research and Experimental Deduction" for additional information.
Southern Power
In September 2017, Southern Power amended its $60 million aggregate principal amount floating rate bank loan to, among other things, increase the aggregate principal amount to $100 million and extend the maturity date from September 2017 to October 2018. The additional $40 million of proceeds were used to repay existing indebtedness and for other general corporate purposes.
Southern Company Gas
In May 2017, Southern Company Gas Capital issued $450 million aggregate principal amount of Series 2017A 4.40% Senior Notes due May 30, 2047. The proceeds were used to repay Southern Company Gas' short-term indebtedness and for general corporate purposes.
In July 2017, Nicor Gas agreed to issue $400 million aggregate principal amount of first mortgage bonds in a private placement. On August 10, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.03% Series due August 10, 2027 and $100 million aggregate principal amount of First Mortgage Bonds 3.62% Series due August 10, 2037. The proceeds were used to repay short-term indebtedness incurred under the Nicor Gas commercial paper program and for other working capital needs. The remaining $200 million is expected to be issued in November 2017.
Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees at Southern Company Gas, as discussed below, and PowerSecure. The Southern Company qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No mandatory contributions to the Southern Company qualified pension plan are anticipated for the year ending December 31, 2017. Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions.
In addition, Southern Company Gas has a qualified defined benefit, trusteed, pension plan covering certain eligible employees, which was closed in 2012 to new employees. This qualified pension plan is funded in accordance with requirements of ERISA. No mandatory contributions to the Southern Company Gas qualified pension plan are anticipated for the year ending December 31, 2017. Southern Company Gas also provides certain non-qualified defined benefit and defined contribution pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company Gas provides certain medical care and life insurance benefits for eligible retired employees through a postretirement benefit plan. Southern Company Gas also has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses.
See Note 2 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Company Gas in Item 8 of the Form 10-K for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Components of the net periodic benefit costs for the three and nine months ended September 30, 2017 and 2016 are presented in the following tables.
|
| | | | | | | | | | | | | | | | | | | |
| Pension Plans | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power |
| | (in millions) |
| Three Months Ended September 30, 2017 | | | | | | | | | |
| Service cost | $ | 73 |
| | $ | 15 |
| | $ | 19 |
| | $ | 3 |
| | $ | 4 |
|
| Interest cost | 114 |
| | 25 |
| | 34 |
| | 5 |
| | 5 |
|
| Expected return on plan assets | (224 | ) | | (49 | ) | | (71 | ) | | (10 | ) | | (9 | ) |
| Amortization: | | | | | | | | | |
| Prior service costs | 3 |
| | 1 |
| | — |
| | — |
| | — |
|
| Net (gain)/loss | 41 |
| | 10 |
| | 15 |
| | 2 |
| | 1 |
|
| Net periodic pension cost (income) | $ | 7 |
| | $ | 2 |
| | $ | (3 | ) | | $ | — |
| | $ | 1 |
|
| Nine Months Ended September 30, 2017 | | | | | | | | | |
| Service cost | $ | 220 |
| | $ | 47 |
| | $ | 56 |
| | $ | 10 |
| | $ | 11 |
|
| Interest cost | 341 |
| | 73 |
| | 103 |
| | 15 |
| | 15 |
|
| Expected return on plan assets | (673 | ) | | (147 | ) | | (212 | ) | | (29 | ) | | (29 | ) |
| Amortization: | | | | | | | | | |
| Prior service costs | 9 |
| | 2 |
| | 2 |
| | — |
| | 1 |
|
| Net (gain)/loss | 122 |
| | 31 |
| | 43 |
| | 5 |
| | 5 |
|
| Net periodic pension cost (income) | $ | 19 |
| | $ | 6 |
| | $ | (8 | ) | | $ | 1 |
| | $ | 3 |
|
| Three Months Ended September 30, 2016 | | | | | | | | | |
| Service cost | $ | 68 |
| | $ | 14 |
| | $ | 17 |
| | $ | 3 |
| | $ | 3 |
|
| Interest cost | 110 |
| | 23 |
| | 34 |
| | 5 |
| | 4 |
|
| Expected return on plan assets | (203 | ) | | (46 | ) | | (64 | ) | | (9 | ) | | (9 | ) |
| Amortization: | | | | | | | | | |
| Prior service costs | 3 |
| | 1 |
| | 1 |
| | — |
| | 1 |
|
| Net (gain)/loss | 45 |
| | 10 |
| | 14 |
| | 2 |
| | 2 |
|
| Net periodic pension cost | $ | 23 |
| | $ | 2 |
| | $ | 2 |
| | $ | 1 |
| | $ | 1 |
|
| Nine Months Ended September 30, 2016 | | | | | | | | | |
| Service cost | $ | 192 |
| | $ | 43 |
| | $ | 52 |
| | $ | 9 |
| | $ | 9 |
|
| Interest cost | 311 |
| | 71 |
| | 102 |
| | 14 |
| | 14 |
|
| Expected return on plan assets | (577 | ) | | (138 | ) | | (193 | ) | | (26 | ) | | (26 | ) |
| Amortization: | | | | | | | | | |
| Prior service costs | 10 |
| | 2 |
| | 4 |
| | 1 |
| | 1 |
|
| Net (gain)/loss | 120 |
| | 30 |
| | 41 |
| | 5 |
| | 5 |
|
| Net periodic pension cost | $ | 56 |
| | $ | 8 |
| | $ | 6 |
| | $ | 3 |
| | $ | 3 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | |
| Pension Plans | Southern Company Gas |
| | (in millions) |
| Successor – Three Months Ended September 30, 2017 | |
| Service cost | $ | 6 |
|
| Interest cost | 10 |
|
| Expected return on plan assets | (18 | ) |
| Amortization of net (gain)/loss | 5 |
|
| Net periodic pension cost | $ | 3 |
|
| Successor – Nine Months Ended September 30, 2017 | |
| Service cost | $ | 17 |
|
| Interest cost | 30 |
|
| Expected return on plan assets | (53 | ) |
| Amortization: | |
| Prior service costs | (1 | ) |
| Net (gain)/loss | 15 |
|
| Net periodic pension cost | $ | 8 |
|
| Successor – July 1, 2016 through September 30, 2016 | |
| Service cost | $ | 7 |
|
| Interest cost | 10 |
|
| Expected return on plan assets | (17 | ) |
| Amortization of regulatory asset | 6 |
|
| Net periodic pension cost | $ | 6 |
|
| | |
| | |
| Predecessor – January 1, 2016 through June 30, 2016 | |
| Service cost | $ | 13 |
|
| Interest cost | 21 |
|
| Expected return on plan assets | (33 | ) |
| Amortization: | |
| Prior service costs | (1 | ) |
| Net (gain)/loss | 13 |
|
| Net periodic pension cost | $ | 13 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | |
| Postretirement Benefits | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power |
| | (in millions) |
| Three Months Ended September 30, 2017 | | | | | | | | | |
| Service cost | $ | 6 |
| | $ | 1 |
| | $ | 2 |
| | $ | — |
| | $ | — |
|
| Interest cost | 19 |
| | 4 |
| | 6 |
| | 1 |
| | 1 |
|
| Expected return on plan assets | (16 | ) | | (5 | ) | | (6 | ) | | — |
| | — |
|
| Amortization: | | | | | | | | | |
| Prior service costs | 2 |
| | 1 |
| | — |
| | — |
| | — |
|
| Net (gain)/loss | 3 |
| | — |
| | 3 |
| | — |
| | — |
|
| Net periodic postretirement benefit cost | $ | 14 |
| | $ | 1 |
| | $ | 5 |
| | $ | 1 |
| | $ | 1 |
|
| Nine Months Ended September 30, 2017 | | | | | | | | | |
| Service cost | $ | 18 |
| | $ | 4 |
| | $ | 5 |
| | $ | 1 |
| | $ | 1 |
|
| Interest cost | 59 |
| | 13 |
| | 21 |
| | 2 |
| | 3 |
|
| Expected return on plan assets | (49 | ) | | (19 | ) | | (18 | ) | | (1 | ) | | (1 | ) |
| Amortization: | | | | | | | | | |
| Prior service costs | 5 |
| | 3 |
| | 1 |
| | — |
| | — |
|
| Net (gain)/loss | 10 |
| | 1 |
| | 6 |
| | — |
| | — |
|
| Net periodic postretirement benefit cost | $ | 43 |
| | $ | 2 |
| | $ | 15 |
| | $ | 2 |
| | $ | 3 |
|
| Three Months Ended September 30, 2016 | | | | | | | | | |
| Service cost | $ | 6 |
| | $ | 1 |
| | $ | 2 |
| | $ | — |
| | $ | — |
|
| Interest cost | 20 |
| | 5 |
| | 7 |
| | 1 |
| | — |
|
| Expected return on plan assets | (16 | ) | | (6 | ) | | (6 | ) | | — |
| | — |
|
| Amortization: | | | | | | | | | |
| Prior service costs | 1 |
| | 1 |
| | — |
| | — |
| | — |
|
| Net (gain)/loss | 5 |
| | — |
| | 3 |
| | — |
| | 1 |
|
| Net periodic postretirement benefit cost | $ | 16 |
| | $ | 1 |
| | $ | 6 |
| | $ | 1 |
| | $ | 1 |
|
| Nine Months Ended September 30, 2016 | | | | | | | | | |
| Service cost | $ | 17 |
| | $ | 4 |
| | $ | 5 |
| | $ | 1 |
| | $ | 1 |
|
| Interest cost | 55 |
| | 14 |
| | 22 |
| | 2 |
| | 2 |
|
| Expected return on plan assets | (44 | ) | | (19 | ) | | (17 | ) | | (1 | ) | | (1 | ) |
| Amortization: | | | | | | | | | |
| Prior service costs | 4 |
| | 3 |
| | 1 |
| | — |
| | — |
|
| Net (gain)/loss | 12 |
| | 1 |
| | 7 |
| | — |
| | 1 |
|
| Net periodic postretirement benefit cost | $ | 44 |
| | $ | 3 |
| | $ | 18 |
| | $ | 2 |
| | $ | 3 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | |
| Postretirement Benefits | Southern Company Gas |
| | (in millions) |
| Successor – Three Months Ended September 30, 2017 | |
| Service cost | $ | 1 |
|
| Interest cost | 3 |
|
| Expected return on plan assets | (2 | ) |
| Amortization: | |
| Prior service costs | (1 | ) |
| Net (gain)/loss | 1 |
|
| Net periodic postretirement benefit cost | $ | 2 |
|
| Successor – Nine Months Ended September 30, 2017 | |
| Service cost | $ | 2 |
|
| Interest cost | 8 |
|
| Expected return on plan assets | (5 | ) |
| Amortization: | |
| Prior service costs | (2 | ) |
| Net (gain)/loss | 3 |
|
| Net periodic postretirement benefit cost | $ | 6 |
|
| Successor – July 1, 2016 through September 30, 2016 | |
| Service cost | $ | 1 |
|
| Interest cost | 2 |
|
| Expected return on plan assets | (2 | ) |
| Amortization of regulatory asset | 1 |
|
| Net periodic postretirement benefit cost | $ | 2 |
|
| | |
| | |
| Predecessor – January 1, 2016 through June 30, 2016 | |
| Service cost | $ | 1 |
|
| Interest cost | 5 |
|
| Expected return on plan assets | (3 | ) |
| Amortization: | |
| Prior service costs | (1 | ) |
| Net (gain)/loss | 2 |
|
| Net periodic postretirement benefit cost | $ | 4 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
See Note 5 to the financial statements of each registrant in Item 8 of the Form 10-K for additional tax information.
Current and Deferred Income Taxes
Tax Credit Carryforwards
Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) totaling $1.9 billion as of September 30, 2017 compared to $1.8 billion as of December 31, 2016.
The federal ITC carryforwards begin expiring in 2032 but are expected to be fully utilized by 2022. The PTC carryforwards begin expiring in 2036 but are expected to be utilized by 2022. The expected utilization of tax credit carryforwards could be further delayed by numerous factors. These factors include the acquisition of additional renewable projects, increased generation at existing wind facilities, carrying back the federal net operating loss, and potential tax reform legislation, as well as additional deductions in the event of an asset abandonment. The ultimate outcome of these matters cannot be determined at this time.
Valuation Allowances
At September 30, 2017, valuation allowances were as follows:
|
| | | | | | | | | | | |
| | Mississippi Power | | Southern Company Gas | | Southern Company |
| | (in millions) |
| Federal | $ | — |
| | $ | 18 |
| | $ | 18 |
|
| State (net of federal benefit) | 46 |
| | 1 |
| | 64 |
|
| Balance at September 30, 2017 | $ | 46 |
| | $ | 19 |
| | $ | 82 |
|
Southern Company had valuation allowances, net of the federal benefit, of $82 million at September 30, 2017 compared to $21 million at December 31, 2016. The increase was primarily due to Mississippi Power's projected inability to utilize the State of Mississippi net operating loss.
Effective Tax Rate
Southern Company
Southern Company's effective tax rate is typically lower than the statutory rate due to employee stock plans' dividend deduction, non-taxable AFUDC equity, and federal income tax benefits from ITCs and PTCs.
Southern Company's effective tax rate was 42.6% for the nine months ended September 30, 2017 compared to 28.3% for the corresponding period in 2016. The effective tax rate increase was primarily due to the estimated probable losses on the Kemper IGCC, net of the non-deductible AFUDC equity portion. Other factors include a decrease in tax benefits from solar ITCs and an increase in state valuation allowances, partially offset by an increase in tax benefits from wind PTCs.
Southern Company recognizes PTCs when wind energy is generated and sold (using the prescribed KWH rate in applicable federal and state statutes), which may differ significantly from amounts computed on a quarterly basis using an overall estimated annual effective income tax rate. Southern Company uses this method of recognition since the amount of PTCs can be significantly impacted by wind generation. This method can significantly affect the effective income tax rate for the period depending on the amount of pretax income.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Mississippi Power
Mississippi Power's effective tax (benefit) rate was (30.3)% for the nine months ended September 30, 2017 compared to (282.8)% for the corresponding period in 2016. The effective tax rate increase was primarily due to the estimated probable losses on the Kemper IGCC, net of the non-deductible AFUDC equity portion and the related state valuation allowances.
Southern Power
Southern Power's effective tax (benefit) rate was (66.5)% for the nine months ended September 30, 2017 compared to (88.9)% for the corresponding period in 2016. The effective tax rate increase was primarily due to a decrease in tax benefits from solar ITCs, partially offset by additional wind PTCs and state apportionment rate changes.
Southern Power recognizes PTCs when wind energy is generated and sold (using the prescribed KWH rate in applicable federal and state statutes), which may differ significantly from amounts computed on a quarterly basis using an overall estimated annual effective income tax rate. Southern Power uses this method of recognition since the amount of PTCs can be significantly impacted by wind generation. This method can significantly affect the effective income tax rate for the period depending on the amount of pretax income.
During the third quarter 2017, Southern Power began a legal entity reorganization of various direct and indirect subsidiaries that own and operate solar facilities, including certain subsidiaries owned in partnership with various third parties. Southern Power's ownership interests in the various solar entities and facilities will not be affected by the reorganization. The reorganization is expected to result in estimated tax benefits totaling approximately $40 million that will be recorded in the fourth quarter 2017 related to certain changes in state apportionment rates and net operating loss carryforward utilization. The ultimate outcome of this matter cannot be determined at this time.
Southern Company Gas
Southern Company Gas' effective tax rate was 43.4% for the successor nine months ended September 30, 2017 compared to 60.3% for the successor period of July 1, 2016 through September 30, 2016 and 37.6% for the predecessor period of January 1, 2016 through June 30, 2016. The effective tax rate for the successor year-to-date 2017 was impacted by State of Illinois tax legislation enacted during July 2017, the allocation of new tax apportionment factors in several states for the inclusion of Southern Company Gas into the consolidated Southern Company state tax filings, and higher pre-tax earnings. The effective tax rates for the periods in 2016 were impacted by the non-deductibility of certain Merger-related expenses. The effective tax rate for the successor period of July 1, 2016 through September 30, 2016 was also impacted by nondeductible expenses associated with certain compensation costs.
Unrecognized Tax Benefits
See Note 5 to the financial statements of each registrant under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K for additional information.
Changes during the nine months ended September 30, 2017 for unrecognized tax benefits were as follows:
|
| | | | | | | | | | | |
| | Mississippi Power | | Southern Power | | Southern Company |
| | (in millions) |
| Unrecognized tax benefits as of December 31, 2016 | $ | 465 |
| | $ | 17 |
| | $ | 484 |
|
| Tax positions from current periods | 2 |
| | — |
| | 9 |
|
| Tax positions from prior periods | (175 | ) | | (17 | ) | | (186 | ) |
| Reductions due to settlements | (290 | ) | | — |
| | (290 | ) |
| Balance as of September 30, 2017 | $ | 2 |
| | $ | — |
| | $ | 17 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
The tax positions from current and prior periods primarily relate to state tax benefits, deductions for R&E expenditures, and charitable contribution carryforwards that were impacted as a result of the settlement of R&E expenditures associated with the Kemper IGCC, as well as federal income tax benefits from deferred ITCs. See "Section 174 Research and Experimental Deduction" herein for additional information. These amounts are presented on a gross basis without considering the related federal or state income tax impact.
The impact on the effective tax rate, if recognized, is as follows:
|
| | | | | | | | | | | |
| | As of September 30, 2017 | | As of December 31, 2016 |
| | Mississippi Power | | Southern Company | | Southern Company |
| | (in millions) |
| Tax positions impacting the effective tax rate | $ | 2 |
| | $ | 17 |
| | $ | 20 |
|
| Tax positions not impacting the effective tax rate | — |
| | — |
| | 464 |
|
| Balance of unrecognized tax benefits | $ | 2 |
| | $ | 17 |
| | $ | 484 |
|
The tax positions impacting the effective tax rate primarily relate to state tax benefits and charitable contribution carryforwards that were impacted as a result of the settlement of R&E expenditures associated with the Kemper IGCC. See "Section 174 Research and Experimental Deduction" herein for additional information.
Accrued interest for all tax positions was immaterial for all periods presented.
All of the registrants classify interest on tax uncertainties as interest expense. None of the registrants accrued any penalties on uncertain tax positions.
It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2016. Southern Company is a participant in the Compliance Assurance Process of the IRS. However, the pre-Merger Southern Company Gas 2014, 2015, and June 30, 2016 federal tax returns are currently under audit. The audits for Southern Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2011.
Section 174 Research and Experimental Deduction
Southern Company has reflected deductions for R&E expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation (JCT), resolving a methodology for these deductions. As a result of the JCT approval, Southern Company recognized $176 million of previously unrecognized tax benefits and reversed $36 million of associated accrued interest. If the suspension of the Kemper IGCC start-up activities results in an abandonment, any amount not allowed under IRC Section 174 would be claimed as a deduction under IRC Section 165 in the year an abandonment is determined. The ultimate outcome of this matter cannot be determined at this time.
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company GasRegistrants are exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Prior to the sale of Sequent on July 1, 2021, Southern Company Gas' wholesale gas operations useused various contracts in its commercial activities that generally meetmet the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note (C)(I) for additional fair value information. In the statements of cash flows, theany cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. TheAny cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with the classification of the hedged interest or principal, respectively. See Note 1 to the financial statements under "Financial Instruments" in Item 8 of the Form 10-K for additional information. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information regarding the sale of Sequent.
Energy-Related Derivatives
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company GasThe Subsidiary Registrants enter into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies and the natural gas distribution utilities have limited exposure to market volatility in energy-related commodity prices. Each of the traditional electric operating companies and certain of the natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs, implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies, through the use of financial derivative contracts, which isare expected to continue to mitigate price volatility. The Florida PSC extended the moratorium on Gulf Power's fuel-hedging program until January 1, 2021 in connection with the 2017 Rate Case Settlement Agreement. The moratorium does not have an impact on the recovery of existing hedges entered into under the previously-approved hedging program. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in energy-related commodity prices because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted capacity is used to sell electricity. Southern Company Gas retains exposure to price changes that can, in a volatile energy market, be material and can adversely affect its results of operations.
Southern Company Gas also enters into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non exchange-tradedNon-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in the statementsoperating revenues.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Energy-related derivative contracts are accounted for under one of three methods:
•Regulatory Hedges — – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the traditional electric operating companies' and the natural gas distribution utilities' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuelan approved cost recovery clauses.
mechanism.•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 are reflected in earnings.
transactions.•Not Designated — – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric and natural gas industries. When an energy-related
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.
At September 30, 2017,2022, the net volume of energy-related derivative contracts for natural gas positions, for the Southern Company system, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows:
| | | | | | | | | | | | | | | | | |
| Net
Purchased
mmBtu | | Longest
Hedge
Date | | Longest
Non-Hedge
Date |
| (in millions) | | | | |
Southern Company(*) | 399 | | 2030 | | 2025 |
| Alabama Power | 105 | | 2026 | | — |
| Georgia Power | 116 | | 2025 | | — |
| Mississippi Power | 82 | | 2027 | | — |
| Southern Power | 11 | | 2030 | | 2023 |
Southern Company Gas(*) | 85 | | 2025 | | 2025 |
|
| | | | | |
| | Net Purchased mmBtu | | Longest Hedge Date | | Longest Non-Hedge Date |
| | (in millions) | | | | |
Southern Company(*) | 463 | | 2021 | | 2024 |
| Alabama Power | 66 | | 2020 | | — |
| Georgia Power | 159 | | 2021 | | — |
| Gulf Power | 28 | | 2020 | | — |
| Mississippi Power | 44 | | 2021 | | — |
| Southern Power | 13 | | 2018 | | — |
Southern Company Gas(*) | 153 | | 2020 | | 2024 |
| |
(*) | Southern Company's and Southern Company Gas' derivative instruments include both long and short natural gas positions. A long position is a contract to purchase natural gas and a short position is a contract to sell natural gas. Southern Company Gas' volume represents the net of long natural gas positions of 3.3 billion mmBtu and short natural gas positions of 3.1 billion mmBtu as of September 30, 2017, which is also included in Southern Company's total volume. |
In addition to the volumes discussed above, the traditional electric operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess natural gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 3415 million mmBtu for Southern Company, 11which includes 4 million mmbtummBtu for Alabama Power, 5 million mmBtu for Georgia Power, and Southern Power, 5 million mmbtu for Alabama Power, 32 million mmBtu for GulfMississippi Power, and 4 million mmBtu for MississippiSouthern 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 September 30, 20182023 are $5$17 million for Southern PowerCompany, $26 million for Southern Company Gas, and immaterial for allthe other registrants.Registrants.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Interest Rate Derivatives
Southern Company and certain subsidiaries may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses isare recorded in OCI and isare reclassified into earnings at the same time and presented on the same income statement line item as the earnings effect of the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings.transactions. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings providing an offset, with any difference representing ineffectiveness.on the same income statement line item. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
At September 30, 2017,2022, 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, 2022 |
| | (in millions) | | | | | | (in millions) |
| Cash Flow Hedges of Existing Debt | | | | | | |
| Southern Company parent | $ | 175 | | | — | 4.25% | September 2025 | | $ | — | |
| Southern Company parent | 175 | | | — | 3.83% | August 2032 | | — | |
| Fair Value Hedges of Existing Debt | | | | | | |
| Southern Company parent | 400 | | | 1.75% | 1-month LIBOR + 0.68% | March 2028 | | (57) | |
| Southern Company parent | 1,000 | | | 3.70% | 1-month LIBOR + 2.36% | April
2030 | | (167) | |
| Southern Company Gas | 500 | | | 1.75% | 1-month LIBOR + 0.38% | January 2031 | | (87) | |
| Southern Company | $ | 2,250 | | | | | | | $ | (311) | |
|
| | | | | | | | | | | |
| | Notional Amount | | Interest Rate Received | Weighted Average Interest Rate Paid | Hedge Maturity Date | | Fair Value Gain (Loss) at September 30, 2017 |
| | (in millions) | | | | | | (in millions) |
| Cash Flow Hedges of Existing Debt | | | | | | |
| Mississippi Power | $ | 900 |
| | 1-month
LIBOR | 0.79% | March 2018 | | $ | 2 |
|
| Fair Value Hedges of Existing Debt | | | | | | |
Southern Company(*) | 300 |
| | 2.75% | 3-month
LIBOR + 0.92% | June 2020 | | — |
|
Southern Company(*) | 1,500 |
| | 2.35% | 1-month
LIBOR + 0.87% | July 2021 | | (19 | ) |
| Georgia Power | 250 |
| | 5.40% | 3-month
LIBOR + 4.02% | June 2018 | | — |
|
| Georgia Power | 500 |
| | 1.95% | 3-month
LIBOR + 0.76% | December 2018 | | (2 | ) |
| Georgia Power | 200 |
| | 4.25% | 3-month
LIBOR + 2.46% | December 2019 | | — |
|
| Southern Company Consolidated | $ | 3,650 |
| | | | | | $ | (19 | ) |
| |
(*) | RepresentsFor cash flow hedges of interest rate derivatives, the Southern Company parent entity. |
The estimated pre-tax gains (losses) related to interest rate derivatives expected to be reclassified from accumulated OCI to interest expense for the next 12-month period ending September 30, 20182023 are $(19)$(17) million for Southern Company and immaterial for allthe other registrants. Southern Company and certain subsidiaries have deferredRegistrants. Deferred gains and losses related to interest rate derivatives are expected to be amortized into earnings through 2046.2052 for Southern Company, Alabama Power, and Georgia Power, 2028 for Mississippi Power, and 2046 for Southern Company Gas.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Foreign Currency Derivatives
Southern Company and certain subsidiaries, including Southern Power, may also enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses isare recorded in OCI and isare reclassified into earnings at the same time thatand on the same income statement line as the earnings effect of the hedged transactions, affect earnings, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Any ineffectiveness isDerivatives 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. The derivatives employedearnings on the same income statement line item, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Southern Company has elected to exclude the cross-currency basis spread from the assessment of effectiveness in the fair value hedges of its foreign currency risk and record any difference between the change in the fair value of the excluded components and the amounts recognized in earnings as hedging instruments are structured to minimize ineffectiveness.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
a component of OCI.
At September 30, 2017,2022, the following foreign currency derivatives were outstanding:
| | | | | | | | | | | | | | | | | | | | |
| Pay Notional | Pay
Rate | Receive Notional | Receive
Rate | Hedge
Maturity Date | Fair Value Gain (Loss) at September 30, 2022 |
| (in millions) | | (in millions) | | | (in millions) |
| Cash Flow Hedges of Existing Debt | | | | | |
| Southern Power | $ | 564 | | 3.78% | € | 500 | | 1.85% | June 2026 | $ | (80) | |
| | | | | | |
| Fair Value Hedges of Existing Debt | | | | | |
| | | | | | |
| Southern Company parent | 1,476 | | 3.39% | 1,250 | | 1.88% | September 2027 | (243) | |
| | | | | | |
| | | | | | |
| Southern Company | $ | 2,040 | | | € | 1,750 | | | | $ | (323) | |
|
| | | | | | | | | | | | |
| Pay Notional | Pay Rate | Receive Notional | Receive Rate | Hedge
Maturity Date | Fair Value Gain (Loss) at September 30, 2017 |
| (in millions) | | (in millions) | | | (in millions) |
| Cash Flow Hedges of Existing Debt | | | | | |
| Southern Power | $ | 677 |
| 2.95% | € | 600 |
| 1.00% | June 2022 | $ | 42 |
|
| Southern Power | 564 |
| 3.78% | 500 |
| 1.85% | June 2026 | 38 |
|
| Total | $ | 1,241 |
| | € | 1,100 |
| | | $ | 80 |
|
The estimated pre-tax gains (losses) related toFor cash flow hedges of foreign currency derivatives, that willthe estimated pre-tax losses expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending September 30, 20182023 are $(23)$12 million for Southern Company and Southern Power.
Derivative Financial Statement Presentation and Amounts
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company GasThe Registrants 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 sheetsheets are presented net to the extent that there are netting arrangements or similar agreements with the counterparties.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: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:
| | | | | | | | | | | | | | |
| At September 30, 2022 | At December 31, 2021 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| (in millions) | (in millions) |
| Southern Company | | | | |
| Energy-related derivatives designated as hedging instruments for regulatory purposes | | | | |
| | | | |
| Assets from risk management activities/Other current liabilities | $ | 299 | | $ | 70 | | $ | 129 | | $ | 30 | |
| Other deferred charges and assets/Other deferred credits and liabilities | 150 | | 59 | | 72 | | 6 | |
| | | | |
| | | | |
| Total derivatives designated as hedging instruments for regulatory purposes | 449 | | 129 | | 201 | | 36 | |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Energy-related derivatives: | | | | |
| Assets from risk management activities/Other current liabilities | 27 | | 13 | | 7 | | 5 | |
| Other deferred charges and assets/Other deferred credits and liabilities | 7 | | 1 | | 1 | | — | |
| Interest rate derivatives: | | | | |
| Assets from risk management activities/Other current liabilities | — | | 44 | | 19 | | — | |
| Other deferred charges and assets/Other deferred credits and liabilities | — | | 266 | | — | | 29 | |
| Foreign currency derivatives: | | | | |
| Assets from risk management activities/Other current liabilities | — | | 37 | | — | | 39 | |
| Other deferred charges and assets/Other deferred credits and liabilities | — | | 285 | | — | | 40 | |
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | 34 | | 646 | | 27 | | 113 | |
| Energy-related derivatives not designated as hedging instruments | | | | |
| | | | |
| Assets from risk management activities/Other current liabilities | 19 | | 18 | | 9 | | 4 | |
| Other deferred charges and assets/Other deferred credits and liabilities | 2 | | 1 | | 1 | | — | |
| | | | |
| Total derivatives not designated as hedging instruments | 21 | | 19 | | 10 | | 4 | |
| Gross amounts recognized | 504 | | 794 | | 238 | | 153 | |
Gross amounts offset(a) | (113) | | (128) | | (25) | | (28) | |
Net amounts recognized in the Balance Sheets(b) | $ | 391 | | $ | 666 | | $ | 213 | | $ | 125 | |
| | | | |
|
| | | | | | | | | | | | |
| | As of September 30, 2017 | As of December 31, 2016 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| | (in millions) | (in millions) |
| Southern Company | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 21 |
| $ | 25 |
| $ | 73 |
| $ | 27 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 13 |
| 23 |
| 25 |
| 33 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 34 |
| $ | 48 |
| $ | 98 |
| $ | 60 |
|
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 8 |
| $ | 6 |
| $ | 23 |
| $ | 7 |
|
| Interest rate derivatives: | | | | |
| Other current assets/Other current liabilities | 5 |
| 1 |
| 12 |
| 1 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 23 |
| 1 |
| 28 |
|
| Foreign currency derivatives: | | | | |
| Other current assets/Other current liabilities | — |
| 23 |
| — |
| 25 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 103 |
| — |
| — |
| 33 |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 116 |
| $ | 53 |
| $ | 36 |
| $ | 94 |
|
| Derivatives not designated as hedging instruments | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 271 |
| $ | 254 |
| $ | 489 |
| $ | 483 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 115 |
| 103 |
| 66 |
| 81 |
|
| Interest rate derivatives: | | | | |
| Other current assets/Other current liabilities | — |
| — |
| 1 |
| — |
|
| Total derivatives not designated as hedging instruments | $ | 386 |
| $ | 357 |
| $ | 556 |
| $ | 564 |
|
| Gross amounts recognized | $ | 536 |
| $ | 458 |
| $ | 690 |
| $ | 718 |
|
Gross amounts offset(*) | $ | (275 | ) | $ | (351 | ) | $ | (462 | ) | $ | (524 | ) |
| Net amounts recognized in the Balance Sheets | $ | 261 |
| $ | 107 |
| $ | 228 |
| $ | 194 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS:STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | |
| At September 30, 2022 | At December 31, 2021 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| (in millions) | (in millions) |
| Alabama Power | | | | |
| Energy-related derivatives designated as hedging instruments for regulatory purposes | | | | |
| | | | |
| Other current assets/Other current liabilities | $ | 90 | | $ | 12 | | $ | 30 | | $ | 9 | |
| Other deferred charges and assets/Other deferred credits and liabilities | 57 | | 23 | | 25 | | 2 | |
| Total derivatives designated as hedging instruments for regulatory purposes | 147 | | 35 | | 55 | | 11 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| Gross amounts offset | (31) | | (31) | | (5) | | (5) | |
| Net amounts recognized in the Balance Sheets | $ | 116 | | $ | 4 | | $ | 50 | | $ | 6 | |
| | | | |
| Georgia Power | | | | |
| Energy-related derivatives designated as hedging instruments for regulatory purposes | | | | |
| | | | |
| Assets from risk management activities/Other current liabilities | $ | 107 | | $ | 28 | | $ | 54 | | $ | 6 | |
| Other deferred charges and assets/Other deferred credits and liabilities | 38 | | 23 | | 21 | | 2 | |
| Total derivatives designated as hedging instruments for regulatory purposes | 145 | | 51 | | 75 | | 8 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| Energy-related derivatives not designated as hedging instruments | | | | |
| | | | |
| Other current assets/Other current liabilities | 1 | | — | | — | | — | |
| | | | |
| Gross amounts recognized | 146 | | 51 | | 75 | | 8 | |
| Gross amounts offset | (41) | | (41) | | (8) | | (8) | |
| Net amounts recognized in the Balance Sheets | $ | 105 | | $ | 10 | | $ | 67 | | $ | — | |
| | | | |
| Mississippi Power | | | | |
| Energy-related derivatives designated as hedging instruments for regulatory purposes | | | | |
| | | | |
| Assets from risk management activities/Other current liabilities | $ | 78 | | $ | 12 | | $ | 30 | | $ | 3 | |
| Other deferred charges and assets/Other deferred credits and liabilities | 55 | | 12 | | 26 | | 2 | |
| Total derivatives designated as hedging instruments for regulatory purposes | 133 | | 24 | | 56 | | 5 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| Gross amounts offset | (20) | | (20) | | (4) | | (4) | |
| Net amounts recognized in the Balance Sheets | $ | 113 | | $ | 4 | | $ | 52 | | $ | 1 | |
| | | | |
|
| | | | | | | | | | | | |
| | As of September 30, 2017 | As of December 31, 2016 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| | (in millions) | (in millions) |
| | | | | |
| Alabama Power | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 6 |
| $ | 4 |
| $ | 13 |
| $ | 5 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 3 |
| 3 |
| 7 |
| 4 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 9 |
| $ | 7 |
| $ | 20 |
| $ | 9 |
|
| Gross amounts recognized | $ | 9 |
| $ | 7 |
| $ | 20 |
| $ | 9 |
|
| Gross amounts offset | $ | (5 | ) | $ | (5 | ) | $ | (8 | ) | $ | (8 | ) |
| Net amounts recognized in the Balance Sheets | $ | 4 |
| $ | 2 |
| $ | 12 |
| $ | 1 |
|
| | | | | |
| Georgia Power | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 10 |
| $ | 3 |
| $ | 30 |
| $ | 1 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 8 |
| 8 |
| 14 |
| 7 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 18 |
| $ | 11 |
| $ | 44 |
| $ | 8 |
|
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Interest rate derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 1 |
| $ | 1 |
| $ | 2 |
| $ | — |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 2 |
| — |
| 3 |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 1 |
| $ | 3 |
| $ | 2 |
| $ | 3 |
|
| Gross amounts recognized | $ | 19 |
| $ | 14 |
| $ | 46 |
| $ | 11 |
|
| Gross amounts offset | $ | (10 | ) | $ | (10 | ) | $ | (8 | ) | $ | (8 | ) |
| Net amounts recognized in the Balance Sheets | $ | 9 |
| $ | 4 |
| $ | 38 |
| $ | 3 |
|
| | | | | |
| Gulf Power | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | — |
| $ | 13 |
| $ | 4 |
| $ | 12 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 9 |
| 1 |
| 17 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | — |
| $ | 22 |
| $ | 5 |
| $ | 29 |
|
| Gross amounts recognized | $ | — |
| $ | 22 |
| $ | 5 |
| $ | 29 |
|
| Gross amounts offset | $ | — |
| $ | — |
| $ | (4 | ) | $ | (4 | ) |
| Net amounts recognized in the Balance Sheets | $ | — |
| $ | 22 |
| $ | 1 |
| $ | 25 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS:STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | |
| At September 30, 2022 | At December 31, 2021 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| (in millions) | (in millions) |
| Southern Power | | | | |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | — | | $ | 10 | | $ | 2 | | $ | — | |
| Other deferred charges and assets/Other deferred credits and liabilities | 5 | | 1 | | 1 | | — | |
| Foreign currency derivatives: | | | | |
| Other current assets/Other current liabilities | — | | 12 | | — | | 16 | |
| Other deferred charges and assets/Other deferred credits and liabilities | — | | 68 | | — | | — | |
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | 5 | | 91 | | 3 | | 16 | |
| Energy-related derivatives not designated as hedging instruments | | | | |
| | | | |
| Other current assets/Other current liabilities | 2 | | 2 | | 1 | | — | |
| | | | |
| | | | |
| | | | |
| | | | |
| Gross amounts recognized | 7 | | 93 | | 4 | | 16 | |
| Gross amounts offset | (3) | | (3) | | — | | — | |
| Net amounts recognized in the Balance Sheets | $ | 4 | | $ | 90 | | $ | 4 | | $ | 16 | |
| | | | |
| Southern Company Gas | | | | |
| Energy-related derivatives designated as hedging instruments for regulatory purposes | | | | |
| | | | |
| Other current assets/Other current liabilities | $ | 24 | | $ | 17 | | $ | 15 | | $ | 12 | |
| | | | |
| | | | |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | 26 | | 3 | | 5 | | 5 | |
| Other deferred charges and assets/Other deferred credits and liabilities | 3 | | — | | — | | — | |
| Interest rate derivatives: | | | | |
| Other current assets/Other current liabilities | — | | 13 | | 6 | | — | |
| Other deferred charges and assets/Other deferred credits and liabilities | — | | 74 | | — | | 6 | |
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | 29 | | 90 | | 11 | | 11 | |
| Energy-related derivatives not designated as hedging instruments | | | | |
| | | | |
| Other current assets/Other current liabilities | 16 | | 16 | | 8 | | 4 | |
| Other deferred charges and assets/Other deferred credits and liabilities | 2 | | 1 | | 1 | | — | |
| | | | |
| Total derivatives not designated as hedging instruments | 18 | | 17 | | 9 | | 4 | |
| Gross amounts recognized | 71 | | 124 | | 35 | | 27 | |
Gross amounts offset(a) | (18) | | (33) | | (8) | | (11) | |
Net amounts recognized in the Balance Sheets(b) | $ | 53 | | $ | 91 | | $ | 27 | | $ | 16 | |
(a)Gross amounts offset includes cash collateral held on deposit in broker margin accounts of $15 million and $3 million at September 30, 2022 and December 31, 2021, respectively.
(b)Net amounts of derivative instruments outstanding exclude immaterial premium and intrinsic value associated with weather derivatives for all periods presented.
|
| | | | | | | | | | | | |
| | As of September 30, 2017 | As of December 31, 2016 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| | (in millions) | (in millions) |
| | | | | |
| Mississippi Power | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 1 |
| $ | 4 |
| $ | 2 |
| $ | 6 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 2 |
| 3 |
| 2 |
| 5 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 3 |
| $ | 7 |
| $ | 4 |
| $ | 11 |
|
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Interest rate derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 2 |
| $ | — |
| $ | 2 |
| $ | — |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| — |
| 1 |
| — |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 2 |
| $ | — |
| $ | 3 |
| $ | — |
|
| Gross amounts recognized | $ | 5 |
| $ | 7 |
| $ | 7 |
| $ | 11 |
|
| Gross amounts offset | $ | (3 | ) | $ | (3 | ) | $ | (3 | ) | $ | (3 | ) |
| Net amounts recognized in the Balance Sheets | $ | 2 |
| $ | 4 |
| $ | 4 |
| $ | 8 |
|
| | | | | |
| Southern Power | | | | |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 8 |
| $ | 4 |
| $ | 18 |
| $ | 4 |
|
| Foreign currency derivatives: | | | | |
| Other current assets/Other current liabilities | — |
| 23 |
| — |
| 25 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 103 |
| — |
| — |
| 33 |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 111 |
| $ | 27 |
| $ | 18 |
| $ | 62 |
|
| Derivatives not designated as hedging instruments | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 1 |
| $ | — |
| $ | 3 |
| $ | 1 |
|
| Interest rate derivatives: | | | | |
| Other current assets/Other current liabilities | — |
| — |
| 1 |
| — |
|
| Total derivatives not designated as hedging instruments | $ | 1 |
| $ | — |
| $ | 4 |
| $ | 1 |
|
| Gross amounts recognized | $ | 112 |
| $ | 27 |
| $ | 22 |
| $ | 63 |
|
| Gross amounts offset | $ | (1 | ) | $ | (1 | ) | $ | (5 | ) | $ | (5 | ) |
| Net amounts recognized in the Balance Sheets | $ | 111 |
| $ | 26 |
| $ | 17 |
| $ | 58 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS:STATEMENTS (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | |
| | As of September 30, 2017 | As of December 31, 2016 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| | (in millions) | (in millions) |
| | | | | |
| Southern Company Gas | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Assets from risk management activities/Liabilities from risk management activities-current | $ | 4 |
| $ | 1 |
| $ | 24 |
| $ | 3 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| — |
| 1 |
| — |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 4 |
| $ | 1 |
| $ | 25 |
| $ | 3 |
|
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Energy-related derivatives: | | | | |
| Assets from risk management activities/Liabilities from risk management activities-current | $ | — |
| $ | 2 |
| $ | 4 |
| $ | 3 |
|
| Derivatives not designated as hedging instruments | | | | |
| Energy-related derivatives: | | | | |
| Assets from risk management activities/Liabilities from risk management activities-current | $ | 270 |
| $ | 254 |
| $ | 486 |
| $ | 482 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 115 |
| 103 |
| 66 |
| 81 |
|
| Total derivatives not designated as hedging instruments | $ | 385 |
| $ | 357 |
| $ | 552 |
| $ | 563 |
|
| Gross amounts of recognized | $ | 389 |
| $ | 360 |
| $ | 581 |
| $ | 569 |
|
Gross amounts offset(*) | $ | (251 | ) | $ | (327 | ) | $ | (435 | ) | $ | (497 | ) |
| Net amounts recognized in the Balance Sheets | $ | 138 |
| $ | 33 |
| $ | 146 |
| $ | 72 |
|
| |
(*) | Gross amounts offset include cash collateral held on deposit in broker margin accounts of $76 million and $62 million as of September 30, 2017 and December 31, 2016, respectively. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Energy-related derivatives not designated as hedging instruments were immaterial for Alabama Power and Mississippi Power at September 30, 2022. There were no such instruments for the traditional electric operating companies at December 31, 2021.
At September 30, 20172022 and December 31, 2016,2021, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:
| | | | | | | | | | | | | | | | | |
| Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet |
Derivative Category and Balance Sheet
Location | Southern
Company | Alabama
Power | Georgia
Power | Mississippi
Power | Southern Company Gas |
| | (in millions) |
| At September 30, 2022: | | | | | |
| Energy-related derivatives: | | | | | |
| Other regulatory assets, current | $ | (17) | | $ | (2) | | $ | (8) | | $ | (3) | | $ | (4) | |
| Other regulatory assets, deferred | (6) | | (2) | | (3) | | (1) | | — | |
| | | | | |
| | | | | |
| Other regulatory liabilities, current | 246 | | 80 | | 87 | | 69 | | 10 | |
| Other regulatory liabilities, deferred | 98 | | 36 | | 18 | | 44 | | — | |
| Total energy-related derivative gains (losses) | $ | 321 | | $ | 112 | | $ | 94 | | $ | 109 | | $ | 6 | |
| | | | | |
| At December 31, 2021: | | | | | |
| Energy-related derivatives: | | | | | |
| Other regulatory assets, current | $ | (17) | | $ | (6) | | $ | — | | $ | — | | $ | (11) | |
| | | | | |
| Other regulatory liabilities, current | 107 | | 28 | | 48 | | 27 | | 4 | |
| Other regulatory liabilities, deferred | 65 | | 22 | | 19 | | 24 | | — | |
| Total energy-related derivative gains (losses) | $ | 155 | | $ | 44 | | $ | 67 | | $ | 51 | | $ | (7) | |
|
| | | | | | | | | | | | | | | | | | |
| Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at September 30, 2017 |
Derivative Category and Balance Sheet Location | Southern Company(b) | Alabama Power | Georgia Power | Gulf Power | Mississippi Power | Southern Company Gas(c) |
| | (in millions) | |
| Energy-related derivatives: | | | | | | |
| Other regulatory assets, current | $ | (18 | ) | $ | (1 | ) | $ | — |
| $ | (13 | ) | $ | (3 | ) | $ | (1 | ) |
| Other regulatory assets, deferred | (12 | ) | (1 | ) | (1 | ) | (9 | ) | (1 | ) | — |
|
Other regulatory liabilities, current(a) | 14 |
| 3 |
| 7 |
| — |
| — |
| 4 |
|
Other regulatory liabilities, deferred(b) | 2 |
| 1 |
| 1 |
| — |
| — |
| — |
|
| Total energy-related derivative gains (losses) | $ | (14 | ) | $ | 2 |
| $ | 7 |
| $ | (22 | ) | $ | (4 | ) | $ | 3 |
|
| |
(a) | Georgia Power includes other regulatory liabilities, current in other current liabilities. |
| |
(b) | Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities. |
| |
(c) | Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $1 million at September 30, 2017. |
|
| | | | | | | | | | | | | | | | | | |
| Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2016 |
Derivative Category and Balance Sheet Location | Southern Company(c) | Alabama Power | Georgia Power | Gulf Power | Mississippi Power | Southern Company Gas(c) |
| | (in millions) | |
| Energy-related derivatives: | | | | | | |
| Other regulatory assets, current | $ | (16 | ) | $ | (1 | ) | $ | — |
| $ | (9 | ) | $ | (5 | ) | $ | (1 | ) |
| Other regulatory assets, deferred | (19 | ) | — |
| — |
| (16 | ) | (3 | ) | — |
|
Other regulatory liabilities, current(a) | 56 |
| 8 |
| 29 |
| 1 |
| 1 |
| 17 |
|
Other regulatory liabilities, deferred(b) | 12 |
| 4 |
| 7 |
| — |
| — |
| 1 |
|
| Total energy-related derivative gains (losses) | $ | 33 |
| $ | 11 |
| $ | 36 |
| $ | (24 | ) | $ | (7 | ) | $ | 17 |
|
| |
(a) | Georgia Power includes other regulatory liabilities, current in other current liabilities. |
| |
(b) | Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities. |
| |
(c) | Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $8 million at December 31, 2016. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS:STATEMENTS (Continued)
(UNAUDITED)
For the three months ended September 30, 2017 and 2016, the pre-tax effects of energy-related derivatives, interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instruments were as follows:
|
| | | | | | | | | | | | | | | | |
Derivatives in Cash Flow Hedging Relationships | Gain (Loss) Recognized in OCI on Derivative (Effective Portion) | | Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) |
| | Statements of Income Location | Amount |
| | 2017 | | 2016 | | | 2017 | | 2016 |
| | (in millions) | | | (in millions) |
| Southern Company | | | | | | | | |
| Energy-related derivatives | $ | (6 | ) | | $ | — |
| | Depreciation and amortization | $ | (6 | ) | | $ | 1 |
|
| Interest rate derivatives | (1 | ) | | (6 | ) | | Interest expense, net of amounts capitalized | (5 | ) | | (6 | ) |
| Foreign currency derivatives | 46 |
| | 37 |
| | Interest expense, net of amounts capitalized | (5 | ) | | (6 | ) |
| | | | | | Other income (expense), net(*) | 43 |
| | 7 |
|
| Total | $ | 39 |
| | $ | 31 |
| | | $ | 27 |
| | $ | (4 | ) |
| Alabama Power | | | | | | | | |
| Interest rate derivatives | $ | — |
| | $ | — |
| | Interest expense, net of amounts capitalized | $ | (2 | ) | | $ | (2 | ) |
| Georgia Power | | | | | | | | |
| Interest rate derivatives | $ | — |
| | $ | — |
| | Interest expense, net of amounts capitalized | $ | (1 | ) | | $ | (1 | ) |
| Mississippi Power | | | | | | | | |
| Interest rate derivatives | $ | (1 | ) | | $ | (1 | ) | | Interest expense, net of amounts capitalized | $ | — |
| | $ | — |
|
| Southern Power | | | | | | | | |
| Energy-related derivatives | $ | (6 | ) | | $ | — |
| | Depreciation and amortization | $ | (6 | ) | | $ | 1 |
|
| Foreign currency derivatives | 46 |
| | 37 |
| | Interest expense, net of amounts capitalized | (5 | ) | | (6 | ) |
| | | | | | Other income (expense), net(*) | 43 |
| | 7 |
|
| Total | $ | 40 |
| | $ | 37 |
| | | $ | 32 |
| | $ | 2 |
|
| Southern Company Gas | | | | | | | | |
| Interest rate derivatives | $ | — |
| | $ | (5 | ) | | Interest expense, net of amounts capitalized | $ | — |
| | $ | — |
|
| |
(*) | The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
For the nine months ended September 30, 2017 and 2016, the pre-tax effects of energy-related derivatives, interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instruments were as follows:
|
| | | | | | | | | | | | | | | | |
Derivatives in Cash Flow
Hedging Relationships | Gain (Loss)
Recognized in OCI
on Derivative
(Effective Portion) | | Gain (Loss) Reclassified from Accumulated OCI into
Income (Effective Portion) |
| | Statements of Income Location | Amount |
| | 2017 | | 2016 | | | 2017 | | 2016 |
| | (in millions) | | | (in millions) |
| Southern Company | | | | | | | | |
| Energy-related derivatives | $ | (26 | ) | | $ | (1 | ) | | Depreciation and amortization | $ | (12 | ) | | $ | 1 |
|
| Interest rate derivatives | (2 | ) | | (189 | ) | | Interest expense, net of amounts capitalized | (15 | ) | | (13 | ) |
| Foreign currency derivatives | 114 |
| | (1 | ) | | Interest expense, net of amounts capitalized | (17 | ) | | (7 | ) |
| | | | | | Other income (expense), net(*) | 139 |
| | (13 | ) |
| Total | $ | 86 |
| | $ | (191 | ) | | | $ | 95 |
| | $ | (32 | ) |
| Alabama Power | | | | | | | | |
| Interest rate derivatives | $ | — |
| | $ | (3 | ) | | Interest expense, net of amounts capitalized | $ | (5 | ) | | $ | (5 | ) |
| Georgia Power | | | | | | | | |
| Interest rate derivatives | $ | — |
| | $ | — |
| | Interest expense, net of amounts capitalized | $ | (3 | ) | | $ | (3 | ) |
| Gulf Power | | | | | | | | |
| Energy-related derivatives | $ | (1 | ) | | $ | — |
| | Depreciation and amortization | $ | — |
| | $ | — |
|
| Interest rate derivatives | (1 | ) | | (7 | ) | | Interest expense, net of amounts capitalized | — |
| | — |
|
| Total | $ | (2 | ) | | $ | (7 | ) | | | $ | — |
| | $ | — |
|
| Mississippi Power | | | | | | | | |
| Interest rate derivatives | $ | — |
| | $ | (1 | ) | | Interest expense, net of amounts capitalized | $ | (1 | ) | | $ | (1 | ) |
| Southern Power | | | | | | | | |
| Energy-related derivatives | $ | (21 | ) | | $ | (1 | ) | | Depreciation and amortization | $ | (12 | ) | | $ | 1 |
|
| Interest rate derivatives | — |
| | — |
| | Interest expense, net of amounts capitalized | — |
| | (1 | ) |
| Foreign currency derivatives | 114 |
| | (1 | ) | | Interest expense, net of amounts capitalized | (17 | ) | | (7 | ) |
| |
|
| |
|
| | Other income (expense), net(*) | 139 |
| | (13 | ) |
| Total | $ | 93 |
| | $ | (2 | ) | | | $ | 110 |
| | $ | (20 | ) |
| |
(*) | The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes. |
For Southern Company Gas, the pre-tax effect of energy related derivatives and interest rate derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings for the successor nine months ended September 30, 2017, the successor period of July 1, 2016 through September 30, 2016, and the predecessor period of January 1, 2016 through June 30, 2016 were as follows:
|
| | | | | | | | |
| | Gain (Loss) Recognized in OCI on Derivative (Effective Portion) | | | Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) |
| Derivatives in Cash Flow Hedging Relationships | Nine Months Ended September 30, 2017 | | Statements of Income Location | Nine Months Ended September 30, 2017 |
| | (in millions) | | | (in millions) |
| Energy-related derivatives | $ | (4 | ) | | Cost of natural gas | $ | — |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | |
| | Gain (Loss) Recognized in OCI on Derivative (Effective Portion) | | | Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) |
| | Successor | | | Predecessor | | | Successor | | | Predecessor |
| Derivatives in Cash Flow Hedging Relationships | July 1, 2016 through September 30, 2016 | | | January 1, 2016 through June 30, 2016 | | Statements of Income Location | July 1, 2016
through
September 30, 2016 | | | January 1, 2016 through June 30, 2016 |
| | (in millions) | | | (in millions) | | | (in millions) | | | (in millions) |
| Energy-related derivatives | $ | — |
| | | $ | — |
| | Cost of natural gas | $ | — |
| | | $ | (1 | ) |
| Interest rate derivatives | (5 | ) | | | (64 | ) | | Interest expense, net of amounts capitalized | — |
| | | — |
|
| Total | $ | (5 | ) | | | $ | (64 | ) | | | $ | — |
| | | $ | (1 | ) |
For the three and nine months ended September 30, 20172022 and 2016,2021, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instrumentsand fair value hedge accounting on accumulated OCI were immaterialas follows:
| | | | | | | | | | | | | | |
| Gain (Loss) Recognized in OCI on Derivative | For the Three Months Ended September 30, | For the Nine Months Ended September 30, |
| 2022 | 2021 | 2022 | 2021 |
| (in millions) | (in millions) |
| Southern Company | | | | |
| Cash flow hedges: | | | | |
| Energy-related derivatives | $ | 11 | | $ | 38 | | $ | 51 | | $ | 59 | |
| Interest rate derivatives | 6 | | 5 | | 36 | | 7 | |
| Foreign currency derivatives | (35) | | (36) | | (137) | | (79) | |
Fair value hedges(*): | | | | |
| Foreign currency derivatives | 20 | | (4) | | 18 | | (4) | |
| Total | $ | 2 | | $ | 3 | | $ | (32) | | $ | (17) | |
| | | | |
| | | | |
| Georgia Power | | | | |
| | | | |
| Interest rate derivatives | $ | — | | $ | — | | $ | 31 | | $ | — | |
| | | | |
| | | | |
| | | | |
| Southern Power | | | | |
| Cash flow hedges: | | | | |
| Energy-related derivatives | $ | (11) | | $ | 8 | | $ | (4) | | $ | 16 | |
| | | | |
| Foreign currency derivatives | (35) | | (36) | | (137) | | (79) | |
| Total | $ | (46) | | $ | (28) | | $ | (141) | | $ | (63) | |
| Southern Company Gas | | | | |
| Cash flow hedges: | | | | |
| Energy-related derivatives | $ | 22 | | $ | 30 | | $ | 55 | | $ | 43 | |
| Interest rate derivatives | 5 | | — | | — | | — | |
| Total | $ | 27 | | $ | 30 | | $ | 55 | | $ | 43 | |
(*)Represents amounts excluded from the assessment of effectiveness for which the other registrants.difference between changes in fair value and periodic amortization is recorded in OCI.
For the three and nine months ended September 30, 20172022 and 2016,2021, the pre-tax effects of energy-relatedinterest rate derivatives designated as cash flow hedging instruments on accumulated OCI were immaterial for the other Registrants.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
For the three and nine months ended September 30, 2022 and 2021, 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, |
|
| 2022 | 2021 | 2022 | 2021 |
| (in millions) | (in millions) |
| Southern Company | | | | |
| Total cost of natural gas | $ | 294 | | $ | 129 | | $ | 1,840 | | $ | 943 | |
Gain (loss) on energy-related cash flow hedges(a) | 9 | | 2 | | 28 | | — | |
| Total depreciation and amortization | 922 | | 896 | | 2,728 | | 2,658 | |
Gain (loss) on energy-related cash flow hedges(a) | (1) | | 3 | | 5 | | 6 | |
| Total interest expense, net of amounts capitalized | (511) | | (451) | | (1,461) | | (1,352) | |
Gain (loss) on interest rate cash flow hedges(a) | (7) | | (7) | | (19) | | (20) | |
Gain (loss) on foreign currency cash flow hedges(a) | (3) | | (6) | | (16) | | (18) | |
Gain (loss) on interest rate fair value hedges(b) | (102) | | (4) | | (300) | | (16) | |
| Total other income (expense), net | 132 | | 131 | | 414 | | 290 | |
Gain (loss) on foreign currency cash flow hedges(a)(c) | (32) | | (34) | | (129) | | (76) | |
| Gain (loss) on foreign currency fair value hedges | (59) | | (32) | | (180) | | (32) | |
| Amount excluded from effectiveness testing recognized in earnings | (21) | | 4 | | (17) | | 4 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| Southern Power | | | | |
| Total depreciation and amortization | $ | 133 | | $ | 132 | | $ | 384 | | $ | 383 | |
Gain (loss) on energy-related cash flow hedges(a) | (1) | | 3 | | 5 | | 6 | |
| Total interest expense, net of amounts capitalized | (32) | | (36) | | (105) | | (111) | |
Gain (loss) on foreign currency cash flow hedges(a) | (3) | | (6) | | (16) | | (18) | |
| Total other income (expense), net | 3 | | 2 | | 5 | | 10 | |
Gain (loss) on foreign currency cash flow hedges(a)(c) | (32) | | (34) | | (129) | | (76) | |
| Southern Company Gas | | | | |
| Total cost of natural gas | $ | 294 | | $ | 129 | | $ | 1,840 | | $ | 943 | |
Gain (loss) on energy-related cash flow hedges(a) | 9 | | 2 | | 28 | | — | |
| Total interest expense, net of amounts capitalized | (65) | | (57) | | (187) | | (175) | |
Gain (loss) on interest rate cash flow hedges(a) | (2) | | (1) | | (3) | | (2) | |
Gain (loss) on interest rate fair value hedges(b) | (30) | | — | | (87) | | 2 | |
(a)Reclassified from accumulated OCI into earnings.
(b)For fair value hedges, changes in the fair value of the derivative contracts are generally equal to changes in the fair value of the underlying debt and have no material impact on income.
(c)The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes.
For the three and nine months ended September 30, 2022 and 2021, the pre-tax effects of cash flow hedge accounting on income for interest rate derivatives were immaterial for Alabama Power, Georgia Power, and Mississippi Power.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
At September 30, 2022 and December 31, 2021, 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 | At September 30, 2022 | At December 31, 2021 | | At September 30, 2022 | At December 31, 2021 |
| (in millions) | | (in millions) |
| Southern Company | | | | | |
| | | | | |
| Long-term debt | $ | (2,788) | | $ | (3,280) | | | $ | 306 | | $ | 9 | |
| | | | | |
| Southern Company Gas | | | | | |
| | | | | |
| Long-term debt | $ | (411) | | $ | (493) | | | $ | 86 | | $ | 2 | |
For the three and nine months ended September 30, 2022 and 2021, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income of Southern Company and Southern Company Gas were as follows:
| | | | | | | | | | | | | | | | | | | | |
| | Gain (Loss) |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| Derivatives in Non-Designated Hedging Relationships | Statements of Income Location | 2022 | 2021 | | 2022 | 2021 |
| | (in millions) | | (in millions) |
| | | | | | |
| Energy-related derivatives: | Natural gas revenues(*) | $ | 3 | | $ | (2) | | | $ | (10) | | $ | (122) | |
| Cost of natural gas | (2) | | 20 | | | (7) | | 36 | |
| | | | | | |
| Total derivatives in non-designated hedging relationships | $ | 1 | | $ | 18 | | | $ | (17) | | $ | (86) | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | |
|
| | | | | | | | | | | | | | |
| | | Gain (Loss) |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| Derivatives in Non-Designated Hedging Relationships | Statements of Income Location | 2017 | 2016 | | 2017 | 2016 |
| | | (in millions) | | (in millions) |
| Southern Company | | | | | | |
| Energy Related derivatives: | Natural gas revenues(*) | $ | (17 | ) | $ | — |
| | $ | 48 |
| $ | — |
|
| | Cost of natural gas | 2 |
| 6 |
| | (2 | ) | 6 |
|
| Total derivatives in non-designated hedging relationships | $ | (15 | ) | $ | 6 |
| | $ | 46 |
| $ | 6 |
|
| |
(*) | Excludes gains (losses) recorded in cost of natural gas associated with weather derivatives of $15 million for the nine months ended September 30, 2017 and immaterial amounts for all other periods presented. |
|
| | | | | | | | | | | | | | | | | | | | | |
| | | Gain (Loss) |
| | | Successor |
| Successor | | Successor | | Successor | | | Predecessor |
| Derivatives in Non-Designated Hedging Relationships | Statements of Income Location | Three Months Ended September 30, 2017 | | Three Months Ended September 30, 2016 | | Nine Months Ended September 30, 2017 | | July 1, 2016 through September 30, 2016 | | | January 1, 2016 through June 30, 2016 |
| | | (in millions) | | (in millions) | | (in millions) | | (in millions) | | | |
| Southern Company Gas | | | | | | | | | | |
| Energy Related derivatives: | Natural gas revenues(*) | $ | (17 | ) | | $ | — |
| | $ | 48 |
| | $ | — |
| | | $ | (1 | ) |
| | Cost of natural gas | 2 |
| | 6 |
| | (2 | ) | | 6 |
| | | (62 | ) |
| Total derivatives in non-designated hedging relationships | $ | (15 | ) | | $ | 6 |
| | $ | 46 |
| | $ | 6 |
| | | $ | (63 | ) |
| |
(*) | Excludes gains recorded in cost of natural gas associated with weather derivatives of $15 million for the successor nine months ended September 30, 2017 and immaterial amounts for all other periods presented. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
(*)Excludes immaterial gains (losses) recorded in natural gas revenues associated with weather derivatives for all periods presented.
For the three and nine months ended September 30, 20172022 and 2016,2021, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments were immaterial for the traditional electric operating companies and Southern Power.
For the three and nine months ended September 30, 2017 and 2016, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were as follows:
|
| | | | | | | | | | | | | | | |
| Derivatives in Fair Value Hedging Relationships |
| | | Gain (Loss) |
| | | Three Months Ended September 30, | Nine Months Ended September 30, |
| Derivative Category | Statements of Income Location | 2017 | | 2016 | 2017 | | 2016 |
| | | (in millions) | (in millions) |
| Southern Company | | | | | | | |
| Interest rate derivatives: | Interest expense, net of amounts capitalized | $ | (5 | ) | | $ | (9 | ) | $ | (6 | ) | | $ | 15 |
|
| Georgia Power | | | | | | | |
| Interest rate derivatives: | Interest expense, net of amounts capitalized | $ | — |
| | $ | (5 | ) | $ | (1 | ) | | $ | 10 |
|
For the three and nine months ended September 30, 2017 and 2016, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were offset by changes to the carrying value of long-term debt.
There was no material ineffectiveness recorded in earnings for any registrant for any period presented.other Registrants.
Contingent Features
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company GasThe Registrants 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. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. At September 30, 2017,2022, the registrantsRegistrants had no collateral posted with derivative counterparties to satisfy these arrangements.
At September 30, 2017,For Southern Company and Southern Power, the fair value of interest rate derivative liabilities with contingent features was immaterial for all registrants. Theand the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $156 million and $38 million, respectively at September 30, 2022. For the traditional electric operating companies and Southern Power, 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.at September 30, 2022. 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.
Generally, collateral may be provided by a Following the sale of Gulf Power to NextEra Energy, Inc., Gulf Power continued participating in the Southern Company guaranty, letterpower pool through July 13, 2022.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Alabama Power and Southern Power maintain accounts with certain regional transmission organizations to facilitate financial derivative transactions. Basedtransactions and they may be required to post collateral 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.requirements. At September 30, 2017,2022, cash collateral posted in these accounts was immaterial. Southern Company Gas maintains accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Southern Company Gas may be required to deposit cash into these accounts. At September 30, 2017,2022, cash collateral held on deposit in broker margin accounts was $76$15 million.
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company GasThe Registrants are exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Company, the traditional electric operating companies, Southern Power, and Southern Company GasThe Registrants only enter into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company GasThe Registrants have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate Southern Company's, the traditional electric operating companies', Southern Power's, and Southern Company Gas'their exposure to counterparty credit risk. 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 uses established credit policies to determine and monitor the creditworthiness of counterparties, including requirements to post collateral or other credit security, as well as the quality of pledged collateral. Collateral or credit security is most often in the form of cash or letters of credit from an investment-grade financial institution, but may also utilizes master netting agreements whenever possibleinclude cash or U.S. government securities held by a trustee. Prior to mitigate exposure to counterparty credit risk. Whenentering a physical transaction, Southern Company Gas is engaged in more than one outstanding derivative transaction withassigns its counterparties an internal credit rating and credit limit based on the same counterpartycounterparties' Moody's, S&P, and it also has a legally enforceable netting agreement with that counterparty, the "net" mark-to-market exposure represents the netting of the positiveFitch ratings, commercially available credit reports, 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.audited financial statements. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.
Southern Company the traditional electric operating companies, Southern Power, andGas utilizes netting agreements whenever possible to mitigate exposure to counterparty credit risk. Netting agreements enable Southern Company Gas to net certain assets and liabilities by counterparty across product lines and against cash collateral, provided the netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, counterparties are settled net, they are recorded on a gross basis on the balance sheet as energy marketing receivables and energy marketing payables.
The Registrants do not anticipate a material adverse effect on thetheir respective financial statements as a result of counterparty nonperformance.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| |
(I) | (K) ACQUISITIONS AND DISPOSITIONS |
Southern Company
Merger with Southern Company Gas
Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through the natural gas distribution utilities. On July 1, 2016, Southern Company completed the Merger for a total purchase price of approximately $8.0 billion and Southern Company Gas became a wholly-owned, direct subsidiary of Southern Company.
The Merger was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value as of the acquisition date. The following table presents the final purchase price allocation:
|
| | | |
| Southern Company Gas Purchase Price | |
| | (in millions) |
| Current assets | $ | 1,557 |
|
| Property, plant, and equipment | 10,108 |
|
| Goodwill | 5,967 |
|
| Intangible assets | 400 |
|
| Regulatory assets | 1,118 |
|
| Other assets | 229 |
|
| Current liabilities | (2,201 | ) |
| Other liabilities | (4,742 | ) |
| Long-term debt | (4,261 | ) |
| Noncontrolling interest | (174 | ) |
| Total purchase price | $ | 8,001 |
|
The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $6.0 billion is recognized as goodwill, which is primarily attributable to positioning the Southern Company system to provide natural gas infrastructure to meet customers' growing energy needs and to compete for growth across the energy value chain. Southern Company anticipates that much of the value assigned to goodwill will not be deductible for tax purposes.
The valuation of identifiable intangible assets included customer relationships, trade names, and storage and transportation contracts with estimated lives of one to 28 years. The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3).
The results of operations for Southern Company Gas have been included in Southern Company's consolidated financial statements from the date of acquisition and consist of operating revenues of $565 million and $2.8 billion and net income of $15 million and $303 million for the three and nine months ended September 30, 2017, respectively, and operating revenues and net income of $543 million and $4 million, respectively, for the three months ended September 30, 2016.
The following summarized unaudited pro forma consolidated statement of earnings information assumes that the acquisition of Southern Company Gas was completed on January 1, 2015. The summarized unaudited pro forma consolidated statement of earnings information includes adjustments for (i) intercompany sales, (ii) amortization of intangible assets, (iii) adjustments to interest expense to reflect current interest rates on Southern Company Gas debt and additional interest expense associated with borrowings by Southern Company to fund the Merger, and (iv) the elimination of nonrecurring expenses associated with the Merger.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | |
| | For the Nine Months Ended September 30, |
| | 2016 |
Operating revenues (in millions) | $ | 16,609 |
|
Net income attributable to Southern Company (in millions) | $ | 2,394 |
|
| Basic Earnings Per Share (EPS) | $ | 2.52 |
|
| Diluted EPS | $ | 2.51 |
|
These unaudited pro forma results are for comparative purposes only and may not be indicative of the results that would have occurred had this acquisition been completed on January 1, 2015 or the results that would be attained in the future.
Acquisition of PowerSecure
On May 9, 2016, Southern Company acquired all of the outstanding stock of PowerSecure, a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure, for $18.75 per common share in cash, resulting in an aggregate purchase price of $429 million. As a result, PowerSecure became a wholly-owned subsidiary of Southern Company.
The acquisition of PowerSecure was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value as of the acquisition date. The following table presents the final purchase price allocation:
|
| | | |
| PowerSecure Purchase Price | |
| | (in millions) |
| Current assets | $ | 172 |
|
| Property, plant, and equipment | 46 |
|
| Intangible assets | 106 |
|
| Goodwill | 284 |
|
| Other assets | 4 |
|
| Current liabilities | (121 | ) |
| Long-term debt, including current portion | (48 | ) |
| Deferred credits and other liabilities | (14 | ) |
| Total purchase price | $ | 429 |
|
The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $284 million was recognized as goodwill, which is primarily attributable to expected business expansion opportunities for PowerSecure. Southern Company anticipates that the majority of the value assigned to goodwill will not be deductible for tax purposes.
The valuation of identifiable intangible assets included customer relationships, trade names, patents, backlog, and software with estimated lives of one to 26 years. The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3).
The results of operations for PowerSecure have been included in Southern Company's consolidated financial statements from the date of acquisition and are immaterial to the consolidated financial results of Southern Company. Pro forma results of operations have not been presented for the acquisition because the effects of the acquisition were immaterial to Southern Company's consolidated financial results for all periods presented.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Southern Power
See Note 215 to the financial statements of Southern Power and Note 12 to the financial statements of Southern Company under "Southern Power" in Item 8 of the Form 10-K for additional information.
Acquisitions During the Nine Months Ended
Alabama Power
On September 30, 20172022, Alabama Power completed its acquisition of the Calhoun Generating Station, which was accounted for as an asset acquisition. The total purchase price was $179 million, of which $171 million was related to net assets recorded within property, plant, and equipment on the balance sheet and the remainder primarily related to fossil fuel stock and materials and supplies. See Note (B) and Note 15 to the financial statements in Item 8 of the Form 10-K under "Alabama Power" for additional information.
Southern Power
Construction Projects
During the nine months ended September 30, 2017, in accordance with Southern Power's overall growth strategy, one of Southern Power's wholly-owned subsidiaries acquired the project discussed below. Acquisition-related costs were expensed as incurred and were not material.
|
| | | | | | | | | |
| Project Facility | Resource | Seller; Acquisition Date | Approximate Nameplate Capacity (MW) | Location | Southern Power Percentage Ownership | Actual COD | PPA Contract Period |
| Bethel | Wind | Invenergy,
January 6, 2017 | 276 | Castro County, TX | 100 | % | | January 2017 | 12 years |
The aggregate amounts of revenue and net income recognized by Southern Power related to the Bethel facility included in Southern Power's condensed consolidated statements of income for year-to-date 2017 were immaterial. The Bethel facility did not have operating revenues or activities prior to completion of construction and the assets being placed in service; therefore, supplemental pro forma information as though the acquisition occurred as of the beginning of 2017 and for the comparable 2016 period is not meaningful and has been omitted.
In connection with Southern Power's 2016 acquisitions, allocations of the purchase price to individual assets were finalized during the nine months ended September 30, 2017 with no changes to amounts originally reported for Boulder 1, Grant Plains, Grant Wind, Henrietta, Mankato, Passadumkeag, Salt Fork, Tyler Bluff, and Wake Wind.
Subsequent to September 30, 2017, Southern Power purchased all of the redeemable noncontrolling interests, representing 10% of the membership interests, in Southern Turner Renewable Energy, LLC and repaid $14 million of notes payable to Turner Renewable Energy, LLC.
Construction Projects Completed and in Progress
During the nine months ended September 30, 2017, in accordance with its overall growth strategy,2022, Southern Power completed construction of and placed in service or continued constructionthe remaining 40 MWs of the projects set forthTranquillity battery energy storage facility and the remaining 15 MWs of the Garland battery energy storage facility.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | | | | |
| Project Facility | Resource | Approximate Nameplate Capacity (MW) | Location | COD | PPA Contract Period |
| Projects Completed During the Nine Months Ended September 30, 2022 |
Garland Solar Storage(a) | Battery energy storage system | 88 | Kern County, CA | September 2021 through February 2022(b) | 20 years |
Tranquillity Solar Storage(a) | Battery energy storage system | 72 | Fresno County, CA | November 2021 through March 2022(c) | 20 years |
(a)Southern Power consolidates each project's operating results in its financial statements and the tax equity partner and two other partners each own a noncontrolling interest.
(b)The facility has a total capacity of 88 MWs, of which 73 MWs were placed in service in 2021 and 15 MWs were placed in service in February 2022.
(c)The facility has a total capacity of 72 MWs, of which 32 MWs were placed in service in 2021 and 40 MWs were placed in service in March 2022.
Southern Company Gas
Sale of Natural Gas Storage Facilities
On September 7, 2022, certain affiliates of Southern Company Gas entered into agreements to sell two natural gas storage facilities located in California and Texas for an aggregate purchase price of $186 million, plus working capital and certain other adjustments. Completion of the sales is subject to material closing conditions, including, among others, release of a Southern Company Gas parent guarantee, approval from the California Public Utility Commission without a material burdensome condition, and the expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. The parent guarantee release was executed on October 20, 2022, which resolved a material closing condition. As a result, Southern Company Gas expects to record pre-tax impairment charges totaling approximately $125 million ($95 million after tax) in the following table. Through September 30, 2017, total costsfourth quarter 2022. The sale of construction incurred for these projects were $494 million, of which $122 million remained in CWIP. Total aggregate construction costs, excluding the acquisition costs, areTexas facility is expected to be between $360 millioncompleted later in the fourth quarter 2022, and $415 million for the Mankato and Cactus Flats facilities. Thesale of the California facility is expected to be completed during 2023; however, the ultimate outcome of these matters cannot be determined at this time.
|
| | | | | |
Project Facility | Resource | Approximate Nameplate Capacity (MW)
| Location | Actual/Expected COD | PPA Contract Period |
Projects Completed During the Nine Months Ended September 30, 2017 |
East Pecos | Solar | 120 | Pecos County, TX | March 2017 | 15 years |
Lamesa | Solar | 102 | Dawson County, TX | April 2017 | 15 years |
| | | | | |
Projects Under Construction as of September 30, 2017 |
Cactus Flats(*)
| Wind | 148 | Concho County, TX | Third quarter 2018 | 12-15 years |
Mankato | Natural Gas | 345 | Mankato, MN | Second quarter 2019 | 20 years |
| |
(*) | On July 31, 2017, Southern Power acquired a 100% ownership interest in the Cactus Flats facility, which is in the early stages of construction, from RES America Developments, Inc. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Development Projects
In December 2016, as partSale of Southern Power's renewable development strategy, one of Southern Power's wholly-owned subsidiaries entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct approximately 3,000 MWs of wind projects. Also in December 2016, Southern Power signed agreements and made payments to purchase wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. All of the wind turbine equipment was delivered by April 2017, which allows the projects to qualify for 100% PTCs for 10 years following their expected commercial operation dates between 2018 and 2020. The ultimate outcome of these matters cannot be determined at this time.
Southern Company GasPivotal LNG
On October 15, 2017,May 20, 2022, Southern Company Gas subsidiary, Pivotal Utilityreceived the final $5 million contingent payment from Dominion Modular LNG Holdings, entered into agreements for theInc. in connection with its 2020 sale of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries,Pivotal LNG, Inc. for a total cash purchase price of $1.7 billion. The completion of each sale is subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act; (ii) the receipt of required regulatory approvals, including the FERC, the Federal Communications Commission, the New Jersey BPU, and, with respect to the sale of Elkton Gas, the Maryland PSC; and (iii) other customary closing conditions. The sales are expected to be completed by the end of the third quarter 2018.
The ultimate outcome of these matters cannot be determined at this time.
| |
(J) | JOINT OWNERSHIP AGREEMENTS |
Southern Company Gas
See Note 4 to the financial statements of Southern Company Gas in Item 8 of the Form 10-K for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Equity Method Investments
The carrying amounts of Southern Company Gas' equity method investments as of September 30, 2017 and December 31, 2016 and related income from those investments for the successor three and nine month periods ended September 30, 2017, the successor three-month period ended September 30, 2016, and for the predecessor period January 1, 2016 through June 30, 2016 were as follows:
|
| | | | | | |
| Balance Sheet Information | September 30, 2017 | December 31, 2016 |
| | (in millions) |
| SNG | $ | 1,385 |
| $ | 1,394 |
|
| Atlantic Coast Pipeline | 61 |
| 33 |
|
| PennEast Pipeline | 49 |
| 22 |
|
| Triton | 43 |
| 44 |
|
| Pivotal JAX LNG, LLC | 40 |
| 16 |
|
| Horizon Pipeline | 30 |
| 30 |
|
| Other | 1 |
| 2 |
|
| Total | $ | 1,609 |
| $ | 1,541 |
|
|
| | | | | | | | | | | | |
| | Successor | Successor | Successor | Predecessor |
| Income Statement Information | Three Months Ended September 30, 2017 | Three Months Ended September 30, 2016 | Nine Months Ended September 30, 2017 | January 1, 2016 through June 30, 2016 |
| | (in millions) | (in millions) | (in millions) | (in millions) |
| SNG | $ | 28 |
| $ | 27 |
| $ | 86 |
| $ | — |
|
| PennEast Pipeline | 1 |
| — |
| 5 |
| — |
|
| Atlantic Coast Pipeline | 1 |
| 1 |
| 4 |
| — |
|
| Triton | 1 |
| 1 |
| 3 |
| 1 |
|
| Horizon Pipeline | 1 |
| — |
| 2 |
| 1 |
|
| Total | $ | 32 |
| $ | 29 |
| $ | 100 |
| $ | 2 |
|
Southern Natural Gas
In September 2016, Southern Company Gas, through a wholly-owned, indirect subsidiary, acquired a 50% equity interest in SNG, which is accounted for as an equity method investment. On March 31, 2017, Southern Company Gas made an additional $50 million contribution to maintain its 50% equity interest in SNG. See Note 11 to the financial statements of Southern Company Gas under "Investment in SNG" in Item 8 of the Form 10-K for additional information on this investment. Selected financial information of SNG for the three and nine months ended September 30, 2017 and for the period September 1, 2016 through September 30, 2016 is as follows:
|
| | | | | | | | | |
| Income Statement Information | Three Months Ended September 30, 2017 | Nine Months Ended September 30, 2017 | September 1, 2016 through September 30, 2016 |
| | (in millions) |
| Revenues | $ | 146 |
| $ | 445 |
| $ | 82 |
|
| Operating income | $ | 71 |
| $ | 218 |
| $ | 60 |
|
| Net income | $ | 57 |
| $ | 172 |
| $ | 55 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
(K)(L) 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 and battery energy storage projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through the sevenits natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas pipeline investments and gas marketing services,services. Prior to the sale of Sequent on July 1, 2021, Southern Company Gas' other businesses also included wholesale gas services, and gas midstream operations.services.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Southern Company's reportable business segments are the sale of electricity by the four traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Company Gas. Revenues from sales by Southern Power to the traditional electric operating companies were $105$336 million and $295$673 million for the three and nine months ended September 30, 2017,2022, respectively, and $110$167 million and $313$361 million for the three and nine months ended September 30, 2016,2021, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies were immaterial for all periods presented. Revenues from sales of natural gas from Southern Company Gas (prior to its sale of Sequent) to Southern Power were $18 million for the nine months ended September 30, 2021. 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 distributed energy technologies and services to electric utilitiesresilience solutions and largedeploying microgrids for commercial, industrial, commercial, institutional,governmental, and municipal customers;utility customers, as well as investments in telecommunications and, for the three and nine months ended September 30, 2021, leveraged lease projects. All other inter-segment revenues are not material.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS:STATEMENTS (Continued)
(UNAUDITED)
Financial data for business segments and products and services for the three and nine months ended September 30, 20172022 and 20162021 was as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Electric Utilities | | | | |
| Traditional
Electric Operating
Companies | Southern
Power | Eliminations | Total | Southern Company Gas | All
Other | Eliminations | Consolidated |
| (in millions) |
| Three Months Ended September 30, 2022 | | | | | | | |
| Operating revenues | $ | 6,938 | | $ | 1,180 | | $ | (691) | | $ | 7,427 | | $ | 857 | | $ | 135 | | $ | (41) | | $ | 8,378 | |
Segment net income (loss)(a)(b) | 1,445 | | 95 | | — | | 1,540 | | 83 | | (152) | | 1 | | 1,472 | |
| Nine Months Ended September 30, 2022 | | | | | | | |
| Operating revenues | $ | 16,716 | | $ | 2,618 | | $ | (1,391) | | $ | 17,943 | | $ | 3,998 | | $ | 418 | | $ | (127) | | $ | 22,232 | |
Segment net income (loss)(a)(b) | 3,256 | | 265 | | — | | 3,521 | | 516 | | (415) | | (11) | | 3,611 | |
| At September 30, 2022 | | | | | | | | |
| Goodwill | $ | — | | $ | 2 | | $ | — | | $ | 2 | | $ | 5,015 | | $ | 263 | | $ | — | | $ | 5,280 | |
| Total assets | 95,659 | | 13,283 | | (748) | | 108,194 | | 24,097 | | 2,372 | | (658) | | 134,005 | |
| Three Months Ended September 30, 2021 | | | | | | | |
| Operating revenues | $ | 5,018 | | $ | 679 | | $ | (170) | | $ | 5,527 | | $ | 623 | | $ | 124 | | $ | (36) | | $ | 6,238 | |
Segment net income (loss)(a)(b)(c) | 1,085 | | 78 | | — | | 1,163 | | 56 | | (121) | | 3 | | 1,101 | |
| Nine Months Ended September 30, 2021 | | | | | | | |
| Operating revenues | $ | 12,813 | | $ | 1,610 | | $ | (372) | | $ | 14,051 | | $ | 2,994 | | $ | 412 | | $ | (111) | | $ | 17,346 | |
Segment net income (loss)(a)(b)(c)(d)(e) | 2,352 | | 211 | | — | | 2,563 | | 389 | | (338) | | (6) | | 2,608 | |
| At December 31, 2021 | | | | | | | | |
| Goodwill | $ | — | | $ | 2 | | $ | — | | $ | 2 | | $ | 5,015 | | $ | 263 | | $ | — | | $ | 5,280 | |
| Total assets | 89,051 | | 13,390 | | (667) | | 101,774 | | 23,560 | | 2,975 | | (775) | | 127,534 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Electric Utilities | | | | |
| | Traditional Electric Operating Companies | Southern Power | Eliminations | Total | Southern Company Gas | All Other | Eliminations | Consolidated |
| | (in millions) |
Three Months Ended
September 30, 2017: | | | | | | | | |
| Operating revenues | $ | 5,017 |
| $ | 618 |
| $ | (112 | ) | $ | 5,523 |
| $ | 565 |
| $ | 153 |
| $ | (40 | ) | $ | 6,201 |
|
Segment net income (loss)(a)(b) | 1,008 |
| 124 |
| — |
| 1,132 |
| 15 |
| (80 | ) | 2 |
| 1,069 |
|
Nine Months Ended
September 30, 2017: | | | | |
|
| | | |
| Operating revenues | $ | 12,960 |
| $ | 1,597 |
| $ | (318 | ) | $ | 14,239 |
| $ | 2,841 |
| $ | 442 |
| $ | (119 | ) | $ | 17,403 |
|
Segment net income (loss)(a)(b)(c) | — |
| 276 |
| — |
| 276 |
| 303 |
| (232 | ) | — |
| 347 |
|
| Total assets at September 30, 2017 | $ | 73,056 |
| $ | 14,648 |
| $ | (322 | ) | $ | 87,382 |
| $ | 22,190 |
| $ | 2,275 |
| $ | (1,532 | ) | $ | 110,315 |
|
Three Months Ended
September 30, 2016: | | | | | | | | |
| Operating revenues | $ | 5,236 |
| $ | 500 |
| $ | (117 | ) | $ | 5,619 |
| $ | 543 |
| $ | 139 |
| $ | (37 | ) | $ | 6,264 |
|
Segment net income (loss)(a)(b) | 1,022 |
| 176 |
| — |
| 1,198 |
| 4 |
| (62 | ) | (1 | ) | 1,139 |
|
Nine Months Ended
September 30, 2016: | | | | | | | | |
| Operating revenues | $ | 13,120 |
| $ | 1,189 |
| $ | (330 | ) | $ | 13,979 |
| $ | 543 |
| $ | 311 |
| $ | (118 | ) | $ | 14,715 |
|
Segment net income (loss)(a)(b) | 2,086 |
| 315 |
| — |
| 2,401 |
| 4 |
| (146 | ) | (8 | ) | 2,251 |
|
| Total assets at December 31, 2016 | $ | 72,141 |
| $ | 15,169 |
| $ | (316 | ) | $ | 86,994 |
| $ | 21,853 |
| $ | 2,474 |
| $ | (1,624 | ) | $ | 109,697 |
|
| |
(a) | Attributable to Southern Company. |
| |
(b) | Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated probable losses on the Kemper IGCC of $34 million ($21 million after tax) and $88 million ($54 million after tax) for the three months ended September 30, 2017 and 2016, respectively, and $3.2 billion ($2.2 billion after tax) and $222 million ($137 million after tax) for the nine months ended September 30, 2017 and 2016, respectively. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information.
|
| |
(c) | Segment net income (loss) for the traditional electric operating companies also includes a pre-tax charge for the write-down of Gulf Power's ownership of Plant Scherer Unit(b)For the traditional electric operating companies, includes pre-tax charges (credits) to income at Georgia Power for the estimated probable loss associated with the construction of Plant Vogtle Units 3 of $33 million ($20 million after tax) for the nine months ended September 30, 2017. See Note (B) under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" for additional information. |
Products and Services4 of $(70) million ($(52) million after tax) and $(18) million ($(13) million after tax) for the three and nine months ended September 30, 2022, respectively, and $264 million ($197 million after tax) and $772 million ($576 million after tax) for the three and nine months ended September 30, 2021, respectively. See Note (B) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.
(c)For Southern Company Gas, includes a pre-tax gain of $121 million ($93 million after tax) related to its sale of Sequent, as well as the resulting $85 million of additional tax expense as a result of the sale. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
(d)For Southern Power, includes gains on wind turbine equipment contributed to various equity method investments totaling approximately $37 million pre-tax ($28 million after tax). See Note 15 to the financial statements under "Southern Power – Development Projects" in Item 8 of the Form 10-K for additional information.
(e)For Southern Company Gas, includes pre-tax impairment charges totaling $84 million ($67 million after tax) related to its equity method investment in the PennEast Pipeline project. See Note 7 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
|
| | | | | | | | | | | | | | | | |
| | | Electric Utilities' Revenues |
| Period | | Retail | | Wholesale | | Other | | Total |
| | | (in millions) |
| Three Months Ended September 30, 2017 | | $ | 4,615 |
| | $ | 718 |
| | $ | 190 |
| | $ | 5,523 |
|
| Three Months Ended September 30, 2016 | | 4,808 |
| | 613 |
| | 198 |
| | 5,619 |
|
| | | | | | | | | |
| Nine Months Ended September 30, 2017 | | $ | 11,786 |
| | $ | 1,867 |
| | $ | 586 |
| | $ | 14,239 |
|
| Nine Months Ended September 30, 2016 | | 11,932 |
| | 1,455 |
| | 592 |
| | 13,979 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS:STATEMENTS (Continued)
(UNAUDITED)
Products and Services
| | | | | | | | | | | | | | |
| | Electric Utilities' Revenues |
| Retail | Wholesale | Other | Total |
| (in millions) |
| Three Months Ended September 30, 2022 | $ | 5,961 | | $ | 1,197 | | $ | 269 | | $ | 7,427 | |
| Three Months Ended September 30, 2021 | 4,551 | | 731 | | 245 | | 5,527 | |
| Nine Months Ended September 30, 2022 | $ | 14,363 | | $ | 2,798 | | $ | 782 | | $ | 17,943 | |
| Nine Months Ended September 30, 2021 | 11,492 | | 1,822 | | 737 | | 14,051 | |
|
| | | | | | | | | | | | |
| | Southern Company Gas' Revenues |
| Period | Gas
Distribution
Operations | Gas
Marketing
Services | Other | Total |
| | (in millions) |
| Three Months Ended September 30, 2017 | $ | 430 |
| $ | 143 |
| $ | (8 | ) | $ | 565 |
|
| Nine Months Ended September 30, 2017 | $ | 2,119 |
| $ | 597 |
| $ | 125 |
| $ | 2,841 |
|
| Three and Nine Months Ended September 30, 2016 | $ | 420 |
| $ | 126 |
| $ | (3 | ) | $ | 543 |
|
| | | | | | | | | | | | | | | | | |
| | Southern Company Gas' Revenues |
| Gas
Distribution
Operations | Wholesale Gas Services(*) | Gas
Marketing
Services | Other | Total |
| (in millions) |
| Three Months Ended September 30, 2022 | $ | 748 | | $ | — | | $ | 85 | | $ | 24 | | $ | 857 | |
| Three Months Ended September 30, 2021 | 553 | | — | | 52 | | 18 | | 623 | |
| Nine Months Ended September 30, 2022 | $ | 3,513 | | $ | — | | $ | 420 | | $ | 65 | | $ | 3,998 | |
| Nine Months Ended September 30, 2021 | 2,451 | | 188 | | 311 | | 44 | | 2,994 | |
(*)Prior to the sale of Sequent, the revenues for wholesale gas services were netted with costs associated with its energy and risk management activities. See "Southern Company Gas" herein and Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information. Southern Company Gas
Southern Company Gas manages its business through fourthree reportable segments – gas distribution operations, gas pipeline investments, and gas marketing services,services. Prior to the sale of Sequent on July 1, 2021, Southern Company Gas' reportable segments also included wholesale gas services, and gas midstream operations.services. The non-reportable segments are combined and presented as all other. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information on the sale of Sequent.
Gas distribution operations is the largest component of Southern Company Gas' business and includes natural gas local distribution utilities that construct, manage, and maintain intrastate natural gas pipelines and gas distribution facilities in sevenfour states.
Gas marketing services includespipeline investments consists of joint ventures in natural gas marketingpipeline investments including a 50% interest in SNG and a 50% joint ownership interest in the Dalton Pipeline. These natural gas pipelines enable the provision of diverse sources of natural gas supplies to end-usethe customers primarilyof Southern Company Gas. Gas pipeline investments also includes a 20% ownership interest in Georgia and Illinois. Additionally, gas marketing services provides home equipment protection products and services. Wholesalethe PennEast Pipeline project, which was cancelled in September 2021. See Note 7 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Through July 1, 2021, wholesale gas services providesprovided 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 engagesengaged 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.
The all other column includes segments below the quantitative threshold for separate disclosure, including theand subsidiaries that fall below the quantitative threshold for separate disclosure.
After the Merger,disclosure, including storage and fuels operations. See Note (K) under "Southern Company Gas" for information regarding agreements by certain affiliates of Southern Company Gas changed its segment performance measure to net income. In ordersell two natural gas storage facilities.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Business segment financial data for the successor three months ended September 30, 2017 and 2016, the successor nine months ended September 30, 2017,2022 and 2021 was as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Gas Distribution Operations | Gas Pipeline Investments | Wholesale Gas Services(a) | Gas Marketing Services | Total | All Other | Eliminations | Consolidated |
| (in millions) |
| Three Months Ended September 30, 2022 | | | | | | |
| Operating revenues | $ | 751 | | $ | 8 | | $ | — | | $ | 85 | | $ | 844 | | $ | 16 | | $ | (3) | | $ | 857 | |
| Segment net income (loss) | 59 | | 24 | | — | | (2) | | 81 | | 2 | | — | | 83 | |
| Nine Months Ended September 30, 2022 | | | | | | |
| Operating revenues | $ | 3,533 | | $ | 24 | | $ | — | | $ | 420 | | $ | 3,977 | | $ | 43 | | $ | (22) | | $ | 3,998 | |
| Segment net income (loss) | 365 | | 76 | | — | | 65 | | 506 | | 10 | | — | | 516 | |
| Total assets at September 30, 2022 | 21,605 | | 1,425 | | — | | 1,595 | | 24,625 | | 9,100 | | (9,628) | | 24,097 | |
| Three Months Ended September 30, 2021 | | | | | | |
| Operating revenues | $ | 556 | | $ | 8 | | $ | — | | $ | 52 | | $ | 616 | | $ | 11 | | $ | (4) | | $ | 623 | |
Segment net income (loss)(b)(c) | 45 | | 10 | | 94 | | (2) | | 147 | | (91) | | — | | 56 | |
| Nine Months Ended September 30, 2021 | | | | | | | |
| Operating revenues | $ | 2,466 | | $ | 24 | | $ | 188 | | $ | 311 | | $ | 2,989 | | $ | 29 | | $ | (24) | | $ | 2,994 | |
Segment net income (loss)(b)(c)(d) | 308 | | 3 | | 108 | | 60 | | 479 | | (90) | | — | | 389 | |
| Total assets at December 31, 2021 | 20,917 | | 1,467 | | 31 | | 1,556 | | 23,971 | | 12,114 | | (12,525) | | 23,560 | |
(a)As a result of the successor periodsale of Sequent, wholesale gas services is no longer a reportable segment for the three and nine months ended September 30, 2022. Prior to the sale of Sequent, the revenues for wholesale gas services were 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) |
| | | | | |
| | | | | |
| | | | | |
| Nine Months Ended September 30, 2021 | $ | 3,881 | | $ | 90 | | $ | 3,971 | | $ | 3,783 | | $ | 188 | |
(b)For wholesale gas services, includes a pre-tax gain of $121 million ($93 million after tax) related to the sale of Sequent. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
(c)For the "All Other" column, includes $85 million of additional tax expense as a result of the sale. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
(d)For gas pipeline investments, includes pre-tax impairment charges totaling $84 million ($67 million after tax) related to the equity method investment in the PennEast Pipeline project. See Note 7 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.
| | | | | |
| Page |
| Combined Management's Discussion and Analysis of Financial Condition and Results of Operations | |
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The following Management's Discussion and Analysis of Financial Condition and Results of Operations is a combined presentation; however, information contained herein relating to any individual Registrant is filed by such Registrant on its own behalf and each Registrant makes no representation as to information related to the other Registrants.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
OVERVIEW
Southern Company is a holding company that owns all of the common stock of three traditional electric operating companies (Alabama Power, Georgia Power, and Mississippi Power), Southern Power, and Southern Company Gas and owns other direct and indirect subsidiaries. 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. Southern Company's reportable segments are the sale of electricity by the traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Company Gas. Southern Company Gas' reportable segments are gas distribution operations, gas pipeline investments, and gas marketing services. Prior to the sale of Sequent on July 1, 2021, Southern Company Gas' reportable segments also included wholesale gas services. See Note (L) to the Condensed Financial Statements herein for additional information on segment reporting. For additional information on the Registrants' primary business activities and the sale of Sequent, see BUSINESS – "The Southern Company System" in Item 1 of the Form 10-K and Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K, respectively.
The Registrants continue to focus on several key performance indicators. For the traditional electric operating companies and Southern Company Gas, these indicators include, but are not limited to, customer satisfaction, plant availability, electric and natural gas system reliability, and execution of major construction projects. For Southern Power, these indicators include, but are not limited to, the equivalent forced outage rate and contract availability to evaluate operating results and help ensure its ability to meet its contractual commitments to customers. In addition, Southern Company and the Subsidiary Registrants focus on earnings per share and net income, respectively, as a key performance indicator.
Recent Developments
Alabama Power
On July 12, 2022, the Alabama PSC approved the following items:
•Alabama Power's petition for a certificate of convenience and necessity authorizing Alabama Power to complete the acquisition of the Calhoun Generating Station. The transaction closed on September 30, 2022 and, on October 3, 2022, Alabama Power filed Rate CNP New Plant with the Alabama PSC to recover the related costs. The filing reflected an increase in annual revenues of $34 million, or 0.6%, effective with the billing month of November 2022.
•An increase to Rate ECR effective with August 2022 billings, which is expected to result in an increase of approximately $310 million annually. The approved increase in the Rate ECR factor has no significant effect on Alabama Power's net income, but does increase operating cash flows related to fuel cost recovery.
•Modifications to Rate NDR.
•An accounting order authorizing Alabama Power to create a reliability reserve separate from the NDR and transition the previous Rate NDR authority related to reliability expenditures to the reliability reserve. Alabama Power may make accruals to the reliability reserve if the NDR balance exceeds $35 million.
See Note (B) to the Condensed Financial Statements under "Alabama Power" herein for additional information.
On September 23, 2022, the FERC authorized Alabama Power to use updated depreciation rates from its 2021 depreciation study effective January 1, 2023. The study was also provided to the Alabama PSC, and the new depreciation rates will be reflected in Alabama Power's future rate filings. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Alabama Power" herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Georgia Power
Plant Vogtle Units 3 and 4 Construction and Start-Up Status
Construction continues on Plant Vogtle Units 3 and 4 (with electric generating capacity of approximately 1,100 MWs each), in which Georgia Power currently holds a 45.7% ownership interest. Georgia Power's share of the total project capital cost forecast to complete Plant Vogtle Units 3 and 4, including contingency, through the end of the first quarter 2023 and the fourth quarter 2023, respectively, is $10.4 billion.
On July 29, 2022, Southern Nuclear announced that all Unit 3 ITAACs had been submitted to the NRC. On August 3, 2022, the NRC published its 103(g) finding that the acceptance criteria in the combined license for Unit 3 had been met, which allowed nuclear fuel to be loaded and allows start-up testing to begin. Fuel load for Unit 3 was completed on October 17, 2022, and the unit is projected to be placed in service by the end of the first quarter 2023. The projected schedule for Unit 3 primarily depends on the pace of system and area transitions to operations, including the completion of closure documentation necessary to support start-up testing, and the progression of start-up, final component, and pre-operational testing, which may be impacted by equipment or other operational failures. Unit 4 is projected to be placed in service by the end of the fourth quarter 2023. The projected schedule for Unit 4 primarily depends on Unit 3 progress through start-up and testing; overall construction productivity and production levels improving, particularly in electrical installation, including terminations; and appropriate levels of craft laborers, particularly electricians, being added and maintained. Any further delays could result in later in-service dates and cost increases.
During the first nine months of 2022, established construction contingency totaling $170 million was assigned to the base capital cost forecast for costs primarily associated with construction productivity, the pace of system turnovers, additional craft and support resources, and procurement for Units 3 and 4. Georgia Power also increased its total project capital cost forecast by adding $36 million and $32 million to replenish construction contingency in the second quarter 2022 and the third quarter 2022, respectively. After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded pre-tax charges to income in the second quarter 2022 and the third quarter 2022 of $36 million ($27 million after tax) and $32 million ($24 million after tax), respectively, for the increases in the total project capital cost forecast. Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery during the prudence review following the Unit 4 fuel load pursuant to the twenty-fourth VCM stipulation described in Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction – Regulatory Matters" herein.
Georgia Power and the other Vogtle Owners do not agree on the starting dollar amount for the determination of cost increases subject to the cost-sharing and tender provisions of the Global Amendments (as defined in Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction – Joint Owner Contracts" herein). The other Vogtle Owners have notified Georgia Power that they believe the current capital cost expenditures have already exceeded the cost-sharing thresholds and the current project capital cost forecast triggers the tender provisions under the Global Amendments.
On June 17, 2022 and July 26, 2022, OPC and Dalton, respectively, notified Georgia Power of their purported exercises of their tender options. On June 18, 2022, OPC and MEAG Power each filed a separate lawsuit against Georgia Power in the Superior Court of Fulton County, Georgia seeking a declaratory judgment that the starting dollar amount is $17.1 billion and that the cost-sharing and tender provisions have been triggered. On July 25, 2022 and July 28, 2022, Georgia Power filed its answers in the lawsuits filed by MEAG Power and OPC, respectively, and included counterclaims seeking a declaratory judgment that the starting dollar amount is $18.38 billion and that costs related to force majeure events are excluded prior to calculating the cost-sharing and tender provisions and when calculating Georgia Power's related financial obligations. On September 26, 2022, Dalton filed complaints in each of these lawsuits.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
On September 29, 2022, Georgia Power and MEAG Power reached an agreement to resolve their dispute regarding the proper interpretation of the cost-sharing and tender provisions of the Global Amendments. Under the terms of the agreement, among other items, (i) MEAG Power will not exercise its tender option and will retain its full ownership interest in Plant Vogtle Units 3 and 4; (ii) Georgia Power will pay a portion of MEAG Power's costs of construction for Plant Vogtle Units 3 and 4 as such costs are incurred and with no further adjustment for force majeure costs, which payments will total approximately $79 million based on the current project capital cost forecast; and (iii) Georgia Power will pay 20% of MEAG Power's costs of construction with respect to any amounts over the current project capital cost forecast, with no further adjustment for force majeure costs. On October 4, 2022, MEAG Power and Georgia Power filed a notice of settlement and voluntary dismissal of the pending litigation described above, including Georgia Power's counterclaim, and, on October 6, 2022, Dalton dismissed its related complaint. Georgia Power recorded pre-tax charges (credits) to income in the fourth quarter 2021, the second quarter 2022, and the third quarter 2022 of approximately $440 million ($328 million after tax), $16 million ($12 million after tax), and $(102) million ($(76) million after tax), respectively, associated with the cost-sharing and tender provisions of the Global Amendments, including the settlement with MEAG Power, which are included in the total project capital cost forecast. The settlement with MEAG Power does not resolve the separate pending litigation with OPC, including Dalton's associated complaint. Georgia Power may be required to record further pre-tax charges to income of up to approximately $300 million associated with the cost-sharing and tender provisions of the Global Amendments for OPC and Dalton based on the current project capital cost forecast.
The ultimate impact of these matters on the construction schedule and project capital cost forecast for Plant Vogtle Units 3 and 4 cannot be determined at this time. See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information.
2022 Base Rate Case
On June 24, 2022, Georgia Power filed a base rate case (Georgia Power 2022 Base Rate Case) with the Georgia PSC. The filing, as modified on August 22, 2022, proposes a three-year alternate rate plan with requested rate increases totaling $889 million, $107 million, and $45 million effective January 1, 2023, January 1, 2024, and January 1, 2025, respectively. Georgia Power expects the Georgia PSC to render a final decision in this matter on December 20, 2022. The ultimate outcome of this matter cannot be determined at this time. See Note (B) to the Condensed Financial Statements under "Georgia Power – Rate Plans – 2022 Base Rate Case" herein for additional information.
Integrated Resource Plan
On July 21, 2022, the Georgia PSC approved Georgia Power's triennial IRP (2022 IRP), as modified by a stipulated agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors and as further modified by the Georgia PSC. In the 2022 IRP decision, the Georgia PSC approved several requests, including the following:
•Decertification and retirement of Plant Wansley Units 1 and 2 (926 MWs based on 53.5% ownership), which occurred on August 31, 2022, and Plant Scherer Unit 3 (614 MWs based on 75% ownership) by December 31, 2028, as well as the reclassification to regulatory asset accounts of the remaining net book values of these units and any remaining unusable materials and supplies inventories upon retirement.
•Decertification and retirement of Plant Gaston Units 1 through 4 (500 MWs based on 50% ownership through SEGCO) by December 31, 2028. See Note 7 to the financial statements under "SEGCO" in Item 8 of the Form 10-K for additional information.
•Georgia Power's environmental compliance strategy, including approval of Georgia Power's plans to address CCR at its ash ponds and landfills.
The Georgia PSC deferred a decision on the requested decertification and retirement of Plant Bowen Units 1 and 2 (1,400 MWs) to the 2025 IRP.
See Note (B) to the Condensed Financial Statements under "Georgia Power – Integrated Resource Plans" herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Mississippi Power
On June 7, 2022, the Mississippi PSC approved Mississippi Power's annual retail PEP filing for 2022, resulting in an annual increase in revenues of approximately $18 million, or 1.9%. The rate increase became effective with the first billing cycle of April 2022 in accordance with the PEP rate schedule.
On August 26, 2022, the FERC accepted an amended shared service agreement (SSA) between Mississippi Power and Cooperative Energy, effective July 1, 2022, under which Cooperative Energy will continue to decrease its use of Mississippi Power's generation services under the MRA tariff up to 2.5% annually through 2035. At September 30, 2022, Mississippi Power is serving approximately 400 MWs of Cooperative Energy's annual demand.Beginning in 2036, Cooperative Energy will provide 100% of its electricity requirements at the MRA delivery points under the tariff. Neither party has the option to cancel the amended SSA. Mississippi Power expects to remarket this capacity, including the potential development of future arrangements with Cooperative Energy.
On July 15, 2022, Mississippi Power filed a request with the FERC for a $23 million increase in annual wholesale base revenues under the MRA tariff and requested an effective date of July 15, 2022. Cooperative Energy has filed a complaint with FERC challenging the new rates. On September 13, 2022, the FERC issued an order accepting Mississippi Power's request effective September 14, 2022, subject to refund, and establishing hearing and settlement judge procedures. The ultimate outcome of this matter cannot be determined at this time.
See Note (B) to the Condensed Financial Statements under "Mississippi Power" herein for additional information.
Southern Power
During the nine months ended September 30, 2022, Southern Power completed construction of and placed in service the remaining 40 MWs of the Tranquillity battery energy storage facility and the remaining 15 MWs of the Garland battery energy storage facility. See Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information.
At September 30, 2022, Southern Power's average investment coverage ratio for its generating assets, including those owned with various partners, based on the ratio of investment under contract to total investment using the respective facilities' net book value (or expected in-service value for facilities under construction) as the investment amount was 95% through 2026 and 92% through 2031, with an average remaining contract duration of approximately 13 years.
Southern Company Gas
On July 1, 20162022, Atlanta Gas Light filed its annual GRAM update with the Georgia PSC. The filing requests an annual base rate increase of $53 million based on the projected 12-month period beginning January 1, 2023. Resolution of the GRAM filing is expected by December 28, 2022, with the new rates effective January 1, 2023.
On August 1, 2022, Virginia Natural Gas filed a general base rate case with the Virginia Commission seeking an increase in annual base rate revenues of $69 million, including $15 million related to the recovery of investments under the SAVE program, primarily to recover investments and increased costs associated with infrastructure, technology, and workforce development. The requested increase is based on a projected 12-month period beginning January 1, 2023, a ROE of 10.35%, and an equity ratio of 53.2%. Rate adjustments are expected to be effective January 1, 2023, subject to refund. The Virginia Commission is expected to rule on the requested increase in the third quarter 2023.
On September 7, 2022, certain affiliates of Southern Company Gas entered into agreements to sell two natural gas storage facilities located in California and Texas for an aggregate purchase price of $186 million, plus working capital and certain other adjustments. On October 20, 2022, the release of a Southern Company Gas parent guarantee was executed, which resolved a material closing condition. As a result, Southern Company Gas expects to record pre-tax impairment charges totaling approximately $125 million ($95 million after tax) in the fourth quarter
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
2022. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
The ultimate outcome of these matters cannot be determined at this time.
RESULTS OF OPERATIONS
Southern Company
Net Income
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $371 | | 33.7 | | $1,003 | | 38.5 |
Consolidated net income attributable to Southern Company was $1.5 billion ($1.36 per share) in the third quarter 2022 compared to $1.1 billion ($1.04 per share) for the corresponding period in 2021. Consolidated net income attributable to Southern Company was $3.6 billion ($3.38 per share) for year-to-date 2022 compared to $2.6 billion ($2.46 per share) for the corresponding period in 2021. The increases were primarily due to decreases of $249 million and $589 million in the third quarter and year-to-date 2022, respectively, in after-tax charges related to the construction of Plant Vogtle Units 3 and 4, increases in retail electric revenues associated with rates and pricing, warmer weather, and sales growth, and increases in natural gas revenues from base rate increases and continued infrastructure replacement, partially offset by higher non-fuel operations and maintenance costs. The increase for year-to-date 2022 also reflects after-tax charges totaling $67 million in 2021 related to the PennEast Pipeline project at Southern Company Gas.
See Note (B) to the Condensed Financial Statements herein and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4 and Note 7 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information on the PennEast Pipeline project.
Retail Electric Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1,410 | | 31.0 | | $2,871 | | 25.0 |
In the third quarter 2022, retail electric revenues were $6.0 billion compared to $4.6 billion for the corresponding period in 2021. For year-to-date 2022, retail electric revenues were $14.4 billion compared to $11.5 billion for the corresponding period in 2021.
Details of the changes in retail electric revenues were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Third Quarter 2022 | | Year-To-Date 2022 |
| (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail electric – prior year | $ | 4,551 | | | | | $ | 11,492 | | | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 165 | | | 3.6 | % | | 458 | | | 4.0 | % |
| Sales growth | 73 | | | 1.6 | | | 158 | | | 1.4 | |
| Weather | 26 | | | 0.6 | | | 188 | | | 1.6 | |
| Fuel and other cost recovery | 1,146 | | | 25.2 | | | 2,067 | | | 18.0 | |
| Retail electric – current year | $ | 5,961 | | | 31.0 | % | | $ | 14,363 | | | 25.0 | % |
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2022 when compared to the corresponding periods in 2021. The increases were primarily due to higher contributions from commercial and industrial customers with variable demand-driven pricing, base tariff increases in accordance with Georgia Power's 2019 ARP, and pricing effects associated with customer usage. See Note 2 to the financial statements under "Georgia Power – Rate Plans" in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales increased in the third quarter and year-to-date 2022 when compared to the corresponding periods in 2021. Weather-adjusted residential KWH sales increased 1.3% and 0.4% in the third quarter and year-to-date 2022, respectively, and weather-adjusted commercial KWH sales increased 2.0% in both the third quarter and year-to-date 2022 when compared to the corresponding periods in 2021 primarily due to customer growth. In addition, commercial customer usage increased in the third quarter and year-to-date 2022 and residential customer usage decreased for year-to-date 2022 when compared to the corresponding periods in 2021 as customers return to pre-pandemic levels of activity outside the home. Industrial KWH sales increased 2.2% and 2.6% in the third quarter and year-to-date 2022, respectively, when compared to the corresponding periods in 2021 primarily due to increases in the pipeline and paper sectors, partially offset by a decrease in the chemicals sector.
Fuel and other cost recovery revenues increased $1.1 billion and $2.1 billion in the third quarter and year-to-date 2022, respectively, compared to the corresponding periods in 2021 primarily due to higher fuel and purchased power costs and an increase in the volume of KWHs generated. 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. 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.
Wholesale Electric Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $466 | | 63.7 | | $976 | | 53.6 |
In the third quarter 2022, wholesale electric revenues were $1.2 billion compared to $731 million for the corresponding period in 2021. For year-to-date 2022, wholesale electric revenues were $2.8 billion compared to $1.8 billion for the corresponding period in 2021. The increases were primarily due to increases of $437 million and $930 million in the third quarter and year-to-date 2022, respectively, in energy revenues as a result of fuel and purchased power price increases when compared to the corresponding periods in 2021, an increase in the volume of KWHs sold primarily associated with natural gas PPAs at Southern Power, and increased opportunity sales at Alabama Power due to warmer weather.
Wholesale electric revenues consist of revenues from PPAs and short-term opportunity sales. Wholesale electric revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues generally represent the greatest contribution to net income and are designed to provide recovery of fixed costs plus a return on investment. Energy revenues will vary depending on fuel prices, the market prices of wholesale energy compared to the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Energy sales from solar and wind PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or through a fixed price related to the energy. As a result, the ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors. Wholesale electric revenues at Mississippi Power include FERC-regulated municipal and rural association sales
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
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.
Other Electric Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $6 | | 3.4 | | $29 | | 5.5 |
In the third quarter 2022, other electric revenues were $185 million compared to $179 million for the corresponding period in 2021. The increase was primarily due to increases of $14 million in transmission revenues primarily associated with open access transmission tariff sales and $7 million in cogeneration steam revenues associated with higher natural gas prices at Alabama Power, partially offset by a $14 million increase in realized losses associated with price stability products for retail customers on variable demand-driven pricing tariffs at Georgia Power.
For year-to-date 2022, other electric revenues were $554 million compared to $525 million for the corresponding period in 2021. The increase was primarily due to increases of $41 million in transmission revenues primarily associated with open access transmission tariff sales, $15 million in cogeneration steam revenues associated with higher natural gas prices at Alabama Power, and $13 million in outdoor lighting sales at Georgia Power, partially offset by a decrease of $26 million resulting from the termination of a transmission service contract and an increase of $21 million in realized losses associated with price stability products for retail customers on variable demand-driven pricing tariffs, both at Georgia Power.
Natural Gas Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $234 | | 37.6 | | $1,004 | | 33.5 |
In the third quarter 2022, natural gas revenues were $857 million compared to $623 million for the corresponding period in 2021. For year-to-date 2022, natural gas revenues were $4.0 billion compared to $3.0 billion for the corresponding period in 2021.
Details of the changes in natural gas revenues were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 | | Year-To-Date 2022 |
| (in millions) | | (% change) | | (in millions) | | (% change) |
| Natural gas revenues – prior year | $ | 623 | | | | | $ | 2,994 | | | |
| Estimated change resulting from – | | | | | | | |
| Infrastructure replacement programs and base rate changes | 54 | | | 8.7 | % | | 186 | | | 6.2 | % |
| Gas costs and other cost recovery | 172 | | | 27.6 | | | 955 | | | 31.9 | |
| Gas marketing services | 1 | | | 0.2 | | | 14 | | | 0.5 | |
| Wholesale gas services | — | | | — | | | (187) | | | (6.2) | |
| Other | 7 | | | 1.1 | | | 36 | | | 1.1 | |
| Natural gas revenues – current year | $ | 857 | | | 37.6 | % | | $ | 3,998 | | | 33.5 | % |
Revenues from infrastructure replacement programs and base rate changes at the natural gas distribution utilities increased in the third quarter and year-to-date 2022 compared to the corresponding periods in 2021 primarily due to rate increases at Nicor Gas, Atlanta Gas Light, and Chattanooga Gas and continued investment in infrastructure replacement. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Revenues associated with gas costs and other cost recovery increased in the third quarter and year-to-date 2022 compared to the corresponding periods in 2021 primarily due to higher natural gas cost recovery. Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from the natural gas distribution utilities.
Revenues from gas marketing services increased for year-to-date 2022 compared to the corresponding period in 2021 due to higher commodity prices and higher sales to commercial customers.
The changes in year-to-date 2022 revenues related to Southern Company Gas' wholesale gas services were due to the sale of Sequent on July 1, 2021. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Other Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $24 | | 15.6 | | $6 | | 1.2 |
In the third quarter 2022, other revenues were $178 million compared to $154 million for the corresponding period in 2021. The increase was primarily due to a $15 million increase in unregulated sales at the traditional electric operating companies primarily associated with power delivery construction and maintenance projects, energy conservation projects, and lighting. Also contributing to the increase was a $9 million increase primarily related to distributed infrastructure projects at PowerSecure.
For year-to-date 2022, other revenues were $519 million compared to $513 million for the corresponding period in 2021. The increase was primarily due to increases of $10 million in unregulated sales associated with power delivery construction and maintenance projects at Mississippi Power, $9 million in unregulated energy conservation projects at Georgia Power, $8 million in unregulated lighting sales at Alabama Power, and $5 million primarily related to distribution infrastructure projects at PowerSecure, partially offset by a $28 million decrease associated with the timing of revenue recognition for a large, ongoing power delivery construction and maintenance contract at Georgia Power.
Fuel and Purchased Power Expenses
| | | | | | | | | | | | | | | | | | | | | | | |
| | Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | 1,189 | | | 96.4 | | $ | 2,319 | | | 79.1 |
| Purchased power | 357 | | | 124.0 | | 573 | | | 80.5 |
| Total fuel and purchased power expenses | $ | 1,546 | | | | | $ | 2,892 | | | |
In the third quarter 2022, total fuel and purchased power expenses were $3.1 billion compared to $1.5 billion for the corresponding period in 2021. The increase was primarily the result of a $1.2 billion increase in the average cost of fuel and purchased power and a $310 million increase in the volume of KWHs generated and purchased.
For year-to-date 2022, total fuel and purchased power expenses were $6.5 billion compared to $3.6 billion for the corresponding period in 2021. The increase was primarily the result of a $2.4 billion increase in the average cost of fuel and purchased power and a $523 million increase in the volume of KWHs generated and purchased.
Fuel and purchased power energy transactions at the traditional electric operating companies are generally offset by fuel revenues and do not have a significant impact on net income. See Note 2 to the financial statements in Item 8 of the Form 10-K for additional information. Fuel expenses incurred under Southern Power's PPAs are generally the responsibility of the counterparties and do not significantly impact net income.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of the Southern Company system's generation and purchased power were as follows:
| | | | | | | | | | | | | | |
| Third Quarter 2022 | Third Quarter 2021 | Year-To-Date 2022 | Year-To-Date 2021 |
Total generation (in billions of KWHs)(a) | 50 | 50 | 141 | 136 |
Total purchased power (in billions of KWHs) | 9 | 5 | 20 | 13 |
Sources of generation (percent)(a) — | | | | |
| Gas | 54 | 48 | 50 | 47 |
| Coal | 21 | 26 | 22 | 24 |
| Nuclear | 16 | 16 | 16 | 17 |
| Hydro | 2 | 3 | 4 | 4 |
| Wind, Solar, and Other | 7 | 7 | 8 | 8 |
Cost of fuel, generated (in cents per net KWH)— | | | | |
Gas(a) | 6.75 | 3.38 | 5.42 | 2.87 |
| Coal | 4.12 | 2.82 | 3.58 | 2.84 |
| Nuclear | 0.71 | 0.78 | 0.72 | 0.76 |
Average cost of fuel, generated (in cents per net KWH)(a) | 5.05 | 2.75 | 4.07 | 2.45 |
Average cost of purchased power (in cents per net KWH)(b) | 8.94 | 6.45 | 7.84 | 5.77 |
(a)Excludes Central Alabama Generating Station KWHs and associated cost of fuel through July 12, 2022 as its fuel was previously provided by the purchaser under a power sales agreement. See Note 15 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.
(b)Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider.
Fuel
In the third quarter 2022, fuel expense was $2.4 billion compared to $1.2 billion for the corresponding period in 2021. The increase was primarily due to a 99.7% increase in the average cost of natural gas per KWH generated, a 52.7% decrease in the volume of KWHs generated by hydro, a 46.1% increase in the average cost of coal per KWH generated, and a 13.0% increase in the volume of KWHs generated by natural gas, partially offset by a 19.0% decrease in the volume of KWHs generated by coal.
For year-to-date 2022, fuel expense was $5.2 billion compared to $2.9 billion for the corresponding period in 2021. The increase was primarily due to an 88.9% increase in the average cost of natural gas per KWH generated, a 26.1% increase in the average cost of coal per KWH generated, a 9.6% increase in the volume of KWHs generated by natural gas, and an 8.7% decrease in the volume of KWHs generated by hydro, partially offset by a 4.1% decrease in the volume of KWHs generated by coal.
Purchased Power
In the third quarter 2022, purchased power expense was $645 million compared to $288 million for the corresponding period in 2021. The increase was primarily due to a 38.6% increase in the average cost per KWH purchased primarily due to higher natural gas and coal prices and an 87.2% increase in the volume of KWHs purchased.
For year-to-date 2022, purchased power expense was $1.3 billion compared to $712 million for the corresponding period in 2021. The increase was primarily due to a 35.9% increase in the average cost per KWH purchased primarily due to higher natural gas and coal prices and a 50.9% increase in the volume of KWHs purchased.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Energy purchases will vary depending on demand for energy within the Southern Company system's electric service territory, the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, and the availability of the Southern Company system's generation.
Cost of Natural Gas
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $165 | | N/M | | $897 | | 95.1 |
Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from the natural gas distribution utilities. Cost of natural gas at the natural gas distribution utilities represented 78% and 87% of the total cost of natural gas in the third quarter and year-to-date 2022, respectively.
In the third quarter 2022, cost of natural gas was $294 million compared to $129 million for the corresponding period in 2021. For year-to-date 2022, cost of natural gas was $1.8 billion compared to $943 million for the corresponding period in 2021. The increases reflect higher gas cost recovery as a result of increases of 104% and 113% in natural gas prices in the third quarter and year-to-date 2022, respectively, compared to the corresponding periods in 2021.
Cost of Other Sales
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $21 | | 29.6 | | $20 | | 7.8 |
In the third quarter 2022, cost of other sales was $92 million compared to $71 million for the corresponding period in 2021. The increase was primarily related to distributed infrastructure projects at PowerSecure.
For year-to-date 2022, cost of other sales was $275 million compared to $255 million for the corresponding period in 2021. The increase was primarily due to increases of $32 million related to distributed infrastructure projects at PowerSecure, $9 million related to unregulated power delivery construction and maintenance projects at Mississippi Power, and $9 million primarily associated with unregulated merchandising and energy services expenses at Alabama Power, partially offset by a decrease of $32 million associated with unregulated power delivery construction and maintenance projects at Georgia Power.
Other Operations and Maintenance Expenses
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $101 | | 7.0 | | $364 | | 8.6 |
In the third quarter 2022, other operations and maintenance expenses were $1.5 billion compared to $1.4 billion for the corresponding period in 2021. The increase was primarily due to increases of $49 million in transmission and distribution expenses primarily related to line maintenance, $18 million in customer accounts, customer service, and sales expenses primarily related to bad debt expenses, payment convenience fees, and labor, $12 million in compensation and benefit expenses, and $10 million in generation expenses primarily related to scheduled outage and maintenance costs.
For year-to-date 2022, other operations and maintenance expenses were $4.6 billion compared to $4.3 billion for the corresponding period in 2021. Excluding $53 million of expenses related to Sequent in 2021, other operations and
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
maintenance expenses increased $417 million. The increase was primarily due to increases of $135 million in transmission and distribution expenses primarily related to line maintenance, $90 million in generation expenses primarily related to scheduled outage and maintenance costs, $38 million in compensation and benefit expenses, $30 million in expenses at Southern Company Gas passed through directly to customers primarily related to bad debt, and $21 million in customer accounts, customer service, and sales expenses primarily related to bad debt expenses, payment convenience fees, and labor.
Depreciation and Amortization
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $26 | | 2.9 | | $70 | | 2.6 |
In the third quarter 2022, depreciation and amortization was $922 million compared to $896 million for the corresponding period in 2021. For year-to-date 2022, depreciation and amortization was $2.73 billion compared to $2.66 billion for the corresponding period in 2021. The increases were primarily due to additional plant in service, including continued infrastructure investments at the natural gas distribution utilities.
Taxes Other Than Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $40 | | 12.8 | | $104 | | 10.7 |
In the third quarter 2022, taxes other than income taxes were $352 million compared to $312 million for the corresponding period in 2021. For year-to-date 2022, taxes other than income taxes were $1.1 billion compared to $969 million for the corresponding period in 2021. The increases primarily reflect an increase in municipal franchise fees at Georgia Power and an increase in revenue tax expenses at Southern Company Gas.
Estimated Loss on Plant Vogtle Units 3 and 4
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(334) | | N/M | | $(790) | | N/M |
Georgia Power recorded pre-tax charges (credits) to income for the estimated probable loss on Plant Vogtle Units 3 and 4 totaling $(70) million and $264 million in the third quarter 2022 and 2021, respectively, and $(18) million and $772 million for year-to-date 2022 and 2021, respectively. The charges (credits) reflect revisions to the total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements herein and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.
Gain on Dispositions, Net
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(105) | | (84.0) | | $(126) | | (70.4) |
In the third quarter 2022, gain on dispositions, net was $20 million compared to $125 million for the corresponding period in 2021. For year-to-date 2022, gain on dispositions, net was $53 million compared to $179 million for the corresponding period in 2021. The decreases primarily reflect a $121 million gain at Southern Company Gas related to the sale of Sequent in the third quarter 2021, partially offset by a $14 million gain recorded in the third quarter
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
2022 as a result of the early termination of the transition services agreement related to the 2019 sale of Gulf Power. The year-to-date 2022 decrease also reflects a $39 million gain at Southern Power primarily from contributions of wind turbine equipment to various equity method investments in 2021, partially offset by a $17 million gain from sales of integrated transmission system assets at Georgia Power in 2022. See Note 15 to the financial statements under "Southern Power – Development Projects" and "Southern Company Gas – Sale of Sequent" in Item 8 of the Form 10-K for additional information.
Allowance for Equity Funds Used During Construction
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $10 | | 20.4 | | $23 | | 16.4 |
In the third quarter 2022, allowance for equity funds used during construction was $59 million compared to $49 million for the corresponding period in 2021. For year-to-date 2022, allowance for equity funds used during construction was $163 million compared to $140 million for the corresponding period in 2021. The increases were primarily associated with an increase in capital expenditures related to Plant Barry Unit 8 construction at Alabama Power and transmission and distribution projects related to grid modernization at Georgia Power.
Earnings from Equity Method Investments
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(2) | | (6.7) | | $74 | | N/M |
For year-to-date 2022, earnings from equity method investments were $109 million compared to $35 million for the corresponding period in 2021. The increase was primarily due to pre-tax impairment charges in 2021 totaling $84 million related to the PennEast Pipeline project at Southern Company Gas, partially offset by a $16 million decrease at Southern Holdings primarily due to a decrease in investment income. See Note 7 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements herein under "Southern Company Gas" for additional information.
Interest Expense, Net of Amounts Capitalized
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $60 | | 13.3 | | $109 | | 8.1 |
In the third quarter 2022, interest expense, net of amounts capitalized was $511 million compared to $451 million for the corresponding period in 2021. The increase was primarily due to increases of approximately $28 million due to higher average outstanding borrowings and $28 million due to higher interest rates.
For year-to-date 2022, interest expense, net of amounts capitalized was $1.5 billion compared to $1.4 billion for the corresponding period in 2021. The increase was primarily due to higher average outstanding borrowings.
See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Other Income (Expense), Net
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1 | | 0.8 | | $124 | | 42.8 |
For year-to-date 2022, other income (expense), net was $414 million compared to $290 million for the corresponding period in 2021. The increase was primarily due to charitable contributions of $101 million at Southern Company Gas during the first and second quarters of 2021 and a $44 million increase in non-service cost-related retirement benefits income. See Note (H) to the Condensed Financial Statements herein for additional information.
Income Taxes
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| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $42 | | 11.3 | | $341 | | 62.0 |
In the third quarter 2022, income taxes were $414 million compared to $372 million for the corresponding period in 2021. For year-to-date 2022, income taxes were $891 million compared to $550 million for the corresponding period in 2021. The increases were primarily due to higher pre-tax earnings, partially offset by $113 million of additional tax expense in 2021 resulting from Southern Company Gas' sale of Sequent in the third quarter 2021. The year-to-date 2022 increase was also due to an adjustment in the second quarter 2022 related to a prior year state tax credit carryforward at Georgia Power. See Note (G) to the Condensed Financial Statements herein for additional information.
Net Income (Loss) Attributable to Noncontrolling Interests
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| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $7 | | N/M | | $(28) | | N/M |
Substantially all noncontrolling interests relate to renewable projects at Southern Power. In the third quarter 2022, net income attributable to noncontrolling interests was $12 million compared to $5 million for the corresponding period in 2021. The increase was primarily due to lower HLBV loss allocations to Southern Power's tax equity partners, including loss allocation impacts associated with the Garland battery energy storage facility being placed in service in the third quarter 2021, and higher income allocations to Southern Power's equity partners.
For year-to-date 2022, net loss attributable to noncontrolling interests was $55 million compared to $27 million for the corresponding period in 2021. The increased loss was primarily due to higher HLBV loss allocations to Southern Power's tax equity partners, partially offset by loss allocation impacts associated with the Garland battery energy storage facility being placed in service in the third quarter 2021 and higher income allocations to Southern Power's equity partners.
See Notes 9 and 15 to the financial statements under "Lessor" and "Southern Power," respectively, in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Alabama Power
Net Income
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $26 | | 5.2 | | $67 | | 5.6 |
Alabama Power's net income after dividends on preferred stock in the third quarter 2022 was $525 million compared to $499 million for the corresponding period in 2021. Alabama Power's net income after dividends on preferred stock for year-to-date 2022 was $1.26 billion compared to $1.19 billion for the corresponding period in 2021. These increases were primarily due to an increase in retail revenues associated with warmer weather in Alabama Power's service territory in 2022 compared to the corresponding periods in 2021 and sales growth, partially offset by higher non-fuel operations and maintenance costs.
Retail Revenues
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| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $357 | | 21.6 | | $658 | | 15.1 |
In the third quarter 2022, retail revenues were $2.01 billion compared to $1.65 billion for the corresponding period in 2021. For year-to-date 2022, retail revenues were $5.02 billion compared to $4.36 billion for the corresponding period in 2021.
Details of the changes in retail revenues were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Third Quarter 2022 | | Year-To-Date 2022 |
| (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | $ | 1,651 | | | | | $ | 4,357 | | | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 3 | | | 0.2 | % | | 7 | | | 0.2 | % |
| Sales growth | 20 | | | 1.2 | | | 53 | | | 1.2 | |
| Weather | 25 | | | 1.5 | | | 88 | | | 2.0 | |
| Fuel and other cost recovery | 309 | | | 18.7 | | | 510 | | | 11.7 | |
| Retail – current year | $ | 2,008 | | | 21.6 | % | | $ | 5,015 | | | 15.1 | % |
Revenues attributable to changes in sales increased inthe third quarter and year-to-date 2022 when compared to the corresponding periods in 2021. Weather-adjusted residential KWH sales decreased 0.4% and 0.3% in the third quarter and year-to-date 2022, respectively, when compared to the corresponding periods in 2021 primarily due to decreased customer usage. Weather-adjusted commercial KWH sales decreased 0.7% in the third quarter 2022 when compared to the corresponding period in 2021 primarily due to decreased customer usage. Weather-adjusted commercial KWH sales were flat for year-to-date 2022 when compared to the corresponding period in 2021. Industrial KWH sales increased 2.9% and 2.3% in the third quarter and year-to-date 2022, respectively, when compared to the corresponding periods in 2021 primarily due to increases in the forest product and pipeline sectors, partially offset by decreases in the chemicals sector.
Fuel and other cost recovery revenues increased in the third quarter and year-to-date 2022 when compared to the corresponding periods in 2021 primarily due to increases in the volume of KWHs generated and the average cost of fuel.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Electric rates include provisions to recognize the recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the NDR. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income. See Note 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.
Wholesale Revenues – Non-Affiliates
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| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $143 | | N/M | | $237 | | 83.2 |
In the third quarter 2022, wholesale revenues from sales to non-affiliates were $250 million compared to $107 million for the corresponding period in 2021. For year-to-date 2022, wholesale revenues from sales to non-affiliates were $522 million compared to $285 million for the corresponding period in 2021. The increases for the third quarter and year-to-date 2022 were primarily due to increases of 75.9% and 41.8%, respectively, in the price of energy due to higher natural gas prices, as well as increases of 32.3% and 29.3%, respectively, in KWH sales as a result of increased opportunity sales due to warmer weather in the third quarter and year-to-date 2022 compared to the corresponding periods in 2021.
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Alabama Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not 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.
Wholesale Revenues – Affiliates
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| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $17 | | 32.1 | | $61 | | 56.0 |
In the third quarter 2022, wholesale revenues from sales to affiliates were $70 million compared to $53 million for the corresponding period in 2021. The increase was primarily due to a 142.2% increase in the price of energy due to higher natural gas prices, partially offset by a 45.7% decrease in KWH sales due to the availability of lower cost Southern Company system resources compared to Alabama Power's generation.
For year-to-date 2022, wholesale revenues from sales to affiliates were $170 million compared to $109 million for the corresponding period in 2021. The increase was primarily due to an 84.7% increase in the price of energy due to higher natural gas prices, partially offset by a 15.3% decrease in KWH sales due to the availability of lower cost Southern Company system resources compared to Alabama Power's generation.
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.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Other Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $23 | | 24.7 | | $48 | | 17.9 |
In the third quarter 2022, other revenues were $116 million compared to $93 million for the corresponding period in 2021. For year-to-date 2022, other revenues were $316 million compared to $268 million for the corresponding period in 2021. The third quarter and year-to-date 2022 increases were primarily due to increases of $7 million and $15 million, respectively, in cogeneration steam revenue associated with higher natural gas prices, $6 million and $13 million, respectively, in transmission revenues primarily due to open access transmission tariff sales, and $3 million and $8 million, respectively, in unregulated lighting sales. The year-to-date 2022 increase also included a $5 million increase in energy services revenue.
Fuel and Purchased Power Expenses
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| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | 293 | | | 78.6 | | | $ | 472 | | | 50.9 | |
| Purchased power – non-affiliates | 109 | | | 143.4 | | | 174 | | | 100.6 | |
| Purchased power – affiliates | 68 | | | 151.1 | | | 146 | | | 128.1 | |
| Total fuel and purchased power expenses | $ | 470 | | | | | $ | 792 | | | |
In the third quarter 2022, total fuel and purchased power expenses were $964 million compared to $494 million for the corresponding period in 2021. The increase was primarily due to a $257 million increase in the cost of fuel and purchased power and a $213 million increase related to the volume of KWHs generated and purchased.
For year-to-date 2022, total fuel and purchased power expenses were $2.01 billion compared to $1.21 billion for the corresponding period in 2021. The increase was primarily due to a $518 million increase in the cost of fuel and purchased power and a $274 million increase related to the volume of KWHs generated and purchased.
Fuel and purchased power energy transactions do not have a significant impact on earnings, since energy expenses are generally offset by energy revenues through Alabama Power's energy cost recovery clause. See Note 2 to the financial statements under "Alabama Power – Rate ECR" in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of Alabama Power's generation and purchased power were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 | | Third Quarter 2021 | | Year-To-Date 2022 | | Year-To-Date 2021 |
Total generation (in billions of KWHs)(a) | 16 | | 16 | | 45 | | 45 |
Total purchased power (in billions of KWHs) | 4 | | 2 | | 9 | | 5 |
Sources of generation (percent)(a) — | | | | | | | |
| Coal | 47 | | 50 | | 45 | | 47 |
| Nuclear | 22 | | 24 | | 24 | | 25 |
| Gas | 28 | | 18 | | 23 | | 19 |
| Hydro | 3 | | 8 | | 8 | | 9 |
Cost of fuel, generated (in cents per net KWH) — | | | | | | | |
| Coal | 3.89 | | 2.85 | | 3.40 | | 2.78 |
| Nuclear | 0.67 | | 0.73 | | 0.67 | | 0.71 |
Gas(a) | 6.55 | | 3.03 | | 5.20 | | 2.68 |
Average cost of fuel, generated (in cents per net KWH)(a) | 3.91 | | 2.33 | | 3.13 | | 2.20 |
Average cost of purchased power (in cents per net KWH)(b) | 8.55 | | 7.96 | | 8.33 | | 6.70 |
(a)Excludes Central Alabama Generating Station KWHs and associated cost of fuel through July 12, 2022 as its fuel was previously provided by the purchaser under a power sales agreement. See Note 15 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.
(b)Average cost of purchased power includes fuel, energy, and transmission purchased by Alabama Power for tolling agreements where power is generated by the provider.
Fuel
In the third quarter 2022, fuel expense was $666 million compared to $373 million for the corresponding period in 2021. The increase was primarily due to a 116.2% increase in the average cost of natural gas per KWH generated, which excludes tolling agreements, a 36.5% increase in the average cost of coal per KWH generated, a 56.8% decrease in the volume of KWHs generated by hydro facilities as a result of less rainfall in the third quarter 2022 compared to the corresponding period in 2021, and a 46.9% increase in the volume of KWHs generated by natural gas.
For year-to-date 2022, fuel expense was $1.4 billion compared to $0.9 billion for the corresponding period in 2021. The increase was primarily due to a 94.0% increase in the average cost of natural gas per KWH generated, which excludes tolling agreements, a 22.3% increase in the average cost of coal per KWH generated, an 18.3% increase in the volume of KWHs generated by natural gas, and an 8.5% decrease in the volume of KWHs generated by hydro facilities as a result of less rainfall for year-to-date 2022 compared to the corresponding period in 2021.
Purchased Power – Non-Affiliates
In the third quarter 2022, purchased power expense from non-affiliates was $185 million compared to $76 million for the corresponding period in 2021. The increase was primarily due to a 193.7% increase in the volume of KWHs purchased as a result of warmer weather in the third quarter 2022 compared to the corresponding period in 2021, partially offset by an 11.2% decrease in the average cost per KWH purchased due to fixed capacity costs allocated across a higher level of generation.
For year-to-date 2022, purchased power expense from non-affiliates was $347 million compared to $173 million for the corresponding period in 2021. The increase was primarily due to a 100.5% increase in the volume of KWHs purchased as a result of warmer weather for year-to-date 2022 compared to the corresponding period in 2021, as well as an 8.2% increase in the average cost per KWH purchased due to higher natural gas and coal prices.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the third quarter 2022, purchased power expense from affiliates was $113 million compared to $45 million for the corresponding period in 2021. The increase was primarily due to an 84.5% increase in the average cost per KWH purchased due to higher natural gas and coal prices and a 36.4% increase in the volume of KWHs purchased as a result of warmer weather in the third quarter 2022 compared to the corresponding period in 2021.
For year-to-date 2022, purchased power expense from affiliates was $260 million compared to $114 million for the corresponding period in 2021. The increase was primarily due to a 71.0% increase in the average cost per KWH purchased due to higher natural gas and coal prices and a 33.6% increase in the volume of KWHs purchased as a result of warmer weather for year-to-date 2022 compared to the corresponding period in 2021.
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
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| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $17 | | 4.2 | | $95 | | 8.1 |
In the third quarter 2022, other operations and maintenance expenses were $418 million compared to $401 million for the corresponding period in 2021. For year-to-date 2022, other operations and maintenance expenses were $1.27 billion compared to $1.18 billion for the corresponding period in 2021. The increases for the third quarter and year-to-date 2022 were primarily due to increases of $18 million and $41 million, respectively, in transmission and distribution expenses primarily associated with line maintenance and $6 million and $12 million, respectively, in customer accounts, customer service, and sales expenses primarily associated with labor and bad debt expense. The increase for the third quarter 2022 was partially offset by a $15 million decrease in generation expenses primarily associated with scheduled outages and maintenance. The year-to-date 2022 increase also included a $24 million increase in generation expenses primarily associated with scheduled outages and maintenance and Rate CNP Compliance-related expenses. See Note 2 to the financial statements under "Alabama Power – Rate CNP Compliance" in Item 8 of the Form 10-K for additional information.
Allowance for Equity Funds Used During Construction
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $4 | | 28.6 | | $13 | | 34.2 |
For year-to-date 2022, allowance for equity funds used during construction was $51 million compared to $38 million for the corresponding period in 2021. The increase for year-to-date 2022 was primarily due to an increase in capital expenditures related to Plant Barry Unit 8 construction.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Interest Expense, Net of Amounts Capitalized
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $14 | | 16.7 | | $26 | | 10.3 |
In the third quarter 2022, interest expense, net of amounts capitalized was $98 million compared to $84 million for the corresponding period in 2021. For year-to-date 2022, interest expense, net of amounts capitalized was $278 million compared to $252 million for the corresponding period in 2021. The increases were primarily due to higher average outstanding borrowings. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings.
Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $14 | | 9.2 | | $28 | | 7.7 |
In the third quarter 2022, income taxes were $166 million compared to $152 million for the corresponding period in 2021. For year-to-date 2022, income taxes were $394 million compared to $366 million for the corresponding period in 2021. The increases were primarily due to higher pre-tax earnings.
Georgia Power
Net Income
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $322 | | 60.1 | | $821 | | 79.7 |
Georgia Power's net income in the third quarter 2022 was $858 million compared to $536 million for the corresponding period in 2021. For year-to-date 2022 net income was $1.85 billion compared to $1.03 billion for the corresponding period in 2021. The increases were primarily due to decreases of $249 million and $589 million in the third quarter and year-to-date 2022, respectively, in after-tax charges related to the construction of Plant Vogtle Units 3 and 4 and increases in retail revenues associated with rates and pricing and sales growth, partially offset by higher non-fuel operations and maintenance costs. The increase for year-to-date 2022 was also due to warmer weather in Georgia Power's service territory compared to the corresponding period in 2021.
See Note (B) to the Condensed Financial Statements herein and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.
Retail Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1,051 | | 39.6 | | $2,164 | | 33.5 |
In the third quarter 2022, retail revenues were $3.70 billion compared to $2.65 billion for the corresponding period in 2021. For year-to-date 2022, retail revenues were $8.63 billion compared to $6.47 billion for the corresponding period in 2021.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of the changes in retail revenues were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Third Quarter 2022 | | Year-To-Date 2022 |
| (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | $ | 2,652 | | | | | $ | 6,465 | | | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 157 | | | 5.9 | % | | 442 | | | 6.8 | % |
| Sales growth | 54 | | | 2.0 | | | 101 | | | 1.6 | |
| Weather | (1) | | | — | | | 89 | | | 1.4 | |
| Fuel cost recovery | 841 | | | 31.7 | | | 1,532 | | | 23.7 | |
| Retail – current year | $ | 3,703 | | | 39.6 | % | | $ | 8,629 | | | 33.5 | % |
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2022 when compared to the corresponding periods in 2021. The increases were primarily due to higher contributions from commercial and industrial customers with variable demand-driven pricing, base tariff increases in accordance with the 2019 ARP, and pricing effects associated with customer usage. See Note 2 to the financial statements under "Georgia Power – Rate Plans" in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales increased in the third quarter and year-to-date 2022 when compared to the corresponding periods in 2021. Weather-adjusted residential KWH sales increased 2.7% and 1.0% in the third quarter and year-to-date 2022, respectively, when compared to the corresponding periods in 2021 primarily due to customer growth. The increase for the third quarter 2022 also reflects increased customer usage. Weather-adjusted commercial KWH sales increased 3.2% and 2.9% in the third quarter and year-to-date 2022, respectively, when compared to the corresponding periods in 2021 primarily due to impacts on customer usage from increased activity outside the home as customers return to pre-pandemic levels of activity, as well as customer growth. Weather-adjusted industrial KWH sales increased 1.8% and 2.8% in the third quarter and year-to-date 2022, respectively, when compared to the corresponding periods in 2021 primarily due to increases in the pipeline, electronic, and paper sectors, partially offset by decreases in the chemicals and textiles sectors.
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 2022 when compared to the corresponding periods in 2021 due to higher fuel and purchased power costs. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See Note 2 to the financial statements under "Georgia Power – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.
Wholesale Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(7) | | (11.1) | | $43 | | 30.1 |
In the third quarter 2022, wholesale revenues were $56 million compared to $63 million for the corresponding period in 2021. The decrease was primarily due to a $22 million decrease in KWH sales associated with lower market demand and a $3 million decrease in capacity revenues due to the expiration of a non-affiliate PPA in 2021, largely offset by an increase of $20 million related to the average cost of fuel primarily due to higher natural gas and coal prices.
For year-to-date 2022, wholesale revenues were $186 million compared to $143 million for the corresponding period in 2021. The increase was primarily due to an increase of $60 million related to the average cost of fuel primarily due to higher natural gas and coal prices, partially offset by a $10 million decrease in KWH sales
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
associated with lower market demand and an $8 million decrease in capacity revenues due to the expiration of a non-affiliate PPA in 2021.
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 in amounts billable under the contract terms and provide for recovery of fixed costs and a return on investment. Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Georgia Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above Georgia Power's variable cost of energy.
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.
Other Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(11) | | (7.8) | | $(39) | | (8.8) |
In the third quarter 2022, other revenues were $130 million compared to $141 million for the corresponding period in 2021. For year-to-date 2022, other revenues were $403 million compared to $442 million for the corresponding period in 2021. The decreases for the third quarter and year-to-date 2022 were primarily due to increases of $14 million and $21 million, respectively, in realized losses associated with price stability products for retail customers on variable demand-driven pricing tariffs, decreases of $9 million and $12 million, respectively, from retail solar programs as a result of higher avoided cost credits to customers, and $6 million and $26 million, respectively, resulting from the termination of a transmission service contract. These reductions were partially offset by increases of $8 million and $22 million, respectively, associated with unregulated outdoor lighting sales and energy conservation projects and $6 million and $16 million, respectively, in open access transmission tariff sales. Also contributing to the decrease for year-to-date 2022 was a decrease of $28 million associated with the timing of revenue recognition for a large, ongoing power delivery construction and maintenance contract.
Fuel and Purchased Power Expenses
| | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-to-Date 2022 vs. Year-to-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | 409 | | | 94.7 | | | $ | 799 | | | 73.4 | |
| Purchased power – non-affiliates | 131 | | | 75.7 | | | 239 | | | 51.8 | |
| Purchased power – affiliates | 283 | | | 98.3 | | | 527 | | | 92.0 | |
| Total fuel and purchased power expenses | $ | 823 | | | | | $ | 1,565 | | | |
In the third quarter 2022, total fuel and purchased power expenses were $1.7 billion compared to $0.9 billion for the corresponding period in 2021. For year-to-date 2022, total fuel and purchased power expenses were $3.7 billion compared to $2.1 billion for the corresponding period in 2021. The increases for the third quarter and year-to-date 2022 were primarily due to increases of $0.8 billion and $1.4 billion, respectively, related to the average cost of fuel
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
and purchased power and net increases of $30 million and $158 million, respectively, related to 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 Note 2 to the financial statements under "Georgia Power – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.
Details of Georgia Power's generation and purchased power were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 | | Third Quarter 2021 | | Year-To-Date 2022 | | Year-To-Date 2021 |
Total generation (in billions of KWHs) | 15 | | 16 | | 45 | | 46 |
Total purchased power (in billions of KWHs) | 11 | | 10 | | 27 | | 23 |
Sources of generation (percent) — | | | | | | | |
| Gas | 53 | | 45 | | 48 | | 46 |
| | | | | | | |
| Nuclear | 28 | | 24 | | 26 | | 26 |
| Coal | 16 | | 28 | | 22 | | 24 |
| Hydro and other | 3 | | 3 | | 4 | | 4 |
Cost of fuel, generated (in cents per net KWH) — | | | | | | | |
| Gas | 6.10 | | 3.28 | | 4.99 | | 2.84 |
| Coal | 4.73 | | 2.73 | | 3.84 | | 2.89 |
| Nuclear | 0.75 | | 0.83 | | 0.76 | | 0.80 |
| | | | | | | |
Average cost of fuel, generated (in cents per net KWH) | 4.32 | | 2.51 | | 3.56 | | 2.30 |
Average cost of purchased power (in cents per net KWH)(*) | 10.14 | | 5.24 | | 8.00 | | 4.80 |
(*)Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider.
Fuel
In the third quarter 2022, fuel expense was $841 million compared to $432 million for the corresponding period in 2021. The increase was primarily due to increases of 86.0% and 73.3% in the average cost per KWH generated by natural gas and coal, respectively, and an 11.1% increase in the volume of KWHs generated by natural gas, partially offset by a 44.2% decrease in the volume of KWHs generated by coal.
For year-to-date 2022, fuel expense was $1.89 billion compared to $1.09 billion for the corresponding period in 2021. The increase was primarily due to increases of 75.7% and 32.9% in the average cost per KWH generated by natural gas and coal, respectively, partially offset by a 9.1% decrease in the volume of KWHs generated by coal.
Purchased Power – Non-Affiliates
In the third quarter 2022, purchased power expense from non-affiliates was $304 million compared to $173 million for the corresponding period in 2021. For year-to-date 2022, purchased power expense from non-affiliates was $700 million compared to $461 million for the corresponding period in 2021. The increases for the third quarter and year-to-date 2022 were primarily due to increases of 50.5% and 39.4%, respectively, in the volume of KWHs purchased primarily due to less available Georgia Power-owned coal generation and increases of 53.1% and 31.6%, respectively, in the average cost per KWH purchased primarily due to higher natural gas and coal 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.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Purchased Power – Affiliates
In the third quarter 2022, purchased power expense from affiliates was $571 million compared to $288 million for the corresponding period in 2021. For year-to-date 2022, purchased power expense from affiliates was $1.1 billion compared to $573 million for the corresponding period in 2021. The increases for the third quarter and year-to-date 2022 were primarily due to increases of 120.3% and 93.3%, respectively, in the average cost per KWH purchased primarily due to higher natural gas and coal prices.
Energy purchases from affiliates will vary depending on the 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 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $51 | | 9.4 | | $128 | | 8.2 |
In the third quarter 2022, other operations and maintenance expenses were $595 million compared to $544 million for the corresponding period in 2021. The increase was primarily due to increases of $35 million in distribution expenses primarily associated with line maintenance, $10 million in generation expenses primarily related to non-outage maintenance costs, and $9 million in certain compensation and benefit expenses, partially offset by a decrease of $6 million related to unregulated power delivery construction and maintenance projects.
For year-to-date 2022, other operations and maintenance expenses were $1.69 billion compared to $1.56 billion for the corresponding period in 2021. The increase was primarily due to increases of $80 million in distribution expenses primarily associated with line maintenance, $37 million in generation expenses primarily related to non-outage maintenance costs, $20 million in certain compensation and benefit expenses, $11 million in legal and regulatory expenses, and $8 million in amortization of cloud software, partially offset by a net decrease of $19 million related to unregulated products and services and $17 million in gains from sales of integrated transmission system assets.
Depreciation and Amortization
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $14 | | 4.1 | | $41 | | 4.0 |
In the third quarter 2022, depreciation and amortization was $359 million compared to $345 million for the corresponding period in 2021. For year-to-date 2022, depreciation and amortization was $1.07 billion compared to $1.03 billion for the corresponding period in 2021. The increases for the third quarter and year-to-date 2022 were primarily due to additional plant in service and increases of $3 million and $9 million, respectively, in amortization of regulatory assets related to CCR AROs under the terms of the 2019 ARP. See Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Rate Plans – 2019 ARP" for additional information on recovery of CCR AROs.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Taxes Other Than Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $25 | | 19.2 | | $55 | | 15.1 |
In the third quarter 2022, taxes other than income taxes were $155 million compared to $130 million for the corresponding period in 2021. For year-to-date 2022, taxes other than income taxes were $420 million compared to $365 million for the corresponding period in 2021. The increases were primarily due to increases in municipal franchise fees resulting from higher retail revenues.
Estimated Loss on Plant Vogtle Units 3 and 4
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(334) | | N/M | | $(790) | | N/M |
Georgia Power recorded pre-tax charges (credits) to income for the estimated probable loss on Plant Vogtle Units 3 and 4 totaling $(70) million and $264 million in the third quarter 2022 and 2021, respectively, and $(18) million and $772 million for year-to-date 2022 and 2021, respectively. The charges (credits) reflect revisions to the total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements herein and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.
Interest Expense, Net of Amounts Capitalized
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $17 | | 16.0 | | $32 | | 10.2 |
In the third quarter 2022, interest expense, net of amounts capitalized was $123 million compared to $106 million for the corresponding period in 2021. For year-to-date 2022, interest expense, net of amounts capitalized was $347 million compared to $315 million for the corresponding period in 2021. The increases for the third quarter and year-to-date 2022 were primarily associated with increases of approximately $11 million and $23 million, respectively, related to higher average outstanding borrowings and $10 million and $12 million, respectively, related to higher interest rates. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings.
Other Income (Expense), Net
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(6) | | (14.3) | | $16 | | 12.9 |
For year-to-date 2022, other income (expense), net was $140 million compared to $124 million for the corresponding period in 2021. The increase was primarily due to an increase of $11 million in non-service cost-related retirement benefits income. See Note (H) to the Condensed Financial Statements herein for additional information on retirement benefits.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $113 | | 100.0 | | $340 | | N/M |
In the third quarter 2022, income taxes were $226 million compared to $113 million for the corresponding period in 2021. For year-to-date 2022, income taxes were $421 million compared to $81 million for the corresponding period in 2021. The increases were primarily due to higher pre-tax earnings largely resulting from lower charges associated with the construction of Plant Vogtle Units 3 and 4. The year-to-date increase also reflects an adjustment in the second quarter 2022 related to a prior year state tax credit carryforward. See Note (B) to the Condensed Financial Statements herein and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" and Note (G) to the Condensed Financial Statements herein for additional information.
Mississippi Power
Net Income
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $12 | | 24.0 | | $17 | | 12.8 |
Mississippi Power's net income in the third quarter 2022 was $62 million compared to $50 million for the corresponding period in 2021. For year-to-date 2022, net income was $150 million compared to $133 million for the corresponding period in 2021. The increases were primarily due to an increase in revenues, partially offset by an increase in income taxes. The year-to-date 2022 increase was also partially offset by higher non-fuel operations and maintenance costs.
Retail Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $2 | | 0.8 | | $48 | | 7.2 |
In the third quarter 2022, retail revenues were$250 million compared to $248 million for the corresponding period in 2021. For year-to-date 2022, retail revenues were $718 million compared to $670 million for the corresponding period in 2021.
Details of the changes in retail revenues were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Third Quarter 2022 | | Year-To-Date 2022 |
| | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | $ | 248 | | | | | $ | 670 | | | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 4 | | | 1.6 | % | | 9 | | | 1.3 | % |
| Sales growth (decline) | — | | | — | | | 3 | | | 0.5 | |
| Weather | 3 | | | 1.2 | | | 10 | | | 1.5 | |
| Fuel and other cost recovery | (5) | | | (2.0) | | | 26 | | | 3.9 | |
| Retail – current year | $ | 250 | | | 0.8 | % | | $ | 718 | | | 7.2 | % |
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2022 when compared to the corresponding periods in 2021 primarily due to new PEP rates that became effective for the first billing cycle of April 2022, partially offset by a decrease in revenues associated with a tolling arrangement. See Note (B) to the Condensed Financial Statements under "Mississippi Power – Performance Evaluation Plan" herein for additional information.
Revenues attributable to changes in salesdecreased in the third quarter 2022 when compared to the corresponding period in 2021. Revenues attributable to changes in sales increased for year-to-date 2022 when compared to the corresponding period in 2021. Weather-adjusted residential KWH sales decreased 3.3% and 1.2% in the third quarter and year-to-date 2022, respectively, when compared to the corresponding periods in 2021 due to a decrease in customer usage resulting from increased activity outside the home as customers return to pre-pandemic levels of activity. Weather-adjusted commercial KWH sales increased 0.3% and 1.3% in the third quarter and year-to-date 2022, respectively, when compared to the corresponding periods in 2021 due to customer growth. Industrial KWH sales increased 1.9% and 1.8% in the third quarter and year-to-date 2022, respectively, when compared to the corresponding periods in 2021 primarily due to increases in the petroleum, pipeline, and transportation sectors.
Fuel and other cost recovery revenues decreased in the third quarter 2022 when compared to the corresponding period in 2021 primarily as a result of lower recoverable fuel costs. Fuel and other cost recovery revenues increased for year-to-date 2022 when compared to the corresponding period in 2021 primarily as a result of higher 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. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Mississippi Power" for additional information.
Wholesale Revenues – Non-Affiliates
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $— | | — | | $13 | | 7.3 |
For year-to-date 2022, wholesale revenues from sales to non-affiliates were $191 million compared to $178 million for the corresponding period in 2021. The increase was primarily due to higher fuel costs and an increase in base revenue from MRA customers primarily due to increased demand as a result of weather impacts in 2022.
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 Note 2 to the financial statements under "Mississippi Power" in Item 8 of the Form 10-K for additional information. See Note (B) to the Condensed Financial Statements under "Mississippi Power – Municipal and Rural Associations Tariff" herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Wholesale Revenues – Affiliates
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $125 | | N/M | | $216 | | N/M |
In the third quarter 2022, wholesale revenues from sales to affiliates were $187 million compared to $62 million for the corresponding period in 2021. For year-to-date 2022, wholesale revenues from sales to affiliates were $336 million compared to $120 million for the corresponding period in 2021. Theincreases were primarily due toincreases of $111 million and $197 million, respectively, associated with higher fuel prices, primarily for natural gas, and $14 million and $19 million, respectively, associated with higher KWH sales due to lower cost available Mississippi Power resources as compared to the available affiliate company generation.
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.
Other Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $5 | | 62.5 | | $14 | | 70.0 |
In the third quarter 2022, other revenues were $13 million compared to $8 million for the corresponding period in 2021. For year-to-date 2022, other revenues were $34 million compared to $20 million for the corresponding period in 2021. The increases for the third quarter and year-to-date 2022 were primarily due to increases of $5 million and $10 million, respectively, in unregulated sales associated with power delivery construction and maintenance projects.
Fuel and Purchased Power Expenses
| | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-to-Date 2022 vs. Year-to-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | 103 | | | 74.2 | | $ | 235 | | | 71.1 |
| Purchased power | 14 | | | 250.0 | | 15 | | | 70.6 |
| Total fuel and purchased power expenses | $ | 117 | | | | | $ | 250 | | | |
In the third quarter 2022, total fuel and purchased power expenses were $262 millioncompared to $145 million for the corresponding period in 2021. Theincrease was due to a $106 millionincrease related to the average cost of fuel and purchased power and an $11 million increase related to the volume of KWHs generated and purchased.
For year-to-date 2022, total fuel and purchased power expenses were $601 millioncompared to $351 million for the corresponding period in 2021. Theincreasewas primarily due to a $233 millionincrease related to the average cost of fuel and purchased power and a $17 millionincrease related to the volume of KWHs generated.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Mississippi Power's fuel cost recovery clause.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of Mississippi Power's generation and purchased power were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 | | Third Quarter 2021 | | Year-To-Date 2022 | | Year-To-Date 2021 |
Total generation (in millions of KWHs) | 5,093 | | 4,878 | | 13,650 | | 13,016 |
Total purchased power (in millions of KWHs) | 241 | | 124 | | 527 | | 562 |
Sources of generation (percent) – | | | | | | | |
| Gas | 89 | | 93 | | 89 | | 91 |
| Coal | 11 | | 7 | | 11 | | 9 |
Cost of fuel, generated (in cents per net KWH) – | | | | | | | |
| Gas | 5.10 | | 2.99 | | 4.43 | | 2.66 |
| Coal | 4.50 | | 3.16 | | 4.12 | | 3.13 |
Average cost of fuel, generated (in cents per net KWH) | 5.02 | | 3.00 | | 4.40 | | 2.70 |
Average cost of purchased power (in cents per net KWH) | 8.15 | | 4.51 | | 6.83 | | 3.78 |
Fuel
In the third quarter 2022, fuel expense was $242 million compared to $139 million for the corresponding period in 2021. The increasewas due to a 70.6%increase in the average cost of natural gas per KWH generated, a 42.4%increase in the average cost of coal per KWHs generated, and a 61.3%increase in the volume of KWHs generated by coal.
For year-to-date 2022, fuel expense was $565 million compared to $330 million for the corresponding period in 2021. Theincreasewas due to a 66.5%increase in the average cost of natural gas per KWH generated, a 31.6%increase in the average cost of coal per KWHs generated, a 30.2%increase in the volume of KWHs generated by coal, and a 2.4%increase in the volume of KWHs generated by natural gas.
Purchased Power
In the third quarter 2022, purchased power expense was $20 million compared to $6 million for the corresponding period in 2021. The increasewas due to a 93.6% increase in the volume of KWHs purchased and an 80.7% increase in the average cost per KWH purchased.
For year-to-date 2022, purchased power expense was $36 million compared to $21 million for the corresponding period in 2021. The increasewas primarily due to an 80.6% increase in the average cost per KWH purchased, partially offset by a 6.3% decrease in the volume of KWHs purchased.
Energy purchases will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Other Operations and Maintenance Expenses
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1 | | 1.2 | | $22 | | 9.6 |
For year-to-date 2022, other operations and maintenance expenses were $252 million compared to $230 million for the corresponding period in 2021. The increase was primarily due to increases of $9 million related to unregulated power delivery construction and maintenance projects, $6 million associated with storm reserve accruals, $4 million in transmission and distribution line maintenance, and $4 million in sales and use taxes associated with the Kemper County energy facility. See Note 2 to the financial statements under "Mississippi Power – System Restoration Rider" in Item 8 of the Form 10-K and Note (C) to the Condensed Financial Statements under "Other Matters – Mississippi Power" herein for additional information.
Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $7 | | 70.0 | | $16 | | 72.7 |
In the third quarter 2022, income taxes were $17 million compared to $10 million for the corresponding period in 2021. For year-to-date 2022, income taxes were $38 million compared to $22 million for the corresponding period in 2021. The third quarter and year-to-date 2022 increases primarily relate to a reduction of $3 million and $8 million, respectively, in the flowback of excess deferred income taxes associated with new PEP rates that became effective in April 2022, as well as increases of $4 million and $8 million, respectively, due to higher pre-tax earnings. See Note (G) to the Condensed Financial Statements herein for additional information.
Southern Power
Net Income Attributable to Southern Power
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $17 | | 21.8 | | $54 | | 25.6 |
Net income attributable to Southern Power in the third quarter 2022 was $95 million compared to $78 million for the corresponding period in 2021. Net income attributable to Southern Power for year-to-date 2022 was $265 million compared to $211 million for the corresponding period in 2021. The increases were primarily due to higher revenues driven by higher market prices of energy, partially offset by higher other operations and maintenance expenses. Also contributing to the year-to-date 2022 increase were higher revenues from new natural gas PPAs and higher income associated with tax equity partnerships. The year-to-date 2022 increase was partially offset by gains from contributions of wind turbine equipment to various equity method investments in the first quarter 2021 and a tax benefit due to a change in state apportionment methodology resulting from tax legislation enacted by the State of Alabama in the first quarter 2021.
See Note 15 to the financial statements under "Southern Power – Development Projects" in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Operating Revenues
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $501 | | 73.8 | | $1,008 | | 62.6 |
Total operating revenues include PPA capacity revenues, which are derived primarily from long-term contracts involving natural gas facilities, and PPA energy revenues from Southern Power's generation facilities. To the extent Southern Power has capacity not contracted under a PPA, it may sell power into an accessible wholesale market, or, to the extent those generation assets are part of the FERC-approved IIC, it may sell power into the Southern Company power pool.
Natural Gas Capacity and Energy Revenue
Capacity revenues generally represent the greatest contribution to operating income and are designed to provide recovery of fixed costs plus a return on investment.
Energy is generally sold at variable cost or is indexed to published natural gas indices. Energy revenues will vary depending on the energy demand of Southern Power's customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Power's energy. Energy revenues also include fees for support services, fuel storage, and unit start charges. Increases and decreases in energy revenues under PPAs that are driven by fuel or purchased power prices are accompanied by an increase or decrease in fuel and purchased power costs and do not have a significant impact on net income.
Solar and Wind Energy Revenue
Southern Power's energy sales from solar and wind generating facilities are predominantly through long-term PPAs that do not have capacity revenue. Customers either purchase the energy output of a dedicated renewable facility through an energy charge or pay a fixed price related to the energy generated from the respective facility and sold to the grid. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors.
See FUTURE EARNINGS POTENTIAL – "Southern Power's Power Sales Agreements" in Item 7 of the Form 10-K for additional information regarding Southern Power's PPAs.
Operating Revenues Details
Details of Southern Power's operating revenues were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 | | Third Quarter 2021 | | Year-To-Date 2022 | | Year-To-Date 2021 |
| (in millions) |
| PPA capacity revenues | $ | 131 | | | $ | 118 | | | $ | 344 | | | $ | 311 | |
| PPA energy revenues | 736 | | | 413 | | | 1,657 | | | 954 | |
| Total PPA revenues | 867 | | | 531 | | | 2,001 | | | 1,265 | |
| Non-PPA revenues | 304 | | | 139 | | | 590 | | | 327 | |
| Other revenues | 9 | | | 9 | | | 27 | | | 18 | |
| Total operating revenues | $ | 1,180 | | | $ | 679 | | | $ | 2,618 | | | $ | 1,610 | |
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
In the third quarter 2022, total operating revenues were $1.2 billion, reflecting a $501 million, or 74%, increase from the corresponding period in 2021. The increase in operating revenues was primarily due to the following:
•PPA capacity revenues increased $13 million, or 11%, primarily due to increased capacity sales under existing natural gas PPAs.
•PPA energy revenues increased $323 million, or 78%, primarily due to a $333 million increase in sales under existing natural gas PPAs resulting from a $287 million increase in the price of fuel and purchased power and a $45 million increase in the volume of KWHs sold.
•Non-PPA revenues increased $165 million, or 119%, due to a $172 million increase in the market price of energy, partially offset by a $7 million decrease in the volume of KWHs sold through short-term sales.
For year-to-date 2022, total operating revenues were $2.6 billion, reflecting a $1.0 billion, or 63%, increase from the corresponding period in 2021. The increase in operating revenues was primarily due to the following:
•PPA capacity revenues increased $33 million, or 11%, primarily due to new natural gas PPAs and increased capacity sales under existing natural gas PPAs, partially offset by the contractual expiration of natural gas PPAs.
•PPA energy revenues increased $703 million, or 74%, primarily due to a $540 million increase in sales under existing natural gas PPAs resulting from a $442 million increase in the price of fuel and purchased power and a $98 million increase in the volume of KWHs sold. Also contributing to the increase was a $186 million increase in sales associated with new natural gas PPAs, partially offset by a $17 million decrease due to the contractual expiration of natural gas PPAs.
•Non-PPA revenues increased $263 million, or 80%, due to a $299 million increase in the market price of energy, partially offset by a $35 million decrease in the volume of KWHs sold through short-term sales.
Fuel and Purchased Power Expenses
Details of Southern Power's generation and purchased power were as follows:
| | | | | | | | | | | | | | | | | |
| | Third Quarter 2022 | Third Quarter 2021 | | Year-To-Date 2022 | Year-To-Date 2021 |
| (in billions of KWHs) |
| Generation | 12.8 | 12.1 | | 36.7 | 31.8 |
| Purchased power | 1.2 | 0.8 | | 2.3 | 2.0 |
| Total generation and purchased power | 14.0 | 12.9 | | 39.0 | 33.8 |
| | | | | |
Total generation and purchased power (excluding solar, wind, fuel cells, and tolling agreements) | 8.8 | 7.7 | | 23.2 | 20.2 |
Southern Power's PPAs for natural gas generation generally provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing Southern Power for substantially all of the cost of fuel relating to the energy delivered under such PPAs. Consequently, changes in such fuel costs are generally accompanied by a corresponding change in related fuel revenues and do not have a significant impact on net income. Southern Power is responsible for the cost of fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the wholesale market or into the Southern Company power pool for capacity owned directly by Southern Power.
Purchased power expenses will vary depending on demand, availability, and the cost of generating resources throughout the Southern Company system and other contract resources. Load requirements are submitted to the Southern Company power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power, an affiliate company, or external parties. Such purchased power costs are generally recovered through PPA revenues.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of Southern Power's fuel and purchased power expenses were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Third Quarter 2022 vs. Third Quarter 2021 | | Year-to-Date 2022 vs. Year-to-Date 2021 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | 346 | | | 133.6 | | $ | 734 | | | 135.9 |
| Purchased power | 103 | | | 251.2 | | 147 | | | 170.9 |
| Total fuel and purchased power expenses | $ | 449 | | | | | $ | 881 | | | |
In the third quarter 2022, total fuel and purchased power expenses increased $449 million, or 150%, compared to the corresponding period in 2021. Fuel expense increased $346 million due to a $323 million increase associated with the average cost of fuel and a $23 million increase associated with the volume of KWHs generated. Purchased power expense increased $103 million due to a $79 million increase associated with the average cost of purchased power and a $24 million increase associated with the volume of KWHs purchased.
For year-to-date 2022, total fuel and purchased power expenses increased $881 million, or 141%, compared to the corresponding period in 2021. Fuel expense increased $734 million due to a $651 million increase associated with the average cost of fuel and an $83 million increase associated with the volume of KWHs generated. Purchased power expense increased $147 million due to a $134 million increase associated with the average cost of purchased power and a $13 million increase associated with the volume of KWHs purchased.
Other Operations and Maintenance Expenses
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $19 | | 20.1 | | $23 | | 7.4 |
In the third quarter 2022, other operations and maintenance expenses were $113 million compared to $94 million for the corresponding period in 2021. For year-to-date 2022, other operations and maintenance expenses were $331 million compared to $308 million for the corresponding period in 2021. The increases for the third quarter and year-to-date 2022 were primarily due to increases of $11 million and $13 million, respectively, related to the timing of non-outage generation maintenance expenses. Also contributing to the year-to-date 2022 increase was an increase of $11 million in transmission expenses to serve new natural gas PPAs, partially offset by $6 million related to the allocation in 2021 of uncollected settlements by the Energy Reliability Council of Texas market as a result of Winter Storm Uri.
Loss on Sales-Type Lease
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(15) | | (100.0) | | $(14) | | (93.4) |
In the third quarter 2021, a $15 million loss on sales-type lease was recorded upon commencement of the Garland battery energy storage facility PPA, $10 million of which was allocated through noncontrolling interests to Southern Power's partners in the project. See Notes 9 and 15 to the financial statements under "Lessor" and "Southern Power," respectively, in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Gain on Dispositions, Net
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $— | | N/M | | $(37) | | (94.9) |
For year-to-date 2022, gain on dispositions, net was $2 million compared to $39 million for the corresponding period in 2021. The decrease primarily resulted from gains associated with contributions of wind turbine equipment to various equity method investments in the first quarter 2021. See Note 15 to the financial statements under "Southern Power – Development Projects" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Southern Power" herein for additional information.
Income Taxes (Benefit)
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $27 | | N/M | | $52 | | N/M |
In the third quarter 2022, income tax expense was $36 million compared to $9 million for the corresponding period in 2021. The change was primarily due to higher pre-tax earnings, partially offset by higher wind PTCs.
For year-to-date 2022, income tax expense was $49 million compared to a benefit of $3 million for the corresponding period in 2021. The change was primarily due to higher pre-tax earnings for year-to-date 2022 and a change in state apportionment methodology resulting from tax legislation enacted by the State of Alabama in the first quarter 2021, partially offset by higher wind PTCs for year-to-date 2022.
Net Income (Loss) Attributable to Noncontrolling Interests
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $7 | | N/M | | $(28) | | N/M |
In the third quarter 2022, net income attributable to noncontrolling interests was $12 million compared to $5 million for the corresponding period in 2021. The increase was primarily due to lower HLBV loss allocations to tax equity partners, including loss allocation impacts associated with the Garland battery energy storage facility being placed in service in the third quarter 2021, and higher income allocations to equity partners.
For year-to-date 2022, net loss attributable to noncontrolling interests was $55 million compared to $27 million for the corresponding period in 2021. The increased loss was primarily due to higher HLBV loss allocations to tax equity partners, partially offset by loss allocation impacts associated with the Garland battery energy storage facility being placed in service in the third quarter 2021 and higher income allocations to equity partners.
See Notes 9 and 15 to the financial statements under "Lessor" and "Southern Power," respectively, in Item 8 of the Form 10-K for additional information.
Southern Company Gas
Operating Metrics
Southern Company Gas continues to focus on several operating metrics, including Heating Degree Days, customer count, and volumes of natural gas sold.
Southern Company Gas measures weather and the effect on its business using Heating Degree Days. Generally, increased Heating Degree Days result in higher demand for natural gas on Southern Company Gas' distribution system. Southern Company Gas has various regulatory mechanisms, such as weather and revenue normalization and straight-fixed-variable rate design, which limit its exposure to weather changes within typical ranges in each of its
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
utility's respective service territory. Southern Company Gas also utilizes weather hedges to limit the negative income impacts in the event of warmer-than-normal weather.
The number of customers served by gas distribution operations and gas marketing services can be impacted by natural gas prices, economic conditions, and competition from alternative fuels. Gas distribution operations and gas marketing services' customers are primarily located in Georgia and Illinois.
Southern Company Gas' natural gas volume metrics for gas distribution operations and gas marketing services illustrate the effects of weather and customer demand for natural gas.
Seasonality of Results
During the Heating Season, natural gas usage and operating revenues are generally higher as more customers are connected to the gas distribution systems and natural gas usage is higher in periods of colder weather. Southern Company Gas' base operating expenses, excluding cost of natural gas, bad debt expense, and certain incentive compensation costs, are incurred relatively evenly throughout the year. Seasonality also affects the comparison of certain balance sheet items across quarters, including receivables, unbilled revenues, natural gas for sale, and notes payable. However, these items are comparable when reviewing Southern Company Gas' annual results. Thus, Southern Company Gas' operating results for the interim periods presented are not necessarily indicative of annual results and can vary significantly from quarter to quarter.
Net Income
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $27 | | 48.2 | | $127 | | 32.6 |
In the third quarter 2022, net income was $83 million compared to $56 million for the corresponding period in 2021. Net income increased $14 million at gas distribution operations primarily due to base rate increases and continued investment in infrastructure replacement and $14 million at gas pipeline investments primarily as a result of higher earnings at SNG and lower income taxes related to the PennEast Pipeline project. The third quarter 2021 results also included a $93 million after-tax gain and $85 million of additional tax expense as a result of the July 1, 2021 sale of Sequent.
For year-to-date 2022, net income was $516 million compared to $389 million for the corresponding period in 2021. Net income increased $73 million at gas pipeline investments primarily as a result of a 2021 impairment charge related to the PennEast Pipeline project and $57 million at gas distribution operations primarily due to base rate increases and continued investment in infrastructure replacement. The year-to-date 2021 results also included $108 million of net income from Sequent, including the $93 million after-tax gain, and $85 million of additional tax expense as a result of the July 1, 2021 sale of Sequent.
See Notes 2, 7, and 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Natural Gas Revenues, including Alternative Revenue Programs
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $234 | | 37.6 | | $1,004 | | 33.5 |
In the third quarter 2022, natural gas revenues, including alternative revenue programs, were $857 million compared to $623 million for the corresponding period in 2021. For year-to-date 2022, natural gas revenues, including alternative revenue programs, were $4.0 billion compared to $3.0 billion for the corresponding period in 2021.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of the changes in natural gas revenues, including alternative revenue programs, were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 | | Year-To-Date 2022 |
| (in millions) | | (% change) | | (in millions) | | (% change) |
| Natural gas revenues – prior year | $ | 623 | | | | | $ | 2,994 | | | |
| Estimated change resulting from – | | | | | | | |
| Infrastructure replacement programs and base rate changes | 54 | | | 8.7 | % | | 186 | | | 6.2 | % |
| Gas costs and other cost recovery | 172 | | | 27.6 | | | 955 | | | 31.9 | |
| Gas marketing services | 1 | | | 0.2 | | | 14 | | | 0.5 | |
| Wholesale gas services | — | | | — | | | (187) | | | (6.2) | |
| | | | | | | |
| Other | 7 | | | 1.1 | | | 36 | | | 1.1 | |
| Natural gas revenues – current year | $ | 857 | | | 37.6 | % | | $ | 3,998 | | | 33.5 | % |
Revenues from infrastructure replacement programs and base rate changes increased in the third quarter and year-to-date 2022 compared to the corresponding periods in 2021 primarily due to rate increases at Nicor Gas, Atlanta Gas Light, and Chattanooga Gas and continued investment in infrastructure replacement. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" in Item 8 of the Form 10-K for additional information.
Revenues associated with gas costs and other cost recovery increased in the third quarter and year-to-date 2022 compared to the corresponding periods in 2021 primarily due to higher natural gas cost recovery. See "Cost of Natural Gas" herein for additional information. Revenue impacts from weather and customer growth are described further below.
Revenues from gas marketing services increased for year-to-date 2022 compared to the corresponding period in 2021 due to higher commodity prices and higher sales to commercial customers.
The changes in year-to-date 2022 revenues related to wholesale gas services were due to the sale of Sequent on July 1, 2021. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Southern Company Gas' natural gas distribution utilities have various regulatory mechanisms that limit their exposure to weather changes. Southern Company Gas also uses hedges for the majority of any remaining exposure to warmer-than-normal weather in Illinois for gas distribution operations and in Illinois and Georgia for gas marketing services; therefore, weather typically does not have a significant net income impact. The following table presents Heating Degree Days information for Illinois and Georgia, the primary locations where Southern Company Gas' operations are impacted by weather.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter | | 2022 vs. normal | 2022 vs. 2021 | | Year-to-Date | | 2022 vs. normal | 2022 vs. 2021 |
| Normal(*) | 2022 | 2021 | | colder (warmer) | colder (warmer) | | Normal(*) | 2022 | 2021 | | colder (warmer) | colder (warmer) |
| (in thousands) | | | | | (in thousands) | | | |
| Illinois | 42 | | 56 | | 14 | | | 33.3 | % | 300.0 | % | | 3,686 | | 3,683 | | 3,594 | | | (0.1) | % | 2.5 | % |
| Georgia | 3 | | — | | 3 | | | — | % | — | % | | 1,431 | | 1,361 | | 1,396 | | | (4.9) | % | (2.5) | % |
(*)Normal represents the 10-year average from January 1, 2012 through September 30, 2016,2021 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.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
The following table provides the number of customers served by Southern Company Gas at September 30, 2022 and 2021:
| | | | | | | | | | | | | | | | | |
| September 30, | | |
| 2022 | | 2021 | | 2022 vs. 2021 |
| (in thousands, except market share %) | | (% change) |
| Gas distribution operations | 4,300 | | | 4,283 | | | 0.4 | % |
| Gas marketing services | | | | | |
Energy customers(*) | 598 | | | 603 | | | (0.8) | % |
| Market share of energy customers in Georgia | 28.3 | % | | 28.9 | % | | |
| | | | | |
| | | | | |
(*)Gas marketing services' customers are primarily located in Georgia and Illinois.
Southern Company Gas anticipates customer growth and uses a variety of targeted marketing programs to attract new customers and to retain existing customers.
Cost of Natural Gas
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $165 | | N/M | | $897 | | 95.1 |
Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations. Cost of natural gas at gas distribution operations represented 78% and 87% of the total cost of natural gas in the third quarter and year-to-date 2022, respectively. See MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – "Southern Company Gas – Cost of Natural Gas" in Item 7 of the Form 10-K and "Natural Gas Revenues, including Alternative Revenue Programs" herein for additional information.
In the third quarter 2022, cost of natural gas was $294 million compared to $129 million for the corresponding period in 2021. For year-to-date 2022, cost of natural gas was $1.8 billion compared to $943 million for the corresponding period in 2021. The increases reflect higher gas cost recovery as a result of increases of 104% and 113% in natural gas prices in the third quarter and year-to-date 2022, respectively, compared to the corresponding periods in 2021.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
The following table details the volumes of natural gas sold during all periods presented.
| | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter | 2022 vs. 2021 | | Year-to-Date | 2022 vs. 2021 |
| 2022 | 2021 | | 2022 | 2021 |
Gas distribution operations (mmBtu in millions) | | | | | | |
| Firm | 70 | | 74 | | (5.4) | % | | 485 | | 465 | | 4.3 | % |
| Interruptible | 22 | | 23 | | (4.3) | | | 69 | | 73 | | (5.5) | |
| Total | 92 | | 97 | | (5.2) | % | | 554 | | 538 | | 3.0 | % |
| | | | | | |
| | | | | | | |
Gas marketing services (mmBtu in millions) | | | | | | |
| Firm: | | | | | | | |
| Georgia | 3 | | 3 | | — | % | | 24 | | 26 | | (7.7) | % |
| Illinois | — | | — | | — | | | 4 | | 5 | | (20.0) | |
| | | | | | | |
| Other | 2 | | 2 | | — | | | 8 | | 10 | | (20.0) | |
| Interruptible large commercial and industrial | 3 | | 3 | | — | | | 11 | | 10 | | 10.0 | |
| Total | 8 | | 8 | | — | % | | 47 | | 51 | | (7.8) | % |
Other Operations and Maintenance Expenses
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $14 | | 5.9 | | $53 | | 6.8 |
In the third quarter 2022, other operations and maintenance expenses were $252 million compared to $238 million for the corresponding period in 2021. The increase was primarily due to higher compensation and benefit expenses and higher expenses passed through directly to customers primarily related to bad debt at gas distribution operations.
For year-to-date 2022, other operations and maintenance expenses were $829 million compared to $776 million for the corresponding period in 2021. Excluding $53 million of expenses related to Sequent for year-to-date 2021, other operations and maintenance expenses increased approximately $106 million. The increase was primarily due to increases of $47 million in compensation and benefit expenses, $30 million in expenses passed through directly to customers primarily related to bad debt at gas distribution operations, $18 million in customer accounts expenses, and $15 million in technology-related costs.
Depreciation and Amortization
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $7 | | 5.3 | | $18 | | 4.5 |
In the third quarter 2022, depreciation and amortization was $140 million compared to $133 million for the corresponding period in 2021. For year-to-date 2022, depreciation and amortization was $414 million compared to $396 million for the corresponding period in 2021. The increases were primarily due to continued infrastructure investments at the natural gas distribution utilities.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Taxes Other Than Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $9 | | 25.0 | | $42 | | 25.3 |
In the third quarter 2022, taxes other than income taxes were $45 million compared to $36 million for the corresponding period in 2021. For year-to-date 2022, taxes other than income taxes were $208 million compared to $166 million for the corresponding period in 2021. The increases primarily reflect an increase in revenue tax expenses as a result of higher natural gas revenues and an increase in invested capital tax expense at Nicor Gas. Revenue tax expenses are passed through directly to customers and have no impact on net income.
Gain on Dispositions, Net
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(121) | | (100.0) | | $(122) | | (96.1) |
The sale of Sequent in the third quarter 2021 resulted in a gain on dispositions, net of $121 million. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Earnings from Equity Method Investments
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $9 | | 36.0 | | $91 | | N/M |
In the third quarter 2022, earnings from equity method investments were $34 million compared to $25 million for the corresponding period in 2021. The increase was primarily due to higher earnings at SNG resulting from higher revenues primarily due to increased demand.
For year-to-date 2022, earnings from equity method investments were $105 million compared to $14 million for the corresponding period in 2021. The increase was primarily due to pre-tax impairment charges totaling $84 million in 2021 related to the PennEast Pipeline project and higher earnings at SNG resulting from higher revenues primarily due to increased demand.
See Note 7 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements herein under "Southern Company Gas" for additional information.
Other Income (Expense), Net
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $2 | | 15.4 | | $113 | | N/M |
For year-to-date 2022, other income (expense), net was $47 million of income compared to $66 million of expense for the corresponding period in 2021. The change was largely due to charitable contributions totaling $101 million during the first and second quarters of 2021 and an increase of $12 million at gas distribution operations primarily related to an increase in non-service cost-related retirement benefits income. See Note (H) to the Condensed Financial Statements herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Income Taxes
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2022 vs. Third Quarter 2021 | | Year-To-Date 2022 vs. Year-To-Date 2021 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(106) | | (79.7) | | $(63) | | (28.1) |
In the third quarter 2022, income taxes were$27 million compared to $133 million for the corresponding period in 2021. For year-to-date 2022, income taxes were $161 million compared to $224 million for the corresponding period in 2021. The decreases were primarily the result of $113 million in additional tax expense in the third quarter 2021 as a result of the sale of Sequent. Partially offsetting the third quarter 2022 decrease was an increase of $9 million in income tax expense at gas distribution operations primarily as a result of higher pre-tax earnings. The year-to-date 2022 decrease was partially offset by increases in income tax expense of $25 million at gas distribution operations primarily as a result of higher pre-tax earnings and $20 million at gas pipeline investments primarily from $18 million of tax benefits resulting from the impairment charge in the second quarter 2021 related to the PennEast Pipeline project. See Notes 7 and 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Segment Information
Operating revenues, operating expenses, and net income (loss) for each segment are provided in the table below. See Note (L) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2022 | | 2021 |
| Operating Revenues | | Operating Expenses | | Net Income (Loss) | | Operating Revenues | | Operating Expenses | | Net Income (Loss) |
| (in millions) | | (in millions) |
| Third Quarter |
| Gas distribution operations | $ | 751 | | | $ | 629 | | | $ | 59 | | | $ | 556 | | | $ | 459 | | | $ | 45 | |
| Gas pipeline investments | 8 | | | 3 | | | 24 | | | 8 | | | 3 | | | 10 | |
Wholesale gas services(*) | — | | | — | | | — | | | — | | | (120) | | | 94 | |
| Gas marketing services | 85 | | | 87 | | | (2) | | | 52 | | | 52 | | | (2) | |
| All other | 16 | | | 12 | | | 2 | | | 11 | | | 25 | | | (91) | |
| Intercompany eliminations | (3) | | | — | | | — | | | (4) | | | (4) | | | — | |
| Consolidated | $ | 857 | | | $ | 731 | | | $ | 83 | | | $ | 623 | | | $ | 415 | | | $ | 56 | |
| | | | | | | | | | | |
| Year-to-Date |
| Gas distribution operations | $ | 3,533 | | | $ | 2,922 | | | $ | 365 | | | $ | 2,466 | | | $ | 1,936 | | | $ | 308 | |
| Gas pipeline investments | 24 | | | 8 | | | 76 | | | 24 | | | 9 | | | 3 | |
Wholesale gas services(*) | — | | | — | | | — | | | 188 | | | (53) | | | 108 | |
| Gas marketing services | 420 | | | 327 | | | 65 | | | 311 | | | 226 | | | 60 | |
| All other | 43 | | | 48 | | | 10 | | | 29 | | | 60 | | | (90) | |
| Intercompany eliminations | (22) | | | (19) | | | — | | | (24) | | | (24) | | | — | |
| Consolidated | $ | 3,998 | | | $ | 3,286 | | | $ | 516 | | | $ | 2,994 | | | $ | 2,154 | | | $ | 389 | |
(*)As a result of the sale of Sequent, wholesale gas services is no longer a reportable segment for the third quarter and year-to-date 2022. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K 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 regulatory 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
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
gas delivered to its customers and its fixed and variable costs, including depreciation, interest expense, operations and maintenance, taxes, and overhead costs, and to earn a reasonable return on its investments.
With the exception of Atlanta Gas Light, Southern Company Gas' second largest utility that operates in a deregulated natural gas market and has a straight-fixed-variable rate design that minimizes the variability of its revenues based on consumption, the earnings of the natural gas distribution utilities can be affected by customer consumption patterns that are a function of weather conditions, price levels for natural gas, and general economic conditions that may impact customers' ability to pay for natural gas consumed. Southern Company Gas has various regulatory and other mechanisms, such as weather and revenue normalization mechanisms and weather derivative instruments, that limit its exposure to changes in customer consumption, including weather changes within typical ranges in its natural gas distribution utilities' service territories. See Note 2 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
In the third quarter and year-to-date 2022, net income increased $14 million, or 31.1%, and $57 million, or 18.5%, respectively, when compared to the corresponding periods in 2021, as described further below:
•Operating revenues increased $195 million and $1.07 billion, respectively, when compared to the corresponding periods in 2021 primarily due to higher gas cost recovery, rate increases, and continued investment in infrastructure replacement. Gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas.
•Operating expenses increased $170 million and $986 million, respectively, when compared to the corresponding periods in 2021 primarily due to increases of $129 million and $802 million, respectively, in the cost of gas as a result of higher natural gas prices compared to 2021, higher compensation and benefit expenses, and higher depreciation resulting from additional assets placed in service. The increase in operating expenses also includes higher costs passed through directly to customers, primarily related to bad debt expenses and revenue taxes.
•Other income and (expense) increased $3 million and $12 million, respectively, when compared to the corresponding periods in 2021, primarily due to an increase in non-service cost-related retirement benefits income. See Note (H) to the Condensed Financial Statements herein for additional information.
•Interest expense, net of amounts capitalized increased $5 million and $11 million, respectively, when compared to the corresponding periods in 2021 primarily due to additional debt issued to finance continued investments. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings.
•Income taxes increased $9 million and $25 million, respectively, when compared to the corresponding periods in 2021 primarily due to higher pre-tax earnings.
Gas Pipeline Investments
Gas pipeline investments consists primarily of joint ventures in natural gas pipeline investments including SNG, Dalton Pipeline, and PennEast Pipeline. See Note (E) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
In the third quarter 2022, net income increased $14 million when compared to the corresponding period in 2021 primarily due to higher earnings at SNG resulting from higher revenues primarily due to increased demand and lower income taxes related to the PennEast Pipeline project.
For year-to-date 2022, net income increased $73 million when compared to the corresponding period in 2021 primarily due to pre-tax impairment charges totaling $84 million ($67 million after tax) in 2021 related to the equity method investment in the PennEast Pipeline project and higher earnings at SNG resulting from higher revenues primarily due to increased demand. See Note 7 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Gas Marketing Services
Gas marketing services provides energy-related products and services to natural gas markets and participants in customer choice programs that were approved in various states to increase competition. These programs allow customers to choose their natural gas supplier while the local distribution utility continues to provide distribution and transportation services. Gas marketing services is weather sensitive and uses a variety of hedging strategies, such as weather derivative instruments and other risk management tools, to partially mitigate potential weather impacts.
In the third quarter 2022, net income was flat when compared to the corresponding period in 2021 primarily due to an increase of $35 million in operating expenses primarily due to higher cost of gas, largely offset by a related increase of $33 million in operating revenues.
For year-to-date 2022, net income increased $5 million, or 8.3%, when compared to the corresponding period in 2021 primarily due to a $109 million increase in operating revenues as a result of higher commodity prices and higher sales to commercial customers, partially offset by a $101 million increase in operating expenses primarily due to $95 million in higher cost of natural gas and an increase of $4 million in income taxes as a result of higher pre-tax earnings.
All Other
All other includes natural gas storage businesses, a renewable natural gas business, 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. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for information regarding agreements by certain affiliates of Southern Company Gas to sell two natural gas storage facilities.
In the third quarter 2022, net income increased $93 million when compared to the corresponding period in 2021. The change primarily relates to additional tax expense as a result of the sale of Sequent in 2021 and a decrease of $13 million in operating expenses related to lower depreciation in 2022 and transaction costs in 2021 related to the sale of Sequent.
For year-to-date 2022, net income increased $100 million when compared to the corresponding period in 2021. The change primarily relates to additional tax expense as a result of the sale of Sequent in 2021 and an increase in operating revenues of $14 million primarily related to higher demand fees and favorable hedge gains at the natural gas storage businesses, higher sales from the renewable natural gas business, and lower depreciation in 2022.
FUTURE EARNINGS POTENTIAL
Each Registrant's results of operations are not necessarily indicative of its future earnings potential. The level of the Registrants' future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Registrants' primary businesses of selling electricity and/or distributing natural gas, as described further herein.
For the traditional electric operating companies, these factors include the ability to maintain constructive regulatory environments that allow for the timely recovery of prudently-incurred costs during a time of increasing costs, including those related to projected long-term demand growth, stringent environmental standards, including CCR rules, safety, system reliability and resiliency, fuel, restoration following major storms, and capital expenditures, including constructing new electric generating plants and expanding and improving the transmission and distribution systems; continued customer growth; and the predecessortrends of higher inflation and reduced electricity usage per customer, especially in residential and commercial markets. For Georgia Power, completing construction of Plant Vogtle Units 3 and 4 and the related cost recovery proceedings is another major factor.
Earnings in the electricity business will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions, which could contribute to a net reduction in customer usage.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Global and U.S. economic conditions have been significantly affected by a series of demand and supply shocks that caused a global and national economic recession in 2020. The drivers, speed, and depth of the 2020 economic contraction were unprecedented and continue to reduce energy demand across the Southern Company system's service territory, primarily in the commercial class. Retail electric revenues attributable to changes in sales increased in the first nine months of 2022 when compared to the corresponding period in 2021 primarily due to the normalization of economic activity; however, total retail electric sales for the Southern Company system continued to be negatively impacted by the COVID-19 pandemic when compared to pre-pandemic trends. Most prominently, the COVID-19 pandemic has negatively impacted global supply chains and business operations as suppliers continue to experience difficulties keeping up with strong demand for factory goods, which is being driven by low business inventories. In addition, rising inflation in 2021 and 2022 has resulted in increasing costs for many goods and services. As a result of persistently high inflation, interest rates have been on the rise and are expected to continue rising in the near term, which has impacted, and may continue to impact, the Registrants' borrowing costs. Based on these factors, the probability of the U.S. economy falling into a recession has heightened. The impacts of new COVID-19 variants, responses to the COVID-19 pandemic by both customers and governments, ongoing geopolitical threats, such as the escalation of the Russia-Ukraine war, and the potential of future COVID-19-related lockdowns in Asia or elsewhere could further disrupt global supply chains and increase the severity of a possible economic downturn in the Southern Company system's service territory. See RESULTS OF OPERATIONS herein for information on COVID-19-related impacts on energy demand in the Southern Company system's service territory during the first nine months of 2022.
The level of future earnings for Southern Power's competitive wholesale electric business depends on numerous factors including the parameters of the wholesale market and the efficient operation of its wholesale generating assets; Southern Power's ability to execute its growth strategy through the development or acquisition of renewable facilities and other energy projects while containing costs; regulatory matters; customer creditworthiness; total electric generating capacity available in Southern Power's market areas; Southern Power's ability to successfully remarket capacity as current contracts expire; renewable portfolio standards; availability of federal and state ITCs and PTCs, which could be impacted by future tax legislation; transmission constraints; cost of generation from units within the Southern Company power pool; and operational limitations. See "Income Tax Matters" herein for additional information on recent tax legislation expanding the availability of federal ITCs and PTCs.
The level of future earnings for Southern Company Gas' primary business of distributing natural gas and its complementary businesses in the gas pipeline investments and gas marketing services sectors depends on numerous factors. These factors include the natural gas distribution utilities' ability to maintain constructive regulatory environments that allow for the timely recovery of prudently-incurred costs, including those related to projected long-term demand growth, safety, system reliability and resiliency, natural gas, and capital expenditures, including expanding and improving the natural gas distribution systems; the completion and subsequent operation of ongoing infrastructure and other construction projects; customer creditworthiness; and certain policies to limit the use of natural gas, such as the potential across certain parts of the U.S. for state or municipal bans on the use of natural gas. The volatility of natural gas prices has an impact on Southern Company Gas' customer rates, its long-term competitive position against other energy sources, and the ability of Southern Company Gas' gas marketing services business to capture value from locational and seasonal spreads. Additionally, changes in commodity prices, primarily driven by tight gas supplies, geopolitical events, and diminished gas production, subject a portion of Southern Company Gas' operations to earnings variability and have recently resulted in higher natural gas prices. Additional economic factors may contribute to this environment. 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. Alternatively, a significant drop in oil and natural gas prices could lead to a consolidation of natural gas producers or reduced levels of natural gas production.
Earnings for both the electricity and natural gas businesses are subject to a variety of other factors. These factors include weather; competition; developing new and maintaining existing energy contracts and associated load requirements with wholesale customers; energy conservation practiced by customers; the use of alternative energy sources by customers; government incentives to reduce overall energy usage; the prices of electricity and natural
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
gas; costs and availability of labor and materials in a time of rising costs, impacted by heightened inflation caused by unprecedented shocks to the broader economy, and supply chain disruptions; and the price elasticity of demand. Demand for electricity and natural gas in the Registrants' service territories is primarily driven by the pace of economic growth or decline that may be affected by changes in regional and global economic conditions, which may impact future earnings.
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, or the sale of interests in, certain assets or businesses, internal restructuring, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations, risks, and financial condition of Southern Company. In addition, Southern Power and Southern Company Gas regularly consider and evaluate joint development arrangements as well as acquisitions and dispositions of businesses and assets as part of their business strategies. See Note 15 to the financial statements in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements herein for additional information.
For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL in Item 7 of the Form 10-K.
Environmental Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" in Item 7 and Note 3 to the financial statements under "Environmental Remediation" in Item 8 of the Form 10-K, as well as Note (C) to the Condensed Financial Statements under "General Litigation Matters" and "Environmental Remediation" herein, for additional information.
Environmental Laws and Regulations
Air Quality
On August 30, 2022, the EPA found that 15 states, including Alabama and Mississippi, failed to submit regional haze state implementation plans for the second 10-year planning period (2018 through 2028) by July 31, 2021. The finding of failure to submit establishes a two-year deadline for the EPA to promulgate a Federal Implementation Plan (FIP) to address these requirements for each applicable state unless, before the EPA promulgates a FIP, the state submits, and the EPA approves, a state implementation plan that meets the requirements. The ultimate outcome of this matter, including any potential impacts to Alabama Power, Mississippi Power, and Southern Power, cannot be determined at this time.
Global Climate Issues
On June 30, 2022, the U.S. Supreme Court issued an opinion limiting the EPA's authority to regulate greenhouse gas emissions under the Clean Air Act. The Court's review in the case focused on whether the EPA's authority under the Clean Air Act allows the EPA to regulate the electric industry in a manner as broad as the Clean Power Plan (CPP), which was repealed and replaced by the Affordable Clean Energy rule (ACE Rule). The Court held that the generation shifting to lower carbon emitting sources approach in the CPP is not authorized by the Clean Air Act. However, the Court did not decide whether the EPA may adopt measures only applied at the individual electric generating source, which is the basis for the ACE Rule. The EPA has announced its intent to propose a rule for existing power plants pursuant to the Clean Air Act by March 2023. The ultimate impact of the Court's decision cannot be determined at this time.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Regulatory Matters
See Note 2 to the financial statements in Item 8 of the Form 10-K, OVERVIEW – "Recent Developments" herein, and Note (B) to the Condensed Financial Statements herein for a discussion of regulatory matters related to Alabama Power, Georgia Power, Mississippi Power, and Southern Company Gas, including items that could impact the applicable Registrants' future earnings, cash flows, and/or financial condition.
Alabama Power
On September 23, 2022, the FERC authorized Alabama Power to use updated depreciation rates from its 2021 depreciation study effective January 1, 20162023. The study was also provided to the Alabama PSC, and the new depreciation rates will be reflected in Alabama Power's future rate filings. The updated depreciation rates are expected to result in an approximately $500 million increase in annual depreciation expense. See Notes 2 and 5 to the financial statements under "Alabama Power" and "Depreciation and Amortization," respectively, in Item 8 of the Form 10-K for additional information.
Construction Programs
The Subsidiary Registrants are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system strategy continues to include developing and constructing new electric generating facilities, expanding and improving the electric transmission and electric and natural gas distribution systems, and undertaking projects to comply with environmental laws and regulations.
For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. The largest construction project currently underway in the Southern Company system is Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information. Also see Note 2 to the financial statements under "Alabama Power – Certificates of Convenience and Necessity" in Item 8 of the Form 10-K for information regarding Alabama Power's construction of Plant Barry Unit 8.
See Note 15 to the financial statements in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements herein under "Southern Power" for information about costs relating to Southern Power's construction of renewable energy facilities.
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, reduce emissions, 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 Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Southern Company Gas" for additional information on Southern Company Gas' construction program.
See FINANCIAL CONDITION AND LIQUIDITY – "Cash Requirements" herein for additional information regarding the Registrants' capital requirements for their construction programs.
Income Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" in Item 7 of the Form 10-K for additional information.
On August 16, 2022, the Inflation Reduction Act (IRA) was signed into law. The IRA extends, expands, and increases ITCs and PTCs for clean energy projects, allows PTCs for solar projects, adds ITCs for stand-alone energy storage projects with an option to elect out of the tax normalization requirement, and allows for the transferability of the tax credits. The IRA extends and increases the tax credits for carbon capture and sequestration projects and adds tax credits for clean hydrogen and nuclear projects. Additional ITC and PTC amounts are available if the projects meet domestic content requirements or are located in low-income or energy communities.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
The IRA also enacted a 15% corporate minimum tax on book income, with some adjustments including adjustments for pension and tax depreciation. The 15% corporate minimum tax on book income can be reduced by energy tax credits.
For solar projects placed in service in 2022 through 2032, the IRA provides for a 30% ITC and an option to claim a PTC instead of an ITC. Starting in 2023 and through 2032, the IRA provides for a 30% ITC for stand-alone energy storage projects. For wind projects placed in service in 2022 through 2032, the IRA provides for a 100% PTC. The PTC rate for 2022 is 2.6 cents per KWH and will be adjusted for inflation annually. The same PTC rate applies for solar projects for which the PTC option has been elected. To realize the full value of ITCs and PTCs, the IRA requires satisfaction of prevailing wage and apprenticeship requirements.
Implementation of the IRA provisions is subject to the issuance of additional guidance by the U.S. Treasury Department, and the ultimate impacts cannot be determined at this time; however, the IRA is not expected to have a material impact on the Registrants' financial statements for the year ending December 31, 2022.
General Litigation and Other Matters
The Registrants are involved in various matters being litigated and/or regulatory and other matters that could affect future earnings, cash flows, and/or financial condition. The ultimate outcome of such pending or potential litigation against each Registrant and any subsidiaries or regulatory and other matters cannot be determined at this time; however, for current proceedings and/or matters not specifically reported herein or in Notes (B) and (C) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings and/or matters would have a material effect on such Registrant's financial statements. See Notes (B) and (C) to the Condensed Financial Statements for a discussion of various contingencies, including matters being litigated, regulatory matters, and other matters which may affect future earnings potential.
ACCOUNTING POLICIES
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES in Item 7 of the Form 10-K for a complete discussion of the Registrants' critical accounting policies and estimates, as well as recently issued accounting standards.
Application of Critical Accounting Policies and Estimates
The Registrants prepare their financial statements in accordance with GAAP. Significant accounting policies are described in the notes 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 the Registrants' results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements.
Estimated Cost, Schedule, and Rate Recovery for the Construction of Plant Vogtle Units 3 and 4
(Southern Company and Georgia Power)
As of September 30, 2022, Georgia Power revised its total project capital cost forecast to $10.4 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds). This forecast includes construction contingency of $49 million and is based on projected in-service dates at the end of the first quarter 2023 and the fourth quarter 2023 for Units 3 and 4, respectively.
The projected schedule for Unit 3 primarily depends on the pace of system and area transitions to operations, including the completion of closure documentation necessary to support start-up testing, and the progression of start-up, final component, and pre-operational testing, which may be impacted by equipment or other operational failures. The projected schedule for Unit 4 primarily depends on Unit 3 progress through start-up and testing; overall construction productivity and production levels improving, particularly in electrical installation, including terminations; and appropriate levels of craft laborers, particularly electricians, being added and maintained. Any further delays could result in later in-service dates and cost increases.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
During the first nine months of 2022, established construction contingency totaling $170 million was assigned to the base capital cost forecast for costs primarily associated with construction productivity, the pace of system turnovers, additional craft and support resources, and procurement for Units 3 and 4. Georgia Power also increased its total project capital cost forecast and recorded pre-tax charges of $36 million ($27 million after tax) and $32 million ($24 million after tax) to replenish construction contingency in the second quarter 2022 and the third quarter 2022, respectively.
Georgia Power and the other Vogtle Owners do not agree on either the starting dollar amount for the determination of cost increases subject to the cost-sharing and tender provisions of the Global Amendments (as defined in Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction – Joint Owner Contracts" herein) or the extent to which COVID-19-related costs impact those provisions. In October 2021, Georgia Power and the other Vogtle Owners entered into an agreement, which was modified on June 3, 2022, to clarify the process for the tender provisions of the Global Amendments to provide for a decision between 120 and 194 days after the tender option is triggered, which the other Vogtle Owners assert occurred on February 14, 2022. On June 17, 2022 and July 26, 2022, OPC and Dalton, respectively, notified Georgia Power of their purported exercises of their tender options. On September 29, 2022, Georgia Power and MEAG Power reached an agreement to resolve their dispute regarding the proper interpretation of the cost-sharing and tender provisions of the Global Amendments. Under the terms of the agreement, among other items, (i) MEAG Power will not exercise its tender option and will retain its full ownership interest in Plant Vogtle Units 3 and 4; (ii) Georgia Power will pay a portion of MEAG Power's costs of construction for Plant Vogtle Units 3 and 4 as such costs are incurred and with no further adjustment for force majeure costs, which payments will total approximately $79 million based on the current project capital cost forecast; and (iii) Georgia Power will pay 20% of MEAG Power's costs of construction with respect to any amounts over the current project capital cost forecast, with no further adjustment for force majeure costs.
Georgia Power recorded additional pre-tax charges (credits) to income in the second quarter 2022 and the third quarter 2022 of approximately $16 million ($12 million after tax) and $(102) million ($(76) million after tax), respectively, associated with the cost-sharing and tender provisions of the Global Amendments, including the settlement with MEAG Power, which are included in the total project capital cost forecast. The settlement with MEAG Power does not resolve the separate pending litigation with OPC, including Dalton's associated complaint, regarding the cost-sharing and tender provisions of the Global Amendments described in Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction – Joint Owner Contracts" herein. Georgia Power may be required to record further pre-tax charges to income of up to approximately $300 million associated with these provisions for OPC and Dalton based on the current project capital cost forecast.
The ultimate outcome of these matters cannot be determined at this time. However, any extension of the in-service date beyond the first quarter 2023 for Unit 3 or the fourth quarter 2023 for Unit 4, including the current level of cost sharing described in Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein, is estimated to result in additional base capital costs for Georgia Power of up to $15 million per month for Unit 3 and $35 million per month for Unit 4, as well as the related AFUDC and any additional related construction, support resources, or testing costs. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Georgia Power – Nuclear Construction" for additional information.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" in Item 7 of the Form 10-K for additional information. The financial condition of each Registrant remained stable at September 30, 20162022. The Registrants intend to continue to monitor their access to short-term and long-term capital markets as well as their bank credit arrangements to meet future capital and liquidity needs. See "Cash Requirements," "Sources of Capital," and "Financing Activities" herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
At the end of the third quarter 2022, the market price of Southern Company's common stock was $68.00 per share (based on the closing price as reported on the NYSE) and the book value was $28.69 per share, representing a market-to-book ratio of 237%, compared to $68.58, $26.30, and 261%, respectively, at the end of 2021. Southern Company's common stock dividend for the third quarter 2022 was $0.68 per share compared to $0.66 per share in the third quarter 2021.
Cash Requirements
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Cash Requirements" in Item 7 of the Form 10-K for a description of the Registrants' significant cash requirements.
The Registrants' significant cash requirements include estimated capital expenditures associated with their construction programs and, for the traditional electric operating companies, operating cash flows related to fuel cost under recovery. The fuel cost under recovery balances are primarily the result of higher than forecasted prices for natural gas and purchased power.
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 and/or regulation; the cost, availability, and efficiency of construction labor, equipment, and materials; project scope and design changes; abnormal weather; delays in construction due to judicial or regulatory action; storm impacts; and the cost of capital. The continued impacts of the COVID-19 pandemic could also impair the ability to develop, construct, and operate facilities, as discussed further in Item 1A of the Form 10-K. In addition, there can be no assurance that costs related to capital expenditures and AROs will be fully recovered. Additionally, expenditures associated with Southern Power's planned acquisitions may vary due to market opportunities and the execution of its growth strategy. See Note 15 to the financial statements in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements herein under "Southern Power" for additional information regarding Southern Power's plant acquisitions and construction projects.
The construction program of Georgia Power includes Plant Vogtle Units 3 and 4, which includes components based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale and which may be subject to additional revised cost estimates during construction. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Georgia Power – Nuclear Construction" for information regarding Plant Vogtle Units 3 and 4 and additional factors that may impact construction expenditures.
Long-term debt maturities and the interest payable on long-term debt each represent a significant cash requirement for the Registrants. See "Financing Activities" herein for information on changes in the Registrants' long-term debt balances since December 31, 2021.
Sources of Capital
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" in Item 7 of the Form 10-K for additional information. Southern Company intends to meet its future capital needs through operating cash flows, borrowings from financial institutions, and debt and equity issuances. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings. Southern Company does not expect to issue any equity in the capital markets through 2026, but may issue equity through its stock plans during this time.
The Subsidiary Registrants plan to obtain the funds to meet their future capital needs from sources similar to those they used in the past, which were primarily from operating cash flows, external securities issuances, borrowings from financial institutions, and equity contributions from Southern Company. Operating cash flows provide a
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
substantial portion of the Registrants' cash needs. During the nine months ended September 30, 2022, Southern Power utilized tax credits, which provided $218 million in operating cash flows. In addition, Southern Power plans to utilize tax equity partnership contributions (as discussed further herein). Georgia Power intends to utilize short-term floating rate bank loans and commercial paper issuances to fund operating cash flows related to fuel cost under recovery. Subsequent to September 30, 2022, Georgia Power borrowed $250 million pursuant to a short-term uncommitted bank credit arrangement and intends to borrow up to an additional $1.2 billion pursuant to a short-term floating rate bank loan in November 2022.
The amount, type, and timing of any financings in 2022, as well as in subsequent years, will be contingent on investment opportunities and the Registrants' capital requirements and will depend upon prevailing market conditions, regulatory approvals (for certain of the Subsidiary Registrants), and other factors. See "Cash Requirements" and "Financing Activities" herein for additional information.
Southern Power utilizes tax equity partnerships as one of its financing sources, where the tax partner takes significantly all of the federal tax benefits. These tax equity partnerships are consolidated in Southern Power's financial statements and are accounted for using HLBV methodology to allocate partnership gains and losses. During the nine months ended September 30, 2022, Southern Power obtained tax equity funding for existing tax equity partnerships totaling $51 million. See Note 1 to the financial statements under "General" in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information.
By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. At September 30, 2022, the amount of subsidiary retained earnings restricted to dividend totaled $1.4 billion. This restriction did not impact Southern Company Gas' ability to meet its cash obligations, nor does management expect such restriction to materially impact Southern Company Gas' ability to meet its currently anticipated cash obligations.
Certain Registrants' current liabilities frequently exceed their current assets because of long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs. The Registrants generally plan to refinance long-term debt as it matures. The following table shows the amount by which current liabilities exceeded current assets at September 30, 2022 for the applicable Registrants:
| | | | | | | | | | | | | | | | |
| At September 30, 2022 | Southern Company | | Georgia
Power | Mississippi Power | Southern Power | |
| (in millions) |
| Current liabilities in excess of current assets | $ | 2,438 | | | $ | 2,442 | | $ | 18 | | $ | 325 | | |
The Registrants believe the need for working capital can be adequately met by utilizing operating cash flows, as well as commercial paper, lines of credit, and short-term bank notes, as market conditions permit. In addition, under certain circumstances, the Subsidiary Registrants may utilize equity contributions and/or loans from Southern Company.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Bank Credit Arrangements
At September 30, 2022, the Registrants' unused committed credit arrangements with banks were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| At September 30, 2022 | Southern
Company
parent | Alabama Power | Georgia
Power | Mississippi Power | Southern Power(a) | Southern Company Gas(b) | SEGCO | Southern
Company |
| (in millions) |
| Unused committed credit | $ | 1,998 | | $ | 1,250 | | $ | 1,726 | | $ | 275 | | $ | 569 | | $ | 1,748 | | $ | 30 | | $ | 7,596 | |
(a)At September 30, 2022, Southern Power also had two continuing letters of credit facilities for standby letters of credit, of which $16 million was unused. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities.
(b)Includes $798 million and $950 million at Southern Company Gas Capital and Nicor Gas, respectively.
Subject to applicable market conditions, the Registrants, Nicor Gas, and SEGCO expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, the Registrants, Nicor Gas, and SEGCO may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the unused credit with banks is allocated to provide liquidity support to the revenue bonds of the traditional electric operating companies and the commercial paper programs of the Registrants, Nicor Gas, and SEGCO. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support at September 30, 2022 was approximately $1.4 billion (comprised of approximately $789 million at Alabama Power, $619 million at Georgia Power, and $34 million at Mississippi Power). In addition, at September 30, 2022, Georgia Power had approximately $288 million of fixed rate revenue bonds outstanding that are required to be remarketed within the next 12 months.
See Note 8 to the financial statements in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements herein under "Bank Credit Arrangements" for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services(*) | Gas Midstream Operations | Total | All Other | Eliminations | Consolidated |
| | (in millions) |
| Successor – Three Months Ended September 30, 2017: | | | | | | |
| Operating revenues | $ | 472 |
| $ | 143 |
| $ | (24 | ) | $ | 16 |
| $ | 607 |
| $ | 2 |
| $ | (44 | ) | $ | 565 |
|
| Segment net income | 52 |
| 1 |
| (23 | ) | 14 |
| 44 |
| (29 | ) | — |
| 15 |
|
| Successor – Nine Months Ended September 30, 2017: | | | | | | |
| Operating revenues | $ | 2,255 |
| $ | 597 |
| $ | 95 |
| $ | 53 |
| $ | 3,000 |
| $ | 7 |
| $ | (166 | ) | $ | 2,841 |
|
| Segment net income | 223 |
| 36 |
| 28 |
| 38 |
| 325 |
| (22 | ) | — |
| 303 |
|
Successor – Total assets at
September 30, 2017 | $ | 18,711 |
| $ | 2,089 |
| $ | 893 |
| $ | 2,359 |
| $ | 24,052 |
| $ | 11,400 |
| $ | (13,262 | ) | $ | 22,190 |
|
The Registrants, Nicor Gas, and SEGCO make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Southern Power's subsidiaries are not issuers or obligors under its commercial paper program. Commercial paper and short-term bank term loans are included in notes payable in the balance sheets. Details of the Registrants' short-term borrowings were as follows:
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Short-term Debt at September 30, 2022 | | Short-term Debt During the Period(*) |
| | Amount
Outstanding | | Weighted
Average
Interest
Rate | | Average
Amount
Outstanding | | Weighted
Average
Interest
Rate | | Maximum
Amount
Outstanding |
| | (in millions) | | | | (in millions) | | | | (in millions) |
| Southern Company | $ | 1,398 | | | 3.5 | % | | $ | 1,859 | | | 2.5 | % | | $ | 2,809 | |
| Alabama Power | — | | | — | | | — | | | — | | | — | |
| Georgia Power | 814 | | | 3.4 | | | 443 | | | 2.7 | | | 815 | |
| Mississippi Power | — | | | — | | | 3 | | | 2.1 | | | 23 | |
| Southern Power | 208 | | | 3.6 | | | 199 | | | 2.5 | | | 306 | |
| Southern Company Gas: | | | | | | | | | |
| Southern Company Gas Capital | $ | 35 | | | 3.4 | % | | $ | 347 | | | 2.5 | % | | $ | 547 | |
| Nicor Gas | 325 | | | 3.5 | | | 218 | | | 2.7 | | | 330 | |
| Southern Company Gas Total | $ | 360 | | | 3.5 | % | | $ | 565 | | | 2.6 | % | | |
(UNAUDITED)(*)Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2022.
Analysis of Cash Flows
Net cash flows provided from (used for) operating, investing, and financing activities for the nine months ended September 30, 2022 and 2021 are presented in the following table:
| | | | | | | | | | | | | | | | | | | | |
Net cash provided from
(used for): | Southern Company | Alabama Power | Georgia
Power | Mississippi Power | Southern Power | Southern Company Gas |
| (in millions) |
| Nine Months Ended September 30, 2022 | | | | | | |
| Operating activities | $ | 5,017 | | $ | 1,072 | | $ | 1,482 | | $ | 279 | | $ | 827 | | $ | 1,532 | |
| Investing activities | (5,952) | | (1,641) | | (2,653) | | (219) | | (128) | | (1,239) | |
| Financing activities | 1,119 | | 967 | | 1,171 | | (72) | | (603) | | (313) | |
| | | | | | |
| Nine Months Ended September 30, 2021 | | | | | | |
| Operating activities | $ | 5,081 | | $ | 1,419 | | $ | 2,350 | | $ | 159 | | $ | 750 | | $ | 757 | |
| Investing activities | (5,850) | | (1,335) | | (2,572) | | (182) | | (753) | | (966) | |
| Financing activities | 1,802 | | 56 | | 505 | | 130 | | 33 | | 222 | |
Fluctuations in cash flows from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Southern Company
Net cash provided from operating activities decreased $64 million for the nine months ended September 30, 2022 as compared to the corresponding period in 2021 primarily due to decreased fuel cost recovery at the traditional electric operating companies and the timing of customer receivable collections, largely offset by the timing of vendor payments and increased natural gas cost recovery at the natural gas distribution utilities.
The net cash used for investing activities for the nine months ended September 30, 2022 was primarily related to the Subsidiary Registrants' construction programs.
The net cash provided from financing activities for the nine months ended September 30, 2022 was primarily related to net issuances of long-term debt and the issuance of common stock to settle the purchase contracts entered into as part of the 2019 Series A Equity Units (Equity Units) (as discussed in Note (F) to the Condensed Financial Statements under "Equity Units" herein), partially offset by common stock dividend payments.
Alabama Power
Net cash provided from operating activities decreased $347 million for the nine months ended September 30, 2022 as compared to the corresponding period in 2021 primarily due to decreased fuel cost recovery, the timing of customer receivable collections, and fossil fuel stock purchases, partially offset by the timing of vendor payments.
The net cash used for investing activities for the nine months ended September 30, 2022 was primarily related to gross property additions, including approximately $182 million related to the construction of Plant Barry Unit 8 and $171 million related to the acquisition of the Calhoun Generating Station. See Notes (B) and (K) to the Condensed Financial Statements under "Alabama Power" herein for additional information.
The net cash provided from financing activities for the nine months ended September 30, 2022 was primarily related to the net issuance of long-term debt and capital contributions from Southern Company, partially offset by common stock dividend payments.
Georgia Power
Net cash provided from operating activities decreased $868 million for the nine months ended September 30, 2022 as compared to the corresponding period in 2021 primarily due to decreased fuel cost recovery and the timing of customer receivable collections and fossil fuel stock purchases, partially offset by the timing of vendor payments.
The net cash used for investing activities for the nine months ended September 30, 2022 was primarily related to gross property additions, including a total of approximately $820 million related to the construction of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information on construction of Plant Vogtle Units 3 and 4.
The net cash provided from financing activities for the nine months ended September 30, 2022 was primarily related to net issuances of senior notes, a net increase in short-term borrowings, and capital contributions from Southern Company, partially offset by common stock dividend payments.
Mississippi Power
Net cash provided from operating activities increased $120 million for the nine months ended September 30, 2022 as compared to the corresponding period in 2021 primarily due to the timing of vendor payments, partially offset by the timing of customer receivable collections.
The net cash used for investing activities for the nine months ended September 30, 2022 was primarily related to gross property additions.
The net cash used for financing activities for the nine months ended September 30, 2022 was primarily related to common stock dividend payments, partially offset by capital contributions from Southern Company.
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services(*) | Gas Midstream Operations | Total | All Other | Eliminations | Consolidated |
| | (in millions) |
| Successor – Three Months Ended September 30, 2016: | | | | | | |
| Operating revenues | $ | 455 |
| $ | 126 |
| $ | (8 | ) | $ | 13 |
| $ | 586 |
| $ | 2 |
| $ | (45 | ) | $ | 543 |
|
| Segment net income (loss) | 27 |
| (4 | ) | (11 | ) | 14 |
| 26 |
| (22 | ) | — |
| 4 |
|
| Predecessor – January 1, 2016 through June 30, 2016: | | | | | | |
| Operating revenues | $ | 1,575 |
| $ | 435 |
| $ | (32 | ) | $ | 25 |
| $ | 2,003 |
| $ | 4 |
| $ | (102 | ) | $ | 1,905 |
|
| Segment EBIT | 353 |
| 109 |
| (68 | ) | (6 | ) | 388 |
| (60 | ) | — |
| 328 |
|
Successor – Total assets at
December 31, 2016 | $ | 19,453 |
| $ | 2,084 |
| $ | 1,127 |
| $ | 2,211 |
| $ | 24,875 |
| $ | 11,145 |
| $ | (14,167 | ) | $ | 21,853 |
|
| |
(*) | The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table. |
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
|
| | | | | | | | | | | | | | | | | | | |
| | Third Party Gross Revenues | | Intercompany Revenues | | Total Gross Revenues | | Less Gross Gas Costs | | Operating Revenues |
| | (in millions) |
| Successor – Three Months Ended September 30, 2017 | $ | 1,411 |
| | $ | 103 |
| | $ | 1,514 |
| | $ | 1,538 |
| | $ | (24 | ) |
| Successor – Nine Months Ended September 30, 2017 | 4,781 |
| | 362 |
| | 5,143 |
| | 5,048 |
| | 95 |
|
| Successor – Three Months Ended September 30, 2016 | 1,688 |
| | 77 |
| | 1,765 |
| | 1,773 |
| | (8 | ) |
| Predecessor – January 1, 2016 through June 30, 2016 | $ | 2,500 |
| | $ | 143 |
| | $ | 2,643 |
| | $ | 2,675 |
| | $ | (32 | ) |
Net cash provided from operating activities increased $77 million for the nine months ended September 30, 2022 as compared to the corresponding period in 2021 primarily due to an increase in wholesale revenues driven by higher market prices of energy and the timing of vendor payments, partially offset by the timing of customer receivable collections.
The net cash used for investing activities for the nine months ended September 30, 2022 was primarily related to construction payments. See Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information.
The net cash used for financing activities for the nine months ended September 30, 2022 was primarily related to the repayment of senior notes at maturity, common stock dividend payments, net capital distributions to noncontrolling interests, and a decrease in commercial paper borrowings, partially offset by a capital contribution from Southern Company.
Southern Company Gas
Net cash provided from operating activities increased $775 million for the nine months ended September 30, 2022 as compared to the corresponding period in 2021 primarily due to increased natural gas cost recovery and the timing of vendor payments, partially offset by an increase in natural gas for sale as a result of higher prices for natural gas purchases.
The net cash used for investing activities for the nine months ended September 30, 2022 was primarily related to construction of transportation and distribution assets recovered through base rates and infrastructure investment recovered through replacement programs at gas distribution operations.
The net cash used for financing activities for the nine months ended September 30, 2022 was primarily related to common stock dividend payments and net repayments of short-term debt, partially offset by net issuances of long-term debt and capital contributions from Southern Company.
Significant Balance Sheet Changes
Southern Company
Significant balance sheet changes for the nine months ended September 30, 2022 included:
•an increase of $3.2 billion in total stockholders' equity primarily related to net income and the issuance of common stock to settle the purchase contracts entered into as part of the Equity Units (as discussed in Note (F) to the Condensed Financial Statements under "Equity Units" herein), partially offset by common stock dividend payments;
•an increase of $2.4 billion in total property, plant, and equipment primarily related to the Subsidiary Registrants' construction programs, net of the reclassification of $0.6 billion to other regulatory assets and $0.4 billion to regulatory assets associated with AROs upon Georgia Power's retirement of Plant Wansley Units 1 and 2;
•an increase of $1.4 billion in long-term debt (including securities due within one year) related to new issuances;
•an increase of $1.3 billion in deferred under recovered fuel clause revenues due to higher fuel and purchased power costs at Georgia Power;
•an increase of $1.1 billion in accumulated deferred income taxes primarily related to the expected utilization of ITCs in 2022 and the increase in under recovered fuel clause revenues;
•an increase of $0.9 billion in accounts payable primarily related to the timing of vendor payments;
•an increase of $0.7 billion in regulatory assets associated with AROs, net of the reclassification from property, plant, and equipment discussed above, primarily due to a decrease of $0.5 billion in the fair value of the investments held in Alabama Power's and Georgia Power's nuclear decommissioning trusts; and
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
•an increase of $0.6 billion in other deferred credits and liabilities primarily due to changes in the fair value of interest rate and foreign currency derivatives.
See "Financing Activities" herein and Notes (B), (F), (G), (I), and (J) to the Condensed Financial Statements herein for additional information.
Alabama Power
Significant balance sheet changes for the nine months ended September 30, 2022 included:
•an increase of $1.2 billion in common stockholder's equity primarily due to capital contributions from Southern Company, partially offset by dividends paid to Southern Company;
•an increase of $1.1 billion in long-term debt (including securities due within one year) primarily due to net issuances of senior notes;
•an increase of $0.8 billion in total property, plant, and equipment primarily related to the construction of Plant Barry Unit 8, the acquisition of the Calhoun Generating Station, and construction of distribution and transmission facilities;
•an increase of $0.4 billion in cash and cash equivalents, as discussed further under "Analysis of Cash Flows – Alabama Power" herein; and
•an increase of $0.4 billion in regulatory assets associated with AROs primarily due to a decrease of $0.3 billion in the fair value of the investments held in Alabama Power's nuclear decommissioning trust.
See "Financing Activities – Alabama Power" herein and Notes (I) and (K) to the Condensed Financial Statements herein for additional information.
Georgia Power
Significant balance sheet changes for the nine months ended September 30, 2022 included:
•an increase of $1.4 billion in common stockholder's equity primarily due to net income and capital contributions from Southern Company, partially offset by dividends paid to Southern Company;
•an increase of $1.3 billion in deferred under recovered fuel clause revenues due to higher fuel and purchased power costs;
•an increase of $1.1 billion in total property, plant, and equipment primarily related to the construction of generation, transmission, and distribution facilities, including $956 million for Plant Vogtle Units 3 and 4, net of $0.6 billion reclassified to other regulatory assets and $0.4 billion reclassified to regulatory assets associated with AROs due to the retirement of Plant Wansley Units 1 and 2 as approved in Georgia Power's 2022 IRP;
•an increase of $0.9 billion in long-term debt (including securities due within one year) primarily due to net issuances of senior notes;
•an increase of $0.8 billion in notes payable due to an increase in commercial paper and short-term bank debt;
•an increase of $0.6 billion in accumulated deferred income taxes primarily due to the increase in under recovered fuel clause revenues and the expected reduction in federal and state credit carryforward balances in 2022;
•an increase of $0.3 billion in regulatory assets associated with AROs, net of the reclassification from property, plant, and equipment discussed above, primarily due to a decrease in the fair value of the investments held in Georgia Power's nuclear decommissioning trust;
•an increase of $0.3 billion in other accounts payable due to the timing of vendor payments; and
•an increase of $0.3 billion in customer accounts receivable primarily due to higher customer usage and the timing of collections.
See "Financing Activities – Georgia Power" herein and Note (B) under "Georgia Power – Nuclear Construction" and " – Integrated Resource Plans" and Note (I) to the Condensed Financial Statements herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Mississippi Power
Significant balance sheet changes for the nine months ended September 30, 2022 included:
•an increase of $79 million in common stockholder's equity related to net income and capital contributions from Southern Company, partially offset by dividends paid to Southern Company and
•an increase of $66 million in total property, plant, and equipment primarily related to the construction of transmission and distribution facilities.
Southern Power
Significant balance sheet changes for the nine months ended September 30, 2022 included:
•a decrease of $756 million in long-term debt (including securities due within one year) primarily due to the redemption of senior notes;
•a decrease of $289 million in total property, plant, and equipment primarily due to continued depreciation of assets;
•an increase of $282 million in common stockholder's equity primarily due to capital contributions from Southern Company and net income, partially offset by dividends paid to Southern Company and distributions to noncontrolling interests; and
•increases of $194 million in accrued taxes and $100 million in accumulated deferred income tax liabilities primarily related to the expected utilization of ITCs in 2022.
See "Financing Activities – Southern Power" herein and Note (G) to the Condensed Financial Statements herein for additional information.
Southern Company Gas
Significant balance sheet changes for the nine months ended September 30, 2022 included:
•a decrease of $849 million in notes payable due to repayments of short-term debt and commercial paper borrowings;
•an increase of $760 million in total property, plant, and equipment primarily related to the construction of transportation and distribution assets and additional infrastructure investment;
•an increase of $522 million in common stockholder's equity related to net income and capital contributions from Southern Company, partially offset by dividends paid to Southern Company;
•an increase of $459 million in long-term debt (including securities due with one year) due to issuances of senior notes and first mortgage bonds, partially offset by the repayment of medium-term notes and adjustments related to fair value hedges;
•a decrease of $313 million in total accounts receivable primarily relating to decreases of $166 million in customer accounts receivable and $156 million in unbilled revenues as a result of seasonality;
•an increase of $231 million in other accounts payable due to seasonality and the timing of vendor payments; and
•a decrease of $221 million in other regulatory assets, deferred primarily due to a $207 million reduction in natural gas cost under recovery.
See "Financing Activities – Southern Company Gas" herein and Note (B) to the Condensed Financial Statements herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Financing Activities
The following table outlines the Registrants' long-term debt financing activities for the first nine months of 2022:
| | | | | | | | | | | | | | | | | | | | | | |
| Issuances | | | Maturities and Redemptions |
| Company | Senior
Notes | | Other
Long-Term Debt | | | Senior
Notes | Revenue
Bonds | Other Long-Term Debt(a) |
| (in millions) |
| | | | | | | | |
| Alabama Power | $ | 1,700 | | | $ | — | | | | $ | 550 | | $ | — | | $ | 1 | |
| Georgia Power | 1,500 | | | — | | | | 400 | | 53 | | 201 | |
| | | | | | | | |
| Southern Power | — | | | — | | | | 677 | | — | | — | |
| Southern Company Gas | 500 | | | 100 | | | | — | | — | | 46 | |
| Other | — | | | — | | | | — | | — | | 8 | |
Elimination(b) | — | | | — | | | | — | | — | | (4) | |
| Southern Company | $ | 3,700 | | | $ | 100 | | | | $ | 1,627 | | $ | 53 | | $ | 252 | |
(a)Includes reductions in finance lease obligations resulting from cash payments under finance leases and, for Georgia Power, principal amortization payments totaling $66 million for FFB 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.
(b)Represents reductions in affiliate finance lease obligations at Georgia Power, which are eliminated in Southern Company's consolidated financial statements.
Except as otherwise described herein, the Registrants 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 Subsidiary Registrants also used the proceeds for their construction programs.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, the Registrants plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
Southern Company
During the first nine months of 2022, Southern Company issued approximately 3.5 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $78 million.
In May 2022, Southern Company remarketed its Series 2019A and Series 2019B Remarketable Junior Subordinated Notes pursuant to the terms of its 2019 Series A Equity Units (Equity Units). Southern Company did not receive any proceeds from the remarketing, which were used to purchase a portfolio of treasury securities maturing on July 28, 2022. On August 1, 2022, the proceeds from this portfolio were used to settle the purchase contracts entered into as part of the Equity Units and Southern Company issued approximately 25.2 million shares of common stock and received proceeds of $1.725 billion. See Note (F) to the Condensed Financial Statements herein under "Equity Units" for additional information.
In March 2022, Southern Company entered into a $400 million short-term floating rate bank loan bearing interest based on term SOFR, which it repaid in August 2022.
In May 2022, Southern Company borrowed $100 million pursuant to a short-term uncommitted bank credit arrangement bearing interest at a mutually agreed upon rate, which it repaid in August 2022.
Subsequent to September 30, 2022, Southern Company issued $500 million aggregate principal amount of Series 2022A 5.15% Senior Notes due October 6, 2025 and $500 million aggregate principal amount of Series 2022B 5.70% Senior Notes due October 15, 2032.
Alabama Power
In February 2022, Alabama Power redeemed all $550 million aggregate principal amount of its Series 2017A 2.45% Senior Notes due March 30, 2022.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
In March 2022, Alabama Power issued $700 million aggregate principal amount of Series 2022A 3.05% Senior Notes due March 15, 2032.
In June 2022, Alabama Power redeemed the following series of preferred stock: 4.20% Preferred Stock, Par Value $100 Per Share, 4.60% Preferred Stock, Par Value $100 Per Share, 4.92% Preferred Stock, Par Value $100 Per Share, 4.52% Preferred Stock, Par Value $100 Per Share, 4.64% Preferred Stock, Par Value $100 Per Share, and 4.72% Preferred Stock, Par Value $100 Per Share. The redemption price per share for each series of preferred stock equaled the redemption price per share provided in Note 8 to the financial statements under "Outstanding Classes of Capital Stock – Alabama Power" in Item 8 of the Form 10-K, plus accrued and unpaid dividends to the redemption date.
In August 2022, Alabama Power issued $550 million aggregate principal amount of Series 2022B 3.75% Senior Notes due September 1, 2027 and $450 million aggregate principal amount of Series 2022C 3.94% Senior Notes due September 1, 2032. An amount equal to the net proceeds of the Series 2022C Senior Notes will be allocated to finance or refinance, in whole or in part, one or more renewable energy projects and/or expenditures and programs related to enabling opportunities for diverse and small businesses/suppliers.
Subsequent to September 30, 2022, Alabama Power redeemed all of its 5.00% Class A Preferred Stock, Par Value $1 Per Share (Stated Capital $25 Per Share) at a redemption price of $25.00 per share plus accrued and unpaid dividends to the redemption date.
Georgia Power
In January 2022, Georgia Power redeemed all $400 million aggregate principal amount of its Series 2012B 2.85% Senior Notes due May 15, 2022.
In February 2022, Georgia Power borrowed $250 million pursuant to a short-term uncommitted bank credit arrangement, which it repaid in May 2022.
In each of March and April 2022, Georgia Power entered into a $200 million short-term floating rate bank loan bearing interest based on term SOFR.
In May 2022, Georgia Power issued $700 million aggregate principal amount of Series 2022A 4.70% Senior Notes due May 15, 2032 and $800 million aggregate principal amount of Series 2022B 5.125% Senior Notes due May 15, 2052. An amount equal to the net proceeds of the Series 2022B Senior Notes will be allocated to finance or refinance, in whole or in part, one or more renewable energy projects and/or expenditures and programs related to enabling opportunities for diverse and small businesses/suppliers.
In May 2022, Georgia Power repaid its $125 million long-term bank loan that was scheduled to mature in June 2022.
In July 2022, Georgia Power repaid at maturity $53 million aggregate principal amount of Development Authority of Floyd County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Hammond Project), First Series 2010.
Subsequent to September 30, 2022, Georgia Power borrowed $250 million pursuant to a short-term uncommitted bank credit arrangement bearing interest at a mutually agreed upon rate and payable on demand.
Mississippi Power
In June 2022, Mississippi Power repaid $20 million, which was borrowed in March 2022 under its $125 million revolving credit arrangement.
Southern Power
In June 2022, Southern Power repaid at maturity €600 million (approximately $677 million) aggregate principal amount of Series 2016A 1.00% Senior Notes.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Subsequent to September 30, 2022, Southern Power borrowed $100 million pursuant to a short-term uncommitted bank credit arrangement bearing interest at a mutually agreed upon rate and payable on demand.
Southern Company Gas
During the first quarter 2022, Nicor Gas repaid one of its three $100 million short-term floating rate bank loans entered into in March 2021. Nicor Gas also repaid $50 million of one of the other loans and increased the borrowing amount under the other loan to $150 million. In addition, both loans were renewed and amended to extend the maturity dates and change the interest rate provisions so the loans bear interest based on term SOFR.
During the second quarter 2022, Atlanta Gas Light repaid at maturity $46 million aggregate principal amount of medium-term notes with a weighted average interest rate of 8.63%.
In August 2022, Nicor Gas issued in a private placement $100 million aggregate principal amount of 2.21% Series First Mortgage Bonds due August 31, 2032.
In September 2022, Southern Company Gas Capital issued $500 million aggregate principal amount of Series 2022A 5.15% Senior Notes due September 15, 2032, guaranteed by Southern Company Gas.
Credit Rating Risk
At September 30, 2022, the Registrants 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 Registrants to BBB and/or Baa2 or below. These contracts are primarily for physical electricity and natural gas purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, interest rate management, and, for Georgia Power, construction of new generation at Plant Vogtle Units 3 and 4.
The maximum potential collateral requirements under these contracts at September 30, 2022 were as follows:
| | | | | | | | | | | | | | | | | | | | |
| Credit Ratings | Southern Company(*) | Alabama Power | Georgia Power | Mississippi Power | Southern Power(*) | Southern Company Gas |
| (in millions) |
| At BBB and/or Baa2 | $ | 33 | | $ | 1 | | $ | — | | $ | — | | $ | 32 | | $ | — | |
| At BBB- and/or Baa3 | 395 | | 2 | | 61 | | 1 | | 333 | | — | |
| At BB+ and/or Ba1 or below | 2,042 | | 409 | | 907 | | 306 | | 1,205 | | 5 | |
(*)Southern Power has PPAs that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power's credit. The PPAs require credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses resulting from a credit downgrade. Southern Power had $106 million of cash collateral posted related to PPA requirements at September 30, 2022.
The amounts in the previous table for the traditional electric operating companies and Southern Power include certain agreements that could require collateral if either Alabama Power or Georgia Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of the Registrants to access capital markets and would be likely to impact the cost at which they do so.
On February 22, 2022, Fitch downgraded the senior unsecured long-term debt rating of Georgia Power to BBB+ from A- with a stable outlook.
Also on February 22, 2022, Fitch revised the ratings outlook of Southern Company, Alabama Power, Southern Power, Nicor Gas, and SEGCO to negative from stable.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
During the nine months ended September 30, 2022, there were no material changes to Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' disclosures about market risk. For an in-depth discussion of each Registrant's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" 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, as well as Notes (I) and (J) to the Condensed Financial Statements herein.
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.
In July 2022, Southern Company, Alabama Power, Georgia Power, Mississippi Power, Southern Power, and Southern Company Gas implemented a new human resources and payroll application. In August 2022, Southern Company Gas implemented new financial accounting and reporting applications. As a result of these implementations, there were certain changes to processes and procedures, which resulted in changes to Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, Southern Power's, and 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). These changes included automation of certain previously manual controls. These changes in internal controls were not made in response to any identified internal control deficiency.
PART II — OTHER INFORMATION
Item 1. Legal Proceedings.
See the Notes to the Condensed Financial Statements herein for information regarding certain legal and administrative proceedings in which the registrantsRegistrants are involved. The Registrants' threshold for disclosing material environmental legal proceedings involving a governmental authority where potential monetary sanctions are involved is $1 million.
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, thereRegistrants. There have been no material changes to these risk factors from those previously disclosed in the Form 10-K.
The bankruptcy filing of the EPC Contractor is expected to have a material impact on the construction cost and schedule of, as well as the cost recovery for, Plant Vogtle Units 3 and 4 and could have a material impact on the financial statements of Southern Company and Georgia Power, and any inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4, and therefore on the financial statements of Southern Company and Georgia Power.
See "Construction Risk" in Item 1A – Risk Factors of Southern Company and Georgia Power in the Form 10-K for a discussion of risks relating to major construction projects, including Plant Vogtle Units 3 and 4 and see Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein and Note (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information.
On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. To provide for a continuation of work at Plant Vogtle Units 3 and 4, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an interim assessment agreement with the EPC Contractor (Interim Assessment Agreement), which the bankruptcy court approved on March 30, 2017.
The Interim Assessment Agreement provided, among other items, that during the term of the Interim Assessment Agreement Georgia Power was obligated to pay, on behalf of the Vogtle Owners, all costs accrued by the EPC Contractor for subcontractors and vendors for services performed or goods provided. The Interim Assessment Agreement, as amended, expired on July 27, 2017.
Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor, including Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken, and continues to take, actions to remove liens filed by these subcontractors through the posting of surety bonds. Georgia Power estimates the aggregate liability, through September 30, 2017, of the Vogtle Owners for the removal of subcontractor liens and payment of other EPC Contractor pre-petition accounts payable to total approximately $386 million, of which $340 million had been paid or accrued as of September 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $176 million.
The Vogtle 3 and 4 Agreement also provided for liquidated damages upon the EPC Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to an aggregate cap of 10% of the contract price, or approximately $920 million (approximately $420 million based on Georgia Power's ownership interest). Under the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. In January 2016, Westinghouse delivered to the Vogtle Owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020 and require 60 days' written notice to Georgia Power in the event the Westinghouse Letters of Credit will not be renewed.
Under the terms of the Vogtle 3 and 4 Agreement, the EPC Contractor did not have the right to terminate the Vogtle 3 and 4 Agreement for convenience. In the event of an abandonment of work by the EPC Contractor, the maximum liability of the EPC Contractor under the Vogtle 3 and 4 Agreement was 40% of the contract price (approximately $1.7 billion based on Georgia Power's ownership interest).
On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion (Guarantee Obligations), of which Georgia Power's proportionate share is approximately $1.7 billion, and that the Guarantee Obligations exist regardless of whether Plant Vogtle Units 3 and 4 are completed. The Guarantee Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations, which will reduce CWIP, beginning in October 2017 and continuing through January 2021. In the event Toshiba receives certain payments, including sale proceeds, from or related to Westinghouse (or its subsidiaries) or Toshiba Nuclear Energy Holdings (UK) Limited (or its subsidiaries), it will hold a portion of such payments in trust for the Vogtle Owners and promptly pay them as offsets against any remaining Guarantee Obligations. Under the Guarantee Settlement Agreement, the Vogtle Owners will forbear from exercising certain remedies, including drawing on the Westinghouse Letters of Credit, until June 30, 2020, unless certain events of nonpayment, insolvency, or other material breach of the Guarantee Settlement Agreement by Toshiba occur. If such an event occurs, the balance of the Guarantee Obligations will become immediately due and payable, and the Vogtle Owners may exercise any and all rights and remedies, including drawing on the Westinghouse Letters of Credit without restriction. In addition, the Guarantee Settlement Agreement does not restrict the Vogtle Owners from fully drawing on the Westinghouse Letters of Credit in the event they are not renewed or replaced prior to the expiration date. On October 2, 2017, Georgia Power received the first installment of the Guarantee Obligations of $300 million from Toshiba, of which Georgia Power's proportionate share was $137 million. Georgia Power is considering potential options with respect to its right to future payments under the Guarantee Settlement Agreement and its claims against the EPC Contractor in the EPC Contractor's bankruptcy proceeding, including a potential sale of those payment rights and bankruptcy claims. Any such transaction cannot be assured and would be subject to DOE consents and related approvals under the Loan Guarantee Agreement and related agreements.
On August 10, 2017, Toshiba released its financial results for the quarter ended June 30, 2017, which reflected a negative shareholders' equity balance of approximately $4.5 billion as of June 30, 2017. Toshiba previously announced the existence of material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern. As a result, substantial risk regarding the Vogtle Owners' ability to fully collect the Guarantee Obligations continues to exist. An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Southern Company's and Georgia Power's financial statements.
Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into a services agreement (Services Agreement), which was amended and restated on July 20, 2017, for the EPC Contractor to transition construction management of Plant Vogtle Units 3 and 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Services Agreement, (ii) assume and assign to the Vogtle Owners certain project-related contracts, (iii) join the Vogtle Owners as counterparties to certain assumed project-related contracts, and (iv) reject the Vogtle 3 and 4 Agreement. The Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE on July 27, 2017. The Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.
Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement (Bechtel Agreement) with Bechtel Power Corporation (Bechtel), whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4. Facility design and engineering remains the responsibility of the EPC Contractor under the Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its
ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. Pursuant to the Loan Guarantee Agreement, Georgia Power is required to obtain the DOE's approval of the Bechtel Agreement prior to obtaining any further advances under the Loan Guarantee Agreement.
In connection with the recommendation to continue with construction of Plant Vogtle Units 3 and 4 (described below), the Vogtle Owners agreed on a term sheet to amend the existing joint ownership agreements to provide for additional Vogtle Owner approval requirements. Under the term sheet, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including (i) the bankruptcy of Toshiba or a material breach by Toshiba of the Guarantee Settlement Agreement; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth Vogtle Construction Monitoring (VCM) report by more than $1 billion or extension of the project schedule contained in the seventeenth VCM report by more than one year. In addition, under the term sheet, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Services Agreement or agreements with the primary construction contractor or Southern Nuclear.
The term sheet also confirms that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.
In the seventeenth VCM report, Georgia Power recommended that construction of Plant Vogtle Units 3 and 4 be continued, with Southern Nuclear serving as project manager. Georgia Power believes that the most reasonable schedule for completing Plant Vogtle Units 3 and 4 is by November 2021 for Unit 3 and by November 2022 for Unit 4. Georgia Power's recommendation to go forward with completion of Vogtle Units 3 and 4 is based on the following assumptions about the regulatory treatment of this recommendation, if the recommendation to go forward is adopted by the Georgia PSC: (i) that pursuant to Georgia law, the Georgia PSC in the seventeenth VCM proceeding approves the new cost and schedule forecast and finds that it is a reasonable basis for going forward, and that if the Georgia PSC disapproves all or part of the proposed cost and schedule revisions, Georgia Power may cancel Plant Vogtle Units 3 and 4 and recover its actual investment in Plant Vogtle Units 3 and 4; (ii) that the Vogtle Cost Settlement Agreement remains in full force and effect, including Georgia Power retaining the burden of proving all capital costs above $5.680 billion were prudent; (iii) that while the Georgia PSC will make no prudence finding in the seventeenth VCM proceeding, nor will the certified amount be amended consistent with the Vogtle Cost Settlement Agreement, the Georgia PSC recognizes that the certified amount is not a cap, and all costs that are approved and presumed or shown to be prudently incurred will be recoverable by Georgia Power; (iv) that Georgia Power is not a guarantor of the Toshiba Guarantee, and the failure of Toshiba to pay the Toshiba Guarantee, the failure of the U.S. Congress to extend the PTCs for Plant Vogtle Units 3 and 4, or the failure of the DOE to extend the Loan Guarantee Agreement with Georgia Power to reflect the increased capital amounts, will not reduce the amount of investment Georgia Power is otherwise allowed to collect; and (v) that as conditions change and assumptions are either proven or disproven, Georgia Power and the Georgia PSC may reconsider the decision to go forward. The Georgia PSC is expected to make a decision on these matters by February 6, 2018.
Georgia Power's approximate proportionate share of the remaining estimated cost to complete Plant Vogtle Units 3 and 4 is as follows:
|
| | | |
| | (in billions) |
| Estimated cost to complete | $ | 4.2 |
|
| CWIP as of September 30, 2017 | 4.6 |
|
| Guarantee Obligations | (1.7 | ) |
| Estimated capital costs | $ | 7.1 |
|
| Vogtle Cost Settlement Agreement Revised Forecast | (5.7 | ) |
| Estimated net additional capital costs | $ | 1.4 |
|
Georgia Power's estimated financing costs during the construction period total approximately $3.4 billion, of which approximately $1.5 billion had been incurred through September 30, 2017.
Georgia Power's cancellation cost estimate results indicate that its proportionate share of the estimated costs to cancel both units is approximately $350 million. As a result, as of September 30, 2017, total estimated costs subject to evaluation by Georgia Power and the Georgia PSC in the event of a cancellation decision are as follows:
|
| | | |
| | Cancellation Cost Estimate |
| | (in billions) |
| CWIP as of September 30, 2017 | $ | 4.6 |
|
| Financing costs collected, net of tax | 1.5 |
|
Cancellation costs(*) | 0.4 |
|
| Guarantee Obligations | (1.7 | ) |
| Estimated net cancellation cost | $ | 4.8 |
|
| |
(*) | The estimate for cancellation costs includes, but is not limited to, costs to terminate contracts for construction and other services, as well as costs to secure the Plant Vogtle Units 3 and 4 construction site. |
The Guarantee Obligations continue to exist in the event of cancellation. In addition, under Georgia law, prudently incurred costs related to certificated projects cancelled by the Georgia PSC are allowed recovery, including carrying costs, in future retail rates. Georgia Power will continue working with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4, including, but not limited to, the status of construction and rate recovery.
The ultimate outcome of these matters cannot be determined at this time.
Item 6. Exhibits.
The exhibits below with an asterisk (*) preceding the exhibit number are filed herewith. The remaining exhibits have previously been filed with the SEC and are incorporated herein by reference. The exhibits marked with a pound sign (#) are management contracts or compensatory plans or arrangements.
|
| | | | | | | | | | | | | |
| | (3) Articles of Incorporation and By-Laws |
| | | | |
| | Alabama Power |
| | | | |
| | (b)1 | - | |
| | | | |
|
| | | | |
| | (4) Instruments Describing Rights of Security Holders, Including Indentures |
| | | | |
| | GeorgiaSouthern Company |
| | | | |
| | (a)1 | - | |
| | | | |
| | (a)2 | - | |
| | | | |
| | Alabama Power |
| | | | |
| | (c)(b)1 | - | Fifty-EighthSixty-Fourth Supplemental Indenture to Senior Note Indenture dated as of August 8, 2017,12, 2022 providing for the issuance of the Series 2017C 2.00%2022B 3.75% Senior Notes due September 8, 2020. (Designated1, 2027. (Designated in Form 8-K dated August 3, 2017,9, 2022, File No. 1-6468,1-3164, as Exhibit 4.2.4.6(a).) |
| | | | |
| | (c)(b)2 | - | SubordinatedSixty-Fifth Supplemental Indenture to Senior Note Indenture dated as of August 12, 2022 providing for the issuance of the Series 2022C 3.94% Senior Notes due September 1, 2017, between Georgia Power and Wells Fargo Bank, National Association, as Trustee, and 2032. (First Supplemental Indenture thereto dated as of September 21, 2017. (Designated in Form 8-K dated September 18, 2017, File No. 1-6468, as Exhibit 4.3 and in Form 8-K dated September 18, 2017, File No. 1-6468, as Exhibit 4.4.) |
| | | | |
| | (c)3 | - | Amendment No. 3, dated July 27, 2017 to Loan Guarantee Agreement dated February 20, 2014, between Georgia Power and the DOE. (DesignatedDesignated in Form 8-K dated July 27, 2017,August 9, 2022, File No. 1-6468,1-3164, as Exhibit 4.1.4.6(b).) |
| | | | |
| | (10) Material ContractsSouthern Company Gas |
| | | | |
| | Mississippi Power |
| (f)1 | | | | |
| | (e)1 | - | |
| | | | |
| | Southern Company Gas |
| | | | |
| | (g)1 | - | Asset Purchase Agreement, dated as of October 15, 2017, by and between Pivotal Utility Holdings, Inc., as Seller, and South Jersey Industries, Inc., as Buyer. (Designated in Form 8-K dated October 15, 2017,6, 2022, File No. 1-14174, as Exhibit 10.1.4.1.) |
| | | | |
| | (f)2 | - | |
| | | | |
| | (10) Material Contracts |
| | | | |
| | Southern Company |
| | | | |
| # | | (a)1 | - | |
| | | | |
| # | | (a)2 | - | |
| | | | |
| | | | | | | | | | | | | | |
| # | * | (a)3 | - | |
| | | | |
| # | * | (a)4 | - | |
| | | | |
| | Alabama Power |
| | | | |
| # | | (b)1 | - | Amended and Restated Southern Company Change In Control Benefits Protection Plan, effective August 15, 2022. See Exhibit 10(a)1 herein. |
| | | | |
| # | | (b)2 | - | Southern Company Senior Executive Change in Control Severance Plan, Amended and Restated effective August 15, 2022. See Exhibit 10(a)2 herein. |
| | | | |
| # | | (b)3 | - | Southern Company Executive Change In Control Severance Plan, Amended and Restated effective August 15, 2022. See Exhibit 10(a)3 herein. |
| | | | |
| | (24) Power of Attorney and Resolutions |
| | | | |
| | Southern Company |
| | | | |
| | (a) | - | |
| | | | |
| | Alabama Power |
| | | | |
| | (b) | - | |
| | | | |
| | Georgia Power |
| | | | |
| | (c)1 | - | |
| | | | |
| * | (c)2 | - | |
| | | | |
| | Gulf Power |
| (d) | | | | |
| | (d)1 | - | |
| | | | |
| * | (d)2 | - | |
| | | | |
| | Mississippi Power |
| (e)1 | | | | |
| | (e) | - | |
| | | | |
|
| | | | |
| | Southern (e)2 | - | |
| | | | |
| | (f)Southern Company Gas |
| | | | |
| | (f) | - | |
| | | | |
| | Southern Company Gas |
| | | | |
| | (g) | - | |
| | | | |
| | (31) Section 302 Certifications |
| | | | |
| | Southern Company |
| | | | |
| * | (a)1 | - | |
| | | | |
| * | (a)2 | - | |
| | | | |
| | Alabama Power |
| | | | |
| * | (b)1 | - | |
| | | | |
| * | (b)2 | - | |
| | | | |
| | | | | | | | | | | | | | |
| | Georgia Power |
| | | | |
| * | (c)1 | - | |
| | | | |
| * | (c)2 | - | |
| | | | |
| | GulfMississippi Power |
| | | | |
| * | (d)1 | - | |
| | | | |
| * | (d)2 | - | |
| | | | |
| | Mississippi Power |
| | | | |
| * | (e)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) | - | |
| | | | |
| | GulfMississippi Power |
| | | | |
| * | (d) | - | |
| | | | |
| | Mississippi Power |
| | | | |
| * | (e) | - | |
| | | | |
| | Southern Power |
| | | | |
| * | (f)(e) | - | |
| | | | |
| | Southern Company Gas |
| | | | |
| * | (g)(f) | - | |
| | | | |
| | | | | | | | | | | | | | |
| | (101) Interactive Data Files |
| | | | |
| * | INS | - | XBRL Instance Document – The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document. |
| * | SCH | - | XBRL Taxonomy Extension Schema Document |
| * | CAL | - | XBRL Taxonomy Calculation Linkbase Document |
| * | DEF | - | XBRL Definition Linkbase Document |
| * | LAB | - | XBRL Taxonomy Label Linkbase Document |
| * | PRE | - | XBRL Taxonomy Presentation Linkbase Document |
| | | | |
| | (104) Cover Page Interactive Data File |
| * | | | Formatted as inline XBRL with applicable taxonomy extension information contained in Exhibits 101. |
THE SOUTHERN COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
| | | | | | | | | | | |
| | THE SOUTHERN COMPANY |
| | | |
| By | | THE SOUTHERN COMPANY |
| | | |
By | | Thomas A. Fanning |
| | Chairman, President, and Chief Executive Officer |
| | (Principal Executive Officer) |
| | | |
| By | | Art P. BeattieDaniel S. Tucker |
| | Executive Vice President and Chief Financial Officer |
| | (Principal Financial Officer) |
| | | |
| By | | /s/ Melissa K. Caen | |
| | (Melissa K. Caen, Attorney-in-fact) | |
Date: October 31, 201726, 2022
ALABAMA POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
| | | | | | | | | | | |
| | ALABAMA POWER COMPANY |
| | | |
| By | | ALABAMA POWER COMPANY |
| | | |
By | | Mark A. Crosswhite | |
| | Chairman, President, and Chief Executive Officer |
| | (Principal Executive Officer) |
| | | |
| By | | Philip C. Raymond |
| | Executive Vice President, Chief Financial Officer, and Treasurer |
| | (Principal Financial Officer) |
| | | |
| By | | /s/ Melissa K. Caen | |
| | (Melissa K. Caen, Attorney-in-fact) | |
Date: October 31, 201726, 2022
GEORGIA POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
| | | | | | | | | | | |
| | GEORGIA POWER COMPANY |
| | | |
| By | | GEORGIA POWER COMPANYChristopher C. Womack |
| | | |
By | | W. Paul Bowers |
| | Chairman, President, and Chief Executive Officer |
| | (Principal Executive Officer) |
| | | |
| By | | Xia LiuAaron P. Abramovitz |
| | Executive Vice President, Chief Financial Officer, and Treasurer |
| | (Principal Financial Officer) |
| | | |
By | | /s/ Melissa K. Caen | |
| | (Melissa K. Caen, Attorney-in-fact) | |
Date: October 31, 2017
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.
|
| | | |
| By | | GULF POWER COMPANY |
| | | |
By | | S. W. Connally, Jr. |
| | Chairman, President and Chief Executive Officer |
| | (Principal Executive Officer) |
| | | |
By | | Robin B. Boren |
| | Vice President, Chief Financial Officer, and Treasurer |
| | (Principal Financial Officer) |
| | | |
By | | /s/ Melissa K. Caen | |
| | (Melissa K. Caen, Attorney-in-fact) | |
Date: October 31, 201726, 2022
MISSISSIPPI POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
| | | | | | | | | | | |
| | MISSISSIPPI POWER COMPANY |
| | | |
| By | | MISSISSIPPI POWER COMPANY |
| | | |
By | | Anthony L. Wilson |
| | Chairman, President, and Chief Executive Officer |
| | (Principal Executive Officer) |
| | | |
| By | | Moses H. Feagin |
| | Senior Vice President, Chief Financial Officer, and Treasurer |
| | (Principal Financial Officer) |
| | | |
| By | | /s/ Melissa K. Caen | |
| | (Melissa K. Caen, Attorney-in-fact) | |
Date: October 31, 201726, 2022
SOUTHERN POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
| | | | | | | | | | | |
| | SOUTHERN POWER COMPANY |
| | | |
| By | | SOUTHERN POWER COMPANYChristopher Cummiskey |
| | | |
By | | Joseph A. Miller |
| | Chairman President, and Chief Executive Officer |
| | (Principal Executive Officer) |
| | | |
| By | | William C. GranthamGary Kerr |
| | Senior Vice President, Chief Financial Officer, and Treasurer |
| | (Principal Financial Officer) |
| | | |
| By | | /s/ Melissa K. Caen | |
| | (Melissa K. Caen, Attorney-in-fact) | |
Date: October 31, 201726, 2022
SOUTHERN COMPANY GAS
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
| | | | | | | | | | | |
| | SOUTHERN COMPANY GAS |
| | | |
| By | | SOUTHERN COMPANY GASKimberly S. Greene |
| | | |
By | | Andrew W. Evans |
| | Chairman, President, and Chief Executive Officer |
| | (Principal Executive Officer) |
| | | |
| By | | Elizabeth W. ReeseDavid P. Poroch |
| | Executive Vice President, Chief Financial Officer, and Treasurer |
| | (Principal Financial Officer) |
| | | |
| By | | /s/ Melissa K. Caen | |
| | (Melissa K. Caen, Attorney-in-fact) | |
Date: October 31, 201726, 2022