10-Q

    Table of Contents                                Index to Financial Statements

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☑ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2020

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from           to            

Commission
File Number Registrant,
State of Incorporation,
Address and Telephone Number I.R.S. Employer
Identification No.

1-3526 The Southern Company 58-0690070

(A Delaware Corporation)

30 Ivan Allen Jr. Boulevard, N.W.

Atlanta, Georgia 30308

(404) 506-5000

1-3164 Alabama Power Company 63-0004250

(An Alabama Corporation)

600 North 18th Street

Birmingham, Alabama 35203

(205) 257-1000

1-6468 Georgia Power Company 58-0257110

(A Georgia Corporation)

241 Ralph McGill Boulevard, N.E.

Atlanta, Georgia 30308

(404) 506-6526

001-11229 Mississippi Power Company 64-0205820

(A Mississippi Corporation)

2992 West Beach Boulevard

Gulfport, Mississippi 39501

(228) 864-1211

001-37803 Southern Power Company 58-2598670

(A Delaware Corporation)

30 Ivan Allen Jr. Boulevard, N.W.

Atlanta, Georgia 30308

(404) 506-5000

1-14174 Southern Company Gas 58-2210952

(A Georgia Corporation)

Ten Peachtree Place, N.E.

Atlanta, Georgia 30309

(404) 584-4000

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Securities registered pursuant to Section 12(b) of the Act:

Registrant	Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
The Southern Company	Common Stock, par value $5 per share	SO	New York Stock Exchange
			(NYSE)
The Southern Company	Series 2015A 6.25% Junior Subordinated Notes due 2075	SOJA	NYSE
The Southern Company	Series 2016A 5.25% Junior Subordinated Notes due 2076	SOJB	NYSE
The Southern Company	Series 2017B 5.25% Junior Subordinated Notes due 2077	SOJC	NYSE
The Southern Company	2019 Series A Corporate Units	SOLN	NYSE
The Southern Company	Series 2020A 4.95% Junior Subordinated Notes due 2080	SOJD	NYSE
The Southern Company	Series 2020C 4.20% Junior Subordinated Notes due 2060	SOJE	NYSE
Alabama Power Company	5.00% Series Class A Preferred Stock	ALP PR Q	NYSE
Georgia Power Company	Series 2017A 5.00% Junior Subordinated Notes due 2077	GPJA	NYSE
Southern Power Company	Series 2016A 1.000% Senior Notes due 2022	SO/22B	NYSE
Southern Power Company	Series 2016B 1.850% Senior Notes due 2026	SO/26A	NYSE

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes þ No ¨

Indicate by check mark whether the registrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit such files). 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.

Registrant	Large Accelerated Filer	Accelerated Filer	Non-accelerated Filer	Smaller Reporting Company	Emerging Growth Company
The Southern Company	X
Alabama Power Company			X
Georgia Power Company			X
Mississippi Power Company			X
Southern Power Company			X
Southern Company Gas			X

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No þ (Response applicable to all registrants.)

Registrant	Description of Common Stock	Shares Outstanding at September 30, 2020
The Southern Company	Par Value $5 Per Share	1,056,241,993
Alabama Power Company	Par Value $40 Per Share	30,537,500
Georgia Power Company	Without Par Value	9,261,500
Mississippi Power Company	Without Par Value	1,121,000
Southern Power Company	Par Value $0.01 Per Share	1,000
Southern Company Gas	Par Value $0.01 Per Share	100

This combined Form 10-Q is separately filed by The Southern Company, Alabama Power Company, Georgia Power Company, 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.

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TABLE OF CONTENTS

		Page
	Definitions	4
	Cautionary Statement Regarding Forward-Looking Information	8
	PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)	10
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	104
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	181
Item 4.	Controls and Procedures	181
	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	182
Item 1A.	Risk Factors	182
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.	Exhibits	183
	Signatures	186

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DEFINITIONS

Term	Meaning
2013 ARP	Alternate Rate Plan approved by the Georgia PSC in 2013 for Georgia Power for the years 2014 through 2016 and subsequently extended through 2019
2019 ARP	Alternate Rate Plan approved by the Georgia PSC in 2019 for Georgia Power for the years 2020 through 2022
AFUDC	Allowance for funds used during construction
Alabama Power	Alabama Power Company
Amended and 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
ARO	Asset retirement obligation
ASU	Accounting Standards Update
Atlanta Gas Light	Atlanta Gas Light Company, a wholly-owned subsidiary of Southern Company Gas
Atlantic Coast Pipeline	Atlantic Coast Pipeline, LLC, a joint venture to construct and operate a natural gas pipeline in which Southern Company Gas held a 5% interest through March 24, 2020
Autauga Combined Cycle Acquisition	Alabama Power's August 31, 2020 acquisition of the Central Alabama Generation Station, an approximately 885-MW combined cycle generation facility in Autauga County, Alabama
Bechtel	Bechtel Power Corporation, the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4
Bechtel Agreement	The October 23, 2017 construction completion agreement between the Vogtle Owners and Bechtel
CCR	Coal combustion residuals
CCR Rule	Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in 2015
Chattanooga Gas	Chattanooga Gas Company, a wholly-owned subsidiary of Southern Company Gas
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
ECO Plan	Mississippi Power's environmental compliance overview plan
Eligible Project Costs	Certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the loan guarantee program established under Title XVII of the Energy Policy Act of 2005
EPA	U.S. Environmental Protection Agency
EPC Contractor	Westinghouse and its affiliate, WECTEC Global Project Services Inc.; the former engineering, procurement, and construction contractor for Plant Vogtle Units 3 and 4
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FFB	Federal Financing Bank
FFB Credit Facilities	Note purchase agreements among the DOE, Georgia Power, and the FFB and related promissory notes which provide for two multi-advance term loan facilities
Fitch	Fitch Ratings, Inc.

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DEFINITIONS

(continued)

Term	Meaning
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, 2019, as applicable
GAAP	U.S. generally accepted accounting principles
Georgia Power	Georgia Power Company
GRAM	Atlanta Gas Light's Georgia Rate Adjustment Mechanism
Guarantee Settlement Agreement	The June 9, 2017 settlement agreement between the Vogtle Owners and Toshiba related to certain payment obligations of the EPC Contractor guaranteed by Toshiba
Gulf Power	Gulf Power Company, until January 1, 2019 a wholly-owned subsidiary of Southern Company
Heating Degree Days	A measure of weather, calculated when the average daily temperatures are less than 65 degrees Fahrenheit
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
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
Marketers	Marketers selling retail natural gas in Georgia and certificated by the Georgia PSC
MEAG Power	Municipal Electric Authority of Georgia
Mississippi Power	Mississippi Power Company
mmBtu	Million British thermal units
Moody's	Moody's Investors Service, Inc.
MRA	Municipal and Rural Associations
MW	Megawatt
natural gas distribution utilities	Southern Company Gas' natural gas distribution utilities (Nicor Gas, Atlanta Gas Light, Virginia Natural Gas, and Chattanooga Gas)
NCCR	Georgia Power's Nuclear Construction Cost Recovery
NDR	Alabama Power's Natural Disaster Reserve
NextEra Energy	NextEra Energy, Inc.
Nicor Gas	Northern Illinois Gas Company, a wholly-owned subsidiary of Southern Company Gas
NRC	U.S. Nuclear Regulatory Commission
NYMEX	New York Mercantile Exchange, Inc.
OCI	Other comprehensive income
Part A CCR Rule	Holistic Approach to Closure Part A final rule published by the EPA on August 28, 2020
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
Pivotal LNG	Pivotal LNG, Inc., through March 24, 2020 a wholly-owned subsidiary of Southern Company Gas

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DEFINITIONS

(continued)

Term	Meaning
PowerSecure	PowerSecure, Inc., a wholly-owned subsidiary of Southern Company
PPA	Power purchase agreements, as well as, for Southern Power, contracts for differences that provide the owner of a renewable facility a certain fixed price for the electricity sold to the grid
PSC	Public Service Commission
PTC	Production tax credit
Rate CNP	Alabama Power's Rate Certificated New Plant, consisting of Rate CNP New Plant, Rate CNP Compliance, 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
Registrants	Southern Company, Alabama Power, Georgia 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.
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
SNG	Southern Natural Gas Company, L.L.C., a pipeline system in which Southern Company Gas has a 50% ownership interest
Southern Company	The Southern Company
Southern Company Gas	Southern Company Gas and its subsidiaries
Southern Company Gas Capital	Southern Company Gas Capital Corporation, a 100%-owned subsidiary of Southern Company Gas
Southern Company power pool	The operating arrangement whereby the integrated generating resources of the traditional electric operating companies and Southern Power (excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations
Southern Company system	Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas, Southern Electric Generating Company, Southern Nuclear, SCS, Southern Communications Services, Inc., PowerSecure, and other subsidiaries
Southern Holdings	Southern Company Holdings, Inc., a wholly-owned subsidiary of Southern Company
Southern Nuclear	Southern Nuclear Operating Company, Inc., a wholly-owned subsidiary of Southern Company
Southern Power	Southern Power Company and its subsidiaries
SouthStar	SouthStar Energy Services, LLC, a wholly-owned subsidiary of Southern Company Gas
SP Solar	SP Solar Holdings I, LP, a limited partnership indirectly owning substantially all of Southern Power's solar facilities, in which Southern Power has a 67% ownership interest
SP Wind	SP Wind Holdings II, LLC, a holding company owning a portfolio of eight operating wind facilities, in which Southern Power is the controlling partner in a tax equity arrangement
Subsidiary Registrants	Alabama Power, Georgia Power, Mississippi Power, Southern Power, and Southern Company Gas
Tax Reform	The impact of the Tax Cuts and Jobs Act, which became effective on January 1, 2018
Toshiba	Toshiba Corporation, the parent company of Westinghouse
traditional electric operating companies	Alabama Power, Georgia Power, and Mississippi Power
Triton	Triton Container Investments, LLC, an investment of Southern Company Gas through May 29, 2019
VCM	Vogtle Construction Monitoring
VIE	Variable interest entity
Virginia Commission	Virginia State Corporation Commission
Virginia Natural Gas	Virginia Natural Gas, Inc., a wholly-owned subsidiary of Southern Company Gas

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DEFINITIONS

(continued)

Term	Meaning
Vogtle 3 and 4 Agreement	Agreement entered into with the EPC Contractor in 2008 by Georgia Power, acting for itself and as agent for the Vogtle Owners, and rejected in bankruptcy in July 2017, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4
Vogtle Owners	Georgia Power, Oglethorpe Power Corporation, MEAG Power, and Dalton
Vogtle Services Agreement	The June 2017 services agreement between the Vogtle Owners and the EPC Contractor, as amended and restated in July 2017, for the EPC Contractor to transition construction management of Plant Vogtle Units 3 and 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear
WACOG	Weighted average cost of gas
Westinghouse	Westinghouse Electric Company LLC
Xcel	Xcel Energy Inc.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q contains forward-looking statements. Forward-looking statements include, among other things, the potential and expected effects of the COVID-19 pandemic, statements concerning regulated rates, the strategic goals for the business, customer and sales growth, economic conditions, fuel and environmental cost recovery and other rate actions, projected equity ratios, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, financing activities, completion dates and costs of construction projects, matters related to the abandonment of the Kemper IGCC, completion of announced acquisitions, filings with state and federal regulatory authorities, and estimated construction plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "would," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

•the impact of recent and future federal and state regulatory changes, including tax, environmental, and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;

•the potential effects of the continued COVID-19 pandemic, including, but not limited to, those described in Item 1A "Risk Factors" herein;

•the extent and timing of costs and legal requirements related to CCR;

•current and future litigation or regulatory investigations, proceedings, or inquiries, including litigation and other disputes related to the Kemper County energy facility;

•the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company's subsidiaries operate, including from the development and deployment of alternative energy sources;

•variations in demand for electricity and natural gas;

•available sources and costs of natural gas and other fuels;

•the ability to complete necessary or desirable pipeline expansion or infrastructure projects, limits on pipeline capacity, and operational interruptions to natural gas distribution and transmission activities;

•transmission constraints;

•effects of inflation;

•the ability to control costs and avoid cost and schedule overruns during the development, construction, and operation of facilities or other projects, including Plant Vogtle Units 3 and 4, which includes components based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale, and including changes in labor costs, availability, and productivity; challenges with management of contractors or vendors; subcontractor performance; adverse weather conditions; shortages, delays, increased costs, or inconsistent quality of equipment, materials, and labor; contractor or supplier delay; delays due to judicial or regulatory action; nonperformance under construction, operating, or other agreements; operational readiness, including specialized operator training and required site safety programs; engineering or design problems; design and other licensing-based compliance matters, including, for nuclear units, the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel; challenges with start-up activities, including major equipment failure, or system integration; and/or operational performance;

•the ability to overcome or mitigate the current challenges at Plant Vogtle Units 3 and 4, including, but not limited to, those related to COVID-19, as described in Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" in Item 1 herein, that could further impact the cost and schedule for the project;

•legal proceedings and regulatory approvals and actions related to construction projects, such as Plant Vogtle Units 3 and 4 and pipeline projects, including PSC approvals and FERC and NRC actions;

•under certain specified circumstances, a decision by holders of more than 10% of the ownership interests of Plant Vogtle Units 3 and 4 not to proceed with construction and the ability of other Vogtle Owners to tender a portion of their ownership interests to Georgia Power following certain construction cost increases;

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

(continued)

•in the event Georgia Power becomes obligated to provide funding to MEAG Power with respect to the portion of MEAG Power's ownership interest in Plant Vogtle Units 3 and 4 involving JEA, any inability of Georgia Power to receive repayment of such funding;

•the ability to construct facilities in accordance with the requirements of permits and licenses (including satisfaction of NRC requirements), to satisfy any environmental performance standards and the requirements of tax credits and other incentives, and to integrate facilities into the Southern Company system upon completion of construction;

•investment performance of the employee and retiree benefit plans and nuclear decommissioning trust funds;

•advances in technology;

•performance of counterparties under ongoing renewable energy partnerships and development agreements;

•state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to ROE, equity ratios, additional generating capacity, and fuel and other cost recovery mechanisms;

•the ability to successfully operate the electric utilities' generating, transmission, and distribution facilities and Southern Company Gas' natural gas distribution and storage facilities and the successful performance of necessary corporate functions;

•the inherent risks involved in operating and constructing nuclear generating facilities;

•the inherent risks involved in transporting and storing natural gas;

•the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities;

•internal restructuring or other restructuring options that may be pursued;

•potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries;

•the ability of counterparties of Southern Company and its subsidiaries to make payments as and when due and to perform as required;

•the ability to obtain new short- and long-term contracts with wholesale customers;

•the direct or indirect effect on the Southern Company system's business resulting from cyber intrusion or physical attack and the threat of physical attacks;

•interest rate fluctuations and financial market conditions and the results of financing efforts;

•access to capital markets and other financing sources;

•changes in Southern Company's and any of its subsidiaries' credit ratings;

•changes in the method of determining LIBOR or the replacement of LIBOR with an alternative reference rate;

•the ability of Southern Company's electric utilities to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;

•catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events, or other similar occurrences;

•the direct or indirect effects on the Southern Company system's business resulting from incidents affecting the U.S. electric grid, natural gas pipeline infrastructure, or operation of generating or storage resources;

•impairments of goodwill or long-lived assets;

•the effect of accounting pronouncements issued periodically by standard-setting bodies; and

•other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Registrants from time to time with the SEC.

The Registrants expressly disclaim any obligation to update any forward-looking statements.

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PART I

Item 1. Financial Statements (Unaudited).

	Page
The Southern Company and Subsidiary Companies:
Condensed Consolidated Statements of Income	11
Condensed Consolidated Statements of Comprehensive Income	12
Condensed Consolidated Statements of Cash Flows	13
Condensed Consolidated Balance Sheets	14
Condensed Consolidated Statements of Stockholders' Equity	16
Alabama Power Company:
Condensed Statements of Income	18
Condensed Statements of Comprehensive Income	18
Condensed Statements of Cash Flows	19
Condensed Balance Sheets	20
Condensed Statements of Common Stockholder's Equity	22
Georgia Power Company:
Condensed Statements of Income	23
Condensed Statements of Comprehensive Income	23
Condensed Statements of Cash Flows	24
Condensed Balance Sheets	25
Condensed Statements of Common Stockholder's Equity	27
Mississippi Power Company:
Condensed Statements of Income	28
Condensed Statements of Comprehensive Income	28
Condensed Statements of Cash Flows	29
Condensed Balance Sheets	30
Condensed Statements of Common Stockholder's Equity	32
Southern Power Company and Subsidiary Companies:
Condensed Consolidated Statements of Income	33
Condensed Consolidated Statements of Comprehensive Income	33
Condensed Consolidated Statements of Cash Flows	34
Condensed Consolidated Balance Sheets	35
Condensed Consolidated Statements of Stockholders' Equity	37
Southern Company Gas and Subsidiary Companies:
Condensed Consolidated Statements of Income	39
Condensed Consolidated Statements of Comprehensive Income	39
Condensed Consolidated Statements of Cash Flows	40
Condensed Consolidated Balance Sheets	41
Condensed Consolidated Statements of Stockholder's Equity	43
Combined Notes to the Condensed Financial Statements	44

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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,
	2020		2019		2020		2019
	(in millions)				(in millions)
Operating Revenues:
Retail electric revenues	$	4,243	$	4,512	$	10,503	$	11,136
Wholesale electric revenues	584		625		1,473		1,667
Other electric revenues	164		163		484		492
Natural gas revenues (includes alternative revenue programs of    $(1), $—, $6, and $—, respectively)	477		498		2,362		2,661
Other revenues	152		197		436		549
Total operating revenues	5,620		5,995		15,258		16,505
Operating Expenses:
Fuel	933		1,072		2,190		2,836
Purchased power	230		254		611		625
Cost of natural gas	71		79		654		956
Cost of other sales	72		114		201		316
Other operations and maintenance	1,286		1,296		3,785		3,898
Depreciation and amortization	889		760		2,619		2,267
Taxes other than income taxes	304		303		932		931
Estimated loss on Plant Vogtle Units 3 and 4	—		—		149		—
Impairment charges	—		110		—		142
(Gain) loss on dispositions, net	—		(6)		(39)		(2,512)
Total operating expenses	3,785		3,982		11,102		9,459
Operating Income	1,835		2,013		4,156		7,046
Other Income and (Expense):
Allowance for equity funds used during construction	38		33		106		96
Earnings from equity method investments	33		39		105		120
Interest expense, net of amounts capitalized	(443)		(434)		(1,343)		(1,294)
Impairment of leveraged lease	—		—		(154)		—
Other income (expense), net	113		61		319		239
Total other income and (expense)	(259)		(301)		(967)		(839)
Earnings Before Income Taxes	1,576		1,712		3,189		6,207
Income taxes	293		367		443		1,872
Consolidated Net Income	1,283		1,345		2,746		4,335
Dividends on preferred stock of subsidiaries	4		4		11		11
Net income attributable to noncontrolling interests	28		25		3		26
Consolidated Net Income Attributable to Southern Company	$	1,251	$	1,316	$	2,732	$	4,298
Common Stock Data:
Earnings per share -
Basic	$	1.18	$	1.26	$	2.58	$	4.12
Diluted	$	1.18	$	1.25	$	2.57	$	4.09
Average number of shares of common stock outstanding (in millions)
Basic	1,058		1,048		1,058		1,043
Diluted	1,064		1,057		1,064		1,051

The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.

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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,
	2020		2019		2020		2019
	(in millions)				(in millions)
Consolidated Net Income	$	1,283	$	1,345	$	2,746	$	4,335
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of    $17, $(33), $(9), and $(54), respectively	49		(92)		(26)		(152)
Reclassification adjustment for amounts included in net income,    net of tax of $(11), $17, $(1), and $25, respectively	(32)		50		(3)		74
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income,    net of tax of $1, $—, $3, and $—, respectively	3		1		6		2
Total other comprehensive income (loss)	20		(41)		(23)		(76)
Comprehensive Income	1,303		1,304		2,723		4,259
Dividends on preferred stock of subsidiaries	4		4		11		11
Comprehensive income attributable to noncontrolling interests	28		25		3		26
Consolidated Comprehensive Income Attributable to Southern Company	$	1,271	$	1,275	$	2,709	$	4,222

The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2020		2019
	(in millions)
Operating Activities:
Consolidated net income	$	2,746	$	4,335
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	2,903		2,514
Deferred income taxes	(196)		253
Utilization of federal investment tax credits	319		722
Allowance for equity funds used during construction	(106)		(96)
Pension, postretirement, and other employee benefits	(190)		(114)
Settlement of asset retirement obligations	(315)		(225)
Stock based compensation expense	99		87
Estimated loss on Plant Vogtle Units 3 and 4	149		—
Storm damage reserve accruals	171		34
Impairment charges	154		142
(Gain) loss on dispositions, net	(36)		(2,517)
Other, net	93		(20)
Changes in certain current assets and liabilities —
-Receivables	125		588
-Prepayments	(39)		61
-Materials and supplies	(141)		(31)
-Other current assets	(80)		(31)
-Accounts payable	(428)		(1,155)
-Accrued taxes	289		679
-Accrued compensation	(183)		(191)
-Retail fuel cost over recovery	158		31
-Customer refunds	(226)		(30)
-Other current liabilities	(46)		(155)
Net cash provided from operating activities	5,220		4,881
Investing Activities:
Property additions	(5,365)		(5,417)
Nuclear decommissioning trust fund purchases	(714)		(683)
Nuclear decommissioning trust fund sales	708		678
Proceeds from dispositions and asset sales	987		5,036
Cost of removal, net of salvage	(233)		(290)
Change in construction payables, net	(40)		(132)
Investment in unconsolidated subsidiaries	(79)		(141)
Payments pursuant to LTSAs	(139)		(139)
Other investing activities	(17)		15
Net cash used for investing activities	(4,892)		(1,073)
Financing Activities:
Decrease in notes payable, net	(1,534)		(773)
Proceeds —
Long-term debt	7,543		4,737
Common stock	63		623
Short-term borrowings	615		250
Redemptions and repurchases —
Long-term debt	(2,472)		(3,216)
Short-term borrowings	(840)		(1,850)
Distributions to noncontrolling interests	(164)		(125)
Capital contributions from noncontrolling interests	173		11
Purchase of membership interests from noncontrolling interests	(60)		—
Payment of common stock dividends	(2,008)		(1,919)
Other financing activities	(239)		(130)
Net cash provided from (used for) financing activities	1,077		(2,392)
Net Change in Cash, Cash Equivalents, and Restricted Cash	1,405		1,416
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	1,978		1,519
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	3,383	$	2,935
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $61 and $55 capitalized for 2020 and 2019, respectively)	$	1,346	$	1,318
Income taxes, net	66		265
Noncash transactions —
Accrued property additions at end of period	917		953
Right-of-use assets obtained under operating leases	158		76
Right-of-use assets obtained under finance leases	8		31

The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2020		At December 31, 2019
	(in millions)
Current Assets:
Cash and cash equivalents	$	3,379	$	1,975
Receivables —
Customer accounts receivable	1,778		1,614
Energy marketing receivables	328		428
Unbilled revenues	503		599
Other accounts and notes receivable	506		817
Accumulated provision for uncollectible accounts	(99)		(49)
Materials and supplies	1,522		1,388
Fossil fuel for generation	506		521
Natural gas for sale	448		479
Prepaid expenses	299		314
Assets from risk management activities, net of collateral	135		183
Regulatory assets – asset retirement obligations	246		287
Other regulatory assets	813		885
Assets held for sale	—		188
Other current assets	210		188
Total current assets	10,574		9,817
Property, Plant, and Equipment:
In service	108,831		105,114
Less: Accumulated depreciation	32,099		30,765
Plant in service, net of depreciation	76,732		74,349
Nuclear fuel, at amortized cost	804		851
Construction work in progress	8,861		7,880
Total property, plant, and equipment	86,397		83,080
Other Property and Investments:
Goodwill	5,280		5,280
Equity investments in unconsolidated subsidiaries	1,358		1,303
Other intangible assets, net of amortization of $316 and $280    at September 30, 2020 and December 31, 2019, respectively	499		536
Nuclear decommissioning trusts, at fair value	2,109		2,036
Leveraged leases	653		788
Miscellaneous property and investments	403		391
Total other property and investments	10,302		10,334
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	1,791		1,800
Deferred charges related to income taxes	799		798
Unamortized loss on reacquired debt	285		300
Regulatory assets – asset retirement obligations, deferred	4,984		4,094
Other regulatory assets, deferred	6,502		6,805
Assets held for sale, deferred	—		601
Other deferred charges and assets	1,524		1,071
Total deferred charges and other assets	15,885		15,469
Total Assets	$	123,158	$	118,700

The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholders' Equity	At September 30, 2020		At December 31, 2019
	(in millions)
Current Liabilities:
Securities due within one year	$	4,378	$	2,989
Notes payable	171		2,055
Energy marketing trade payables	361		442
Accounts payable	1,924		2,115
Customer deposits	496		496
Accrued taxes —
Accrued income taxes	75		—
Other accrued taxes	742		659
Accrued interest	421		474
Accrued compensation	843		992
Asset retirement obligations	640		504
Other regulatory liabilities	616		756
Liabilities held for sale	—		5
Operating lease obligations	235		229
Other current liabilities	848		830
Total current liabilities	11,750		12,546
Long-term Debt	45,581		41,798
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	8,342		7,888
Deferred credits related to income taxes	5,763		6,078
Accumulated deferred ITCs	2,251		2,291
Employee benefit obligations	1,753		1,814
Operating lease obligations, deferred	1,570		1,615
Asset retirement obligations, deferred	10,020		9,282
Accrued environmental remediation	220		234
Other cost of removal obligations	2,231		2,239
Other regulatory liabilities, deferred	315		256
Other deferred credits and liabilities	571		609
Total deferred credits and other liabilities	33,036		32,306
Total Liabilities	90,367		86,650
Redeemable Preferred Stock of Subsidiaries	291		291
Total Stockholders' Equity (See accompanying statements)	32,500		31,759
Total Liabilities and Stockholders' Equity	$	123,158	$	118,700

The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED)

	Southern Company Common Stockholders' Equity
	Number of Common Shares		Common Stock								Accumulated Other Comprehensive Income (Loss)
	Issued	Treasury	Par Value		Paid-In Capital		Treasury		Retained Earnings				Noncontrolling Interests		Total
	(in millions)
Balance at December 31, 2018	1,035	(1)	$	5,164	$	11,094	$	(38)	$	8,706	$	(203)	$	4,316	$	29,039
Consolidated net income (loss)	—	—	—		—		—		2,084		—		(29)		2,055
Stock issued	6	—	28		196		—		—		—		—		224
Stock-based compensation	—	—	—		24		—		—		—		—		24
Cash dividends of $0.60 per share	—	—	—		—		—		(623)		—		—		(623)
Contributions from noncontrolling interests	—	—	—		—		—		—		—		3		3
Distributions to noncontrolling interests	—	—	—		—		—		—		—		(41)		(41)
Other	—	—	—		7		(2)		—		—		1		6
Balance at March 31, 2019	1,041	(1)	5,192		11,321		(40)		10,167		(203)		4,250		30,687
Consolidated net income	—	—	—		—		—		899		—		29		928
Other comprehensive income (loss)	—	—	—		—		—		—		(35)		—		(35)
Stock issued	5	—	25		203		—		—		—		—		228
Stock-based compensation	—	—	—		11		—		—		—		—		11
Cash dividends of $0.62 per share	—	—	—		—		—		(646)		—		—		(646)
Contributions from noncontrolling interests	—	—	—		—		—		—		—		2		2
Distributions to noncontrolling interests	—	—	—		—		—		—		—		(47)		(47)
Other	—	—	—		5		(1)		—		—		(1)		3
Balance at June 30, 2019	1,046	(1)	5,217		11,540		(41)		10,420		(238)		4,233		31,131
Consolidated net income	—	—	—		—		—		1,316		—		25		1,341
Other comprehensive income (loss)	—	—	—		—		—		—		(41)		—		(41)
Issuance of equity units	—	—	—		(198)		—		—		—		—		(198)
Stock issued	4	—	17		154		—		—		—		—		171
Stock-based compensation	—	—	—		12		—		—		—		—		12
Cash dividends of $0.62 per share	—	—	—		—		—		(649)		—		—		(649)
Contributions from noncontrolling interests	—	—	—		—		—		—		—		63		63
Distributions to noncontrolling interests	—	—	—		—		—		—		—		(43)		(43)
Other	—	—	—		4		—		—		—		—		4
Balance at September 30, 2019	1,050	(1)	$	5,234	$	11,512	$	(41)	$	11,087	$	(279)	$	4,278	$	31,791

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED)

	Southern Company Common Stockholders' Equity
	Number of Common Shares		Common Stock								Accumulated Other Comprehensive Income (Loss)
	Issued	Treasury	Par Value		Paid-In Capital		Treasury		Retained Earnings				Noncontrolling Interests		Total
	(in millions)
Balance at December 31, 2019	1,054	(1)	$	5,257	$	11,734	$	(42)	$	10,877	$	(321)	$	4,254	$	31,759
Consolidated net income (loss)	—	—	—		—		—		868		—		(31)		837
Other comprehensive income (loss)	—	—	—		—		—		—		(47)		—		(47)
Stock issued	3	—	9		43		—		—		—		—		52
Stock-based compensation	—	—	—		5		—		—		—		—		5
Cash dividends of $0.62 per share	—	—	—		—		—		(655)		—		—		(655)
Contributions from noncontrolling interests	—	—	—		—		—		—		—		16		16
Distributions to noncontrolling interests	—	—	—		—		—		—		—		(48)		(48)
Other	—	—	—		—		(2)		(2)		1		—		(3)
Balance at March 31, 2020	1,057	(1)	5,266		11,782		(44)		11,088		(367)		4,191		31,916
Consolidated net income	—	—	—		—		—		612		—		5		617
Other comprehensive income	—	—	—		—		—		—		4		—		4
Stock issued	—	—	—		7		—		—		—		—		7
Stock-based compensation	—	—	—		11		—		—		—		—		11
Cash dividends of $0.64 per share	—	—	—		—		—		(677)		—		—		(677)
Contributions from noncontrolling interests	—	—	—		—		—		—		—		165		165
Distributions to noncontrolling interests	—	—	—		—		—		—		—		(70)		(70)
Other	—	—	—		(13)		—		1		—		—		(12)
Balance at June 30, 2020	1,057	(1)	5,266		11,787		(44)		11,024		(363)		4,291		31,961
Consolidated net income	—	—	—		—		—		1,251		—		28		1,279
Other comprehensive income	—	—	—		—		—		—		20		—		20
Stock issued	—	—	1		3		—		—		—		—		4
Stock-based compensation	—	—	—		15		—		—		—		—		15
Cash dividends of $0.64 per share	—	—	—		—		—		(676)		—		—		(676)
Contributions from noncontrolling interests	—	—	—		—		—		—		—		2		2
Distributions to noncontrolling interests	—	—	—		—		—		—		—		(51)		(51)
Purchase of membership interests from noncontrolling interests	—	—	—		5		—		—		—		(60)		(55)
Other	—	—	—		—		—		1		(1)		1		1
Balance at September 30, 2020	1,057	(1)	$	5,267	$	11,810	$	(44)	$	11,600	$	(344)	$	4,211	$	32,500

The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.

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ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)				(in millions)
Operating Revenues:
Retail revenues	$	1,575	$	1,694	$	4,003	$	4,286
Wholesale revenues, non-affiliates	73		71		184		194
Wholesale revenues, affiliates	11		2		36		66
Other revenues	70		74		222		216
Total operating revenues	1,729		1,841		4,445		4,762
Operating Expenses:
Fuel	306		310		721		864
Purchased power, non-affiliates	64		77		153		160
Purchased power, affiliates	44		73		93		164
Other operations and maintenance	387		409		1,078		1,221
Depreciation and amortization	205		195		606		593
Taxes other than income taxes	103		101		311		301
Total operating expenses	1,109		1,165		2,962		3,303
Operating Income	620		676		1,483		1,459
Other Income and (Expense):
Allowance for equity funds used during construction	12		13		34		41
Interest expense, net of amounts capitalized	(84)		(83)		(255)		(248)
Other income (expense), net	30		11		78		36
Total other income and (expense)	(42)		(59)		(143)		(171)
Earnings Before Income Taxes	578		617		1,340		1,288
Income taxes	130		144		307		295
Net Income	448		473		1,033		993
Dividends on Preferred Stock	4		4		11		11
Net Income After Dividends on Preferred Stock	$	444	$	469	$	1,022	$	982

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)				(in millions)
Net Income	$	448	$	473	$	1,033	$	993
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income,    net of tax of $—, $—, $1, and $1, respectively	1		1		3		3
Total other comprehensive income (loss)	1		1		3		3
Comprehensive Income	$	449	$	474	$	1,036	$	996

The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

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ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2020		2019
	(in millions)
Operating Activities:
Net income	$	1,033	$	993
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	731		756
Deferred income taxes	71		148
Allowance for equity funds used during construction	(34)		(41)
Pension, postretirement, and other employee benefits	(71)		(30)
Settlement of asset retirement obligations	(157)		(76)
Other, net	69		18
Changes in certain current assets and liabilities —
-Receivables	(130)		(115)
-Prepayments	(32)		(30)
-Materials and supplies	(55)		11
-Other current assets	(32)		(30)
-Accounts payable	(248)		(267)
-Accrued taxes	142		149
-Accrued compensation	(55)		(55)
-Retail fuel cost over recovery	74		21
-Customer refunds	(64)		(28)
-Other current liabilities	(13)		47
Net cash provided from operating activities	1,229		1,471
Investing Activities:
Property additions	(1,460)		(1,239)
Nuclear decommissioning trust fund purchases	(213)		(201)
Nuclear decommissioning trust fund sales	213		201
Cost of removal, net of salvage	(68)		(79)
Change in construction payables	(46)		(99)
Other investing activities	(17)		(22)
Net cash used for investing activities	(1,591)		(1,439)
Financing Activities:
Proceeds —
Senior notes	600		600
Capital contributions from parent company	649		1,252
Pollution control revenue bonds	87		—
Redemptions —
Pollution control revenue bonds	(87)		—
Senior notes	—		(200)
Payment of common stock dividends	(718)		(633)
Other financing activities	(26)		(27)
Net cash provided from financing activities	505		992
Net Change in Cash, Cash Equivalents, and Restricted Cash	143		1,024
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	894		313
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	1,037	$	1,337
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $11 and $15 capitalized for 2020 and 2019, respectively)	$	249	$	246
Income taxes, net	203		89
Noncash transactions —
Accrued property additions at end of period	154		173
Right-of-use assets obtained under operating leases	63		7
Right-of-use assets obtained under finance leases	2		1

The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

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ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2020		At December 31, 2019
	(in millions)
Current Assets:
Cash and cash equivalents	$	1,037	$	894
Receivables —
Customer accounts receivable	499		425
Unbilled revenues	138		134
Affiliated	37		37
Other accounts and notes receivable	84		72
Accumulated provision for uncollectible accounts	(32)		(22)
Fossil fuel stock	208		212
Materials and supplies	562		512
Prepaid expenses	71		50
Other regulatory assets	207		242
Other current assets	42		30
Total current assets	2,853		2,586
Property, Plant, and Equipment:
In service	31,355		30,023
Less: Accumulated provision for depreciation	9,920		9,540
Plant in service, net of depreciation	21,435		20,483
Nuclear fuel, at amortized cost	257		296
Construction work in progress	926		890
Total property, plant, and equipment	22,618		21,669
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	63		66
Nuclear decommissioning trusts, at fair value	1,039		1,023
Miscellaneous property and investments	130		128
Total other property and investments	1,232		1,217
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	162		132
Deferred charges related to income taxes	242		244
Deferred under recovered regulatory clause revenues	62		40
Regulatory assets – asset retirement obligations	1,475		1,019
Other regulatory assets, deferred	1,923		1,976
Other deferred charges and assets	402		269
Total deferred charges and other assets	4,266		3,680
Total Assets	$	30,969	$	29,152

The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

20

    Table of Contents                                Index to Financial Statements

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At September 30, 2020		At December 31, 2019
	(in millions)
Current Liabilities:
Securities due within one year	$	496	$	251
Accounts payable —
Affiliated	272		316
Other	353		514
Customer deposits	104		100
Accrued taxes	210		78
Accrued interest	83		92
Accrued compensation	172		216
Asset retirement obligations	251		195
Other regulatory liabilities	144		193
Other current liabilities	116		105
Total current liabilities	2,201		2,060
Long-term Debt	8,622		8,270
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,372		3,260
Deferred credits related to income taxes	1,917		1,960
Accumulated deferred ITCs	96		100
Employee benefit obligations	191		206
Operating lease obligations	121		107
Asset retirement obligations, deferred	3,707		3,345
Other cost of removal obligations	360		412
Other regulatory liabilities, deferred	137		146
Other deferred credits and liabilities	39		40
Total deferred credits and other liabilities	9,940		9,576
Total Liabilities	20,763		19,906
Redeemable Preferred Stock	291		291
Common Stockholder's Equity (See accompanying statements)	9,915		8,955
Total Liabilities and Stockholder's Equity	$	30,969	$	29,152

The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

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ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY (UNAUDITED)

	Number of Common Shares Issued	Common Stock		Paid-In Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
	(in millions)
Balance at December 31, 2018	31	$	1,222	$	3,508	$	2,775	$	(28)	$	7,477
Net income after dividends on preferred stock	—	—		—		217		—		217
Capital contributions from parent company	—	—		1,236		—		—		1,236
Other comprehensive income	—	—		—		—		1		1
Cash dividends on common stock	—	—		—		(211)		—		(211)
Balance at March 31, 2019	31	1,222		4,744		2,781		(27)		8,720
Net income after dividends on preferred stock	—	—		—		296		—		296
Capital contributions from parent company	—	—		23		—		—		23
Other comprehensive income	—	—		—		—		1		1
Cash dividends on common stock	—	—		—		(211)		—		(211)
Balance at June 30, 2019	31	1,222		4,767		2,866		(26)		8,829
Net income after dividends on preferred stock	—	—		—		469		—		469
Return of capital to parent company	—	—		(2)		—		—		(2)
Other comprehensive income	—	—		—		—		1		1
Cash dividends on common stock	—	—		—		(211)		—		(211)
Balance at September 30, 2019	31	$	1,222	$	4,765	$	3,124	$	(25)	$	9,086
Balance at December 31, 2019	31	$	1,222	$	4,755	$	3,001	$	(23)	$	8,955
Net income after dividends on preferred stock	—	—		—		280		—		280
Capital contributions from parent company	—	—		612		—		—		612
Other comprehensive income	—	—		—		—		1		1
Cash dividends on common stock	—	—		—		(239)		—		(239)
Balance at March 31, 2020	31	1,222		5,367		3,042		(22)		9,609
Net income after dividends on preferred stock	—	—		—		298		—		298
Capital contributions from parent company	—	—		1		—		—		1
Other comprehensive income	—	—		—		—		1		1
Cash dividends on common stock	—	—		—		(239)		—		(239)
Balance at June 30, 2020	31	1,222		5,368		3,101		(21)		9,670
Net income after dividends on preferred stock	—	—		—		444		—		444
Capital contributions from parent company	—	—		40		—		—		40
Other comprehensive income	—	—		—		—		1		1
Cash dividends on common stock	—	—		—		(240)		—		(240)
Balance at September 30, 2020	31	$	1,222	$	5,408	$	3,305	$	(20)	$	9,915

The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

22

    Table of Contents                                Index to Financial Statements

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)				(in millions)
Operating Revenues:
Retail revenues	$	2,435	$	2,567	$	5,870	$	6,181
Wholesale revenues	34		39		85		107
Other revenues	148		149		416		418
Total operating revenues	2,617		2,755		6,371		6,706
Operating Expenses:
Fuel	368		443		826		1,132
Purchased power, non-affiliates	146		151		409		393
Purchased power, affiliates	142		150		393		460
Other operations and maintenance	483		473		1,411		1,385
Depreciation and amortization	358		250		1,064		733
Taxes other than income taxes	123		127		344		348
Estimated loss on Plant Vogtle Units 3 and 4	—		—		149		—
Total operating expenses	1,620		1,594		4,596		4,451
Operating Income	997		1,161		1,775		2,255
Other Income and (Expense):
Interest expense, net of amounts capitalized	(106)		(103)		(322)		(304)
Other income (expense), net	54		36		156		113
Total other income and (expense)	(52)		(67)		(166)		(191)
Earnings Before Income Taxes	945		1,094		1,609		2,064
Income taxes	172		255		198		466
Net Income	$	773	$	839	$	1,411	$	1,598

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)				(in millions)
Net Income	$	773	$	839	$	1,411	$	1,598
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of     $—, $(12), $(1), and $(21), respectively	—		(35)		(2)		(62)
Reclassification adjustment for amounts included in net income,    net of tax of $—, $—, $2, and $—, respectively	2		—		4		1
Total other comprehensive income (loss)	2		(35)		2		(61)
Comprehensive Income	$	775	$	804	$	1,413	$	1,537

The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.

23

    Table of Contents                                Index to Financial Statements

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2020		2019
	(in millions)
Operating Activities:
Net income	$	1,411	$	1,598
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	1,206		887
Deferred income taxes	(167)		145
Allowance for equity funds used during construction	(63)		(49)
Pension, postretirement, and other employee benefits	(98)		(85)
Settlement of asset retirement obligations	(130)		(110)
Storm damage reserve accruals	160		22
Estimated loss on Plant Vogtle Units 3 and 4	149		—
Other, net	12		40
Changes in certain current assets and liabilities —
-Receivables	(168)		(128)
-Prepaid income taxes	—		102
-Materials and supplies	(74)		(2)
-Contract assets	(34)		(33)
-Other current assets	(31)		(13)
-Accounts payable	25		(134)
-Accrued taxes	44		138
-Accrued compensation	(36)		(12)
-Retail fuel cost over recovery	84		—
-Customer refunds	(162)		18
-Other current liabilities	(3)		(19)
Net cash provided from operating activities	2,125		2,365
Investing Activities:
Property additions	(2,519)		(2,581)
Nuclear decommissioning trust fund purchases	(500)		(483)
Nuclear decommissioning trust fund sales	495		477
Cost of removal, net of salvage	(93)		(136)
Change in construction payables, net of joint owner portion	(14)		(75)
Payments pursuant to LTSAs	(44)		(17)
Proceeds from dispositions and asset sales	143		9
Other investing activities	6		13
Net cash used for investing activities	(2,526)		(2,793)
Financing Activities:
Decrease in notes payable, net	(115)		(294)
Proceeds —
FFB loan	519		835
Senior notes	1,500		750
Pollution control revenue bonds	53		584
Short-term borrowings	250		250
Capital contributions from parent company	1,379		82
Redemptions and repurchases —
Senior notes	(950)		—
Pollution control revenue bonds	(148)		(223)
Short-term borrowings	(375)		—
FFB loan	(55)		—
Payment of common stock dividends	(1,156)		(1,182)
Other financing activities	(35)		(37)
Net cash provided from financing activities	867		765
Net Change in Cash, Cash Equivalents, and Restricted Cash	466		337
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	52		112
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	518	$	449
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $34 and $25 capitalized for 2020 and 2019, respectively)	$	316	$	296
Income taxes, net	311		45
Noncash transactions —
Accrued property additions at end of period	523		589
Right-of-use assets obtained under operating leases	30		18
Right-of-use assets obtained under finance leases	—		24

The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.

24

    Table of Contents                                Index to Financial Statements

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2020		At December 31, 2019
	(in millions)
Current Assets:
Cash and cash equivalents	$	518	$	52
Receivables —
Customer accounts receivable	715		533
Unbilled revenues	237		203
Joint owner accounts receivable	120		136
Affiliated	17		21
Other accounts and notes receivable	39		209
Accumulated provision for uncollectible accounts	(29)		(2)
Fossil fuel stock	269		272
Materials and supplies	572		501
Regulatory assets – storm damage reserves	213		213
Regulatory assets – asset retirement obligations	209		254
Other regulatory assets	251		263
Other current assets	162		140
Total current assets	3,293		2,795
Property, Plant, and Equipment:
In service	39,170		38,137
Less: Accumulated provision for depreciation	12,139		11,753
Plant in service, net of depreciation	27,031		26,384
Nuclear fuel, at amortized cost	547		555
Construction work in progress	6,752		5,650
Total property, plant, and equipment	34,330		32,589
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	50		52
Nuclear decommissioning trusts, at fair value	1,070		1,013
Miscellaneous property and investments	67		64
Total other property and investments	1,187		1,129
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	1,345		1,428
Deferred charges related to income taxes	522		519
Regulatory assets – asset retirement obligations, deferred	3,307		2,865
Other regulatory assets, deferred	2,521		2,716
Other deferred charges and assets	541		500
Total deferred charges and other assets	8,236		8,028
Total Assets	$	47,046	$	44,541

The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.

25

    Table of Contents                                Index to Financial Statements

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At September 30, 2020		At December 31, 2019
	(in millions)
Current Liabilities:
Securities due within one year	$	531	$	1,025
Notes payable	—		365
Accounts payable —
Affiliated	561		512
Other	731		711
Customer deposits	280		283
Accrued taxes	415		407
Accrued interest	100		118
Accrued compensation	198		233
Operating lease obligations	151		144
Asset retirement obligations	351		265
Over recovered fuel clause revenues	84		—
Other regulatory liabilities	302		447
Other current liabilities	201		187
Total current liabilities	3,905		4,697
Long-term Debt	12,314		10,791
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,296		3,257
Deferred credits related to income taxes	2,664		2,862
Accumulated deferred ITCs	272		255
Employee benefit obligations	486		540
Operating lease obligations, deferred	1,163		1,282
Asset retirement obligations, deferred	5,901		5,519
Other deferred credits and liabilities	339		273
Total deferred credits and other liabilities	14,121		13,988
Total Liabilities	30,340		29,476
Common Stockholder's Equity (See accompanying statements)	16,706		15,065
Total Liabilities and Stockholder's Equity	$	47,046	$	44,541

The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.

26

    Table of Contents                                Index to Financial Statements

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY (UNAUDITED)

	Number of Common Shares Issued	Common Stock		Paid-In Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
	(in millions)
Balance at December 31, 2018	9	$	398	$	10,322	$	3,612	$	(9)	$	14,323
Net income	—	—		—		311		—		311
Capital contributions from parent company	—	—		29		—		—		29
Other comprehensive income	—	—		—		—		1		1
Cash dividends on common stock	—	—		—		(394)		—		(394)
Other	—	—		(1)		—		—		(1)
Balance at March 31, 2019	9	398		10,350		3,529		(8)		14,269
Net income	—	—		—		448		—		448
Capital contributions from parent company	—	—		20		—		—		20
Other comprehensive income (loss)	—	—		—		—		(27)		(27)
Cash dividends on common stock	—	—		—		(394)		—		(394)
Other	—	—		1		(1)		—		—
Balance at June 30, 2019	9	398		10,371		3,582		(35)		14,316
Net income	—	—		—		839		—		839
Capital contributions from parent company	—	—		38		—		—		38
Other comprehensive income (loss)	—	—		—		—		(35)		(35)
Cash dividends on common stock	—	—		—		(394)		—		(394)
Other	—	—		(1)		1		—		—
Balance at September 30, 2019	9	$	398	$	10,408	$	4,028	$	(70)	$	14,764
Balance at December 31, 2019	9	$	398	$	10,962	$	3,756	$	(51)	$	15,065
Net income	—	—		—		331		—		331
Capital contributions from parent company	—	—		502		—		—		502
Other comprehensive income (loss)	—	—		—		—		(1)		(1)
Cash dividends on common stock	—	—		—		(385)		—		(385)
Balance at March 31, 2020	9	398		11,464		3,702		(52)		15,512
Net income	—	—		—		308		—		308
Capital contributions from parent company	—	—		1		—		—		1
Other comprehensive income	—	—		—		—		2		2
Cash dividends on common stock	—	—		—		(386)		—		(386)
Balance at June 30, 2020	9	398		11,465		3,624		(50)		15,437
Net income	—	—		—		773		—		773
Capital contributions from parent company	—	—		880		—		—		880
Other comprehensive income	—	—		—		—		2		2
Cash dividends on common stock	—	—		—		(386)		—		(386)
Balance at September 30, 2020	9	$	398	$	12,345	$	4,011	$	(48)	$	16,706

The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.

27

    Table of Contents                                Index to Financial Statements

MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)				(in millions)
Operating Revenues:
Retail revenues	$	232	$	251	$	630	$	669
Wholesale revenues, non-affiliates	61		64		164		178
Wholesale revenues, affiliates	36		51		82		109
Other revenues	7		4		19		14
Total operating revenues	336		370		895		970
Operating Expenses:
Fuel	103		121		266		319
Purchased power	6		6		18		15
Other operations and maintenance	62		72		202		204
Depreciation and amortization	47		48		135		144
Taxes other than income taxes	31		30		90		85
Total operating expenses	249		277		711		767
Operating Income	87		93		184		203
Other Income and (Expense):
Interest expense, net of amounts capitalized	(14)		(17)		(45)		(52)
Other income (expense), net	6		4		19		15
Total other income and (expense)	(8)		(13)		(26)		(37)
Earnings Before Income Taxes	79		80		158		166
Income taxes	12		15		20		27
Net Income	$	67	$	65	$	138	$	139

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)				(in millions)
Net Income	$	67	$	65	$	138	$	139
Other comprehensive income (loss):
Qualifying hedges:
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	$	67	$	65	$	139	$	140

The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.

28

    Table of Contents                                Index to Financial Statements

MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2020		2019
	(in millions)
Operating Activities:
Net income	$	138	$	139
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	142		148
Deferred income taxes	(19)		10
Settlement of asset retirement obligations	(16)		(28)
Other, net	9		8
Changes in certain current assets and liabilities —
-Receivables	(3)		(11)
-Other current assets	(7)		18
-Accounts payable	(54)		(26)
-Accrued taxes	15		(12)
-Accrued compensation	(8)		(10)
-Other current liabilities	(11)		6
Net cash provided from operating activities	186		242
Investing Activities:
Property additions	(174)		(134)
Construction payables	7		(16)
Payments pursuant to LTSAs	(20)		(18)
Other investing activities	(13)		(30)
Net cash used for investing activities	(200)		(198)
Financing Activities:
Proceeds —
Capital contributions from parent company	80		2
Short-term borrowings	40		—
Pollution control revenue bonds	34		43
Other long-term debt	100		—
Redemptions —
Senior notes	(275)		—
Short-term borrowings	(40)		—
Pollution control revenue bonds	(41)		—
Return of capital to parent company	(74)		(113)
Payment of common stock dividends	(37)		—
Other financing activities	(1)		(1)
Net cash used for financing activities	(214)		(69)
Net Change in Cash, Cash Equivalents, and Restricted Cash	(228)		(25)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	286		293
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	58	$	268
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $— and $(1) capitalized for 2020 and 2019, respectively)	$	49	$	55
Income taxes, net	9		—
Noncash transactions — Accrued property additions at end of period	42		20

The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.

29

    Table of Contents                                Index to Financial Statements

MISSISSIPPI POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2020		At December 31, 2019
	(in millions)
Current Assets:
Cash and cash equivalents	$	58	$	286
Receivables —
Customer accounts receivable	46		35
Unbilled revenues	40		39
Affiliated	14		27
Other accounts and notes receivable	34		26
Fossil fuel stock	19		26
Materials and supplies	63		61
Other regulatory assets	60		99
Other current assets	19		10
Total current assets	353		609
Property, Plant, and Equipment:
In service	4,966		4,857
Less: Accumulated provision for depreciation	1,553		1,463
Plant in service, net of depreciation	3,413		3,394
Construction work in progress	140		126
Total property, plant, and equipment	3,553		3,520
Other Property and Investments	149		131
Deferred Charges and Other Assets:
Deferred charges related to income taxes	32		32
Regulatory assets – asset retirement obligations	202		210
Other regulatory assets, deferred	357		360
Accumulated deferred income taxes	130		139
Other deferred charges and assets	72		34
Total deferred charges and other assets	793		775
Total Assets	$	4,848	$	5,035

The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.

30

    Table of Contents                                Index to Financial Statements

MISSISSIPPI POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At September 30, 2020		At December 31, 2019
	(in millions)
Current Liabilities:
Securities due within one year	$	—	$	281
Accounts payable —
Affiliated	54		76
Other	50		75
Accrued taxes	120		105
Accrued interest	14		15
Accrued compensation	28		35
Asset retirement obligations	23		33
Over recovered regulatory clause liabilities	31		29
Other regulatory liabilities	56		21
Other current liabilities	42		64
Total current liabilities	418		734
Long-term Debt	1,402		1,308
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	422		424
Deferred credits related to income taxes	299		352
Employee benefit obligations	95		99
Asset retirement obligations, deferred	158		157
Other cost of removal obligations	195		189
Other regulatory liabilities, deferred	64		76
Other deferred credits and liabilities	35		44
Total deferred credits and other liabilities	1,268		1,341
Total Liabilities	3,088		3,383
Common Stockholder's Equity (See accompanying statements)	1,760		1,652
Total Liabilities and Stockholder's Equity	$	4,848	$	5,035

The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.

31

    Table of Contents                                Index to Financial Statements

MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY (UNAUDITED)

	Number of Common Shares Issued	Common Stock		Paid-In Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
	(in millions)
Balance at December 31, 2018	1	$	38	$	4,546	$	(2,971)	$	(4)	$	1,609
Net income	—	—		—		37		—		37
Return of capital to parent company	—	—		(38)		—		—		(38)
Capital contributions from parent company	—	—		2		—		—		2
Balance at March 31, 2019	1	38		4,510		(2,934)		(4)		1,610
Net income	—	—		—		37		—		37
Return of capital to parent company	—	—		(38)		—		—		(38)
Capital contributions from parent company	—	—		8		—		—		8
Balance at June 30, 2019	1	38		4,480		(2,897)		(4)		1,617
Net income	—	—		—		65		—		65
Return of capital to parent company	—	—		(43)		—		—		(43)
Balance at September 30, 2019	1	$	38	$	4,437	$	(2,832)	$	(4)	$	1,639
Balance at December 31, 2019	1	$	38	$	4,449	$	(2,832)	$	(3)	$	1,652
Net income	—	—		—		32		—		32
Return of capital to parent company	—	—		(37)		—		—		(37)
Capital contributions from parent company	—	—		76		—		—		76
Other	—	—		(1)		—		—		(1)
Balance at March 31, 2020	1	38		4,487		(2,800)		(3)		1,722
Net income	—	—		—		39		—		39
Return of capital to parent company	—	—		(37)		—		—		(37)
Balance at June 30, 2020	1	38		4,450		(2,761)		(3)		1,724
Net income	—	—		—		67		—		67
Capital contributions from parent company	—	—		6		—		—		6
Cash dividends on common stock	—	—		—		(37)		—		(37)
Balance at September 30, 2020	1	$	38	$	4,456	$	(2,731)	$	(3)	$	1,760

The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.

32

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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,
	2020		2019		2020		2019
	(in millions)				(in millions)
Operating Revenues:
Wholesale revenues, non-affiliates	$	418	$	455	$	1,047	$	1,197
Wholesale revenues, affiliates	101		116		279		320
Other revenues	4		3		11		10
Total operating revenues	523		574		1,337		1,527
Operating Expenses:
Fuel	137		166		346		449
Purchased power	19		26		52		82
Other operations and maintenance	89		85		245		250
Depreciation and amortization	129		120		367		357
Taxes other than income taxes	10		10		29		32
(Gain) loss on dispositions, net	—		—		(39)		(23)
Total operating expenses	384		407		1,000		1,147
Operating Income	139		167		337		380
Other Income and (Expense):
Interest expense, net of amounts capitalized	(36)		(43)		(114)		(127)
Other income (expense), net	13		6		19		48
Total other income and (expense)	(23)		(37)		(95)		(79)
Earnings Before Income Taxes	116		130		242		301
Income taxes (benefit)	14		19		27		(41)
Net Income	102		111		215		342
Net income attributable to noncontrolling interests	28		25		3		26
Net Income Attributable to Southern Power	$	74	$	86	$	212	$	316

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)				(in millions)
Net Income	$	102	$	111	$	215	$	342
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of    $15, $(18), $(2), and $(28), respectively	44		(53)		(6)		(84)
Reclassification adjustment for amounts included in net income,    net of tax of $(13), $15, $(8), and $21, respectively	(36)		45		(24)		64
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income,    net of tax of $—, $—, $—, and $—, respectively	—		—		2		—
Total other comprehensive income (loss)	8		(8)		(28)		(20)
Comprehensive Income	110		103		187		322
Comprehensive income attributable to noncontrolling interests	28		25		3		26
Comprehensive Income Attributable to Southern Power	$	82	$	78	$	184	$	296

The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.

33

    Table of Contents                                Index to Financial Statements

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2020		2019
	(in millions)
Operating Activities:
Net income	$	215	$	342
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	386		377
Deferred income taxes	(59)		(122)
Utilization of federal investment tax credits	318		705
Amortization of investment tax credits	(44)		(136)
(Gain) loss on dispositions, net	(39)		(24)
Other, net	(16)		(19)
Changes in certain current assets and liabilities —
-Receivables	(28)		15
-Prepaid income taxes	74		33
-Other current assets	(17)		(3)
-Accounts payable	(12)		(5)
-Accrued taxes	21		66
-Other current liabilities	(25)		(8)
Net cash provided from operating activities	774		1,221
Investing Activities:
Business acquisitions, net of cash acquired	(81)		(50)
Property additions	(135)		(284)
Proceeds from dispositions and asset sales	663		572
Investment in unconsolidated subsidiaries	—		(116)
Payments pursuant to LTSAs	(61)		(85)
Other investing activities	38		(1)
Net cash provided from investing activities	424		36
Financing Activities:
Decrease in notes payable, net	(449)		—
Proceeds — Capital contributions from parent company	—		59
Redemptions —
Short-term borrowings	(100)		(100)
Senior notes	(300)		—
Return of capital to parent company	—		(755)
Distributions to noncontrolling interests	(164)		(125)
Capital contributions from noncontrolling interests	173		11
Purchase of membership interests from noncontrolling interests	(60)		—
Payment of common stock dividends	(151)		(154)
Other financing activities	(9)		(6)
Net cash used for financing activities	(1,060)		(1,070)
Net Change in Cash, Cash Equivalents, and Restricted Cash	138		187
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	279		181
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	417	$	368
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $10 and $11 capitalized for 2020 and 2019, respectively)	$	123	$	133
Income taxes, net	(278)		(612)
Noncash transactions —
Accrued property additions at end of period	44		41
Right-of-use assets obtained under operating leases	30		—

The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2020		At December 31, 2019
	(in millions)
Current Assets:
Cash and cash equivalents	$	416	$	279
Receivables —
Customer accounts receivable	135		107
Affiliated	41		30
Other	37		73
Materials and supplies	204		191
Prepaid income taxes	33		36
Other current assets	37		43
Total current assets	903		759
Property, Plant, and Equipment:
In service	13,600		13,270
Less: Accumulated provision for depreciation	2,776		2,464
Plant in service, net of depreciation	10,824		10,806
Construction work in progress	335		515
Total property, plant, and equipment	11,159		11,321
Other Property and Investments:
Intangible assets, net of amortization of $84 and $69    at September 30, 2020 and December 31, 2019, respectively	307		322
Equity investments in unconsolidated subsidiaries	19		28
Total other property and investments	326		350
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	395		369
Prepaid LTSAs	160		128
Accumulated deferred income taxes	231		551
Income taxes receivable, non-current	13		5
Assets held for sale	—		601
Other deferred charges and assets	237		216
Total deferred charges and other assets	1,036		1,870
Total Assets	$	13,424	$	14,300

The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholders' Equity	At September 30, 2020		At December 31, 2019
	(in millions)
Current Liabilities:
Securities due within one year	$	525	$	824
Notes payable	—		549
Accounts payable —
Affiliated	49		56
Other	69		85
Accrued taxes —
Accrued income taxes	9		—
Other accrued taxes	31		26
Accrued interest	26		32
Other current liabilities	104		132
Total current liabilities	813		1,704
Long-term Debt	3,630		3,574
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	117		115
Accumulated deferred ITCs	1,687		1,731
Operating lease obligations	404		376
Other deferred credits and liabilities	162		178
Total deferred credits and other liabilities	2,370		2,400
Total Liabilities	6,813		7,678
Total Stockholders' Equity (See accompanying statements)	6,611		6,622
Total Liabilities and Stockholders' Equity	$	13,424	$	14,300

The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED)

	Paid-In Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total Common Stockholders' Equity		Noncontrolling Interests		Total
	(in millions)
Balance at December 31, 2018	$	1,600	$	1,352	$	16	$	2,968	$	4,316	$	7,284
Net income (loss)	—		56		—		56		(29)		27
Capital contributions from parent company	1		—		—		1		—		1
Other comprehensive income (loss)	—		—		(4)		(4)		—		(4)
Cash dividends on common stock	—		(51)		—		(51)		—		(51)
Capital contributions from noncontrolling interests	—		—		—		—		3		3
Distributions to noncontrolling interests	—		—		—		—		(41)		(41)
Other	(1)		(1)		—		(2)		1		(1)
Balance at March 31, 2019	1,600		1,356		12		2,968		4,250		7,218
Net income	—		174		—		174		29		203
Return of capital to parent company	(505)		—		—		(505)		—		(505)
Capital contributions from parent company	7		—		—		7		—		7
Other comprehensive income (loss)	—		—		(8)		(8)		—		(8)
Cash dividends on common stock	—		(52)		—		(52)		—		(52)
Capital contributions from noncontrolling interests	—		—		—		—		2		2
Distributions to noncontrolling interests	—		—		—		—		(47)		(47)
Other	—		1		—		1		(1)		—
Balance at June 30, 2019	1,102		1,479		4		2,585		4,233		6,818
Net income	—		86		—		86		25		111
Return of capital to parent company	(250)		—		—		(250)		—		(250)
Capital contributions from parent company	53		—		—		53		—		53
Other comprehensive income (loss)	—		—		(8)		(8)		—		(8)
Cash dividends on common stock	—		(51)		—		(51)		—		(51)
Capital contributions from noncontrolling interests	—		—		—		—		63		63
Distributions to noncontrolling interests	—		—		—		—		(43)		(43)
Balance at September 30, 2019	$	905	$	1,514	$	(4)	$	2,415	$	4,278	$	6,693

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED)

	Paid-In Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total Common Stockholders' Equity		Noncontrolling Interests		Total
	(in millions)
Balance at December 31, 2019	$	909	$	1,485	$	(26)	$	2,368	$	4,254	$	6,622
Net income (loss)	—		75		—		75		(31)		44
Other comprehensive income (loss)	—		—		(33)		(33)		—		(33)
Cash dividends on common stock	—		(50)		—		(50)		—		(50)
Capital contributions from noncontrolling interests	—		—		—		—		16		16
Distributions to noncontrolling interests	—		—		—		—		(48)		(48)
Balance at March 31, 2020	909		1,510		(59)		2,360		4,191		6,551
Net income	—		63		—		63		5		68
Other comprehensive income (loss)	—		—		(3)		(3)		—		(3)
Cash dividends on common stock	—		(50)		—		(50)		—		(50)
Capital contributions from noncontrolling interests	—		—		—		—		165		165
Distributions to noncontrolling interests	—		—		—		—		(70)		(70)
Other	(2)		—		—		(2)		—		(2)
Balance at June 30, 2020	907		1,523		(62)		2,368		4,291		6,659
Net income	—		74		—		74		28		102
Return of capital to parent company	(4)		—		—		(4)		—		(4)
Other comprehensive income	—		—		8		8		—		8
Cash dividends on common stock	—		(51)		—		(51)		—		(51)
Capital contributions from noncontrolling interests	—		—		—		—		2		2
Distributions to noncontrolling interests	—		—		—		—		(51)		(51)
Purchase of membership interests from noncontrolling interests	5		—		—		5		(60)		(55)
Other	—		—		—		—		1		1
Balance at September 30, 2020	$	908	$	1,546	$	(54)	$	2,400	$	4,211	$	6,611

The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.

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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,
	2020		2019		2020		2019
	(in millions)				(in millions)
Operating Revenues:
Natural gas revenues (includes revenue taxes of    $10, $10, $79, and $88, respectively)	$	478	$	498	$	2,356	$	2,661
Alternative revenue programs	(1)		—		6		—
Total operating revenues	477		498		2,362		2,661
Operating Expenses:
Cost of natural gas	71		79		654		956
Other operations and maintenance	217		208		696		642
Depreciation and amortization	125		121		368		359
Taxes other than income taxes	35		33		154		161
Impairment charges	—		92		—		92
Total operating expenses	448		533		1,872		2,210
Operating Income (Loss)	29		(35)		490		451
Other Income and (Expense):
Earnings from equity method investments	33		35		106		115
Interest expense, net of amounts capitalized	(57)		(56)		(171)		(174)
Other income (expense), net	12		5		33		16
Total other income and (expense)	(12)		(16)		(32)		(43)
Earnings (Loss) Before Income Taxes	17		(51)		458		408
Income taxes (benefit)	3		(22)		98		61
Net Income (Loss)	$	14	$	(29)	$	360	$	347

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)				(in millions)
Net Income (Loss)	$	14	$	(29)	$	360	$	347
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of    $1, $(3), $(6), and $(4), respectively	4		(3)		(17)		(6)
Reclassification adjustment for amounts included in net income,    net of tax of $—, $—, $2, and $—, respectively	1		—		7		—
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income,    net of tax of $—, $—, $1, and $(1), respectively	—		—		—		(1)
Total other comprehensive income (loss)	5		(3)		(10)		(7)
Comprehensive Income	$	19	$	(32)	$	350	$	340

The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.

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SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2020		2019
	(in millions)
Operating Activities:
Net income	$	360	$	347
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	368		359
Deferred income taxes	(1)		96
Mark-to-market adjustments	104		44
Impairment charges	—		92
Other, net	(20)		(58)
Changes in certain current assets and liabilities —
-Receivables	403		832
-Natural gas for sale	26		49
-Other current assets	(45)		45
-Accounts payable	(75)		(607)
-Accrued taxes	7		(68)
-Accrued compensation	(17)		(34)
-Other current liabilities	12		(48)
Net cash provided from operating activities	1,122		1,049
Investing Activities:
Property additions	(1,045)		(1,008)
Cost of removal, net of salvage	(60)		(59)
Change in construction payables, net	25		57
Investment in unconsolidated subsidiaries	(79)		(25)
Proceeds from dispositions and asset sales	178		32
Other investing activities	8		14
Net cash used for investing activities	(973)		(989)
Financing Activities:
Decrease in notes payable, net	(500)		(383)
Proceeds —
First mortgage bonds	150		200
Capital contributions from parent company	215		820
Senior notes	500		—
Redemptions —
First mortgage bonds	—		(50)
Senior notes	—		(300)
Payment of common stock dividends	(399)		(353)
Other financing activities	(3)		(2)
Net cash used for financing activities	(37)		(68)
Net Change in Cash, Cash Equivalents, and Restricted Cash	112		(8)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	49		70
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	161	$	62
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $5 capitalized for both 2020 and 2019)	$	162	$	180
Income taxes, net	45		48
Noncash transactions — Accrued property additions at end of period	146		154

The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.

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SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2020		At December 31, 2019
	(in millions)
Current Assets:
Cash and cash equivalents	$	157	$	46
Receivables —
Energy marketing receivables	328		428
Customer accounts receivable	214		323
Unbilled revenues	60		183
Affiliated	3		5
Other accounts and notes receivable	42		114
Accumulated provision for uncollectible accounts	(34)		(18)
Natural gas for sale	448		479
Prepaid expenses	92		65
Assets from risk management activities, net of collateral	75		177
Other regulatory assets	110		92
Assets held for sale	—		171
Other current assets	43		41
Total current assets	1,538		2,106
Property, Plant, and Equipment:
In service	17,202		16,344
Less: Accumulated depreciation	4,761		4,650
Plant in service, net of depreciation	12,441		11,694
Construction work in progress	655		613
Total property, plant, and equipment	13,096		12,307
Other Property and Investments:
Goodwill	5,015		5,015
Equity investments in unconsolidated subsidiaries	1,301		1,251
Other intangible assets, net of amortization of $191 and $176    at September 30, 2020 and December 31, 2019, respectively	55		70
Miscellaneous property and investments	20		20
Total other property and investments	6,391		6,356
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	85		93
Other regulatory assets, deferred	580		618
Other deferred charges and assets	242		207
Total deferred charges and other assets	907		918
Total Assets	$	21,932	$	21,687

The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.

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SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At September 30, 2020		At December 31, 2019
	(in millions)
Current Liabilities:
Securities due within one year	$	334	$	—
Notes payable	150		650
Energy marketing trade payables	361		442
Accounts payable —
Affiliated	46		41
Other	341		315
Customer deposits	94		96
Accrued taxes	78		71
Accrued interest	66		52
Accrued compensation	83		100
Liabilities from risk management activities, net of collateral	31		21
Other regulatory liabilities	112		94
Other current liabilities	128		128
Total current liabilities	1,824		2,010
Long-term Debt	6,127		5,845
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	1,213		1,219
Deferred credits related to income taxes	854		874
Employee benefit obligations	247		265
Operating lease obligations	70		78
Other cost of removal obligations	1,642		1,606
Accrued environmental remediation	220		233
Other deferred credits and liabilities	50		51
Total deferred credits and other liabilities	4,296		4,326
Total Liabilities	12,247		12,181
Common Stockholder's Equity (See accompanying statements)	9,685		9,506
Total Liabilities and Stockholder's Equity	$	21,932	$	21,687

The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.

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SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY (UNAUDITED)

	Paid-In Capital		Retained Earnings (Accumulated Deficit)		Accumulated Other Comprehensive Income (Loss)		Total
	(in millions)
Balance at December 31, 2018	$	8,856	$	(312)	$	26	$	8,570
Net income	—		270		—		270
Capital contributions from parent company	17		—		—		17
Other comprehensive income (loss)	—		—		(1)		(1)
Cash dividends on common stock	—		(118)		—		(118)
Balance at March 31, 2019	8,873		(160)		25		8,738
Net income	—		106		—		106
Capital contributions from parent company	35		—		—		35
Other comprehensive income (loss)	—		—		(3)		(3)
Cash dividends on common stock	—		(117)		—		(117)
Balance at June 30, 2019	8,908		(171)		22		8,759
Net loss	—		(29)		—		(29)
Capital contributions from parent company	784		—		—		784
Other comprehensive income (loss)	—		—		(3)		(3)
Cash dividends on common stock	—		(118)		—		(118)
Balance at September 30, 2019	$	9,692	$	(318)	$	19	$	9,393
Balance at December 31, 2019	$	9,697	$	(198)	$	7	$	9,506
Net income	—		275		—		275
Return of capital to parent company	(2)		—		—		(2)
Other comprehensive income (loss)	—		—		(15)		(15)
Cash dividends on common stock	—		(133)		—		(133)
Balance at March 31, 2020	9,695		(56)		(8)		9,631
Net income	—		71		—		71
Capital contributions from parent company	200		—		—		200
Cash dividends on common stock	—		(133)		—		(133)
Balance at June 30, 2020	9,895		(118)		(8)		9,769
Net income	—		14		—		14
Capital contributions from parent company	30		—		—		30
Other comprehensive income	—		—		5		5
Cash dividends on common stock	—		(133)		—		(133)
Balance at September 30, 2020	$	9,925	$	(237)	$	(3)	$	9,685

The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS

FOR

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

ALABAMA POWER COMPANY

GEORGIA POWER COMPANY

MISSISSIPPI POWER COMPANY

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

(UNAUDITED)

INDEX TO THE NOTES TO THE CONDENSED FINANCIAL STATEMENTS

Note		Page
A	Introduction	45
B	Regulatory Matters	49
C	Contingencies	59
D	Revenue from Contracts with Customers and Lease Income	65
E	Consolidated Entities and Equity Method Investments	72
F	Financing	74
G	Income Taxes	75
H	Retirement Benefits	76
I	Fair Value Measurements	81
J	Derivatives	86
K	Acquisitions and Dispositions	97
L	Segment and Related Information	99

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

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS

(UNAUDITED)

(A) INTRODUCTION

The condensed quarterly financial statements of each Registrant included herein have been prepared by such Registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 2019 have been derived from the audited financial statements of each Registrant. In the opinion of each Registrant's management, the information regarding such Registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended September 30, 2020 and 2019. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each Registrant believes that the disclosures regarding such Registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the 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, including the impacts of the COVID-19 pandemic, 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, 2020 and December 31, 2019 was as follows:

	Goodwill
	(in millions)
Southern Company	$	5,280
Southern Company Gas:
Gas distribution operations	$	4,034
Gas marketing services	981
Southern Company Gas total	$	5,015

Goodwill is not amortized but is subject to an annual impairment test in the fourth quarter of the year and on an interim basis as events and changes in circumstances occur, including, but not limited to, a significant change in operating performance, the business climate, legal or regulatory factors, or a planned sale or disposition of a significant portion of the business. The continued COVID-19 pandemic and related responses continue to disrupt supply chains, reduce labor availability and productivity, and reduce economic activity. These effects could have a variety of adverse impacts on Southern Company and its subsidiaries, including the $263 million of goodwill recorded at PowerSecure. If the impact of the COVID-19 pandemic becomes significant to the operating results of PowerSecure and its businesses, a portion of the associated goodwill may become impaired. The ultimate outcome of this matter cannot be determined at this time.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

Other intangible assets were as follows:

	At September 30, 2020						At December 31, 2019
	Gross Carrying Amount		Accumulated Amortization		Other Intangible Assets, Net		Gross Carrying Amount		Accumulated Amortization		Other Intangible Assets, Net
	(in millions)						(in millions)
Southern Company
Other intangible assets subject to amortization:
Customer relationships	$	212	$	(130)	$	82	$	212	$	(116)	$	96
Trade names	64		(30)		34		64		(25)		39
Storage and transportation contracts	64		(64)		—		64		(62)		2
PPA fair value adjustments	390		(84)		306		390		(69)		321
Other	10		(8)		2		11		(8)		3
Total other intangible assets subject to amortization	$	740	$	(316)	$	424	$	741	$	(280)	$	461
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	75		—		75		75		—		75
Total other intangible assets	$	815	$	(316)	$	499	$	816	$	(280)	$	536
Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	$	390	$	(84)	$	306	$	390	$	(69)	$	321
Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services
Customer relationships	$	156	$	(115)	$	41	$	156	$	(104)	$	52
Trade names	26		(12)		14		26		(10)		16
Wholesale gas services
Storage and transportation contracts	64		(64)		—		64		(62)		2
Total other intangible assets subject to amortization	$	246	$	(191)	$	55	$	246	$	(176)	$	70

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Amortization associated with other intangible assets was as follows:

	Three Months Ended		Nine Months Ended
	September 30, 2020
	(in millions)
Southern Company(a)	$	12	$	37
Southern Power(b)	$	5	$	15
Southern Company Gas
Gas marketing services	$	4	$	13
Wholesale gas services(b)	1		2
Southern Company Gas total	$	5	$	15

(a)Includes $6 million and $17 million for the three and nine months ended September 30, 2020, respectively, recorded as a reduction to operating revenues.

(b)Recorded as a reduction to operating revenues.

Restricted Cash

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed balance sheets that total to the amounts shown in the condensed statements of cash flows for the Registrants that had restricted cash at September 30, 2020 and/or December 31, 2019:

	Southern Company					Southern Power		Southern Company Gas
	At September 30, 2020			At December 31, 2019		At September 30, 2020		At September 30, 2020		At December 31, 2019
	(in millions)					(in millions)		(in millions)
Cash and cash equivalents	$	3,379		$	1,975	$	416	$	157	$	46
Restricted cash(a):
Other accounts and notes receivable	—			3		—		—		3
Other current assets	4			—		—		4		—
Other deferred charges and assets	1			—		1		—		—
Total cash, cash equivalents, and restricted cash	$	3,383	(b)	$	1,978	$	417	$	161	$	49

(a)For Southern Company Gas, reflects restricted cash held as collateral for workers' compensation, life insurance, and long-term disability insurance. For Southern Power, reflects restricted cash held for construction payables.

(b)Total does not add due to rounding.

Natural Gas for Sale

Southern Company Gas, with the exception of Nicor Gas, carries natural gas inventory on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value. 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 the three and nine months ended September 30, 2020 or the three months ended September 30, 2019 and recorded an adjustment of $10

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million for the nine months ended September 30, 2019. Nicor Gas' inventory decrement at September 30, 2020 is expected to be restored prior to year end.

Asset Retirement Obligations

See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.

Details of changes in AROs for Southern Company, Alabama Power, and Georgia Power during the first nine months of 2020 are shown in the following table. There were no material changes in AROs for the other Registrants during the first nine months of 2020.

	Southern Company		Alabama Power		Georgia Power
	(in millions)
Balance at December 31, 2019	$	9,786	$	3,540	$	5,784
Liabilities incurred	15		—		10
Liabilities settled	(315)		(157)		(130)
Accretion	308		113		177
Cash flow revisions	866		462		411
Balance at September 30, 2020	$	10,660	$	3,958	$	6,252

In June 2020, Alabama Power recorded an increase of approximately $462 million to its AROs related to the CCR Rule and the related state rule primarily due to management's completion of a feasibility study and the related cost estimates during the second quarter 2020 for one of its ash ponds. Alabama Power's increase also reflects costs associated with the addition of a water treatment system to the design of another ash pond. The additional estimated costs to close these ash ponds under the planned closure-in-place methodology primarily relate to inputs from contractor bids, design revisions, and changes in the expected volume of ash handling.

During the third quarter 2020, Georgia Power completed an assessment of its plans to close the ash ponds at all of its generating plants in compliance with the CCR Rule and the related state rule. The related cost estimates were further refined, including updates to long-term post-closure care requirements, market pricing, and timing of future cash outlays. As a result, in September 2020, Georgia Power recorded an increase of approximately $411 million to its AROs related to the CCR Rule and the related state rule.

The traditional electric operating companies expect to continue updating their cost estimates and ARO liabilities periodically as additional information related to ash pond closure methodologies, schedules, and/or costs becomes available, and the changes could be material. Additionally, the closure designs and plans in the States of Alabama and Georgia are subject to approval by environmental regulatory agencies. Absent continued recovery of ARO costs through regulated rates, results of operations, cash flows, and financial condition for Southern Company and the traditional electric operating companies could be materially impacted. See Note (B) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Integrated Resource Plan" for additional information. The ultimate outcome of these matters cannot be determined at this time.

Depreciation and Amortization

See Note 5 to the financial statements under "Depreciation and Amortization – Southern Power" in Item 8 of the Form 10-K for additional information.

Effective January 1, 2020, Southern Power revised the depreciable lives of its natural gas generating facilities from up to 45 years to up to 50 years. This revision resulted in an immaterial decrease in depreciation for the three and nine months ended September 30, 2020 and is expected to result in an immaterial decrease in annual depreciation for 2020.

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(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, 2020 and December 31, 2019 were as follows:

Regulatory Clause	Balance Sheet Line Item	September 30, 2020		December 31, 2019
		(in millions)
Alabama Power
Rate CNP Compliance	Other regulatory liabilities, current	$	12	$	55
	Other regulatory liabilities, deferred	38		7
Rate CNP PPA	Deferred under recovered regulatory clause revenues	62		40
Retail Energy Cost Recovery	Other regulatory liabilities, current	107		32
	Other regulatory liabilities, deferred	16		17
Natural Disaster Reserve	Other regulatory liabilities, current	7		37
	Other regulatory liabilities, deferred	51		113
Georgia Power
Fuel Cost Recovery	Over recovered fuel clause revenues	$	84	$	—
	Other deferred credits and liabilities	67		73
Mississippi Power
Fuel Cost Recovery	Over recovered regulatory clause liabilities	$	23	$	23
Ad Valorem Tax	Other regulatory assets	11		47
	Other regulatory assets, deferred	36		—
Property Damage Reserve	Other regulatory liabilities, deferred	48		54
Southern Company Gas
Natural Gas Cost Recovery	Other regulatory liabilities	$	84	$	74

Alabama Power

Petition for Certificate of Convenience and Necessity

On August 14, 2020, the Alabama PSC issued its order regarding Alabama Power's petition for a certificate of convenience and necessity (CCN), which authorized Alabama Power to (i) construct an approximately 720-MW combined cycle facility at Alabama Power's Plant Barry (Plant Barry Unit 8), which is expected to be placed in service by the end of 2023, (ii) complete the Autauga Combined Cycle Acquisition, which occurred on August 31, 2020, (iii) purchase approximately 240 MWs of combined cycle generation under a long-term PPA, which began on September 1, 2020, and (iv) pursue up to approximately 200 MWs of cost-effective demand-side management and distributed energy resource programs.

The Alabama PSC authorized the recovery of actual costs for the construction of Plant Barry Unit 8 up to 5% above the estimated in-service cost of $652 million. In so doing, it recognized the potential for developments that could cause the project costs to exceed the capped amount, in which case Alabama Power would provide documentation to the Alabama PSC to explain and justify potential recovery of the additional costs.

The Alabama PSC further directed that the proposed solar generation of approximately 400 MWs, coupled with battery energy storage systems (solar/battery systems), be evaluated under an existing Renewable Generation

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Certificate (RGC) issued by the Alabama PSC in September 2015. The contracts proposed in the CCN petition expired on July 31, 2020. Any future requests for solar/battery systems will be evaluated under the RGC process.

Energy Alabama, Gasp, Inc., and the Sierra Club filed petitions for reconsideration and rehearing with the Alabama PSC. Alabama PSC action on these petitions is expected by November 10, 2020. Upon issuance of a written order reflecting such action, affected parties would have 30 days to pursue an appeal through the State of Alabama court system.

Alabama Power expects to recover all approved costs associated with the CCN through existing rate mechanisms as outlined in Note 2 to the financial statements in Item 8 of the Form 10-K.

The ultimate outcome of these matters cannot be determined at this time.

Rate ECR

On August 7, 2020, the Alabama PSC issued an order authorizing Alabama Power to reduce its over-collected fuel balance by $100 million and return that amount to customers in the form of bill credits for the billing month of October 2020. Any portion of the $100 million undistributed following the bill credit process will remain in the Rate ECR regulatory liability for the benefit of customers.

Rate NDR

In the third quarter 2020, Alabama Power recorded $44 million against the NDR for damages incurred to its transmission and distribution facilities from Hurricane Sally. The NDR balance available for storm damages was $51 million as of September 30, 2020. If the balance falls below $50 million, a reserve establishment charge would be activated (and the ongoing reserve maintenance charge concurrently suspended) until the reserve balance reaches $75 million.

Georgia Power

Rate Plans

2019 ARP

In accordance with the terms of the 2019 ARP, on October 1, 2020, Georgia Power filed the following tariff adjustments to become effective January 1, 2021 pending approval by the Georgia PSC:

•increase traditional base tariffs by approximately $120 million;

•increase the Environmental Compliance Cost Recovery tariff by approximately $2 million;

•decrease Demand-Side Management tariffs by approximately $15 million; and

•increase Municipal Franchise Fee tariffs by approximately $4 million.

The ultimate outcome of this matter cannot be determined at this time.

2013 ARP

In 2019, Georgia Power's retail ROE exceeded 12.00% and, under the modified sharing mechanism pursuant to the 2019 ARP, Georgia Power reduced regulatory assets by approximately $60 million and accrued refunds for retail customers of approximately $60 million. On September 1, 2020, the Georgia PSC authorized Georgia Power to issue customers bill credits prior to final review of the 2019 Annual Surveillance Report by the staff of the Georgia PSC. Georgia Power issued the bill credits in October 2020.

Deferral of Incremental COVID-19 Costs

On April 7, 2020 and June 2, 2020, in response to the COVID-19 pandemic, the Georgia PSC approved orders directing Georgia Power to continue its previous, voluntary suspension of customer disconnections through July 14, 2020 and to defer the resulting incremental bad debt as a regulatory asset. On June 16, 2020 and July 7, 2020, the Georgia PSC approved orders establishing a methodology for identifying incremental bad debt and allowing the

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deferral of other incremental costs associated with the COVID-19 pandemic. The period over which such costs will be recovered is expected to be determined in Georgia Power's next base rate case. At September 30, 2020, the incremental costs deferred totaled approximately $38 million. The ultimate outcome of this matter cannot be determined at this time.

Integrated Resource Plan

On March 5, 2020, the Sierra Club filed a petition for judicial review in the Superior Court of Fulton County to appeal the Georgia PSC's decision in the 2019 ARP allowing Georgia Power to recover compliance costs for CCR AROs. Georgia Power intervened in the appeal on June 22, 2020. The ultimate outcome of this matter cannot be determined at this time.

Fuel Cost Recovery

On May 28, 2020, the Georgia PSC approved a stipulation agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors to lower total fuel billings by approximately $740 million over a two-year period effective June 1, 2020. In addition, Georgia Power further lowered fuel billings by approximately $44 million under an interim fuel rider effective June 1, 2020 through September 30, 2020. Georgia Power continues to be allowed to adjust its fuel cost recovery rates under an interim fuel rider prior to its next fuel case if the under or over recovered fuel balance exceeds $200 million. Georgia Power is scheduled to file its next fuel case no later than February 28, 2023.

Nuclear Construction

In 2009, the Georgia PSC certified construction 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 begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement. In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.

In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into several transitional arrangements to allow construction to continue. In July 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into the Vogtle Services Agreement, whereby Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis. The Vogtle Services Agreement provides that it will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.

In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, executed the Bechtel Agreement, a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.

See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for information on the Amended and Restated Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.

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Cost and Schedule

Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 by the expected in-service dates of November 2021 and November 2022, respectively, is as follows:

	(in billions)
Base project capital cost forecast(a)(b)	$	8.4
Construction contingency estimate	0.1
Total project capital cost forecast(a)(b)	8.5
Net investment as of September 30, 2020(b)	(6.9)
Remaining estimate to complete(a)	$	1.6

(a)    Excludes financing costs expected to be capitalized through AFUDC of approximately $240 million, of which $71 million had been accrued through September 30, 2020.

(b)    Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds.

Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.0 billion, of which $2.5 billion had been incurred through September 30, 2020.

As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of engineering support, commodity installation, system turnovers and related test results, and workforce statistics.

As of June 30, 2020, assignments of contingency exceeded the remaining balance of the $366 million construction contingency originally established in the second quarter 2018 by approximately $34 million. This contingency was used to address cost risks related to construction productivity, including the April 2020 reduction in workforce designed to mitigate impacts of the COVID-19 pandemic described below; craft labor incentives; adding resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement, among other factors. As a result of these factors, Georgia Power established $115 million of additional construction contingency as of June 30, 2020 for further potential risks including, among other factors, construction productivity and expected impacts of the COVID-19 pandemic; additional resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement.

After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income of $149 million ($111 million after tax) for the increase in the total project capital cost forecast as of June 30, 2020. As and when these amounts are spent, Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery.

During the third quarter 2020, approximately $5 million of the construction contingency established in the second quarter 2020 was assigned to the base capital cost forecast for cost risks primarily associated with construction productivity and field support.

In April 2019, Southern Nuclear established aggressive target values for monthly construction production and system turnover activities as part of a strategy to maintain and, where possible, build margin to the regulatory-approved in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4. Through early 2020, the project faced challenges with the April 2019 aggressive strategy targets including, but not limited to, electrical and pipefitting labor productivity and work package closure rates, which resulted in a backlog of activities and completion percentages below the April 2019 aggressive strategy targets.

In February 2020, Southern Nuclear updated its cost and schedule forecast, which, at that time, did not change the total project capital cost forecast and confirmed the expected in-service dates of November 2021 for Unit 3 and

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November 2022 for Unit 4. This update included initiatives to improve productivity while refining and extending system turnover plans and certain near-term milestone dates. Other milestone dates did not change. Achievement of the February 2020 aggressive site work plan relied on meeting increased monthly production and activity target values during 2020.

In mid-March 2020, Southern Nuclear began implementing policies and procedures designed to mitigate the risk of transmission of COVID-19 at the construction site, including worker distancing measures, isolating individuals who have tested positive for COVID-19, are showing symptoms consistent with COVID-19, are being tested for COVID-19, or have been in close contact with such persons, requiring self-quarantine, and adopting additional precautionary measures.

In April 2020, Georgia Power, acting for itself and as agent for the other Vogtle Owners, announced a reduction in workforce at Plant Vogtle Units 3 and 4, which totaled approximately 20% of the then-existing site workforce. This reduction in workforce was a mitigation action intended to address the impact of the COVID-19 pandemic on the Plant Vogtle Units 3 and 4 workforce and construction site, including challenges with labor productivity that were exacerbated by the impact of the COVID-19 pandemic. The April 2020 workforce reduction was intended to provide operational efficiencies by increasing productivity of the remaining workforce and reducing workforce fatigue and absenteeism. Further, it was also intended to allow for increased social distancing by the workforce and facilitate compliance with the recommendations from the Centers for Disease Control and Prevention. The April 2020 workforce reduction did reduce absenteeism, providing an improvement in operational efficiency and allowing for increased social distancing. From the initial peak in April 2020, the number of active cases at the site declined significantly during May and early June, but began increasing again from mid-June through July, and continued to impact productivity levels and pace of activity completion. As a result of these factors, overall production improvements were not achieved at the levels anticipated, contributing to the June 30, 2020 allocation of, and increase in, construction contingency described above. Through mid-July 2020, Unit 3 mechanical, electrical, and subcontract activities continued to build a backlog to Southern Nuclear's February 2020 aggressive site work plan.

To address these issues, in July 2020, Southern Nuclear updated its aggressive site work plan for both Unit 3 and Unit 4. Through October 2020, the project has faced challenges in meeting the July 2020 aggressive site work plan targets including, but not limited to, overall construction and subcontractor labor productivity, which has resulted in a backlog of activities and completion percentages below the July 2020 aggressive site work plan targets. In addition, while the number of active COVID-19 cases at the site has declined since July 2020, the COVID-19 pandemic continues to impact productivity and the pace of activity completion. After considering these factors, Southern Nuclear has further extended milestone dates from the July 2020 aggressive site work plan. Achievement of these extended milestone dates depends on absenteeism rates continuing to normalize and overall construction productivity and production levels, including subcontractors, significantly improving and being sustained above pre-pandemic levels. In addition, appropriate levels of craft laborers, particularly electrical and pipefitter craft labor, need to be added and maintained. Georgia Power still expects to achieve the regulatory-approved in-service dates of November 2021 and November 2022 for Plant Vogtle Units 3 and 4, respectively. Southern Nuclear and Georgia Power continue to believe that pursuit of an aggressive site work plan is an appropriate strategy to achieve completion of the units by their regulatory-approved in-service dates.

As construction, including subcontract work, continues and testing and system turnover activities increase, challenges with management of contractors and vendors; subcontractor performance; supervision of craft labor and related productivity, particularly in the installation of electrical, mechanical, and instrumentation and controls commodities, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, installation, system turnover, and the initial testing and start-up, including any required engineering changes or any remediation related thereto, of plant systems, structures, or components (some of which are based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale), any of which may require additional labor and/or materials; or other issues could arise and change the projected schedule and estimated cost.

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In addition, the continuing effects of the COVID-19 pandemic could further disrupt or delay construction, testing, supervisory, and support activities at Plant Vogtle Units 3 and 4. Georgia Power's proportionate share of the estimated incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is currently estimated to be between $70 million and $115 million, which is included in the total project capital cost forecast and assumes (i) absenteeism rates continue to normalize and (ii) the intended productivity efficiencies and production targets assumed in Southern Nuclear's July 2020 aggressive site work plan are realized in the coming months. However, the ultimate impact of the COVID-19 pandemic on the construction schedule and budget for Plant Vogtle Units 3 and 4 cannot be determined at this time.

There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel, may arise, which may result in additional license amendments or require other resolution. As part of the aggressive site work plan, in January 2020, Southern Nuclear notified the NRC of its intent to load fuel in 2020. On June 15, 2020, the NRC rejected Nuclear Watch South's April 20, 2020 petition requesting a hearing and challenging the closure of certain ITAAC. On August 10, 2020, the Atomic Safety and Licensing Board rejected the Blue Ridge Environmental Defense League's (BREDL) May 11, 2020 petition challenging a license amendment request. The staff of the NRC has issued the requested amendment to the combined construction and operating license for Plant Vogtle Unit 3. BREDL appealed the Atomic Safety and Licensing Board decision to the NRC. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.

The ultimate outcome of these matters cannot be determined at this time. However, any extension of the regulatory-approved project schedule is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $10 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.

Joint Owner Contracts

In November 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 to provide for, among other conditions, additional Vogtle Owner approval requirements. Effective in August 2018, the Vogtle Owners further amended the joint ownership agreements to clarify and provide procedures for certain provisions of the joint ownership agreements related to adverse events that require the vote of the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 to continue construction (as amended, and together with the November 2017 amendment, the Vogtle Joint Ownership Agreements). The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.

As a result of an increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs in conjunction with the nineteenth VCM report in 2018, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. In September 2018, the Vogtle Owners unanimously voted to continue construction of Plant Vogtle Units 3 and 4.

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Amendments to the Vogtle Joint Ownership Agreements

In connection with the vote to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and MEAG Power's wholly-owned subsidiaries MEAG Power SPVJ, LLC (MEAG SPVJ), MEAG Power SPVM, LLC (MEAG SPVM), and MEAG Power SPVP, LLC (MEAG SPVP) to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners, including additional amendments to the Vogtle Joint Ownership Agreements and the purchase of PTCs from the other Vogtle Owners at pre-established prices, and (ii) a term sheet (MEAG Term Sheet) with MEAG Power and MEAG SPVJ to provide up to $300 million of funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. In January 2019, Georgia Power, MEAG Power, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. In February 2019, Georgia Power, the other Vogtle Owners, and MEAG Power's wholly-owned subsidiaries MEAG SPVJ, MEAG SPVM, and MEAG SPVP entered into certain amendments to the Vogtle Joint Ownership Agreements to implement the provisions of the Vogtle Owner Term Sheet (Global Amendments).

As previously disclosed, pursuant to the Global Amendments: (i) each Vogtle Owner must pay its proportionate share of qualifying construction costs for Plant Vogtle Units 3 and 4 based on its ownership percentage up to the estimated cost at completion (EAC) for Plant Vogtle Units 3 and 4 which formed the basis of Georgia Power's forecast of $8.4 billion in the nineteenth VCM plus $800 million; (ii) Georgia Power will be responsible for 55.7% of actual qualifying construction costs between $800 million and $1.6 billion over the EAC in the nineteenth VCM (resulting in $80 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests; and (iii) Georgia Power will be responsible for 65.7% of qualifying construction costs between $1.6 billion and $2.1 billion over the EAC in the nineteenth VCM (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests. If the EAC is revised and exceeds the EAC in the nineteenth VCM by more than $2.1 billion, each of the other Vogtle Owners will have a one-time option at the time the project budget forecast is so revised to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100% of such Vogtle Owner's remaining share of total construction costs in excess of the EAC in the nineteenth VCM plus $2.1 billion.

In addition, pursuant to the Global Amendments, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including, among other events: (i) the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power's public announcement of its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 or the Georgia PSC determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Vogtle Owners pursuant to the Global Amendments described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Georgia PSC for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates; and (iv) an incremental extension of one year or more over the most recently approved schedule.

The ultimate outcome of these matters cannot be determined at this time.

Regulatory Matters

In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. At September 30, 2020, Georgia Power had recovered approximately $2.5 billion of financing costs. Financing costs related to capital costs above $4.418 billion are being recognized through AFUDC and are expected

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to be recovered through retail rates over the life of Plant Vogtle Units 3 and 4; however, Georgia Power will not record AFUDC related to any capital costs in excess of the total deemed reasonable by the Georgia PSC (currently $7.3 billion) and not requested for rate recovery. On October 1, 2020, Georgia Power filed a request to decrease the NCCR tariff by $142 million annually, effective January 1, 2021, pending Georgia PSC approval.

Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 of each year. In 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.

In 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) Georgia Power's seventeenth VCM report and modified the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.68 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and related customer refunds) was found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap and that prudence decisions on cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective Unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $75 million in 2019 and are estimated to have negative earnings impacts of approximately $145 million, $255 million, and $200 million in 2020, 2021, and 2022, respectively. In its January 11, 2018 order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.

In February 2018, Georgia Interfaith Power & Light, Inc. (GIPL) and Partnership for Southern Equity, Inc. (PSE) filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. In March 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's decision and denial of Georgia Watch's motion for reconsideration. In December 2018, the Fulton County Superior Court granted Georgia Power's motion to dismiss the two appeals. In January 2019, GIPL, PSE, and Georgia Watch filed an appeal of this decision with the Georgia Court of Appeals. In October 2019, the Georgia Court of Appeals issued an opinion affirming the Fulton County Superior Court's ruling that the Georgia PSC's January 11, 2018 order was not a final, appealable decision. In addition, the Georgia Court of Appeals remanded the

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case to the Fulton County Superior Court to clarify its ruling as to whether the petitioners showed that review of the Georgia PSC's final order would not provide them an adequate remedy. On April 21, 2020, the Fulton County Superior Court granted Georgia Power's motion to dismiss the two appeals. The petitioners filed a notice of appeal of the dismissal on May 20, 2020, which was withdrawn on August 20, 2020. This matter is now concluded.

The Georgia PSC has approved 22 VCM reports covering the periods through December 31, 2019, including total construction capital costs incurred through that date of $7.4 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds). Georgia Power filed its twenty-third VCM report with the Georgia PSC on August 31, 2020, which reflects the capital cost forecast discussed above and requests approval of $701 million of construction capital costs incurred from January 1, 2020 through June 30, 2020.

The ultimate outcome of these matters cannot be determined at this time.

Mississippi Power

2019 Base Rate Case

On March 17, 2020, the Mississippi PSC approved a settlement agreement between Mississippi Power and the Mississippi Public Utilities Staff related to Mississippi Power's base rate case filed in November 2019 (Mississippi Power Rate Case Settlement Agreement).

Under the terms of the Mississippi Power Rate Case Settlement Agreement, annual retail rates decreased approximately $16.7 million, or 1.85%, effective for the first billing cycle of April 2020, based on a test year period of January 1, 2020 through December 31, 2020, a 53% average equity ratio, an allowed maximum actual equity ratio of 55% by the end of 2020, and a 7.57% return on investment.

Additionally, the approved Mississippi Power Rate Case Settlement Agreement: (i) established common amortization periods of four years for regulatory assets and three years for regulatory liabilities included in the approved revenue requirement, including those related to unprotected deferred income taxes; (ii) established new depreciation rates reflecting an annual increase in depreciation of approximately $10 million; and (iii) excluded certain compensation costs totaling approximately $3.9 million. It also eliminated separate rates for costs associated with Plant Ratcliffe and energy efficiency initiatives and includes such costs in the PEP, ECO Plan, and ad valorem tax adjustment factor, as applicable. In accordance with the previous order of the Mississippi PSC suspending the operation of PEP and the ECO Plan for 2018 through 2020, Mississippi Power plans to resume PEP proceedings and ECO Plan filings for 2021.

Performance Evaluation Plan

On July 24, 2020, the Mississippi PSC approved Mississippi Power's July 14, 2020 filing of its PEP compliance rate clause reflecting revisions agreed to in the Mississippi Power Rate Case Settlement Agreement. These revisions include, among other things, changing the filing date for the annual PEP rate filing from November of the immediately preceding year to March of the current year, utilizing a historic test year adjusted for "known and measurable" changes, using discounted cash flow and regression formulas to determine base return on equity, and moving all embedded ad valorem property taxes currently collected in PEP to the ad valorem tax adjustment clause.

Deferral of Incremental COVID-19 Costs

On April 14, 2020 and May 12, 2020, in order to mitigate the economic impact of the COVID-19 pandemic on customers, the Mississippi PSC approved orders directing Mississippi Power to continue its previous, voluntary suspension of customer disconnections through May 26, 2020 and to defer as a regulatory asset all necessary and reasonable incremental costs or expenses to plan, prepare, stage, or react to protect and keep safe its employees and customers, and to reliably operate its utility system during the COVID-19 pandemic. The period over which such costs will be recovered is expected to be determined in a future PEP filing. At September 30, 2020, the incremental costs deferred totaled approximately $2 million. The ultimate outcome of this matter cannot be determined at this time.

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Municipal and Rural Associations Tariff

On June 25, 2020, the FERC accepted Mississippi Power's April 27, 2020 request for an increase in wholesale base revenues under the MRA tariff as agreed upon in a settlement agreement reached with its wholesale customers. The MRA settlement agreement resulted in a $2 million annual increase in base rates effective June 1, 2020.

Southern Company Gas

Rate Proceedings

On June 1, 2020, Virginia Natural Gas filed a general rate case with the Virginia Commission seeking an increase in rates of $49.6 million primarily to recover investments and increased costs associated with infrastructure, technology, and workforce development. The requested increase is based on a projected 12-month test year beginning November 1, 2020, a ROE of 10.35%, and an equity ratio of 54%. Rate adjustments are expected to be effective November 1, 2020, subject to refund. The Virginia Commission is expected to rule on the requested increase in the second quarter 2021.

On July 1, 2020, Atlanta Gas Light filed its 2020 GRAM filing with the Georgia PSC. The filing requests an annual base rate increase of $37.6 million based on the projected 12-month period beginning January 1, 2021, which does not exceed the 5% limitation established by the Georgia PSC in its December 2019 approval of Atlanta Gas Light's general base rate case. Resolution of the 2020 GRAM filing is expected by December 31, 2020, with rates effective January 1, 2021.

The ultimate outcome of these matters cannot be determined at this time.

Deferral of Incremental COVID-19 Costs

Atlanta Gas Light

On April 30, 2020, in response to the COVID-19 pandemic, the Georgia PSC approved orders directing Atlanta Gas Light to continue its previous, voluntary suspension of customer disconnections. On June 22, 2020, the Georgia PSC ordered Atlanta Gas Light to resume customer disconnections beginning July 1, 2020, with exceptions for customers still covered by a shelter-in-place order. The orders provide the Marketers, including SouthStar, with a mechanism to receive credits from Atlanta Gas Light for the base rates it charged to the Marketers of non-paying customers during the suspension. Atlanta Gas Light expects to recover these credits through the annual revenue true-up process within its future GRAM filings, which would impact rates starting on January 1, 2022. The ultimate outcome of this matter cannot be determined at this time.

Nicor Gas

On March 18, 2020, in response to the COVID-19 pandemic, the Illinois Commission issued an order directing utilities to cease disconnections for non-payment and to suspend the imposition of late payment fees or penalties. In response to this order, on March 27, 2020, Nicor Gas and other utilities in Illinois filed their plans seeking cost recovery and providing more flexible credit and collection plans.

On June 18, 2020, the Illinois Commission approved a stipulation pursuant to which the utilities will provide more flexible credit and collection procedures to assist customers with financial hardship and which authorizes a special purpose rider for recovery of the following COVID-19 pandemic-related impacts: incremental costs directly associated with the COVID-19 pandemic, net of the offset for COVID-19 pandemic-related credits received, foregone late fees, foregone reconnection charges, and the costs associated with a bill payment assistance program. Nicor Gas resumed late payment fees on July 27, 2020 and, on October 1, 2020, began recovery of the COVID-19 pandemic-related impacts through the special purpose rider, which will continue over a 24-month period. In response to an Illinois Commission request, Nicor Gas will continue to voluntarily suspend residential customer disconnections for non-payment through March 31, 2021. At September 30, 2020, Nicor Gas' related regulatory asset was $13 million.

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Virginia Natural Gas

In response to the COVID-19 pandemic, the Virginia Commission issued orders requiring Virginia Natural Gas to suspend disconnections beginning on March 16, 2020 and also to suspend late payment and reconnection fees beginning on April 9, 2020, both of which expired on October 5, 2020. On April 29, 2020, the Virginia Commission authorized Virginia Natural Gas to defer the following COVID-19 pandemic-related costs as a regulatory asset: incremental uncollectible expense incurred, suspended late fees, suspended reconnection charges, carrying costs, and other incremental prudently incurred costs associated with the COVID-19 pandemic. Specific recovery of the amounts deferred in a regulatory asset will be addressed in a future rate proceeding. At September 30, 2020, Virginia Natural Gas' related regulatory asset was $1 million. The ultimate outcome of this matter cannot be determined at this time.

Infrastructure Replacement Programs and Capital Projects

In December 2019, Virginia Natural Gas filed an application with the Virginia Commission for a 24.1-mile header improvement project to improve resiliency and increase the supply of natural gas delivered to energy suppliers, including Virginia Natural Gas. On June 26, 2020, the Virginia Commission issued an order requiring Virginia Natural Gas to submit additional information by December 31, 2020 related to the financing plans of the project's primary customer before ruling on the December 2019 application. The ultimate outcome of this matter cannot be determined at this time.

(C) CONTINGENCIES

See Note 3 to the financial statements in Item 8 of the Form 10-K for information relating to various lawsuits and other contingencies.

General Litigation Matters

The Registrants are involved in various other matters being litigated and regulatory matters. The ultimate outcome of such pending or potential litigation or regulatory matters against each Registrant and any subsidiaries cannot be determined at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such Registrant's financial statements.

The Registrants believe the pending legal challenges discussed below have no merit; however, the ultimate outcome of these matters cannot be determined at this time.

Southern Company

In January 2017, a securities class action complaint was filed in the U.S. District Court for the Northern District of Georgia by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint names as defendants Southern Company, certain of its current and former officers, and certain former Mississippi Power officers and alleges that the defendants made materially false and misleading statements regarding the Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. In 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. Also in 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition. In 2018, the court issued an order dismissing certain claims against certain officers of Southern Company and Mississippi Power and dismissing the allegations related to a number of the statements that plaintiffs challenged as being false or misleading. In 2018, the court denied the defendants' motion for reconsideration and also denied a motion to certify the issue for interlocutory appeal. In the third quarter 2019, the court certified the plaintiffs' proposed class and the defendants filed a petition for interlocutory appeal of the class certification order with the U.S. Court of Appeals for the Eleventh Circuit. In December 2019, the U.S. District Court for the Northern

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District of Georgia entered an order staying all deadlines in the case pending mediation. The stay automatically expired on March 31, 2020; however, in light of the COVID-19 pandemic, the U.S. District Court for the Northern District of Georgia vacated all existing discovery deadlines until June 15, 2020. On June 30, 2020, the court entered a revised scheduling order, which resumed discovery and set out remaining case deadlines. On August 15, 2020, the parties reached a settlement. On September 8, 2020, the plaintiffs filed a stipulation of settlement and motion for preliminary approval to resolve the case on a class-wide basis, which the court granted on October 1, 2020. The settlement amount will be paid entirely through existing insurance policies and is not expected to have a material impact on Southern Company's financial statements.

In February 2017, Jean Vineyard and Judy Mesirov each filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its current and former officers, and certain former Mississippi Power officers. In 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. In 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the securities class action. On September 25, 2020, the plaintiffs filed a status report noting the settlement of the securities class action and informing the court that the parties have scheduled mediation of this case later in the fourth quarter 2020.

In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, Georgia that names as defendants Southern Company, certain of its directors, certain of its current and former officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. In 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the securities class action. In August 2019, the court granted a motion filed by the plaintiff in July 2019 to substitute a new named plaintiff, Martin J. Kobuck, in place of Helen E. Piper Survivor's Trust. On September 30, 2020, the plaintiffs filed a status report noting the settlement of the securities class action and informing the court that the parties have scheduled mediation of this case later in the fourth quarter 2020.

Georgia Power

In 2011, plaintiffs filed a putative class action against Georgia Power in the Superior Court of Fulton County, Georgia alleging that Georgia Power's collection in rates of amounts for municipal franchise fees (which fees are paid to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state law claims. This case has been ruled upon and appealed numerous times over the last several years. In one recent appeal, the Georgia Supreme Court remanded the case and noted that the trial court could refer the matter to the Georgia PSC to interpret its tariffs. Following a motion by Georgia Power, in February 2019, the Superior Court of Fulton County ordered the parties to submit petitions to the Georgia PSC for a declaratory ruling and also conditionally certified the proposed class. In March 2019, Georgia Power and the plaintiffs filed petitions with the Georgia PSC seeking confirmation of the proper application of the municipal franchise fee schedule pursuant to the Georgia PSC's orders. Also in March 2019, Georgia Power appealed the class certification decision to the Georgia Court of

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Appeals. In October 2019, the Georgia PSC issued an order that found Georgia Power has appropriately implemented the municipal franchise fee schedule. On March 11, 2020, the Georgia Court of Appeals vacated the Superior Court of Fulton County's February 2019 order granting conditional class certification. The Court of Appeals remanded the case to the Superior Court of Fulton County for further proceedings. In September 2020, the plaintiffs and Georgia Power each filed motions for summary judgment on all claims and the plaintiffs renewed their motion for class certification. The amount of any possible losses cannot be calculated at this time because, among other factors, it is unknown whether a class will be certified, the ultimate composition of any class, and whether any losses would be subject to recovery from any municipalities.

On July 29, 2020, a group of individual plaintiffs filed a complaint in the Superior Court of Fulton County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater, surface water, and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages, a medical monitoring fund, and injunctive relief.

Mississippi Power

In May 2018, Southern Company and Mississippi Power received a notice of dispute and arbitration demand filed by Martin Product Sales, LLC (Martin) based on two agreements, both related to Kemper IGCC byproducts for which Mississippi Power provided termination notices in 2017. Martin alleges breach of contract, breach of good faith and fair dealing, fraud and misrepresentation, and civil conspiracy and makes a claim for damages in the amount of approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest. A portion of the claim for damages was on behalf of Martin Transport, Inc. (Martin Transport), an affiliate of Martin. In May 2019, the arbitration panel denied Mississippi Power's and Southern Company's motions to dismiss. In September 2019, Martin Transport filed a separate complaint against Mississippi Power in the Circuit Court of Kemper County, Mississippi alleging claims of fraud, negligent misrepresentation, promissory estoppel, and equitable estoppel, each arising out of the same alleged facts and circumstances that underlie Martin's arbitration demand. Martin Transport seeks compensatory damages of $5 million and punitive damages of $50 million. In November 2019, Martin Transport's claim was combined with the Martin arbitration case and the separate court case was dismissed. In December 2019, Southern Company and Mississippi Power each filed motions for summary judgment on all claims. On February 17, 2020, the arbitration panel granted Southern Company's motion and dismissed Southern Company from the arbitration. On March 12, 2020, the arbitration panel denied Mississippi Power's motions for summary judgment. During the third quarter 2020, the plaintiffs reduced their claim for damages to approximately $76 million. On October 12, 2020, the arbitration panel issued a unanimous award in favor of Mississippi Power on all claims. This matter is now concluded.

In November 2018, Ray C. Turnage and 10 other individual plaintiffs filed a putative class action complaint against Mississippi Power and the three then-serving members of the Mississippi PSC in the U.S. District Court for the Southern District of Mississippi. Mississippi Power received Mississippi PSC approval in 2013 to charge a mirror CWIP rate premised upon including in its rate base pre-construction and construction costs for the Kemper IGCC prior to placing the Kemper IGCC into service. The Mississippi Supreme Court reversed that approval and ordered Mississippi Power to refund the amounts paid by customers under the previously-approved mirror CWIP rate. The plaintiffs allege that the initial approval process, and the amount approved, were improper. They also allege that Mississippi Power underpaid customers by up to $23.5 million in the refund process by applying an incorrect interest rate. The plaintiffs seek to recover, on behalf of themselves and their putative class, actual damages, punitive damages, pre-judgment interest, post-judgment interest, attorney's fees, and costs. In response to Mississippi Power and the Mississippi PSC each filing a motion to dismiss, the plaintiffs filed an amended complaint in March 2019. The amended complaint included four additional plaintiffs and additional claims for gross negligence, reckless conduct, and intentional wrongdoing. Mississippi Power and the Mississippi PSC have each filed a motion to dismiss the amended complaint. On March 27, 2020, the Mississippi PSC's motion to dismiss was granted. Also on March 27, 2020, the plaintiffs filed a motion seeking to name the new members of the Mississippi PSC, the Mississippi Development Authority, and Southern Company as additional defendants and add a cause of action against all defendants based on a dormant commerce clause theory under the U.S. Constitution. On April 9, 2020 and April 10, 2020, Mississippi Power and the Mississippi PSC, respectively, filed responses opposing the

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motion for leave to file a second amended complaint. On May 26, 2020, the court granted Mississippi Power's motion to dismiss the first amended complaint filed in 2019. On July 6, 2020, the plaintiffs filed a motion for revision of the court's decision. The plaintiffs' motion for leave to file a second amended complaint also remains pending before the court. On July 28, 2020, the plaintiffs filed a motion for leave to file a third amended complaint, which includes the same federal claims as the proposed second amended complaint, as well as several additional state law claims based on the allegation that Mississippi Power failed to disclose the annual percentage rate of interest applicable to refunds. An adverse outcome in this proceeding could have a material impact on Mississippi Power's financial statements.

See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility" in Item 8 of the Form 10-K for additional information.

Environmental Remediation

The Southern Company system must comply with environmental laws and regulations governing the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companies and the natural gas distribution utilities in Illinois and Georgia have each received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies.

Georgia Power's environmental remediation liability was $15 million at both September 30, 2020 and December 31, 2019. Georgia Power has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected.

In December 2019, Mississippi Power entered into an agreement with the Mississippi Commission on Environmental Quality related to groundwater conditions arising from the closed ash pond at Plant Watson. Mississippi Power will complete an assessment and remediation consistent with the requirements of the agreement and the CCR Rule. Potential remediation activities and related cost estimates are pending the result of further site assessment and cannot be determined at this time. Mississippi Power expects to recover the retail portion of remedial costs through the ECO Plan and the wholesale portion through MRA rates.

Southern Company Gas' environmental remediation liability was $252 million and $269 million as of September 30, 2020 and December 31, 2019, respectively, based on the estimated cost of environmental investigation and remediation associated with known current and former manufactured gas plant operating sites. These environmental remediation expenditures are generally recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies of the natural gas distribution utilities.

The ultimate outcome of these matters cannot be determined at this time; however, as a result of the regulatory treatment for environmental remediation expenses described above, the final disposition of these matters is not expected to have a material impact on the financial statements of the applicable Registrants.

Nuclear Fuel Disposal Costs

On August 13, 2020, Alabama Power and Georgia Power filed amended complaints in each of the lawsuits against the U.S. government in the Court of Federal Claims for the costs of continuing to store spent nuclear fuel at Plants Farley, Hatch, and Vogtle Units 1 and 2. The amended complaints add damages from January 1, 2018 to December 31, 2019 to the claim period. Damages will continue to accumulate until the issue is resolved, the U.S. government disposes of Alabama Power's and Georgia Power's spent nuclear fuel pursuant to its contractual obligations, or alternative storage is otherwise provided. No amounts have been recognized in the financial statements as of September 30, 2020 for any potential recoveries from the pending lawsuits. The final outcome of these matters cannot be determined at this time. However, Alabama Power and Georgia Power expect to credit any recoveries for

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the benefit of customers in accordance with direction from their respective PSC; therefore, no material impact on Southern Company's, Alabama Power's, or Georgia Power's net income is expected.

Other Matters

Southern Company

See Notes 1 and 3 under "Leveraged Leases" and "Other Matters – Southern Company," respectively, in Item 8 of the Form 10-K for discussion of challenges associated with a leveraged lease agreement with a subsidiary of Southern Holdings. While all required lease payments through September 30, 2020 have been paid in full, the operational and remarketing risks and the resulting cash liquidity challenges persist and significant concerns continue regarding the lessee's ability to make the remaining required semi-annual lease payments to the Southern Holdings subsidiary through the term of the lease.

In its annual impairment analysis of the expected residual value of the generation assets and the overall collectability of the related lease receivable, Southern Company uses multiple scenarios of long-term market energy prices to estimate the cash flows expected to be received from remarketing the generation assets following the expiration of the existing PPA in 2032 and the residual value of the generation assets at the end of the lease in 2047. Southern Company received the latest annual forecasts of natural gas prices during the second quarter 2020 and considered the significant decline in forecasted prices to be an indicator of potential impairment that required an interim impairment assessment. Accordingly, consistent with prior years, Southern Company evaluated the recoverability of the lease receivable and the expected residual value of the generation assets under various natural gas price scenarios. Based on the current forecasts of energy prices in the years following the expiration of the existing PPA, Southern Company concluded that it is no longer probable that any of the associated rental payments will be received, because it is no longer probable the generation assets will be successfully remarketed and continue to operate after that date. During the second quarter 2020, Southern Company revised the estimated cash flows to be received under the leveraged lease to reflect this conclusion, which resulted in a full impairment of the lease investment and a pre-tax charge to earnings of $154 million ($74 million after tax).

If any future lease payment due prior to the expiration of the associated PPA is not paid in full, the Southern Holdings subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. Failure to make the required payment to the debtholders could represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the generation assets, in effect terminating the lease. As the remaining amount of the lease investment was charged against earnings in the second quarter 2020, termination would not be expected to result in additional charges. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments and meet its obligations associated with a future closure or retirement of the generation assets and associated properties, including the dry ash landfill.

Mississippi Power

Kemper County Energy Facility

See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility" in Item 8 of the Form 10-K for additional information.

As the mining permit holder, Liberty Fuels Company, LLC has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities related to the lignite mine and equipment and mineral reserves located around the Kemper County energy facility site. As a result of the abandonment of the Kemper IGCC, final mine reclamation began in 2018 and is expected to be substantially completed in 2020, with monitoring expected to continue through 2027. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.

For year-to-date 2020, Mississippi Power recorded pre-tax (and after-tax) charges to income totaling $2 million primarily associated with abandonment and related closure costs and ongoing period costs, net of salvage proceeds,

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for the mine and gasifier-related assets at the Kemper County energy facility. Dismantlement of the abandoned gasifier-related assets and site restoration activities are expected to be completed in 2025. The additional pre-tax period costs associated with dismantlement and site restoration activities, including related costs for compliance and safety, ARO accretion, and property taxes, net of salvage, are estimated to total $3 million for the remainder of 2020 and $10 million to $15 million annually for 2021 through 2025.

In December 2019, Mississippi Power transferred ownership of the CO2 pipeline to an unrelated gas pipeline company, with no resulting impact on income. In conjunction with the transfer of the CO2 pipeline, the parties agreed to enter into a 15-year firm transportation agreement, which is expected to be signed by the end of 2020, providing for the conversion by the pipeline company of the CO2 pipeline to a natural gas pipeline to be used for the delivery of natural gas to Plant Ratcliffe. The agreement is expected to be treated as a finance lease for accounting purposes upon commencement.

On September 3, 2020, Mississippi Power and Southern Company executed an agreement with the DOE completing Mississippi Power's request for property closeout certification under the contract related to the DOE grants received for the Kemper County energy facility, which enables Mississippi Power to proceed with full dismantlement of the abandoned gasifier-related assets and site restoration activities. The execution of the agreement had no material impact on Mississippi Power's financial statements. In connection with the DOE closeout discussions, in April 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power of an investigation related to the $387 million of DOE grants received. The ultimate outcome of this matter cannot be determined at this time; however, it could have a material impact on Southern Company's and Mississippi Power's financial statements.

Plant Daniel

In conjunction with Southern Company's sale of Gulf Power, Mississippi Power and Gulf Power agreed to seek a restructuring of their 50% undivided ownership interests in Plant Daniel such that each of them would, after the restructuring, own 100% of a generating unit. On April 24, 2020, Mississippi Power and Gulf Power amended the terms of the agreement to extend the deadline from May 1, 2020 to August 1, 2020 for Mississippi Power to notify Gulf Power of which generating unit it has selected for 100% ownership. The parties agreed not to select a specific unit by August 1, 2020 and are continuing negotiations on a mutually acceptable revised operating agreement. The impacts of operating the units on an individual basis continue to be evaluated by Mississippi Power and any transfer of ownership would be subject to approval by the FERC and the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time.

Southern Company Gas

See Notes 3 and 7 to the financial statements in Item 8 of the Form 10-K under "Other Matters – Southern Company Gas" and "Southern Company Gas," respectively, and Note (E) under "Southern Company Gas" for additional information.

On March 24, 2020, Southern Company Gas completed the sale of its interest in Atlantic Coast Pipeline. See Note (K) under "Southern Company Gas" for additional information.

On February 20, 2020, the FERC approved a two-year extension for PennEast Pipeline to complete the project by January 19, 2022.

In September 2019, an appellate court ruled that the PennEast Pipeline does not have federal eminent domain authority over lands in which a state has property rights interests. On June 29, 2020, the U.S. Supreme Court requested the U.S. Solicitor General to provide an opinion on PennEast Pipeline's petition for a writ of certiorari seeking its review of the appellate court's decision.

Expected project costs related to the PennEast Pipeline for Southern Company Gas total approximately $300 million, excluding financing costs. The ultimate outcome of the PennEast Pipeline construction project cannot be determined at this time; however, any work delays, whether caused by judicial or regulatory action, abnormal weather, or other conditions, may result in additional cost or schedule modifications or, ultimately, in project

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(UNAUDITED)

cancellation, any of which could result in impairment of Southern Company Gas' investment and could have a significant impact on Southern Company's financial statements and a material impact on Southern Company Gas' financial statements.

(D) REVENUE FROM CONTRACTS WITH CUSTOMERS AND LEASE INCOME

Revenue from Contracts with Customers

The Registrants generate revenues from a variety of sources, some of which are not accounted for as revenue from contracts with customers, such as leases, derivatives, and certain cost recovery mechanisms. See Note 1 to the financial statements under "Revenues" in Item 8 of the Form 10-K for additional information on the revenue policies of the Registrants. See "Lease Income" herein and Note (J) for additional information on revenue accounted for under lease and derivative accounting guidance, respectively.

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The following table disaggregates revenue from contracts with customers for the three and nine months ended September 30, 2020 and 2019:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended September 30, 2020
Operating revenues
Retail electric revenues
Residential	$	2,019	$	752	$	1,183	$	84	$	—	$	—
Commercial	1,354		447		833		74		—		—
Industrial	783		358		352		73		—		—
Other	22		5		15		2		—		—
Total retail electric revenues	4,178		1,562		2,383		233		—		—
Natural gas distribution revenues
Residential	170		—		—		—		—		170
Commercial	41		—		—		—		—		41
Transportation	224		—		—		—		—		224
Industrial	4		—		—		—		—		4
Other	35		—		—		—		—		35
Total natural gas distribution revenues	474		—		—		—		—		474
Wholesale electric revenues
PPA energy revenues	214		40		13		2		165		—
PPA capacity revenues	136		26		15		1		95		—
Non-PPA revenues	59		10		3		93		68		—
Total wholesale electric revenues	409		76		31		96		328		—
Other natural gas revenues
Wholesale gas services	431		—		—		—		—		431
Gas marketing services	38		—		—		—		—		38
Other natural gas revenues	7		—		—		—		—		7
Total natural gas revenues	476		—		—		—		—		476
Other revenues	218		33		115		6		4		—
Total revenue from contracts with customers	5,755		1,671		2,529		335		332		950
Other revenue sources(a)	968		58		88		1		191		630
Other adjustments(b)	(1,103)		—		—		—		—		(1,103)
Total operating revenues	$	5,620	$	1,729	$	2,617	$	336	$	523	$	477

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	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Nine Months Ended September 30, 2020
Operating revenues
Retail electric revenues
Residential	$	4,802	$	1,839	$	2,760	$	203	$	—	$	—
Commercial	3,589		1,152		2,242		195		—		—
Industrial	2,081		956		907		218		—		—
Other	68		16		46		6		—		—
Total retail electric revenues	10,540		3,963		5,955		622		—		—
Natural gas distribution revenues
Residential	906		—		—		—		—		906
Commercial	229		—		—		—		—		229
Transportation	723		—		—		—		—		723
Industrial	21		—		—		—		—		21
Other	179		—		—		—		—		179
Total natural gas distribution revenues	2,058		—		—		—		—		2,058
Wholesale electric revenues
PPA energy revenues	550		94		38		7		425		—
PPA capacity revenues	339		78		30		3		231		—
Non-PPA revenues	159		33		7		235		184		—
Total wholesale electric revenues	1,048		205		75		245		840		—
Other natural gas revenues
Wholesale gas services	1,168		—		—		—		—		1,168
Gas marketing services	258		—		—		—		—		258
Other natural gas revenues	22		—		—		—		—		22
Total natural gas revenues	1,448		—		—		—		—		1,448
Other revenues	677		117		329		19		11		—
Total revenue from contracts with customers	15,771		4,285		6,359		886		851		3,506
Other revenue sources(a)	2,604		160		12		9		486		1,973
Other adjustments(b)	(3,117)		—		—		—		—		(3,117)
Total operating revenues	$	15,258	$	4,445	$	6,371	$	895	$	1,337	$	2,362

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	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended September 30, 2019
Operating revenues
Retail electric revenues
Residential	$	2,119	$	820	$	1,211	$	88	$	—	$	—
Commercial	1,563		512		965		86		—		—
Industrial	953		421		450		82		—		—
Other	26		7		16		3		—		—
Total retail electric revenues	4,661		1,760		2,642		259		—		—
Natural gas distribution revenues
Residential	162		—		—		—		—		162
Commercial	42		—		—		—		—		42
Transportation	204		—		—		—		—		204
Industrial	3		—		—		—		—		3
Other	30		—		—		—		—		30
Total natural gas distribution revenues	441		—		—		—		—		441
Wholesale electric revenues
PPA energy revenues	245		43		19		2		188		—
PPA capacity revenues	134		25		13		1		100		—
Non-PPA revenues	62		2		3		111		81		—
Total wholesale electric revenues	441		70		35		114		369		—
Other natural gas revenues
Wholesale gas services	425		—		—		—		—		425
Gas marketing services	37		—		—		—		—		37
Other natural gas revenues	10		—		—		—		—		10
Total natural gas revenues	472		—		—		—		—		472
Other revenues	267		36		113		4		3		—
Total revenue from contracts with customers	6,282		1,866		2,790		377		372		913
Other revenue sources(a)	855		(25)		(35)		(7)		202		727
Other adjustments(b)	(1,142)		—		—		—		—		(1,142)
Total operating revenues	$	5,995	$	1,841	$	2,755	$	370	$	574	$	498

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	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Nine Months Ended September 30, 2019
Operating revenues
Retail electric revenues
Residential	$	4,939	$	1,971	$	2,751	$	217	$	—	$	—
Commercial	3,951		1,301		2,427		223		—		—
Industrial	2,428		1,128		1,074		226		—		—
Other	69		20		41		8		—		—
Total retail electric revenues	11,387		4,420		6,293		674		—		—
Natural gas distribution revenues
Residential	992		—		—		—		—		992
Commercial	277		—		—		—		—		277
Transportation	673		—		—		—		—		673
Industrial	25		—		—		—		—		25
Other	191		—		—		—		—		191
Total natural gas distribution revenues	2,158		—		—		—		—		2,158
Wholesale electric revenues
PPA energy revenues	648		110		47		8		508		—
PPA capacity revenues	350		77		41		2		272		—
Non-PPA revenues	174		65		5		275		190		—
Total wholesale electric revenues	1,172		252		93		285		970		—
Other natural gas revenues
Wholesale gas services	1,590		—		—		—		—		1,590
Gas marketing services	313		—		—		—		—		313
Other natural gas revenues	32		—		—		—		—		32
Total natural gas revenues	1,935		—		—		—		—		1,935
Other revenues	763		119		298		14		10		—
Total revenue from contracts with customers	17,415		4,791		6,684		973		980		4,093
Other revenue sources(a)	3,266		(29)		22		(3)		547		2,744
Other adjustments(b)	(4,176)		—		—		—		—		(4,176)
Total operating revenues	$	16,505	$	4,762	$	6,706	$	970	$	1,527	$	2,661

(a)Other revenue sources primarily relate to revenues from customers accounted for as derivatives and leases, as well as alternative revenue programs at Southern Company Gas and other cost recovery mechanisms at the traditional electric operating companies.

(b)Other adjustments relate to the cost of Southern Company Gas' energy and risk management activities. Wholesale gas services revenues are presented net of the related costs of those activities on the statement of income. See Note (L) under "Southern Company Gas" for additional information on the components of wholesale gas services' operating revenues.

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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, 2020 and December 31, 2019:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Accounts Receivables
As of September 30, 2020	$	2,344	$	686	$	901	$	93	$	100	$	385
As of December 31, 2019	2,413		586		688		79		97		749
Contract Assets
As of September 30, 2020	$	159	$	5	$	103	$	—	$	—	$	—
As of December 31, 2019	117		—		69		—		—		—
Contract Liabilities
As of September 30, 2020	$	56	$	1	$	24	$	—	$	3	$	1
As of December 31, 2019	52		10		13		—		1		1

As of September 30, 2020 and December 31, 2019, Georgia Power had contract assets primarily related to fixed retail customer bill programs, where the payment is contingent upon Georgia Power's continued performance and the customer's continued participation in the program over a one-year contract term, 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 certain unregulated service agreements. Alabama Power had contract liabilities for outstanding performance obligations primarily related to extended service agreements. Southern Company's unregulated distributed generation business had $47 million and $40 million of contract assets and $22 million and $28 million of contract liabilities at September 30, 2020 and December 31, 2019, respectively, for outstanding performance obligations.

Revenues recognized by Southern Company in the three and nine months ended September 30, 2020, which were included in contract liabilities at December 31, 2019, were $8 million and $29 million, respectively, and immaterial for all other applicable Registrants.

Remaining Performance Obligations

The traditional electric operating companies and Southern Power have long-term contracts with customers in which revenues are recognized as performance obligations are satisfied over the contract term. These contracts primarily relate to PPAs whereby the traditional electric operating companies and Southern Power provide electricity and generation capacity to a customer. The revenue recognized for the delivery of electricity is variable; however, certain PPAs include a fixed payment for fixed generation capacity over the term of the contract. Southern Company's unregulated distributed generation business also has partially satisfied performance obligations related to certain fixed price contracts. Revenue from contracts with customers related to these performance obligations remaining at September 30, 2020 are expected to be recognized as follows:

	2020 (remaining)		2021		2022		2023		2024		2025 and Thereafter
	(in millions)
Southern Company	$	170	$	487	$	362	$	339	$	319	$	3,062
Alabama Power	7		33		31		24		7		5
Georgia Power	20		71		43		35		24		62
Southern Power	60		290		292		282		290		3,013

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(UNAUDITED)

Revenue expected to be recognized for performance obligations remaining at September 30, 2020 was immaterial for Mississippi Power.

Lease Income

Lease income for the three and nine months ended September 30, 2020 and 2019 is as follows:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
For the Three Months Ended September 30, 2020
Lease income - interest income on sales-type leases	$	3	$	—	$	—	$	3	$	—	$	—
Lease income - operating leases	50		11		14		—		21		9
Variable lease income	145		—		—		—		153		—
Total lease income	$	198	$	11	$	14	$	3	$	174	$	9
For the Nine Months Ended September 30, 2020
Lease income - interest income on sales-type leases	$	8	$	—	$	—	$	8	$	—	$	—
Lease income - operating leases	148		24		44		1		66		26
Variable lease income	345		—		—		—		368		—
Total lease income	$	501	$	24	$	44	$	9	$	434	$	26
For the Three Months Ended September 30, 2019
Lease income - interest income on sales-type leases	$	2	$	—	$	—	$	2	$	—	$	—
Lease income - operating leases	64		5		18		—		31		9
Variable lease income	141		—		—		—		151		—
Total lease income	$	207	$	5	$	18	$	2	$	182	$	9
For the Nine Months Ended September 30, 2019
Lease income - interest income on sales-type leases	$	7	$	—	$	—	$	7	$	—	$	—
Lease income - operating leases	216		19		57		—		111		26
Variable lease income	324		—		—		—		349		—
Total lease income	$	547	$	19	$	57	$	7	$	460	$	26

Lease income for Southern Power is included in wholesale revenues. Lease payments received under tolling arrangements and PPAs consist of either scheduled payments or variable payments based on the amount of energy produced by the underlying electric generating units.

As part of the Autauga Combined Cycle Acquisition, Alabama Power assumed an existing power sales agreement under which the full output of the generating facility remains committed to another third party for its remaining term of approximately three years. These revenues are included above as lease income from operating leases. See Note (B) and Note 15 to the financial statements in Item 8 of the Form 10-K under "Alabama Power" for additional information.

Lease Receivables

Mississippi Power completed construction of additional leased assets under an existing sales-type lease during the third quarter 2020. Upon completion of construction, the book value of $25 million was transferred from CWIP to lease receivables, of which $22 million and $3 million is included in other property and investments and other accounts and notes receivable, respectively, at September 30, 2020. The transfer represents a non-cash investing transaction for purposes of the statements of cash flows.

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(UNAUDITED)

(E) CONSOLIDATED ENTITIES AND EQUITY METHOD INVESTMENTS

See Note 7 to the financial statements in Item 8 of the Form 10-K for additional information.

Southern Power

Variable Interest Entities

Southern Power has certain subsidiaries that are determined to be VIEs. Southern Power is considered the 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.

SP Solar and SP Wind

At September 30, 2020 and December 31, 2019, SP Solar had total assets of $6.3 billion and $6.4 billion, respectively, and total liabilities of $382 million. Noncontrolling interests totaled $1.1 billion at both September 30, 2020 and December 31, 2019. Cash distributions from SP Solar are allocated 67% to Southern Power and 33% to Global Atlantic in accordance with their partnership interest percentage. Under the terms of the limited partnership agreement, distributions without limited partner consent are limited to available cash and SP Solar is obligated to 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, 2020 and December 31, 2019, SP Wind had total assets of $2.4 billion and $2.5 billion, respectively, total liabilities of $129 million and $128 million, respectively, and noncontrolling interests of $44 million and $45 million, respectively. Under the terms of the limited liability agreement, distributions without Class A member consent are limited to 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, 2020 and December 31, 2019, the other VIEs had total assets of $1.1 billion, total liabilities of $109 million and $104 million, respectively, and noncontrolling interests of $471 million and $409 million, 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, 2020 and December 31, 2019, Southern Power had equity method investments in wind and battery storage projects totaling $19 million and $28 million, respectively.

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Southern Company Gas

Equity Method Investments

On March 24, 2020, Southern Company Gas completed the sale of its interests in Pivotal LNG and Atlantic Coast Pipeline. See Note (K) under "Southern Company Gas" for additional information.

The carrying amounts of Southern Company Gas' equity method investments as of September 30, 2020 and December 31, 2019 and related income from those investments for the three and nine months ended September 30, 2020 and 2019 were as follows:

Investment Balance	September 30, 2020		December 31, 2019(a)
	(in millions)
SNG(b)	$	1,180	$	1,137
PennEast Pipeline(c)	89		82
Other	32		32
Total	$	1,301	$	1,251

(a)Excludes investments in Atlantic Coast Pipeline and Pivotal JAX LNG classified as held for sale at December 31, 2019. See Note 15 to the financial statements under "Assets Held for Sale" in Item 8 of the Form 10-K for additional information.

(b)Increase primarily relates to a capital contribution, partially offset by the continued amortization of deferred tax assets established upon acquisition.

(c)See Note (C) under "Other Matters – Southern Company Gas" for additional information on the PennEast Pipeline.

Earnings from Equity Method Investments	Three Months Ended September 30, 2020		Three Months Ended September 30, 2019		Nine Months Ended September 30, 2020		Nine Months Ended September 30, 2019
	(in millions)
SNG	$	30	$	30	$	95	$	104
Atlantic Coast Pipeline(a)(b)	—		3		3		9
PennEast Pipeline(a)	2		2		5		5
Other	1		—		3		(3)
Total	$	33	$	35	$	106	$	115

(a)Amounts primarily result from AFUDC equity recorded by the project entity.

(b)On March 24, 2020, Southern Company Gas completed the sale of its interest in Atlantic Coast Pipeline. See Note (K) under "Southern Company Gas" for additional information.

SNG

Selected financial information of SNG for the three and nine months ended September 30, 2020 and 2019 is as follows:

Income Statement Information	Three Months Ended September 30, 2020		Three Months Ended September 30, 2019		Nine Months Ended September 30, 2020		Nine Months Ended September 30, 2019
	(in millions)
Revenues	$	150	$	152	$	457	$	473
Operating income	85		82		262		274
Net income	59		60		189		208

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(F) FINANCING

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, 2020, committed credit arrangements with banks were as follows:

	Expires
Company	2021		2022		2023		2024		Total		Unused		Due within One Year
	(in millions)
Southern Company parent	$	—	$	—	$	—	$	2,000	$	2,000	$	1,999	$	—
Alabama Power	3		525		—		800		1,328		1,328		3
Georgia Power	—		—		—		1,750		1,750		1,728		—
Mississippi Power	—		150		125		—		275		250		—
Southern Power(a)	—		—		—		600		600		591		—
Southern Company Gas(b)	—		—		—		1,750		1,750		1,745		—
SEGCO	30		—		—		—		30		30		30
Southern Company	$	33	$	675	$	125	$	6,900	$	7,733	$	7,671	$	33

(a)Does not include Southern Power Company's $120 million and $60 million continuing letter of credit facilities for standby letters of credit expiring in 2021 and 2023, respectively, of which $23 million and $40 million, respectively, was unused at September 30, 2020. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities.

(b)Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.25 billion of this arrangement. Southern Company Gas' committed credit arrangement also includes $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. Pursuant to this multi-year credit arrangement, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted.

As reflected in the table above, in March 2020, Mississippi Power entered into a $125 million revolving credit facility that matures in March 2023.

Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.

These bank credit arrangements, as well as the term loan arrangements of the Registrants and SEGCO, contain covenants that limit debt levels and contain cross-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 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 the applicable borrower defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2020, 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 borrowings.

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, 2020 was approximately $1.4 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia Power, and $34 million at Mississippi Power). In addition, at September 30, 2020, Georgia Power had approximately $257 million of fixed rate revenue bonds outstanding that are required to be remarketed within the next 12 months.

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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 equity units issued in August 2019. 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 the Form 10-K for information on the August 2019 equity units issuance and Note 12 to the financial statements in Item 8 of the Form 10-K for information on stock-based compensation plans. Shares used to compute diluted earnings per share were as follows:

	Three Months Ended September 30, 2020	Three Months Ended September 30, 2019	Nine Months Ended September 30, 2020	Nine Months Ended September 30, 2019
	(in millions)
As reported shares	1,058	1,048	1,058	1,043
Effect of stock-based compensation	6	9	6	8
Diluted shares	1,064	1,057	1,064	1,051

An immaterial number of stock-based compensation awards was not included in the diluted earnings per share calculation because the awards were anti-dilutive for the three and nine months ended September 30, 2020. There were no such amounts for the three and nine months ended September 30, 2019.

An immaterial number of shares related to the equity units issued in August 2019 was included in the calculation of diluted earnings per share for the nine months ended September 30, 2020. There were no such amounts for all other periods presented.

(G) INCOME TAXES

See Note 10 to the financial statements in Item 8 of the Form 10-K for additional tax information.

Current and Deferred Income Taxes

Tax Credit and Net Operating Loss Carryforwards

Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) totaling $1.5 billion as of September 30, 2020 compared to $1.8 billion as of December 31, 2019.

The federal ITC and PTC carryforwards begin expiring in 2034 and 2032, respectively, but are expected to be fully utilized by 2024. The utilization of each Registrants' estimated tax credit and net operating loss carryforwards and related valuation allowances could be impacted by numerous factors, including the acquisition of additional renewable projects, the purchase of rights to additional PTCs of Plant Vogtle Units 3 and 4 pursuant to certain joint ownership agreements, potential impacts of the COVID-19 pandemic, and changes in taxable income projections. See Note (B) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information on Plant Vogtle Units 3 and 4.

Effective Tax Rate

Details of significant changes in the effective tax rate for the applicable Registrants are provided herein.

Southern Company

Southern Company's effective tax rate is typically lower than the statutory rate due to employee stock plans' dividend deduction, non-taxable AFUDC equity at the traditional electric operating companies, flowback of excess deferred income taxes at the regulated utilities, and federal income tax benefits from ITCs and PTCs primarily at Southern Power.

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Southern Company's effective tax rate was 13.9% for the nine months ended September 30, 2020 compared to 30.2% for the corresponding period in 2019. The effective tax rate decrease was primarily due to the tax impact from the sale of Gulf Power in 2019, as well as an increase in the flowback of excess deferred income taxes in 2020 primarily at Georgia Power. See Note 15 to the financial statements under "Southern Company" in Item 8 of the Form 10-K for additional information.

Georgia Power

Georgia Power's effective tax rate was 12.3% for the nine months ended September 30, 2020 compared to 22.6% for the corresponding period in 2019. The effective tax rate decrease was primarily due to an increase in the flowback of excess deferred income taxes in 2020 as authorized in the 2019 ARP, as well as the second quarter 2020 charge to earnings associated with the construction of Plant Vogtle Units 3 and 4. See Note (B) under "Georgia Power – Nuclear Construction" and Note 2 to the financial statements under "Georgia Power" in Item 8 of the Form 10-K for additional information.

Mississippi Power

Mississippi Power's effective tax rate was 12.7% for the nine months ended September 30, 2020 compared to 16.3% for the corresponding period in 2019. The effective tax rate decrease was primarily due to an increase in the flowback of excess deferred income taxes in 2020 as authorized in the Mississippi Power Rate Case Settlement Agreement. See Note (B) under "Mississippi Power – 2019 Base Rate Case" for additional information.

Southern Power

Southern Power's effective tax rate was 11.3% for the nine months ended September 30, 2020 compared to a benefit rate of (13.6)% for the corresponding period in 2019. The effective tax rate increase was primarily due to tax benefits resulting from ITCs recognized upon the sale of Plant Nacogdoches in 2019. See Note (K) under "Southern Power" for additional information.

Southern Company Gas

Southern Company Gas' effective tax rate was 21.4% for the nine months ended September 30, 2020 compared to 15.0% for the corresponding period in 2019. The effective tax rate increase was primarily due to higher flowback of excess deferred income taxes in 2019, primarily at Atlanta Gas Light as previously authorized by the Georgia PSC, and the reversal of a federal tax valuation allowance in connection with Southern Company Gas' sale of its investment in Triton in 2019. See Notes 2 and 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.

(H) RETIREMENT BENEFITS

The Southern Company system has a qualified defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees at PowerSecure. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2020. The Southern Company system also provides certain non-qualified defined benefits for a select group of management and highly compensated employees, which are funded on a cash basis. In addition, the Southern Company system provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric operating companies fund other postretirement trusts to the extent required by their respective regulatory commissions. Southern Company Gas has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses.

See Note 11 to the financial statements in Item 8 of the Form 10-K for additional information.

Effective January 1, 2020, Southern Company adopted a change in method of calculating the market-related value of the liability-hedging securities included in its pension plan assets. The market-related value is used to determine the expected return on plan assets component of net periodic pension cost. Southern Company previously used the

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(UNAUDITED)

calculated value approach for all plan assets, which smoothed asset returns and deferred gains and losses by amortizing them into the calculation of the market-related value over five years. Southern Company changed to the fair value approach for liability-hedging securities, which includes measuring the market-related value of that portion of the plan assets at fair value for purposes of determining the expected return on plan assets. The remaining asset classes of plan assets will continue to use the calculated value approach in determining the market-related value. Southern Company considers the fair value approach to be preferable because it results in a current reflection of changes in the value of plan assets in the measurement of net periodic pension cost. Southern Company evaluated the effect of this change in accounting method and deemed it immaterial to the historical and current financial statements of all Registrants and therefore did not account for the change retrospectively. The change in accounting principle was recorded through earnings as a prior period adjustment for the amounts related to the unregulated businesses of Southern Company and Southern Power. Amounts related to the traditional electric operating companies and the natural gas distribution utilities have been reflected as adjustments to regulatory assets as appropriate, consistent with the expected regulatory treatment.

On each Registrant's condensed statements of income, the service cost component of net periodic benefit costs is included in other operations and maintenance expenses and all other components of net periodic benefit costs are included in other income (expense), net. Components of the net periodic benefit costs for the three and nine months ended September 30, 2020 and 2019 are presented in the following tables.

Three Months Ended September 30, 2020	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	94	$	23	$	24	$	3	$	2	$	8
Interest cost	108		25		33		5		1		8
Expected return on plan assets	(274)		(66)		(87)		(13)		(4)		(20)
Amortization:
Prior service costs	—		1		—		—		—		(1)
Regulatory asset	—		—		—		—		—		4
Net (gain)/loss	67		17		22		4		1		2
Net periodic pension cost (income)	$	(5)	$	—	$	(8)	$	(1)	$	—	$	1
Postretirement Benefits
Service cost	$	6	$	1	$	2	$	(1)	$	1	$	—
Interest cost	13		4		5		1		—		2
Expected return on plan assets	(18)		(7)		(7)		—		—		(2)
Amortization:
Prior service costs	—		—		(1)		—		—		—
Regulatory asset	—		—		—		—		—		2
Net (gain)/loss	1		—		1		—		—		(1)
Net periodic postretirement benefit cost	$	2	$	(2)	$	—	$	—	$	1	$	1

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(UNAUDITED)

Nine Months Ended September 30, 2020	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	282	$	67	$	72	$	11	$	6	$	24
Interest cost	324		75		100		15		4		23
Expected return on plan assets	(824)		(198)		(261)		(38)		(10)		(59)
Amortization:
Prior service costs	1		1		1		—		—		(2)
Regulatory asset	—		—		—		—		—		12
Net (gain)/loss	201		53		65		10		2		7
Net periodic pension cost (income)	$	(16)	$	(2)	$	(23)	$	(2)	$	2	$	5
Postretirement Benefits
Service cost	$	17	$	4	$	5	$	—	$	1	$	1
Interest cost	40		10		15		2		—		5
Expected return on plan assets	(54)		(21)		(20)		(1)		—		(5)
Amortization:
Prior service costs	(1)		—		(1)		—		—		—
Regulatory asset	—		—		—		—		—		5
Net (gain)/loss	2		—		2		—		—		(2)
Net periodic postretirement benefit cost	$	4	$	(7)	$	1	$	1	$	1	$	4

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Three Months Ended September 30, 2019	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	73	$	17	$	19	$	3	$	2	$	7
Interest cost	123		28		38		6		1		9
Expected return on plan assets	(222)		(51)		(73)		(10)		(2)		(15)
Amortization:
Prior service costs	1		—		—		—		—		(1)
Regulatory asset	—		—		—		—		—		3
Net (gain)/loss	30		9		11		1		—		1
Net periodic pension cost (income)	$	5	$	3	$	(5)	$	—	$	1	$	4
Postretirement Benefits
Service cost	$	5	$	1	$	2	$	1	$	—	$	—
Interest cost	18		4		6		—		—		2
Expected return on plan assets	(16)		(6)		(7)		—		—		(1)
Amortization:
Prior service costs	—		1		—		—		—		—
Regulatory asset	—		—		—		—		—		1
Net (gain)/loss	(1)		—		1		—		—		—
Net periodic postretirement benefit cost	$	6	$	—	$	2	$	1	$	—	$	2

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Nine Months Ended September 30, 2019	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	219	$	51	$	56	$	9	$	5	$	19
Interest cost	369		85		116		17		4		27
Expected return on plan assets	(664)		(154)		(219)		(30)		(7)		(45)
Amortization:
Prior service costs	2		1		1		—		—		(2)
Regulatory asset	—		—		—		—		—		10
Net (gain)/loss	90		27		33		4		—		2
Net periodic pension cost (income)	$	16	$	10	$	(13)	$	—	$	2	$	11
Postretirement Benefits
Service cost	$	14	$	3	$	4	$	1	$	—	$	1
Interest cost	52		12		19		2		—		7
Expected return on plan assets	(49)		(19)		(19)		(1)		—		(4)
Amortization:
Prior service costs	2		3		—		—		—		—
Regulatory asset	—		—		—		—		—		4
Net (gain)/loss	(2)		—		1		—		—		(2)
Net periodic postretirement benefit cost	$	17	$	(1)	$	5	$	2	$	—	$	6

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(UNAUDITED)

(I) FAIR VALUE MEASUREMENTS

As of September 30, 2020, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:

	Fair Value Measurements Using:
As of September 30, 2020:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Southern Company
Assets:
Energy-related derivatives(a)	$	488	$	218	$	117	$	—	$	823
Interest rate derivatives	—		20		—		—		20
Foreign currency derivatives	—		29		—		—		29
Investments in trusts:(b)(c)
Domestic equity	754		137		—		—		891
Foreign equity	71		220		—		—		291
U.S. Treasury and government agency securities	—		268		—		—		268
Municipal bonds	—		99		—		—		99
Pooled funds – fixed income	—		17		—		—		17
Corporate bonds	15		376		—		—		391
Mortgage and asset backed securities	—		79		—		—		79
Private equity	—		—		—		68		68
Cash and cash equivalents	1		—		—		—		1
Other	25		6		—		—		31
Cash equivalents	2,750		11		—		—		2,761
Other investments	9		19		—		—		28
Total	$	4,113	$	1,499	$	117	$	68	$	5,797
Liabilities:
Energy-related derivatives(a)	$	521	$	155	$	75	$	—	$	751
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		19		—		19
Total	$	521	$	178	$	94	$	—	$	793

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	Fair Value Measurements Using:
As of September 30, 2020:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Alabama Power
Assets:
Energy-related derivatives	$	—	$	23	$	—	$	—	$	23
Nuclear decommissioning trusts:(b)
Domestic equity	477		128		—		—		605
Foreign equity	71		64		—		—		135
U.S. Treasury and government agency securities	—		21		—		—		21
Municipal bonds	—		1		—		—		1
Corporate bonds	15		159		—		—		174
Mortgage and asset backed securities	—		27		—		—		27
Private equity	—		—		—		68		68
Other	6		—		—		—		6
Cash equivalents	825		11		—		—		836
Other investments	—		19		—		—		19
Total	$	1,394	$	453	$	—	$	68	$	1,915
Liabilities:
Energy-related derivatives	$	—	$	6	$	—	$	—	$	6
Georgia Power
Assets:
Energy-related derivatives	$	—	$	31	$	—	$	—	$	31
Nuclear decommissioning trusts:(b)(c)
Domestic equity	277		1		—		—		278
Foreign equity	—		153		—		—		153
U.S. Treasury and government agency securities	—		247		—		—		247
Municipal bonds	—		98		—		—		98
Corporate bonds	—		217		—		—		217
Mortgage and asset backed securities	—		52		—		—		52
Other	19		6		—		—		25
Cash equivalents	485		—		—		—		485
Total	$	781	$	805	$	—	$	—	$	1,586
Liabilities:
Energy-related derivatives	$	—	$	9	$	—	$	—	$	9

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	Fair Value Measurements Using:
As of September 30, 2020:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	18	$	—	$	—	$	18
Cash equivalents	36		—		—		—		36
Total	$	36	$	18	$	—	$	—	$	54
Liabilities:
Energy-related derivatives	$	—	$	7	$	—	$	—	$	7
Southern Power
Assets:
Energy-related derivatives	$	—	$	5	$	—	$	—	$	5
Foreign currency derivatives	—		29		—		—		29
Cash equivalents	149		—		—		—		149
Total	$	149	$	34	$	—	$	—	$	183
Liabilities:
Energy-related derivatives	$	—	$	1	$	—	$	—	$	1
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		19		—		19
Total	$	—	$	24	$	19	$	—	$	43
Southern Company Gas
Assets:
Energy-related derivatives(a)	$	488	$	141	$	117	$	—	$	746
Non-qualified deferred compensation trusts:
Domestic equity	—		8		—		—		8
Foreign equity	—		3		—		—		3
Pooled funds – fixed income	—		17		—		—		17
Cash equivalents	1		—		—		—		1
Cash equivalents and restricted cash	113		—		—		—		113
Total	$	602	$	169	$	117	$	—	$	888
Liabilities:
Energy-related derivatives(a)	$	521	$	132	$	75	$	—	$	728

(a)Energy-related derivatives exclude cash collateral of $70 million.

(b)Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.

(c)Includes investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of September 30, 2020, approximately $25 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.

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(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, 2020 and 2019. The changes were recorded as a change to the regulatory assets and liabilities related to AROs for Georgia Power and Alabama Power, respectively.

Fair value increases (decreases)	Three Months Ended September 30, 2020		Three Months Ended September 30, 2019		Nine Months Ended September 30, 2020		Nine Months Ended September 30, 2019
	(in millions)
Southern Company	$	108	$	27	$	85	$	255
Alabama Power	66		15		24		140
Georgia Power	42		12		61		115

Valuation Methodologies

The energy-related derivatives primarily consist of exchange-traded and over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The fair value of cross-currency swaps reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and discount rates. The interest rate derivatives and cross-currency swaps are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note (J) for additional information on how these derivatives are used.

For fair value measurements of the investments within the nuclear decommissioning trusts and the non-qualified deferred compensation trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgments, are also obtained when available.

The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. See Note 6 to the financial statements under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

Southern Power has contingent payment obligations related to certain acquisitions whereby Southern Power is primarily obligated to make generation-based payments to the seller, which commenced at the commercial operation of the respective facility and continue through 2026. The obligation is categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate.

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(UNAUDITED)

The fair value of contingent consideration reflects the net present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial.

"Other investments" include investments traded in the open market that have maturities greater than 90 days, which are categorized as Level 2 under Fair Value Measurements and are comprised of corporate bonds, bank certificates of deposit, treasury bonds, and/or agency bonds.

As of September 30, 2020, the fair value measurements of private equity investments held in Alabama Power's nuclear decommissioning trusts that are calculated at net asset value per share (or its equivalent) as a practical expedient totaled $68 million and unfunded commitments related to the private equity investments totaled $67 million. Private equity investments include high-quality private equity funds across several market sectors and funds that invest in real estate assets. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated.

As of September 30, 2020, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas(*)
	(in millions)
Long-term debt, including securities due within one year:
Carrying amount	$	49,743	$	9,113	$	12,700	$	1,402	$	4,155	$	6,461
Fair value	56,739		10,741		15,052		1,562		4,535		7,640

(*)The long-term debt of Southern Company Gas is recorded at amortized cost, including the fair value adjustments at the effective date of the 2016 merger with Southern Company. Southern Company Gas amortizes the fair value adjustments over the lives of the respective bonds.

The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to the Registrants.

Commodity Contracts with Level 3 Valuation Inputs

As of September 30, 2020, the fair value of Southern Company Gas' Level 3 physical natural gas forward contracts was $42 million. Since commodity contracts classified as Level 3 typically include a combination of observable and unobservable components, the changes in fair value may include amounts due in part to observable market factors, or changes to assumptions on the unobservable components. The following table includes transfers to Level 3, which represent the fair value of Southern Company Gas' commodity derivative contracts that include a significant unobservable component for the first time during the period.

	Three Months Ended September 30, 2020		Nine Months Ended September 30, 2020
	(in millions)
Beginning balance	$	80	$	14
Transfers to Level 3	—		70
Transfers from Level 3	(2)		(5)
Instruments realized or otherwise settled during period	(9)		(16)
Changes in fair value	(27)		(21)
Ending balance	$	42	$	42

Changes in fair value of Level 3 instruments represent changes in gains and losses for the periods that are reported on Southern Company Gas' statements of income in natural gas revenues.

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The valuation of certain commodity contracts requires the use of certain unobservable inputs. All forward pricing used in the valuation of such contracts is directly based on third-party market data, such as broker quotes and exchange settlements, when that data is available. If third-party market data is not available, then industry standard methodologies are used to develop inputs that maximize the use of relevant observable inputs and minimize the use of unobservable inputs. Observable inputs, including some forward prices used for determining fair value, reflect the best available market information. Unobservable inputs are updated using industry standard techniques such as extrapolation, combining observable forward inputs supplemented by historical market and other relevant data. Level 3 physical natural gas forward contracts include unobservable forward price inputs (ranging from $(1.11) to $0.24 per mmBtu). Forward price increases (decreases) as of September 30, 2020 would have resulted in higher (lower) values on a net basis.

(J) DERIVATIVES

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Southern Company Gas' wholesale gas operations use various contracts in its commercial activities that generally meet the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note (I) for additional fair value information. In the statements of cash flows, any cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Any cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with classification of the hedged interest or principal, respectively. See Note 1 to the financial statements under "Financial Instruments" in Item 8 of the Form 10-K for additional information.

Energy-Related Derivatives

The traditional electric operating companies, Southern Power, and Southern Company Gas enter into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies and the natural gas distribution utilities have limited exposure to market volatility in energy-related commodity prices. Each of the traditional electric operating companies and certain of the natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs, implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies, through the use of financial derivative contracts, which are expected to continue to mitigate price volatility. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in energy-related commodity prices because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted capacity is used to sell electricity. Southern Company Gas retains exposure to price changes that can, in a volatile energy market, be material and can adversely affect its results of operations.

Southern Company Gas also enters into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in operating revenues.

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Energy-related derivative contracts are accounted for under one of three methods:

•Regulatory Hedges — Energy-related derivative contracts designated as regulatory hedges relate primarily to the traditional electric operating companies' and the natural gas distribution utilities' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses.

•Cash Flow Hedges — Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in accumulated OCI before being recognized in the statements of income in the same period and in the same income statement line item as the earnings effect of the hedged transactions.

•Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric and natural gas industries. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.

At September 30, 2020, the net volume of energy-related derivative contracts for natural gas positions, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows:

	Net Purchased mmBtu	Longest Hedge Date	Longest Non-Hedge Date
	(in millions)
Southern Company(*)	877	2024	2031
Alabama Power	78	2024	—
Georgia Power	131	2023	—
Mississippi Power	86	2024	—
Southern Power	14	2022	2021
Southern Company Gas(*)	568	2023	2031

(*)Southern Company Gas' derivative instruments include both long and short natural gas positions. A long position is a contract to purchase natural gas and a short position is a contract to sell natural gas. Southern Company Gas' volume represents the net of long natural gas positions of 4.6 billion mmBtu and short natural gas positions of 4.1 billion mmBtu as of September 30, 2020, which is also included in Southern Company's total volume.

At September 30, 2020, the net volume of Southern Power's energy-related derivative contracts for power to be sold was 1 million MWHs, all of which expire in 2021.

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 12 million mmBtu for Southern Company, which includes 3 million mmBtu for Alabama Power, 4 million mmBtu for Georgia Power, 1 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, 2021 are immaterial for all Registrants.

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Interest Rate Derivatives

Southern Company and certain subsidiaries may enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and presented on the same income statement line item as the earnings effect of the hedged transactions. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

At September 30, 2020, the following interest rate derivatives were outstanding:

	Notional Amount		Interest Rate Received	Weighted Average Interest Rate Paid	Hedge Maturity Date	Fair Value Gain (Loss) at September 30, 2020
	(in millions)					(in millions)
Cash Flow Hedges of Existing Debt
Mississippi Power	$	60	1-month LIBOR	0.58%	December 2021	$	—
Fair Value Hedges of Existing Debt
Southern Company parent	1,500		2.35%	1-month LIBOR + 0.87%	July 2021	20
Southern Company	$	1,560				$	20

For cash flow hedge 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, 2021 total $(25) million for Southern Company and are immaterial for all other Registrants. Deferred gains and losses related to interest rate derivatives are expected to be amortized into earnings through 2046 for the Southern Company parent entity, 2035 for Alabama Power, 2044 for Georgia Power, 2028 for Mississippi Power, and 2046 for Southern Company Gas.

Foreign Currency Derivatives

Southern Company and certain subsidiaries, including Southern Power, may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and on the same income statement line as the earnings effect of the hedged transactions, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

At September 30, 2020, the following foreign currency derivatives were outstanding:

	Pay Notional		Pay Rate	Receive Notional		Receive Rate	Hedge Maturity Date	Fair Value Gain (Loss) at September 30, 2020
	(in millions)			(in millions)				(in millions)
Cash Flow Hedges of Existing Debt
Southern Power	$	677	2.95%	€	600	1.00%	June 2022	$	11
Southern Power	564		3.78%	500		1.85%	June 2026	(5)
Total	$	1,241		€	1,100			$	6

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The estimated pre-tax gains (losses) related to Southern Power's foreign currency derivatives expected to be reclassified from accumulated OCI to earnings for the 12-month period ending September 30, 2021 are $(14) million.

Derivative Financial Statement Presentation and Amounts

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas enter into derivative contracts that may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Southern Company and certain subsidiaries also utilize master netting agreements to mitigate exposure to counterparty credit risk. These agreements may contain provisions that permit netting across product lines and against cash collateral. The fair value amounts of derivative assets and liabilities on the balance sheet are presented net to the extent that there are netting arrangements or similar agreements with the counterparties.

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The fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:

	As of September 30, 2020				As of December 31, 2019
Derivative Category and Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
	(in millions)				(in millions)
Southern Company
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	52	$	13	$	3	$	70
Other deferred charges and assets/Other deferred credits and liabilities	30		15		6		44
Total derivatives designated as hedging instruments for regulatory purposes	$	82	$	28	$	9	$	114
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	8	$	3	$	1	$	6
Other deferred charges and assets/Other deferred credits and liabilities	2		—		—		—
Interest rate derivatives:
Other current assets/Other current liabilities	19		—		2		23
Other deferred charges and assets/Other deferred credits and liabilities	—		—		—		1
Foreign currency derivatives:
Other current assets/Other current liabilities	—		23		—		24
Other deferred charges and assets/Other deferred credits and liabilities	29		—		16		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	58	$	26	$	19	$	54
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	392	$	428	$	461	$	358
Other deferred charges and assets/Other deferred credits and liabilities	338		291		207		225
Total derivatives not designated as hedging instruments	$	730	$	719	$	668	$	583
Gross amounts recognized	$	870	$	773	$	696	$	751
Gross amounts offset(a)	(636)		(706)		(463)		(562)
Net amounts recognized in the Balance Sheets(b)	$	234	$	67	$	233	$	189

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	As of September 30, 2020				As of December 31, 2019
Derivative Category and Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
	(in millions)				(in millions)
Alabama Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	14	$	2	$	2	$	14
Other deferred charges and assets/Other deferred credits and liabilities	9		4		2		10
Total derivatives designated as hedging instruments for regulatory purposes	$	23	$	6	$	4	$	24
Gross amounts recognized	$	23	$	6	$	4	$	24
Gross amounts offset	(5)		(5)		(2)		(2)
Net amounts recognized in the Balance Sheets	$	18	$	1	$	2	$	22
Georgia Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	18	$	3	$	1	$	32
Other deferred charges and assets/Other deferred credits and liabilities	13		6		3		21
Total derivatives designated as hedging instruments for regulatory purposes	$	31	$	9	$	4	$	53
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	—	$	—	$	—	$	17
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	—	$	—	$	—	$	17
Gross amounts recognized	$	31	$	9	$	4	$	70
Gross amounts offset	(9)		(9)		(3)		(3)
Net amounts recognized in the Balance Sheets	$	22	$	—	$	1	$	67

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	As of September 30, 2020				As of December 31, 2019
Derivative Category and Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
	(in millions)				(in millions)
Mississippi Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	10	$	2	$	—	$	15
Other deferred charges and assets/Other deferred credits and liabilities	8		5		1		12
Total derivatives designated as hedging instruments for regulatory purposes	$	18	$	7	$	1	$	27
Gross amounts recognized	$	18	$	7	$	1	$	27
Gross amounts offset	(7)		(7)		(1)		(1)
Net amounts recognized in the Balance Sheets	$	11	$	—	$	—	$	26
Southern Power
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	4	$	1	$	1	$	2
Other deferred charges and assets/Other deferred credits and liabilities	1		—		—		—
Foreign currency derivatives:
Other current assets/Other current liabilities	—		23		—		24
Other deferred charges and assets/Other deferred credits and liabilities	29		—		16		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	34	$	24	$	17	$	26
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	—	$	—	$	2	$	1
Total derivatives not designated as hedging instruments	$	—	$	—	$	2	$	1
Gross amounts recognized	$	34	$	24	$	19	$	27
Gross amounts offset	(1)		(1)		—		—
Net amounts recognized in the Balance Sheets	$	33	$	23	$	19	$	27

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	As of September 30, 2020				As of December 31, 2019
Derivative Category and Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
	(in millions)				(in millions)
Southern Company Gas
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	10	$	6	$	—	$	9
Other deferred charges and assets/Other deferred credits and liabilities	—		—		—		1
Total derivatives designated as hedging instruments for regulatory purposes	$	10	$	6	$	—	$	10
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	4	$	2	$	—	$	4
Other deferred charges and assets/Other deferred credits and liabilities	1		—		—		—
Interest rate derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	—		—		2		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	5	$	2	$	2	$	4
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	392	$	428	$	459	$	357
Other deferred charges and assets/Other deferred credits and liabilities	338		291		207		225
Total derivatives not designated as hedging instruments	$	730	$	719	$	666	$	582
Gross amounts of recognized	$	745	$	727	$	668	$	596
Gross amounts offset(a)	(614)		(684)		(456)		(555)
Net amounts recognized in the Balance Sheets(b)	$	131	$	43	$	212	$	41

(a)Gross amounts offset include cash collateral held on deposit in broker margin accounts of $70 million and $99 million as of September 30, 2020 and December 31, 2019, respectively.

(b)Net amounts of derivative instruments outstanding exclude premium and intrinsic value associated with weather derivatives of $3 million and $4 million as of September 30, 2020 and December 31, 2019, respectively.

The traditional electric operating companies had no energy-related derivatives not designated as hedging instruments at September 30, 2020 and immaterial amounts at December 31, 2019.

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At September 30, 2020 and December 31, 2019, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Company Gas
	(in millions)
At September 30, 2020:
Energy-related derivatives:
Other regulatory assets, current	$	(5)	$	—	$	—	$	—	$	(5)
Other regulatory liabilities, current	41		12		15		8		6
Other regulatory liabilities, deferred	15		5		7		3		—
Total energy-related derivative gains (losses)	$	51	$	17	$	22	$	11	$	1
At December 31, 2019:
Energy-related derivatives:
Other regulatory assets, current	$	(63)	$	(14)	$	(31)	$	(15)	$	(3)
Other regulatory assets, deferred	(37)		(8)		(18)		(11)		—
Other regulatory liabilities, current	6		2		—		—		4
Total energy-related derivative gains (losses)	$	(94)	$	(20)	$	(49)	$	(26)	$	1

For the three and nine months ended September 30, 2020 and 2019, the pre-tax effects of cash flow hedge accounting on accumulated OCI were as follows:

Gain (Loss) Recognized in OCI on Derivative	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)				(in millions)
Southern Company
Energy-related derivatives	$	9	$	(5)	$	2	$	(11)
Interest rate derivatives	1		(52)		(27)		(88)
Foreign currency derivatives	54		(68)		(10)		(107)
Total	$	64	$	(125)	$	(35)	$	(206)
Georgia Power
Interest rate derivatives	$	—	$	(47)	$	(3)	$	(83)
Southern Power
Energy-related derivatives	$	5	$	(3)	$	2	$	(5)
Foreign currency derivatives	54		(68)		(10)		(107)
Total	$	59	$	(71)	$	(8)	$	(112)
Southern Company Gas
Energy-related derivatives	$	4	$	(2)	$	—	$	(6)
Interest rate derivatives	1		(5)		(24)		(5)
Total	$	5	$	(7)	$	(24)	$	(11)

For the three and nine months ended September 30, 2020 and 2019, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on accumulated OCI were immaterial for the other Registrants.

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For the three and nine months ended September 30, 2020 and 2019, the pre-tax effects of cash flow and fair value hedge accounting on income were as follows:

Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)				(in millions)
Southern Company
Total cost of natural gas	$	71	$	79	$	654	$	956
Gain (loss) on energy-related cash flow hedges(a)	—		—		(8)		—
Total depreciation and amortization	889		760		2,619		2,267
Gain (loss) on energy-related cash flow hedges(a)	(1)		(1)		(3)		(5)
Total interest expense, net of amounts capitalized	(443)		(434)		(1,343)		(1,294)
Gain (loss) on interest rate cash flow hedges(a)	(6)		(5)		(19)		(14)
Gain (loss) on foreign currency cash flow hedges(a)	(6)		(6)		(18)		(18)
Gain (loss) on interest rate fair value hedges(b)	(3)		10		27		43
Total other income (expense), net	113		61		319		239
Gain (loss) on foreign currency cash flow hedges(a)(c)	56		(54)		52		(62)
Southern Power
Total depreciation and amortization	$	129	$	120	$	367	$	357
Gain (loss) on energy-related cash flow hedges(a)	(1)		(1)		(3)		(5)
Total interest expense, net of amounts capitalized	(36)		(43)		(114)		(127)
Gain (loss) on foreign currency cash flow hedges(a)	(6)		(6)		(18)		(18)
Total other income (expense), net	13		6		19		48
Gain (loss) on foreign currency cash flow hedges(a)(c)	56		(54)		52		(62)

(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, 2020 and 2019, the pre-tax effects of cash flow and fair value hedge accounting on income for energy-related derivatives and interest rate derivatives were immaterial for the traditional electric operating companies and Southern Company Gas.

As of September 30, 2020 and December 31, 2019, the following amounts were recorded on the balance sheets related to cumulative basis adjustments for fair value hedges:

	Carrying Amount of the Hedged Item				Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item
Balance Sheet Location of Hedged Items	As of September 30, 2020		As of December 31, 2019		As of September 30, 2020		As of December 31, 2019
	(in millions)				(in millions)
Southern Company
Securities due within one year	$	(1,513)	$	(599)	$	(15)	$	—
Long-term debt	—		(1,494)		—		3

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For the three and nine months ended September 30, 2020 and 2019, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income of Southern Company and Southern Company Gas were as follows:

		Gain (Loss)
		Three Months Ended September 30,				Nine Months Ended September 30,
Derivatives in Non-Designated Hedging Relationships	Statements of Income Location	2020		2019		2020		2019
		(in millions)				(in millions)
Energy-related derivatives:	Natural gas revenues(*)	$	(30)	$	(2)	$	54	$	81
	Cost of natural gas	5		2		18		5
Total derivatives in non-designated hedging relationships		$	(25)	$	—	$	72	$	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, 2020 and 2019, the pre-tax effects of energy-related derivatives not designated as hedging instruments were immaterial for all other Registrants.

Contingent Features

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At September 30, 2020, the Registrants had no collateral posted with derivative counterparties to satisfy these arrangements.

For the Registrants with interest rate derivatives at September 30, 2020, the fair value of interest rate derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, was immaterial. At September 30, 2020, the fair value of energy-related derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were immaterial for all Registrants. The maximum potential collateral requirements arising from the credit-risk-related contingent features for the traditional electric operating companies and Southern Power include certain agreements that could require collateral in the event that one or more Southern Company power pool participants has a credit rating change to below investment grade. Following the sale of Gulf Power to NextEra Energy, Gulf Power is continuing to participate in the Southern Company power pool for a defined transition period that, subject to certain potential adjustments, is scheduled to end on January 1, 2024.

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.

Alabama Power and Southern Power maintain accounts with certain regional transmission organizations to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Alabama Power and Southern Power may be required to post collateral. At September 30, 2020, cash collateral posted in these accounts was immaterial. Southern Company Gas maintains accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Southern Company Gas may be required to deposit cash into these accounts. At September 30, 2020, cash collateral held on deposit in broker margin accounts was $70 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

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(UNAUDITED)

investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Registrants have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate their exposure to counterparty credit risk. Prior to entering into a physical transaction, Southern Company Gas assigns physical wholesale counterparties an internal credit rating 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.

In addition, Southern Company Gas conducts credit evaluations and obtains appropriate internal approvals for the counterparty's line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody's and BBB- from S&P. Generally, Southern Company Gas requires credit enhancements by way of a guaranty, cash deposit, or letter of credit for transaction counterparties that do not have investment grade ratings.

Southern Company Gas also utilizes master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When Southern Company Gas is engaged in more than one outstanding derivative transaction with the same counterparty and it also has a legally enforceable netting agreement with that counterparty, the "net" mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of Southern Company Gas' credit risk. Southern Company Gas also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Master netting agreements enable Southern Company Gas to net certain assets and liabilities by counterparty. Southern Company Gas also nets across product lines and against cash collateral provided the master netting and cash collateral agreements include such provisions. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.

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, including details of assets and liabilities held for sale at December 31, 2019 for Southern Company, Southern Power, and Southern Company Gas. The Registrants had no material assets or liabilities held for sale at September 30, 2020.

Alabama Power

On August 31, 2020, Alabama Power completed the Autauga Combined Cycle Acquisition. The total purchase price was $461 million, of which $452 million was related to net assets recorded within property, plant, and equipment on the balance sheet and the remainder primarily related to inventory, current receivables, and accounts payable. Alabama Power assumed an existing power sales agreement under which the full output of the generating facility remains committed to another third party for its remaining term of approximately three years. During the remaining term, the estimated revenues from the power sales agreement are expected to offset the associated costs of operation. See Notes (B) and (D) under "Alabama Power" and "Lease Income," respectively, for additional information.

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(UNAUDITED)

Southern Power

Asset Acquisitions

During the nine months ended September 30, 2020, Southern Power acquired a controlling interest in the wind facility listed below. Acquisition-related costs were expensed as incurred and were not material.

Project Facility	Resource	Seller	Approximate Nameplate Capacity (MW)	Location	Southern Power Ownership Percentage		COD	PPA Contract Period
Beech Ridge II	Wind	Invenergy Renewables LLC	56	Greenbrier County, West Virginia	100% of Class A	(*)	May 2020	12 years

(*)In May 2020, Southern Power purchased 100% of the Class A membership interests and now owns the controlling interest in the project, with the Class B member, Invenergy Renewables LLC, owning the noncontrolling interest.

In March 2020, Southern Power entered into an agreement to acquire a controlling membership interest in an approximately 300-MW wind facility located in South Dakota. The acquisition is subject to FERC approval and certain other customary conditions to closing, including commercial operation of the facility, which is expected to occur in the first quarter 2021. The facility's output is contracted under two long-term PPAs. The ultimate outcome of this matter cannot be determined at this time.

Construction Projects

During the nine months ended September 30, 2020, Southern Power completed construction of and placed in service the Reading wind facility, continued construction of the Skookumchuck wind facility, and commenced construction of the Garland and Tranquillity battery energy storage facilities. Total aggregate construction costs, excluding acquisition costs, are expected to be between $475 million and $545 million for the facilities under construction. At September 30, 2020, total costs of construction incurred for these projects were $244 million and are included in CWIP. The ultimate outcome of these matters cannot be determined at this time.

Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Actual/Expected COD	PPA Contract Period
Projects Completed During the Nine Months Ended September 30, 2020
Reading(a)	Wind	200	Osage and Lyon Counties, KS	May 2020	12 years
Projects Under Construction as of September 30, 2020
Skookumchuck(b)	Wind	136	Lewis and Thurston Counties, WA	November 2020	20 years
Garland Solar Storage(c)	Battery energy storage system	88	Kern County, CA	Second quarter 2021	20 years
Tranquillity Solar Storage(c)	Battery energy storage system	72	Fresno County, CA	Second quarter 2021	20 years

(a)In 2018, Southern Power purchased 100% of the membership interests of the Reading facility pursuant to a joint development arrangement. At the time the facility was placed in service, Southern Power recorded an operating lease right-of-use asset and an operating lease liability, each in the amount of $24 million. In June 2020, Southern Power completed a tax equity transaction whereby it received $156 million and now owns 100% of the Class B membership interests.

(b)In October 2019, Southern Power purchased 100% of the membership interests of the Skookumchuck facility pursuant to a joint development arrangement. Southern Power expects to complete a tax equity transaction upon commercial operation and retain the Class B membership interests. Shortly after the completed tax equity transaction, Southern Power may sell a noncontrolling interest in these Class B membership interests to another partner. Southern Power would retain the controlling ownership interest in the facility. The ultimate outcome of these matters cannot be determined at this time.

(c)Prior to commercial operation, Southern Power may enter into one or more partnerships, in which case it would ultimately own less than 100% of the Class B membership interests, but would retain ownership of the controlling interest. The ultimate outcome of this matter cannot be determined at this time.

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(UNAUDITED)

Development Projects

Southern Power continues to evaluate and refine the deployment of the remaining wind turbine equipment purchased in 2016 and 2017 to development and construction projects. During the nine months ended September 30, 2020, certain wind turbine equipment was sold, resulting in an immaterial gain.

Sales of Natural Gas and Biomass Plants

On January 17, 2020, Southern Power completed the sale of its equity interests in Plant Mankato (including the 385-MW expansion unit completed in May 2019) to a subsidiary of Xcel for a purchase price of approximately $663 million, including final working capital adjustments. The sale resulted in a gain of approximately $39 million ($23 million after tax). The assets and liabilities of Plant Mankato were classified as held for sale on Southern Company's and Southern Power's balance sheets at December 31, 2019.

Plants Nacogdoches (sold in June 2019) and Mankato represented individually significant components of Southern Power; therefore, pre-tax income for these components for the three months ended September 30, 2019 and the nine months ended September 30, 2020 and 2019 is presented below:

	Three Months Ended September 30, 2019		Nine Months Ended September 30,
			2020		2019
	(in millions)
Southern Power's earnings before income taxes:(*)
Plant Nacogdoches	$	—	N/A		$	16
Plant Mankato	$	12	$	2	$	20

(*)Earnings before income taxes for components reflect the cessation of depreciation and amortization on the long-lived assets being sold upon classification as held for sale in November 2018 and April 2019 for Plant Mankato and Plant Nacogdoches, respectively.

Southern Company Gas

On March 24, 2020, Southern Company Gas completed the sale of its interests in Pivotal LNG and Atlantic Coast Pipeline to Dominion Modular LNG Holdings, Inc. and Dominion Atlantic Coast Pipeline, LLC, respectively, with aggregate proceeds of $178 million, including working capital adjustments. The loss associated with the transactions was immaterial. Southern Company Gas also expects to receive payments in February 2021 and September 2021 of $5 million each contingent upon Dominion Modular LNG Holdings, Inc. meeting certain milestones related to Pivotal LNG. The assets and liabilities of Pivotal LNG and the interest in Atlantic Coast Pipeline were classified as held for sale at December 31, 2019. See Notes 3 and 7 under "Other Matters – Southern Company Gas – Gas Pipeline Projects" and "Southern Company Gas – Equity Method Investments," respectively, in Item 8 of the Form 10-K and Notes (C) and (E) under "Other Matters – Southern Company Gas" and "Southern Company Gas," respectively.

(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 – Alabama Power, Georgia Power, and Mississippi Power – 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 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, wholesale gas services, and gas marketing services.

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(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 $101 million and $279 million for the three and nine months ended September 30, 2020, respectively, and $116 million and $320 million for the three and nine months ended September 30, 2019, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies were immaterial for the three and nine months ended September 30, 2020 and $9 million and $13 million for the three and nine months ended September 30, 2019, respectively. Revenues from sales of natural gas from Southern Company Gas to Southern Power were $9 million and $22 million for the three and nine months ended September 30, 2020, respectively, and $20 million and $53 million for the three and nine months ended September 30, 2019, respectively. The "All Other" column includes the Southern Company parent entity, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include providing energy solutions to electric utilities and their customers in the areas of distributed generation, energy storage and renewables, and energy efficiency, as well as investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material.

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(UNAUDITED)

Financial data for business segments and products and services for the three and nine months ended September 30, 2020 and 2019 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, 2020
Operating revenues	$	4,629	$	523	$	(103)	$	5,049	$	477	$	132	$	(38)	$	5,620
Segment net income (loss)(a)	1,284		74		—		1,358		14		(122)		1		1,251
Nine Months Ended September 30, 2020
Operating revenues	$	11,576	$	1,337	$	(285)	$	12,628	$	2,362	$	380	$	(112)	$	15,258
Segment net income (loss)(a)(b)(c)(d)	2,571		212		—		2,783		360		(420)		9		2,732
At September 30, 2020
Goodwill	$	—	$	2	$	—	$	2	$	5,015	$	263	$	—	$	5,280
Total assets	85,218		13,424		(671)		97,971		21,932		4,116		(861)		123,158
Three Months Ended September 30, 2019
Operating revenues	$	4,908	$	574	$	(119)	$	5,363	$	498	$	146	$	(12)	$	5,995
Segment net income (loss)(a)(e)(f)	1,373		86		—		1,459		(29)		(110)		(4)		1,316
Nine Months Ended September 30, 2019
Operating revenues	$	12,252	$	1,527	$	(331)	$	13,448	$	2,661	$	514	$	(118)	$	16,505
Segment net income (loss)(a)(e)(f)(g)	2,719		316		—		3,035		347		931		(15)		4,298
At December 31, 2019
Goodwill	$	—	$	2	$	—	$	2	$	5,015	$	263	$	—	$	5,280
Total assets	81,063		14,300		(713)		94,650		21,687		3,511		(1,148)		118,700

(a)Attributable to Southern Company.

(b)Segment net income (loss) for the traditional electric operating companies includes a pre-tax charge of $149 million ($111 million after tax) related to Plant Vogtle Units 3 and 4. See Note (B) under "Georgia Power – Nuclear Construction" for additional information.

(c)Segment net income (loss) for the "All Other" column includes a pre-tax impairment charge of $154 million ($74 million after tax) related to a leveraged lease investment. See Note (C) under "Other Matters – Southern Company" for additional information.

(d)Segment net income (loss) for Southern Power includes a $39 million pre-tax gain ($23 million gain after tax) on the sale of Plant Mankato. See Note (K) under "Southern Power" for additional information.

(e)Segment net income (loss) for Southern Company Gas includes a pre-tax impairment charge of $92 million ($65 million after tax) related to a natural gas storage facility in Louisiana. See Note 3 to the financial statements under "Other Matters – Southern Company Gas – Natural Gas Storage Facilities" in Item 8 of the Form 10-K for additional information.

(f)Segment net income (loss) for the "All Other" column includes the preliminary pre-tax gain associated with the sale of Gulf Power of $2.5 billion ($1.3 billion after tax) for the nine months ended September 30, 2019, as well as impairment charges in contemplation of the sales of two of PowerSecure's business units totaling $18 million and $50 million for the three and nine months ended September 30, 2019, respectively. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company" for additional information.

(g)Segment net income (loss) for Southern Power includes a $23 million pre-tax gain ($88 million gain after tax) on the sale of Plant Nacogdoches. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power – Sale of Natural Gas and Biomass Plants" for additional information.

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(UNAUDITED)

Products and Services

	Electric Utilities' Revenues
	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended September 30, 2020	$	4,243	$	584	$	222	$	5,049
Three Months Ended September 30, 2019	4,512		625		226		5,363
Nine Months Ended September 30, 2020	$	10,503	$	1,473	$	652	$	12,628
Nine Months Ended September 30, 2019	11,136		1,667		645		13,448

	Southern Company Gas' Revenues
	Gas Distribution Operations		Wholesale Gas Services(*)		Gas Marketing Services		Other		Total
	(in millions)
Three Months Ended September 30, 2020	$	476	$	(51)	$	39	$	13	$	477
Three Months Ended September 30, 2019	445		(2)		39		16		498
Nine Months Ended September 30, 2020	$	2,072	$	(19)	$	272	$	37	$	2,362
Nine Months Ended September 30, 2019	2,169		132		326		34		2,661

(*)The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. See "Southern Company Gas" herein for additional information.

Southern Company Gas

Southern Company Gas manages its business through four reportable segments – gas distribution operations, gas pipeline investments, wholesale gas services, and gas marketing services. The non-reportable segments are combined and presented as all other.

Gas distribution operations is the largest component of Southern Company Gas' business and includes natural gas local distribution utilities that construct, manage, and maintain intrastate natural gas pipelines and gas distribution facilities in four states.

Gas pipeline investments consists of joint ventures in natural gas pipeline investments including a 50% interest in SNG, a 20% ownership interest in the PennEast Pipeline construction project, a 50% joint ownership interest in the Dalton Pipeline, and a 5% ownership interest in the Atlantic Coast Pipeline construction project through its sale on March 24, 2020. These natural gas pipelines enable the provision of diverse sources of natural gas supplies to the customers of Southern Company Gas.

Wholesale gas services provides natural gas asset management and/or related logistics services for each of Southern Company Gas' utilities except Nicor Gas as well as for non-affiliated companies. Additionally, wholesale gas services engages in natural gas storage and gas pipeline arbitrage and related activities.

Gas marketing services provides natural gas marketing to end-use customers primarily in Georgia, Illinois, and Ohio through SouthStar.

The all other column includes segments below the quantitative threshold for separate disclosure, including natural gas storage businesses, fuels operations through the sale of Southern Company Gas' interest in Pivotal LNG on March 24, 2020, the investment in Triton through its sale on May 29, 2019, and other subsidiaries that fall below the quantitative threshold for separate disclosure. See Notes (E) and (K) under "Southern Company Gas" for additional information.

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(UNAUDITED)

Business segment financial data for the three and nine months ended September 30, 2020 and 2019 was as follows:

	Gas Distribution Operations		Gas Pipeline Investments		Wholesale Gas Services(a)		Gas Marketing Services		Total		All Other(b)		Eliminations		Consolidated
	(in millions)
Three Months Ended September 30, 2020
Operating revenues	$	479	$	8	$	(51)	$	39	$	475	$	8	$	(6)	$	477
Segment net income (loss)	46		23		(45)		(3)		21		(7)		—		14
Nine Months Ended September 30, 2020
Operating revenues	$	2,086	$	24	$	(19)	$	272	$	2,363	$	24	$	(25)	$	2,362
Segment net income (loss)	284		74		(45)		59		372		(12)		—		360
Total assets at September 30, 2020	18,715		1,609		650		1,461		22,435		10,979		(11,482)		21,932
Three Months Ended September 30, 2019
Operating revenues	$	448	$	8	$	(2)	$	39	$	493	$	10	$	(5)	$	498
Segment net income (loss)	37		6		(9)		(4)		30		(59)		—		(29)
Nine Months Ended September 30, 2019
Operating revenues	$	2,188	$	24	$	132	$	326	$	2,670	$	34	$	(43)	$	2,661
Segment net income (loss)	228		63		61		54		406		(59)		—		347
Total assets at December 31, 2019	18,204		1,678		850		1,496		22,228		10,759		(11,300)		21,687

(a)The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table.

	Third Party Gross Revenues		Intercompany Revenues		Total Gross Revenues		Less Gross Gas Costs		Operating Revenues
	(in millions)
Three Months Ended September 30, 2020	$	1,050	$	33	$	1,083	$	1,134	$	(51)
Three Months Ended September 30, 2019	1,138		72		1,210		1,212		(2)
Nine Months Ended September 30, 2020	$	3,089	$	81	$	3,170	$	3,189	$	(19)
Nine Months Ended September 30, 2019	4,287		223		4,510		4,378		132

(b)Segment net income (loss) for the "All Other" column includes a pre-tax impairment charge of $92 million ($65 million after tax) for the three and nine months ended September 30, 2019 related to a natural gas storage facility in Louisiana. See Note 3 to the financial statements under "Other Matters – Southern Company Gas – Natural Gas Storage Facilities" in Item 8 of the Form 10-K for additional information.

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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
Overview	105
Results of Operations	108
Southern Company	108
Alabama Power	116
Georgia Power	120
Mississippi Power	125
Southern Power	130
Southern Company Gas	134
Future Earnings Potential	145
Accounting Policies	166
Financial Condition and Liquidity	167

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.

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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), as well as 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, wholesale gas services, and gas marketing 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, see BUSINESS – "The Southern Company System" in Item 1 of the Form 10-K.

The Registrants continue to focus on several key performance indicators. For the 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

COVID-19

During March 2020, COVID-19 was declared a pandemic by the World Health Organization and the Centers for Disease Control and Prevention and has spread globally, including throughout the United States. The Southern Company system provides a critical service to its customers; therefore, it is essential that Southern Company system employees are able to continue to perform their critical duties safely and effectively. The Southern Company system has implemented applicable business continuity plans, including teleworking, canceling non-essential business travel, increasing cleaning frequency at business locations, implementing applicable safety and health guidelines issued by federal and state officials, and establishing protocols for required work on customer premises. To date, these procedures have been effective in maintaining the Southern Company system's critical operations. As a result of the COVID-19 pandemic, there have been economic disruptions in the Registrants' operating territories. The traditional electric operating companies and the natural gas distribution utilities temporarily suspended disconnections for non-payment by customers and waived late fees for certain periods. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters" herein for information regarding deferral of certain incremental COVID-19-related costs, including bad debt, to a regulatory asset by certain of the traditional electric operating companies and the natural gas distribution utilities. In addition, the COVID-19 pandemic has resulted in a reduction in workforce at Plant Vogtle Units 3 and 4, as discussed further herein. Additional information regarding COVID-19 and its past and potential future impacts on the Registrants is provided throughout Management's Discussion and Analysis of Financial Condition and Results of Operations and in Item 1A herein.

Alabama Power

On August 14, 2020, the Alabama PSC issued an order granting Alabama Power a certificate of convenience and necessity (CCN) to procure additional capacity, and, on August 31, 2020, Alabama Power completed the Autauga Combined Cycle Acquisition.

On August 7, 2020, the Alabama PSC issued an order authorizing Alabama Power to reduce its over-collected fuel balance by $100 million and return that amount to customers in the form of bill credits for the billing month of October 2020.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Alabama Power" herein for additional information.

Georgia Power

Plant Vogtle Units 3 and 4 Status

In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4 (with electric generating capacity of approximately 1,100 MWs each), in which Georgia Power holds a 45.7% ownership interest.

As of June 30, 2020, assignments of contingency to the base capital cost forecast exceeded the remaining balance of the construction contingency originally established in the second quarter 2018. As a result, Georgia Power established $115 million of additional construction contingency as of June 30, 2020 for potential risks including, among other factors, construction productivity and expected impacts of the COVID-19 pandemic; additional resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement.

After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income of $149 million ($111 million after tax) for the increase in the total project capital cost forecast as of June 30, 2020. As and when these amounts are spent, Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery.

In mid-March 2020, Southern Nuclear began implementing policies and procedures designed to mitigate the risk of transmission of COVID-19 at the construction site. In April 2020, Georgia Power, acting for itself and as agent for the other Vogtle Owners, announced a reduction in workforce at Plant Vogtle Units 3 and 4, which totaled approximately 20% of the then-existing site workforce. This workforce reduction lowered absenteeism, providing an improvement in operational efficiency and allowing for increased social distancing. From the initial peak in April 2020, the number of active cases at the site declined significantly during May and early June, but began increasing again from mid-June through July, and continued to impact productivity levels and pace of activity completion. As a result, overall production improvements were not achieved at the levels anticipated, contributing to the June 30, 2020 allocation of, and increase in, construction contingency described above.

To address these issues, in July 2020, Southern Nuclear updated its aggressive site work plan for both Unit 3 and Unit 4. In October 2020, Southern Nuclear further extended milestone dates from the July 2020 aggressive site work plan. Georgia Power still expects to achieve the regulatory-approved in-service dates of November 2021 and November 2022 for Plant Vogtle Units 3 and 4, respectively.

The continuing effects of the COVID-19 pandemic could further disrupt or delay construction, testing, supervisory, and support activities at Plant Vogtle Units 3 and 4. Georgia Power's proportionate share of the estimated incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is currently estimated to be between $70 million and $115 million. However, the ultimate impact of the COVID-19 pandemic on the construction schedule and budget for Plant Vogtle Units 3 and 4 cannot be determined at this time.

See FUTURE EARNINGS POTENTIAL – "Construction Programs – Nuclear Construction" herein for additional information.

Mississippi Power

On March 17, 2020, the Mississippi PSC approved a settlement agreement between Mississippi Power and the Mississippi Public Utilities Staff related to Mississippi Power's base rate case filed in November 2019 (Mississippi Power Rate Case Settlement Agreement). Under the terms of the Mississippi Power Rate Case Settlement Agreement, annual retail rates decreased approximately $16.7 million, or 1.85%, effective for the first billing cycle of April 2020. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Mississippi Power – 2019 Base Rate Case" herein for additional information.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

Southern Power

During the nine months ended September 30, 2020, Southern Power completed construction of and placed in service the 200-MW Reading wind facility, continued construction of the 136-MW Skookumchuck wind facility, and commenced construction of the Garland and Tranquillity battery energy storage facilities. See FUTURE EARNINGS POTENTIAL – "Construction Programs – Southern Power" herein for additional information.

On January 17, 2020, Southern Power completed the sale of its equity interests in Plant Mankato (including the 385-MW expansion unit completed in May 2019) to a subsidiary of Xcel for a purchase price of approximately $663 million, including final working capital adjustments.

In March 2020, Southern Power entered into an agreement to acquire a controlling membership interest in an approximately 300-MW wind facility located in South Dakota. The acquisition is subject to FERC approval and certain other customary conditions to closing, including commercial operation of the facility, which is expected to occur in the first quarter 2021. The facility's output is contracted under two long-term PPAs. The ultimate outcome of this matter cannot be determined at this time.

On May 1, 2020, Southern Power purchased a controlling interest in the 56-MW Beech Ridge II wind facility located in Greenbrier County, West Virginia from Invenergy Renewables LLC. The facility's output is contracted under a 12-year PPA. See Note (K) to the Condensed Financial Statements herein for additional information.

At September 30, 2020, Southern Power's average investment coverage ratio for its generating assets, including those owned with various partners, based on the ratio of investment under contract to total investment using the respective generation facilities' net book value (or expected in-service value for facilities under construction) as the investment amount was 94% through 2024 and 92% through 2029, with an average remaining contract duration of approximately 14 years.

Southern Company Gas

On March 24, 2020, Southern Company Gas completed the sale of its interests in Pivotal LNG and Atlantic Coast Pipeline with aggregate proceeds of $178 million, including working capital adjustments. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.

On June 1, 2020, Virginia Natural Gas filed a general rate case with the Virginia Commission seeking an increase in rates of approximately $49.6 million based on a ROE of 10.35% and an equity ratio of 54%. Rate adjustments are expected to be effective November 1, 2020, subject to refund. The Virginia Commission is expected to rule on the requested increase in the second quarter 2021.

On July 1, 2020, Atlanta Gas Light filed its 2020 GRAM filing with the Georgia PSC requesting an increase in annual base rates of $37.6 million. Resolution of the 2020 GRAM filing is expected by December 31, 2020, with rates effective January 1, 2021.

See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Southern Company Gas" herein for additional information regarding Southern Company Gas' regulatory filings. The ultimate outcome of these matters cannot be determined at this time.

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RESULTS OF OPERATIONS

Southern Company

Net Income

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(65)	(4.9)	$(1,566)	(36.4)

Consolidated net income attributable to Southern Company was $1.25 billion ($1.18 per share) for the third quarter 2020 compared to $1.32 billion ($1.26 per share) for the corresponding period in 2019. The decrease was primarily due to a decrease in retail revenues associated with milder weather in the third quarter 2020 compared to the corresponding period in 2019 and higher depreciation and amortization expenses, partially offset by an impairment charge in 2019 recorded at Southern Company Gas related to a natural gas storage facility and lower income tax expense.

Consolidated net income attributable to Southern Company was $2.7 billion ($2.58 per share) for year-to-date 2020 compared to $4.3 billion ($4.12 per share) for the corresponding period in 2019. The decrease was primarily due to the $2.5 billion ($1.3 billion after tax) gain on the sale of Gulf Power recorded in 2019. See Note 15 to the financial statements under "Southern Company" in Item 8 of the Form 10-K for additional information regarding the sale of Gulf Power.

Retail Electric Revenues

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(269)	(6.0)	$(633)	(5.7)

In the third quarter 2020, retail electric revenues were $4.2 billion compared to $4.5 billion for the corresponding period in 2019. For year-to-date 2020, retail electric revenues were $10.5 billion compared to $11.1 billion for the corresponding period in 2019.

Details of the changes in retail electric revenues were as follows:

	Third Quarter 2020				Year-to-Date 2020
	(in millions)		(% change)		(in millions)		(% change)
Retail electric – prior year	$	4,512			$	11,136
Estimated change resulting from –
Rates and pricing	32		0.7	%	299		2.7	%
Sales decline	(23)		(0.5)		(122)		(1.1)
Weather	(141)		(3.1)		(300)		(2.7)
Fuel and other cost recovery	(137)		(3.0)		(510)		(4.6)
Retail electric – current year	$	4,243	(5.9)	%	$	10,503	(5.7)	%

Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2020 when compared to the corresponding periods in 2019 primarily due to an increase in revenue at Georgia Power related to the recovery of environmental compliance costs and the impacts of accruals for customer refunds in 2019 related to Tax Reform, partially offset by lower contributions from commercial and industrial customers with variable demand-driven pricing. The year-to-date 2020 increase was also due to the rate pricing effects of decreased customer usage at Georgia Power and customer bill credits at Alabama Power in the first quarter 2019 related to Tax Reform. See Note 2 to the financial statements under "Alabama Power" and "Georgia Power" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.

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Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2020 when compared to the corresponding periods in 2019 largely due to work-from-home policies related to the COVID-19 pandemic and reluctance of consumers and businesses to resume pre-pandemic levels of activity. Weather-adjusted residential KWH sales increased 3.5% and 3.7% in the third quarter and year-to-date 2020, respectively, when compared to the corresponding periods in 2019 primarily due to customer growth and an increase in average customer usage, primarily due to the temporary suspension of customer disconnections for nonpayment and work-from-home policies. Weather-adjusted commercial KWH sales decreased 5.1% and 5.9% in the third quarter and year-to-date 2020, respectively, when compared to the corresponding periods in 2019 primarily due to lower customer usage resulting from changes in consumer and business behavior in response to the COVID-19 pandemic. Industrial KWH sales decreased 7.3% and 7.8% in the third quarter and year-to-date 2020, respectively, when compared to the corresponding periods in 2019 primarily as a result of disruptions in supply chain and business operations related to the COVID-19 pandemic and the overall decrease in business activity due to the resulting recession.

Fuel and other cost recovery revenues decreased $137 million and $510 million in the third quarter and year-to-date 2020, respectively, compared to the corresponding periods in 2019 primarily due to decreases in generation and the average cost of fuel and purchased power. Electric rates for the traditional electric operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of PPA costs, and do not affect net income. The traditional electric operating companies each have one or more regulatory mechanisms to recover other costs such as environmental and other compliance costs, storm damage, new plants, and PPA capacity costs.

Wholesale Electric Revenues

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(41)	(6.6)	$(194)	(11.6)

Wholesale electric revenues consist of revenues from PPAs and short-term opportunity sales. Wholesale electric revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues generally represent the greatest contribution to net income and are designed to provide recovery of fixed costs plus a return on investment. Energy revenues will vary depending on fuel prices, the market prices of wholesale energy compared to the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Energy sales from solar and wind PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or through a fixed price related to the energy. As a result, the ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors. Wholesale electric revenues at Mississippi Power include FERC-regulated municipal and rural association sales under cost-based tariffs as well as market-based sales. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system's variable cost to produce the energy.

In the third quarter 2020, wholesale electric revenues were $584 million compared to $625 million for the corresponding period in 2019. For year-to-date 2020, wholesale electric revenues were $1.5 billion compared to $1.7 billion for the corresponding period in 2019. These decreases reflect decreases of $31 million and $134 million in energy revenues for the third quarter and year-to-date 2020, respectively, of which $22 million and $88 million, respectively, is from Southern Power. The decreases in energy revenues primarily resulted from lower natural gas prices and a net decrease in the volume of KWHs sold, primarily as a result of milder weather in the Southeast U.S. when compared to the corresponding periods in 2019. In addition, decreases in capacity revenues of $10 million and $60 million in the third quarter and year-to-date 2020, respectively, were primarily due to Southern Power's sale of

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Plant Mankato in the first quarter 2020. The year-to-date 2020 capacity revenue decrease was also due to Southern Power's sale of Plant Nacogdoches in the second quarter 2019. See Note (K) to the Condensed Financial Statements under "Southern Power" herein and Note 15 to the financial statements under "Southern Power – Sales of Natural Gas and Biomass Plants" in Item 8 of the Form 10-K for additional information.

Natural Gas Revenues

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(21)	(4.2)	$(299)	(11.2)

In the third quarter 2020, natural gas revenues were $477 million compared to $498 million for the corresponding period in 2019. For year-to-date 2020, natural gas revenues were $2.4 billion compared to $2.7 billion for the corresponding period in 2019.

Details of the changes in natural gas revenues were as follows:

	Third Quarter 2020				Year-to-Date 2020
	(in millions)		(% change)		(in millions)		(% change)
Natural gas revenues – prior year	$	498			$	2,661
Estimated change resulting from –
Infrastructure replacement programs and base rate changes	34		6.8	%	153		5.7	%
Gas costs and other cost recovery	(8)		(1.6)		(298)		(11.2)
Weather	2		0.4		(6)		(0.2)
Wholesale gas services	(49)		(9.8)		(151)		(5.6)
Other	—		—		3		0.1
Natural gas revenues – current year	$	477	(4.2)	%	$	2,362	(11.2)	%

Revenues from infrastructure replacement programs and base rate changes at the natural gas distribution utilities increased in the third quarter and year-to-date 2020 compared to the corresponding periods in 2019 primarily due to base rate increases at Nicor Gas and Atlanta Gas Light and continued investments recovered through infrastructure replacement programs. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" in Item 8 of the Form 10-K for additional information.

Revenues associated with gas costs and other cost recovery decreased in the third quarter and year-to-date 2020 compared to the corresponding periods in 2019 primarily due to lower natural gas prices. The year-to-date decrease also reflects lower sales volumes in 2020 compared to the corresponding period in 2019 primarily as a result of warmer weather. 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 Southern Company Gas' wholesale gas services business decreased in the third quarter 2020 compared to the corresponding period in 2019 due to decreased commercial activity as a result of milder weather and derivative losses and for year-to-date 2020 compared to the corresponding period in 2019 primarily due to decreased commercial activity as a result of warmer weather and a decrease in derivative gains.

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Other Revenues

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(45)	(22.8)	$(113)	(20.6)

In the third quarter 2020, other revenues were $152 million compared to $197 million for the corresponding period in 2019. For year-to-date 2020, other revenues were $436 million compared to $549 million for the corresponding period in 2019. These decreases primarily relate to the wind-down of a segment of PowerSecure's distributed infrastructure business in the first quarter 2020. Additionally, the year-to-date 2020 decrease reflects the sale of PowerSecure's utility infrastructure services business in July 2019. See Note 15 to the financial statements under "Southern Company" in Item 8 of the Form 10-K for additional information.

Fuel and Purchased Power Expenses

	Third Quarter 2020 vs. Third Quarter 2019			Year-to-Date 2020 vs. Year-to-Date 2019
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	(139)	(13.0)	$	(646)	(22.8)
Purchased power	(24)		(9.4)	(14)		(2.2)
Total fuel and purchased power expenses	$	(163)		$	(660)

In the third quarter 2020, total fuel and purchased power expenses were $1.2 billion compared to $1.3 billion for the corresponding period in 2019. The decrease was primarily the result of a $120 million decrease in the volume of KWHs generated and purchased and a $43 million decrease in the average cost of fuel and purchased power.

For year-to-date 2020, total fuel and purchased power expenses were $2.8 billion compared to $3.5 billion for the corresponding period in 2019. The decrease was primarily the result of a $329 million decrease in the average cost of fuel and purchased power and a $331 million net decrease in the volume of KWHs generated and purchased.

Fuel and purchased power energy transactions at the traditional electric operating companies are generally offset by fuel revenues and do not have a significant impact on net income. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters" herein for additional information. Fuel expenses incurred under Southern Power's PPAs are generally the responsibility of the counterparties and do not significantly impact net income.

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Details of the Southern Company system's generation and purchased power were as follows:

	Third Quarter 2020	Third Quarter 2019	Year-to-Date 2020	Year-to-Date 2019
Total generation (in billions of KWHs)	50	54	132	143
Total purchased power (in billions of KWHs)	5	6	14	14
Sources of generation (percent) —
Gas	52	54	53	51
Nuclear	16	15	17	16
Coal	24	24	17	23
Hydro	2	1	5	4
Other	6	6	8	6
Cost of fuel, generated (in cents per net KWH)—
Gas	1.98	2.25	1.94	2.39
Nuclear	0.78	0.79	0.78	0.79
Coal	3.01	2.85	2.96	2.93
Average cost of fuel, generated (in cents per net KWH)	2.04	2.18	1.91	2.24
Average cost of purchased power (in cents per net KWH)(*)	4.94	4.78	4.53	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 2020, fuel expense was $0.9 billion compared to $1.1 billion for the corresponding period in 2019. The decrease was primarily due to a 10.0% decrease in the volume of KWHs generated by coal, a 12.0% decrease in the average cost of natural gas per KWH generated, and a 6.3% decrease in the volume of KWHs generated by natural gas, partially offset by a 5.6% increase in the average cost of coal per KWH generated.

For year-to-date 2020, fuel expense was $2.2 billion compared to $2.8 billion for the corresponding period in 2019. The decrease was primarily due to a 30.3% decrease in the volume of KWHs generated by coal, an 18.8% decrease in the average cost of natural gas per KWH generated, and a 2.8% decrease in the volume of KWHs generated by natural gas, partially offset by a 1.0% increase in the average cost of coal per KWH generated.

Purchased Power

In the third quarter 2020, purchased power expense was $230 million compared to $254 million for the corresponding period in 2019. The decrease was primarily due to a 15.6% decrease in the volume of KWHs purchased, partially offset by a 3.3% increase in the average cost per KWH purchased.

For year-to-date 2020, purchased power expense was $611 million compared to $625 million for the corresponding period in 2019. The decrease was primarily due to a 4.6% decrease in the average cost per KWH purchased.

Cost of Natural Gas

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(8)	(10.1)	$(302)	(31.6)

Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from

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the natural gas distribution utilities. Cost of natural gas at the natural gas distribution utilities represented 80% and 86% of total cost of natural gas for the third quarter and year-to-date 2020, respectively.

In the third quarter 2020, cost of natural gas was $71 million compared to $79 million for the corresponding period in 2019. The decrease reflects an 11.3% decrease in natural gas prices in the third quarter 2020 compared to the corresponding period in 2019.

For year-to-date 2020, cost of natural gas was $654 million compared to $956 million for the corresponding period in 2019. The decrease reflects a 29.6% decrease in natural gas prices compared to 2019 and decreased volumes primarily as a result of warmer weather, as determined by Heating Degree Days, for year-to-date 2020 compared to the corresponding period in 2019.

Cost of Other Sales

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(42)	(36.8)	$(115)	(36.4)

In the third quarter 2020, cost of other sales was $72 million compared to $114 million for the corresponding period in 2019. For year-to-date 2020, cost of other sales was $201 million compared to $316 million for the corresponding period in 2019. These decreases primarily relate to the wind-down of a segment of PowerSecure's distributed infrastructure business in the first quarter 2020. Additionally, the year-to-date 2020 decrease reflects the sale of PowerSecure's utility infrastructure services business in July 2019. See Note 15 to the financial statements under "Southern Company" in Item 8 of the Form 10-K for additional information.

Other Operations and Maintenance Expenses

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(10)	(0.8)	$(113)	(2.9)

In the third quarter 2020, other operations and maintenance expenses were $1.29 billion compared to $1.30 billion for the corresponding period in 2019. The decrease primarily results from decreases of $38 million in transmission and distribution maintenance expenses, primarily at Alabama Power and Georgia Power, including $9 million of reliability NDR credits at Alabama Power, $23 million in scheduled generation outage and maintenance expenses, and $11 million in compliance and environmental expenses at the traditional electric operating companies, substantially offset by a $46 million increase in storm damage recovery at Georgia Power as authorized in its 2019 ARP and an increase in employee compensation and benefit expenses.

For year-to-date 2020, other operations and maintenance expenses were $3.8 billion compared to $3.9 billion for the corresponding period in 2019. The decrease reflects the impacts of cost containment activities implemented in 2020 to help offset the effects of the recessionary economy resulting from the COVID-19 pandemic. The decrease primarily results from decreases of $128 million in scheduled generation outage and maintenance expenses, $81 million in transmission and distribution expenses at the traditional electric operating companies, including $31 million of reliability NDR credits at Alabama Power, $37 million in compliance and environmental expenses at the traditional electric operating companies, and $21 million primarily related to the sale of PowerSecure's utility infrastructure services business in July 2019 and lighting business in December 2019, partially offset by a $138 million increase in storm damage recovery at Georgia Power as authorized in its 2019 ARP and a $54 million increase in employee compensation and benefit expenses. The decrease was also due to a $32 million increase in nuclear property insurance refunds at Alabama Power and Georgia Power.

See Note 2 to the financial statements under "Alabama Power – Rate NDR" and " – Rate CNP Compliance" and "Georgia Power – Storm Damage Recovery" and Note 15 to the financial statements under "Southern Company" in Item 8 of the Form 10-K for additional information.

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Depreciation and Amortization

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$129	17.0	$352	15.5

In the third quarter 2020, depreciation and amortization was $889 million compared to $760 million for the corresponding period in 2019. For year-to-date 2020, depreciation and amortization was $2.6 billion compared to $2.3 billion for the corresponding period in 2019. These increases primarily reflect increased amortization of regulatory assets related to CCR AROs of $51 million and $152 million for the third quarter and year-to-date 2020, respectively, and higher depreciation of $44 million and $133 million for the third quarter and year-to-date 2020, respectively, as authorized in Georgia Power's 2019 ARP. Also contributing to the increases were $45 million and $92 million increases in depreciation for the third quarter and year-to-date 2020, respectively, associated with additional plant in service. See Note 2 to the financial statements under "Georgia Power – Rate Plans" and " – Integrated Resource Plan" in Item 8 of the Form 10-K for additional information.

Estimated Loss on Plant Vogtle Units 3 and 4

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$—	N/M	$149	N/M

N/M - Not meaningful

In the second quarter 2020, an estimated probable loss of $149 million was recorded at Georgia Power to reflect its revised total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information.

Impairment Charges

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(110)	N/M	$(142)	N/M

N/M - Not meaningful

In the third quarter 2019, an asset impairment charge of $92 million was recorded at Southern Company Gas related to a natural gas storage facility in Louisiana. In the third quarter and year-to-date 2019, goodwill and asset impairment charges totaling $18 million and $50 million, respectively, were recorded related to the sale of PowerSecure's utility infrastructure services business and in contemplation of the sale of its lighting business. See Notes 3 and 15 to the financial statements under "Other Matters – Southern Company Gas – Natural Gas Storage Facilities" and "Southern Company," respectively, in Item 8 of the Form 10-K for additional information.

(Gain) Loss on Dispositions, Net

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(6)	N/M	$(2,473)	N/M

N/M - Not meaningful

For year-to-date 2020, gain on dispositions, net was $39 million compared to $2.5 billion for the corresponding period in 2019. The decrease was primarily due to the $2.5 billion ($1.3 billion after tax) preliminary gain on the sale of Gulf Power recorded in the first quarter 2019. See Note 15 to the financial statements under "Southern Company" in Item 8 of the Form 10-K for additional information.

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Interest Expense, Net of Amounts Capitalized

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$9	2.1	$49	3.8

In the third quarter 2020, interest expense, net of amounts capitalized was $443 million compared to $434 million for the corresponding period in 2019. For year-to-date 2020, interest expense, net of amounts capitalized was $1.34 billion compared to $1.29 billion for the corresponding period in 2019. These increases were primarily due to an increase in average outstanding long-term borrowings primarily at the parent company. See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein and Note 8 to the financial statements in Item 8 of the Form 10-K for additional information.

Impairment of Leveraged Lease

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$—	N/M	$154	N/M

N/M - Not meaningful

For year-to-date 2020, an impairment charge of $154 million was recorded related to a leveraged lease investment at Southern Holdings. See Note (C) to the Condensed Financial Statements under "Other Matters – Southern Company" herein for additional information.

Other Income (Expense), Net

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$52	85.2	$80	33.5

In the third quarter 2020, other income (expense), net was $113 million compared to $61 million for the corresponding period in 2019. For year-to-date 2020, other income (expense), net was $319 million compared to $239 million for the corresponding period in 2019. These increases were primarily related to increases in non-service cost-related retirement benefits income of $30 million and $88 million for the third quarter and year-to-date 2020, respectively, as well as $12 million of additional benefits associated with a litigation settlement at Southern Power in the second quarter 2019. The year-to-date 2020 increase was partially offset by the $36 million gain on the litigation settlement that was recorded in the second quarter 2019. See Note 3 to the financial statements under "General Litigation Matters – Southern Power" in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein for additional information.

Income Taxes

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(74)	(20.2)	$(1,429)	(76.3)

In the third quarter 2020, income taxes were $293 million compared to $367 million for the corresponding period in 2019. For year-to-date 2020, income taxes were $0.4 billion compared to $1.9 billion for the corresponding period in 2019. These decreases were primarily due to the flowback of excess deferred income taxes in 2020 as authorized in Georgia Power's 2019 ARP and lower pre-tax earnings. The year-to-date 2020 decrease also reflects the tax impacts of the sale of Gulf Power in 2019. See Notes 2, 3, and 15 to the financial statements under "Georgia Power – Rate Plans – Tax Reform Settlement Agreement," "Other Matters – Southern Company Gas – Natural Gas Storage Facilities," and "Southern Company," respectively, in Item 8 of the Form 10-K and Notes (B) and (G) to the

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Condensed Financial Statements under "Georgia Power – Nuclear Construction" and "Effective Tax Rate," respectively, herein for additional information.

Net Income Attributable to Noncontrolling Interests

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$3	12.0	$(23)	(88.5)

For year-to-date 2020, net income attributable to noncontrolling interests was $3 million compared to $26 million for the corresponding period in 2019. The change was primarily due to an allocation of approximately $26 million of income to the noncontrolling interest partner related to a litigation settlement at Southern Power in the second quarter 2019. See Note 3 to the financial statements in Item 8 of the Form 10-K under "General Litigation Matters – Southern Power" for additional information.

Alabama Power

Net Income

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(25)	(5.3)	$40	4.1

Alabama Power's net income after dividends on preferred stock for the third quarter 2020 was $444 million compared to $469 million for the corresponding period in 2019. This decrease was primarily due to a decrease in retail revenues associated with milder weather in the third quarter 2020 compared to the corresponding period in 2019 and lower customer usage, partially offset by a decrease in operations and maintenance expenses and an increase in non-service cost-related retirement benefits income.

Alabama Power's net income after dividends on preferred stock for year-to-date 2020 was $1.02 billion compared to $0.98 billion for the corresponding period in 2019. This increase was primarily due to a decrease in operations and maintenance expenses, an increase in retail revenues associated with the impact of customer bill credits issued in 2019 related to Tax Reform, and an increase in non-service cost-related retirement benefits income. These increases to income were partially offset by decreases in retail revenues associated with milder weather in 2020 compared to the corresponding period in 2019 and lower customer usage. See Note 2 to the financial statements under "Alabama Power – Rate RSE" in Item 8 of the Form 10-K for additional information.

Retail Revenues

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(119)	(7.0)	$(283)	(6.6)

In the third quarter 2020, retail revenues were $1.58 billion compared to $1.69 billion for the corresponding period in 2019. For year-to-date 2020, retail revenues were $4.00 billion compared to $4.29 billion for the corresponding period in 2019.

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Details of the changes in retail revenues were as follows:

	Third Quarter 2020				Year-to-Date 2020
	(in millions)		(% change)		(in millions)		(% change)
Retail – prior year	$	1,694			$	4,286
Estimated change resulting from –
Rates and pricing	(9)		(0.5)	%	53		1.2	%
Sales decline	(9)		(0.5)		(54)		(1.3)
Weather	(51)		(3.0)		(104)		(2.4)
Fuel and other cost recovery	(50)		(3.0)		(178)		(4.1)
Retail – current year	$	1,575	(7.0)	%	$	4,003	(6.6)	%

Revenues associated with changes in rates and pricing decreased in the third quarter 2020 and increased year-to-date 2020 when compared to the corresponding periods in 2019. The third quarter 2020 decrease was due to a decrease in Rate CNP Compliance-related revenue. The year-to-date 2020 increase was primarily due to customer bill credits issued in the first quarter 2019 related to Tax Reform and an increase in year-to-date 2020 Rate CNP Compliance-related revenue.

Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2020 when compared to the corresponding periods in 2019 largely due to social distancing and safer-at-home guidelines related to the COVID-19 pandemic and reluctance from consumers and businesses to resume pre-pandemic levels of activity. Weather-adjusted residential KWH sales increased 2.6% and 3.2% in the third quarter and year-to-date 2020, respectively, when compared to the corresponding periods in 2019 primarily due to customer growth and an increase in average customer usage primarily due to the temporary suspension of customer disconnections for nonpayment and safer-at-home guidelines related to the COVID-19 pandemic. Weather-adjusted commercial KWH sales decreased 4.8% and 6.3% in the third quarter and year-to-date 2020, respectively, when compared to the corresponding periods in 2019 primarily due to lower customer usage resulting from changes in consumer and business behavior in response to the COVID-19 pandemic. Industrial KWH sales decreased 10.7% and 9.4% in the third quarter and year-to-date 2020, respectively, when compared to the corresponding periods in 2019 primarily as a result of disruptions in supply chain and business operations driven by the COVID-19 pandemic and the overall decrease in business activity due to the resulting recession.

Fuel and other cost recovery revenues decreased in the third quarter and year-to-date 2020 when compared to the corresponding periods in 2019 primarily due to decreases in generation and the average cost of fuel.

Electric rates include provisions to recognize the recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the natural disaster reserve. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income. See Note 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.

Wholesale Revenues – Affiliates

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$9	N/M	$(30)	(45.5)

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 and energy purchases are generally offset by energy revenues through Alabama Power's energy cost recovery clause.

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For year-to-date 2020, wholesale revenues from sales to affiliates were $36 million compared to $66 million for the corresponding period in 2019. The decrease was primarily due to a 28.7% decrease in KWH sales as a result of decreased coal generation largely due to lower natural gas prices and a 22.5% decrease in the price of energy due to lower natural gas prices in 2020 compared to the corresponding period in 2019.

Fuel and Purchased Power Expenses

	Third Quarter 2020 vs. Third Quarter 2019			Year-to-Date 2020 vs. Year-to-Date 2019
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	(4)	(1.3)	$	(143)	(16.6)
Purchased power – non-affiliates	(13)		(16.9)	(7)		(4.4)
Purchased power – affiliates	(29)		(39.7)	(71)		(43.3)
Total fuel and purchased power expenses	$	(46)		$	(221)

In the third quarter 2020, total fuel and purchased power expenses were $414 million compared to $460 million for the corresponding period in 2019. The decrease was primarily due to a $54 million decrease in the volume of KWHs generated (excluding hydro) and purchased, partially offset by an $8 million net increase in the average cost of generation and purchased power.

For year-to-date 2020, total fuel and purchased power expenses were $0.97 billion compared to $1.19 billion for the corresponding period in 2019. The decrease was primarily due to a $193 million decrease in the volume of KWHs generated (excluding hydro) and purchased and a $28 million net decrease in the average cost of generation and purchased power.

Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Alabama Power's energy cost recovery clause. See Note 2 to the financial statements under "Alabama Power – Rate ECR" in Item 8 of the Form 10-K for additional information.

Details of Alabama Power's generation and purchased power were as follows:

	Third Quarter 2020	Third Quarter 2019	Year-to-Date 2020	Year-to-Date 2019
Total generation (in billions of KWHs)	15	15	41	43
Total purchased power (in billions of KWHs)	2	4	5	8
Sources of generation (percent) —
Coal	47	48	38	45
Nuclear	25	26	28	25
Gas	24	24	23	21
Hydro	4	2	11	9
Cost of fuel, generated (in cents per net KWH) —
Coal	2.86	2.67	2.78	2.76
Nuclear	0.76	0.75	0.76	0.77
Gas	1.80	2.40	1.96	2.48
Average cost of fuel, generated (in cents per net KWH)	2.04	2.10	1.93	2.15
Average cost of purchased power (in cents per net KWH)(*)	5.12	4.35	4.76	4.40

(*)Average cost of purchased power includes fuel, energy, and transmission purchased by Alabama Power for tolling agreements where power is generated by the provider.

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Fuel

In the third quarter 2020, fuel expense was $306 million compared to $310 million for the corresponding period in 2019. The decrease was primarily due to a 64.0% increase in the volume of KWHs generated by hydro and a 25.0% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, partially offset by an 8.0% increase in the volume of KWHs generated by natural gas and a 7.1% increase in the average cost of coal per KWH generated.

For year-to-date 2020, fuel expense was $721 million compared to $864 million for the corresponding period in 2019. The decrease was primarily due to a 21.0% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, an 18.6% decrease in the volume of KWHs generated by coal, and a 15.7% and an 8.5% increase in the volume of KWHs generated by hydro and nuclear, respectively.

Purchased Power – Non-Affiliates

In the third quarter 2020, purchased power expense from non-affiliates was $64 million compared to $77 million for the corresponding period in 2019. This decrease was primarily due to a 29.3% decrease in the amount of energy purchased due to milder weather in the third quarter 2020 as compared to the corresponding period in 2019, partially offset by a 14.1% increase in the average cost of purchased power per KWH as a result of fixed capacity costs for PPAs.

Purchased Power – Affiliates

In the third quarter 2020, purchased power expense from affiliates was $44 million compared to $73 million for the corresponding period in 2019. For year-to-date 2020, purchased power expense from affiliates was $93 million compared to $164 million for the corresponding period in 2019. These decreases were primarily due to reductions of 45.4% and 44.5%, respectively, in the amount of energy purchased due to milder weather during 2020 as compared to 2019.

Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.

Other Operations and Maintenance Expenses

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(22)	(5.4)	$(143)	(11.7)

In the third quarter 2020, other operations and maintenance expenses were $387 million compared to $409 million for the corresponding period in 2019. For year-to-date 2020, other operations and maintenance expenses were $1.08 billion compared to $1.22 billion for the corresponding period in 2019. These decreases reflect the impacts of cost containment activities implemented to help offset the effects of the recessionary economy resulting from the COVID-19 pandemic. The decreases primarily result from decreases of $22 million and $100 million in generation expenses associated with scheduled outages and CNP Compliance-related expenses for the third quarter and year-to-date 2020, respectively. Also contributing were decreases of $15 million and $44 million in transmission and distribution maintenance expenses primarily related to reliability NDR credits for the third quarter and year-to-date 2020, respectively. Partially offsetting the third quarter 2020 decrease was a $13 million increase in bad debt expense.

See Note 2 to the financial statements under "Alabama Power – Rate NDR" and " – Rate CNP Compliance" in Item 8 of the Form 10-K for additional information.

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Other Income (Expense), Net

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$19	172.7	$42	116.7

In the third quarter 2020, other income (expense), net was $30 million compared to $11 million for the corresponding period in 2019. For year-to-date 2020, other income (expense), net was $78 million compared to $36 million for the corresponding period in 2019. These increases were primarily due to an increase in non-service cost-related retirement benefits income. See Note (H) to the Condensed Financial Statements herein for additional information.

Income Taxes

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(14)	(9.7)	$12	4.1

In the third quarter 2020, income taxes were $130 million compared to $144 million for the corresponding period in 2019. This decrease was primarily due to lower pre-tax earnings and the finalization of the 2019 tax return.

For year-to-date 2020, income taxes were $307 million compared to $295 million for the corresponding period in 2019. This increase was primarily due to higher pre-tax earnings.

Georgia Power

Net Income

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(66)	(7.9)	$(187)	(11.7)

Georgia Power's net income for the third quarter 2020 was $773 million compared to $839 million for the corresponding period in 2019. For year-to-date 2020, net income was $1.41 billion compared to $1.60 billion for the corresponding period in 2019. These decreases were primarily due to lower retail revenues associated with milder weather as compared to the corresponding periods in 2019 and decreased customer usage resulting from the COVID-19 pandemic, partially offset by related cost containment activities. The year-to-date decrease was also due to a $111 million after-tax charge in the second quarter 2020 related to the construction of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information on the construction of Plant Vogtle Units 3 and 4.

Retail Revenues

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(132)	(5.1)	$(311)	(5.0)

In the third quarter 2020, retail revenues were $2.44 billion compared to $2.57 billion for the corresponding period in 2019. For year-to-date 2020, retail revenues were $5.87 billion compared to $6.18 billion for the corresponding period in 2019.

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Details of the changes in retail revenues were as follows:

	Third Quarter 2020				Year-to-Date 2020
	(in millions)		(% change)		(in millions)		(% change)
Retail – prior year	$	2,567			$	6,181
Estimated change resulting from –
Rates and pricing	51		2.0	%	260		4.2	%
Sales decline	(9)		(0.4)		(56)		(0.9)
Weather	(87)		(3.4)		(194)		(3.1)
Fuel cost recovery	(87)		(3.4)		(321)		(5.2)
Retail – current year	$	2,435	(5.2)	%	$	5,870	(5.0)	%

Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2020, when compared to the corresponding periods in 2019. These increases were primarily due to an increase in revenue recognized under the Environmental Compliance Cost Recovery (ECCR) tariff effective January 1, 2020 as authorized in the 2019 ARP and the impacts of accruals in 2019 for customer refunds related to Tax Reform. The increase for year-to-date 2020 was also due to the rate pricing effects of decreased customer usage in the first and second quarters 2020. Partially offsetting these increases were lower contributions from commercial and industrial customers with variable demand-driven pricing. See Note 2 to the financial statements under "Georgia Power" in Item 8 of the Form 10-K for additional information.

Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2020 when compared to the corresponding periods in 2019 largely due to work-from-home policies related to the COVID-19 pandemic and reluctance of consumers and businesses to resume pre-pandemic levels of activity. Weather-adjusted residential KWH sales increased 4.0% and 4.1% in the third quarter and year-to-date 2020, respectively, when compared to corresponding periods in 2019 due to customer growth and an increase in average customer usage, primarily due to the temporary suspension of customer disconnections for nonpayment and work-from-home policies. Weather-adjusted commercial KWH sales decreased 5.2% and 5.6% in the third quarter and year-to-date 2020, respectively, when compared to the corresponding periods in 2019 primarily due to lower customer usage resulting from changes in consumer and business behavior in response to the COVID-19 pandemic. Weather-adjusted industrial KWH sales decreased 3.6% and 6.7% in the third quarter and year-to-date 2020, respectively, when compared to the corresponding periods in 2019 primarily as a result of disruptions in supply chain and business operations related to the COVID-19 pandemic and the overall decrease in business activity due to the resulting recession.

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues decreased in the third quarter and year-to-date 2020 when compared to the corresponding periods in 2019 due to lower fuel and purchased power costs. Electric rates include provisions to periodically adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Georgia Power – Fuel Cost Recovery" in Item 7 of the Form 10-K for additional information.

Wholesale Revenues

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(5)	(12.8)	$(22)	(20.6)

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

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wholesale energy compared to the cost of Georgia Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above Georgia Power's variable cost of energy.

Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal costs.

In the third quarter 2020, wholesale revenues were $34 million compared to $39 million for the corresponding period in 2019. For year-to-date 2020, wholesale revenues were $85 million compared to $107 million for the corresponding period in 2019. These decreases were primarily due to lower market demand largely resulting from the expiration of a non-affiliate PPA and lower energy prices.

Fuel and Purchased Power Expenses

	Third Quarter 2020 vs. Third Quarter 2019			Year-to-Date 2020 vs. Year-to-Date 2019
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	(75)	(16.9)	$	(306)	(27.0)
Purchased power – non-affiliates	(5)		(3.3)	16		4.1
Purchased power – affiliates	(8)		(5.3)	(67)		(14.6)
Total fuel and purchased power expenses	$	(88)		$	(357)

In the third quarter 2020, total fuel and purchased power expenses were $656 million compared to $744 million for the corresponding period in 2019. The decrease was due to decreases of $44 million each related to the average cost of fuel and purchased power and the net volume of KWHs generated and purchased.

For year-to-date 2020, total fuel and purchased power expenses were $1.63 billion compared to $1.99 billion for the corresponding period in 2019. The decrease was due to a decrease of $239 million related to the average cost of fuel and purchased power and a net decrease of $118 million 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 MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Georgia Power – Fuel Cost Recovery" in Item 7 of the Form 10-K for additional information.

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Details of Georgia Power's generation and purchased power were as follows:

	Third Quarter 2020	Third Quarter 2019	Year-to-Date 2020	Year-to-Date 2019
Total generation (in billions of KWHs)	17	19	42	48
Total purchased power (in billions of KWHs)	8	8	25	23
Sources of generation (percent) —
Gas	48	46	53	47
Nuclear	24	22	27	24
Coal	26	31	15	26
Hydro and other	2	1	5	3
Cost of fuel, generated (in cents per net KWH) —
Gas	2.14	2.33	2.12	2.45
Nuclear	0.81	0.82	0.81	0.81
Coal	3.19	3.00	3.31	3.10
Average cost of fuel, generated (in cents per net KWH)	2.09	2.20	1.93	2.21
Average cost of purchased power (in cents per net KWH)(*)	3.76	4.20	3.50	4.22

(*)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 2020, fuel expense was $368 million compared to $443 million for the corresponding period in 2019. For year-to-date 2020, fuel expense was $0.83 billion compared to $1.13 billion for the corresponding period in 2019. The decreases for the third quarter and year-to-date 2020 were primarily due to decreases of 25.7% and 50.3%, respectively, in the volume of KWHs generated by coal and decreases of 8.2% and 13.5%, respectively, in the average cost of natural gas per KWH generated.

Purchased Power – Affiliates

For year-to-date 2020, purchased power expense from affiliates was $393 million compared to $460 million for the corresponding period in 2019. The decrease was primarily due to a decrease of 24.7% in the average cost per KWH purchased primarily resulting from lower energy prices, as well as the expiration of a PPA, partially offset by an increase of 5.8% in the volume of KWHs purchased as Georgia Power units generally dispatched at a higher cost than other Southern Company system resources.

Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.

Other Operations and Maintenance Expenses

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$10	2.1	$26	1.9

In the third quarter 2020, other operations and maintenance expenses were $483 million compared to $473 million for the corresponding period in 2019. The increase was primarily due to increases of $46 million in storm damage recovery as authorized in the 2019 ARP and $7 million in employee benefit expenses, partially offset by decreases of $24 million in distribution- and transmission-related expenses and $11 million associated with generation

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maintenance. These decreases reflect the impacts of cost containment activities implemented to help offset the effects of the recessionary economy resulting from the COVID-19 pandemic. Also contributing to the offset was a decrease of $6 million in expenses from unregulated sales associated with new energy conservation projects.

For year-to-date 2020, other operations and maintenance expenses were $1.41 billion compared to $1.39 billion for the corresponding period in 2019. The increase was primarily due to increases of $138 million in storm damage recovery as authorized in the 2019 ARP and $15 million in employee benefit expenses, partially offset by decreases of $42 million in distribution- and transmission-related expenses, $34 million associated with generation maintenance and scheduled outages, and $13 million associated with generation environmental projects. These decreases reflect the impacts of cost containment activities implemented to help offset the effects of the recessionary economy resulting from the COVID-19 pandemic. Other expense reductions include a decrease of $15 million related to an adjustment in 2019 for FERC fees following the conclusion of a multi-year audit of headwater benefits associated with hydro facilities, an $11 million increase in nuclear property insurance refunds, and a decrease of $9 million associated with workers compensation and legal expenses.

See Note 2 to the financial statements under "Georgia Power – Storm Damage Recovery" in Item 8 of the Form 10-K for additional information.

Depreciation and Amortization

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$108	43.2	$331	45.2

In the third quarter 2020, depreciation and amortization was $358 million compared to $250 million for the corresponding period in 2019. For year-to-date 2020, depreciation and amortization was $1.06 billion compared to $0.73 billion for the corresponding period in 2019. These increases primarily reflect increased amortization of regulatory assets related to CCR AROs of $51 million and $152 million for the third quarter and year-to-date 2020, respectively, and higher depreciation of $44 million and $133 million for the third quarter and year-to-date 2020, respectively, as authorized in the 2019 ARP. Also contributing to the increases were $16 million and $52 million increases in depreciation for the third quarter and year-to-date 2020, respectively, associated with additional plant in service. See Note 2 to the financial statements under "Georgia Power – Rate Plans" and " – Integrated Resource Plan" in Item 8 of the Form 10-K for additional information.

Estimated Loss on Plant Vogtle Units 3 and 4

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$—	N/M	$149	N/M

N/M - Not meaningful

In the second quarter 2020, an estimated probable loss of $149 million was recorded to reflect Georgia Power's revised total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information.

Interest Expense, Net of Amounts Capitalized

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$3	2.9	$18	5.9

For year-to-date 2020, interest expense, net of amounts capitalized was $322 million compared to $304 million for the corresponding period in 2019. The increase was primarily due to a $32 million increase in interest expense associated with an increase in average outstanding long-term borrowings, partially offset by a $15 million increase

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in amounts capitalized in connection with the construction of Plant Vogtle Units 3 and 4. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings and Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.

Other Income (Expense), Net

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$18	50.0	$43	38.1

In the third quarter 2020, other income (expense), net was $54 million compared to $36 million for the corresponding period in 2019. For year-to-date 2020, other income (expense), net was $156 million compared to $113 million for the corresponding period in 2019. The third quarter and year-to-date 2020 increases were primarily due to increases of $10 million and $32 million, respectively, in non-service cost-related retirement benefits income and increases in AFUDC equity of $5 million and $14 million, respectively, primarily associated with the construction of Plant Vogtle Units 3 and 4. See Note (H) to the Condensed Financial Statements herein for additional information on retirement benefits and Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.

Income Taxes

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(83)	(32.5)	$(268)	(57.5)

In the third quarter 2020, income taxes were $172 million compared to $255 million for the corresponding period in 2019. For year-to-date 2020, income taxes were $198 million compared to $466 million for the corresponding period in 2019. These decreases were primarily due to the flowback of excess deferred income taxes in 2020 as authorized in the 2019 ARP and lower pre-tax earnings, which includes, for year-to-date 2020, the charge in the second quarter 2020 associated with the construction of Plant Vogtle Units 3 and 4. See Note (B) under "Nuclear Construction" and Note (G) to the Condensed Financial Statements herein and Note 2 to the financial statements under "Georgia Power – Rate Plans – Tax Reform Settlement Agreement" in Item 8 of the Form 10-K for additional information.

Mississippi Power

Net Income

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$2	3.1	$(1)	(0.7)

Mississippi Power's net income for the third quarter 2020 was $67 million compared to $65 million for the corresponding period in 2019. The increase was primarily due to a decrease in amortization associated with ECO Plan regulatory assets, a decrease in income taxes associated with the flowback of excess deferred income taxes, and a decrease in scheduled generation outage costs, partially offset by a decrease in revenues as a result of a base rate reduction that became effective for the first billing cycle of April 2020, as well as a decrease in customer usage due to the COVID-19 pandemic, and an increase in depreciation.

For year-to-date 2020, net income was $138 million compared to $139 million for the corresponding period in 2019. The decrease was primarily due to a decrease in revenues as a result of a base rate reduction that became effective for the first billing cycle of April 2020, as well as a decrease in customer usage due to the COVID-19 pandemic,

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and an increase in depreciation, substantially offset by a decrease in amortization associated with ECO Plan regulatory assets and a decrease in income taxes associated with the flowback of excess deferred income taxes.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Mississippi Power – 2019 Base Rate Case" herein and Note 2 to the financial statements under "Mississippi Power – Environmental Compliance Overview Plan" in Item 8 of the Form 10-K for additional information.

Retail Revenues

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(19)	(7.6)	$(39)	(5.8)

In the third quarter 2020, retail revenues were $232 million compared to $251 million for the corresponding period in 2019. For year-to-date 2020, retail revenues were $630 million compared to $669 million for the corresponding period in 2019.

Details of the changes in retail revenues were as follows:

	Third Quarter 2020				Year-to-Date 2020
	(in millions)		(% change)		(in millions)		(% change)
Retail – prior year	$	251			$	669
Estimated change resulting from –
Rates and pricing	(10)		(4.0)	%	(15)		(2.2)	%
Sales decline	(5)		(2.0)		(12)		(1.8)
Weather	(4)		(1.6)		(2)		(0.3)
Fuel and other cost recovery	—		—		(10)		(1.5)
Retail – current year	$	232	(7.6)	%	$	630	(5.8)	%

Revenues associated with changes in rates and pricing decreased in the third quarter and year-to-date 2020 when compared to the corresponding periods in 2019 primarily due to decreases in rates in accordance with the Mississippi Power Rate Case Settlement Agreement. The third quarter 2020 decrease was also due to a decrease in revenue associated with a tolling arrangement. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Mississippi Power – 2019 Base Rate Case" herein for additional information.

Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2020 when compared to the corresponding periods in 2019 largely due to lower overall customer usage resulting from work-from-home policies related to the COVID-19 pandemic and reluctance of consumers and businesses to resume pre-pandemic levels of activity.

Weather-adjusted residential KWH sales increased 3.3% and 2.7% in the third quarter and year-to-date 2020, respectively, primarily due to customer growth and an increase in average customer usage as a result of changes in customer behavior and work-from-home policies in response to the COVID-19 pandemic. Weather-adjusted commercial KWH sales decreased 5.8% and 7.1% in the third quarter and year-to-date 2020, respectively, primarily due to lower customer usage resulting from changes in consumer and business behavior, including the temporary closure of casinos, in response to the COVID-19 pandemic. Industrial KWH sales decreased 7.9% and 3.6% in the third quarter and year-to-date 2020, respectively, as a result of disruptions in supply chain and business operations driven by the COVID-19 pandemic and the overall decrease in business activity due to the resulting recession.

Fuel and other cost recovery revenues decreased for year-to-date 2020 when compared to the corresponding period in 2019 primarily as a result of lower recoverable fuel costs. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power's service territory. Electric rates include provisions to adjust billings for fluctuations in fuel costs,

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including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income.

Wholesale Revenues – Non-Affiliates

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(3)	(4.7)	$(14)	(7.9)

Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Mississippi Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. In addition, Mississippi Power provides service under long-term contracts with rural electric cooperative associations and municipalities located in southeastern Mississippi under cost-based electric tariffs which are subject to regulation by the FERC. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Mississippi Power" in Item 7 of the Form 10-K for additional information.

For year-to-date 2020, wholesale revenues from sales to non-affiliates were $164 million compared to $178 million for the corresponding period in 2019. This decrease was primarily due to decreases in revenue from MRA customers as a result of lower fuel costs, milder weather, and decreased customer usage as a result of the COVID-19 pandemic, and from fewer opportunity sales.

Wholesale Revenues – Affiliates

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(15)	(29.4)	$(27)	(24.8)

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 2020, wholesale revenues from sales to affiliates were $36 million compared to $51 million for the corresponding period in 2019. This decrease was primarily due to an $8 million decrease associated with lower KWH sales and a $7 million decrease primarily associated with lower natural gas prices.

For year-to-date 2020, wholesale revenues from sales to affiliates were $82 million compared to $109 million for the corresponding period in 2019. This decrease was primarily due to a $34 million decrease associated with lower natural gas prices, partially offset by a $7 million increase associated with higher KWH sales due to the dispatch of Mississippi Power's lower cost generation resources to serve the Southern Company system's territorial load.

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Fuel and Purchased Power Expenses

	Third Quarter 2020 vs. Third Quarter 2019			Year-to-Date 2020 vs. Year-to-Date 2019
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	(18)	(14.9)	$	(53)	(16.6)
Purchased power	—		—	3		20.0
Total fuel and purchased power expenses	$	(18)		$	(50)

In the third quarter 2020, total fuel and purchased power expenses were $109 million compared to $127 million for the corresponding period in 2019. The decrease was primarily due to a $9 million decrease associated with the volume of KWHs generated and a $9 million decrease primarily related to the lower average cost of natural gas.

For year-to-date 2020, total fuel and purchased power expenses were $284 million compared to $334 million for the corresponding period in 2019. The decrease was primarily due to a $47 million decrease related to the cost of fuel and purchased power primarily due to the lower average cost of natural gas.

Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Mississippi Power's fuel cost recovery clause.

Details of Mississippi Power's generation and purchased power were as follows:

	Third Quarter 2020	Third Quarter 2019	Year-to-Date 2020	Year-to-Date 2019
Total generation (in millions of KWHs)	5,011	5,554	13,662	14,125
Total purchased power (in millions of KWHs)	162	161	558	403
Sources of generation (percent) –
Coal	11	8	6	7
Gas	89	92	94	93
Cost of fuel, generated (in cents per net KWH) –
Coal	3.52	3.88	3.70	3.98
Gas	1.99	2.16	1.94	2.29
Average cost of fuel, generated (in cents per net KWH)	2.16	2.30	2.06	2.41
Average cost of purchased power (in cents per net KWH)	3.66	3.96	3.17	3.84

Fuel

In the third quarter 2020, fuel expense was $103 million compared to $121 million for the corresponding period in 2019. This decrease was primarily due to a 12.2% decrease in the volume of KWHs generated by natural gas, a 9.3% decrease in the average cost of coal per KWH generated, and a 7.8% decrease in the average cost of natural gas per KWH generated, partially offset by a 24.7% increase in the volume of KWHs generated by coal.

For year-to-date 2020, fuel expense was $266 million compared to $319 million for the corresponding period in 2019. This decrease was due to a 15.1% decrease in the average cost of natural gas per KWH generated, a 10.8% decrease in the volume of KWHs generated by coal, a 6.9% decrease in the average cost of coal per KWH generated, and a 2.0% decrease in the volume of KWHs generated by natural gas.

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Other Operations and Maintenance Expenses

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(10)	(13.9)	$(2)	(1.0)

In the third quarter 2020, other operations and maintenance expenses were $62 million compared to $72 million for the corresponding period in 2019. The decrease was primarily due to a $6 million decrease associated with the Kemper IGCC primarily related to an increase in salvage proceeds and the settlement of litigation and a decrease of $3 million in scheduled generation outage costs.

For year-to-date 2020, other operations and maintenance expenses were $202 million compared to $204 million for the corresponding period in 2019. The decrease was primarily due to an $8 million decrease associated with the Kemper IGCC primarily related to an increase in salvage proceeds, largely offset by increases of $3 million in certain employee compensation expenses deferred in 2019, $2 million in vegetation management expenses, and $2 million in scheduled generation outage costs.

See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (C) to the Condensed Financial Statements under "Other Matters – Mississippi Power – Kemper County Energy Facility" herein for additional information.

Depreciation and Amortization

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(1)	(2.1)	$(9)	(6.3)

In the third quarter 2020, depreciation and amortization was $47 million compared to $48 million for the corresponding period in 2019. For year-to-date 2020, depreciation and amortization was $135 million compared to $144 million for the corresponding period in 2019. These decreases were related to decreases in amortization of $5 million and $17 million in the third quarter and year-to-date 2020, respectively, primarily as a result of the ECO Plan regulatory assets being fully amortized in 2019, partially offset by amortization of a regulatory asset associated with an ARO. These decreases were partially offset by increases in depreciation of $4 million and $8 million in the third quarter and year-to-date 2020, respectively, primarily related to additional plant in service and an increase in depreciation rates in accordance with the Mississippi Power Rate Case Settlement Agreement. See Note (B) to the Condensed Financial Statements under "Mississippi Power – 2019 Base Rate Case" herein and Note 2 to the financial statements under "Mississippi Power – Environmental Compliance Overview Plan" in Item 8 of the Form 10-K for additional information.

Interest Expense, Net of Amounts Capitalized

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(3)	(17.6)	$(7)	(13.5)

For year-to-date 2020, interest expense, net of amounts capitalized was $45 million compared to $52 million for the corresponding period in 2019. The decrease primarily resulted from a decrease in outstanding long-term borrowings.

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Income Taxes

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(3)	(20.0)	$(7)	(25.9)

For year-to-date 2020, income taxes were $20 million compared to $27 million for the corresponding period in 2019. The decrease was primarily due to a decrease of $9 million associated with the flowback of excess deferred income taxes as a result of the Mississippi Power Rate Case Settlement Agreement. See Note (G) to the Condensed Financial Statements herein for additional information.

Southern Power

Net Income Attributable to Southern Power

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(12)	(14.0)	$(104)	(32.9)

Net income attributable to Southern Power for the third quarter 2020 was $74 million compared to $86 million for the corresponding period in 2019. The decrease was primarily due to reduced net income related to the disposition of Plant Mankato in the first quarter 2020.

Net income attributable to Southern Power for year-to-date 2020 was $212 million compared to $316 million for the corresponding period in 2019. The decrease was primarily due to the gain on the sale of Plant Nacogdoches in the second quarter 2019 of $88 million after tax, partially offset by the gain on sale of Plant Mankato in the first quarter 2020 of $23 million after tax. In addition, the decrease reflects the reduced net income related to these dispositions.

See Note (K) to the Condensed Financial Statements under "Southern Power" herein and Note 15 to the financial statements under "Southern Power" in Item 8 of the Form 10-K for additional information.

Operating Revenues

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(51)	(8.9)	$(190)	(12.4)

Total operating revenues include PPA capacity revenues, which are derived primarily from long-term contracts involving natural gas facilities and a biomass generating facility (through the second quarter 2019 sale of Plant Nacogdoches), and PPA energy revenues from Southern Power's generation facilities. To the extent Southern Power has capacity not contracted under a PPA, it may sell power into an accessible wholesale market, or, to the extent those generation assets are part of the FERC-approved IIC, it may sell power into the Southern Company power pool.

Natural Gas and Biomass Capacity and Energy Revenue

Capacity revenues generally represent the greatest contribution to operating income and are designed to provide recovery of fixed costs plus a return on investment.

Energy is generally sold at variable cost or is indexed to published natural gas indices. Energy revenues will vary depending on the energy demand of Southern Power's customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Power's energy. Energy revenues also include fees for support services, fuel storage, and unit start charges. Increases and decreases in energy revenues under PPAs that are driven by fuel or purchased power prices are accompanied by an increase or decrease in fuel and purchased power costs and do not have a significant impact on net income.

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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" herein for additional information regarding Southern Power's PPAs.

Operating Revenues Details

Details of Southern Power's operating revenues were as follows:

	Third Quarter 2020		Third Quarter 2019		Year-to-Date 2020		Year-to-Date 2019
	(in millions)
PPA capacity revenues	$	116	$	131	$	297	$	384
PPA energy revenues	319		339		794		857
Total PPA revenues	435		470		1,091		1,241
Non-PPA revenues	84		101		235		276
Other revenues	4		3		11		10
Total operating revenues	$	523	$	574	$	1,337	$	1,527

In the third quarter 2020, total operating revenues were $523 million, reflecting a $51 million, or 9%, decrease from the corresponding period in 2019. The decrease in operating revenues was primarily due to the following:

•PPA capacity revenues decreased $15 million, or 11%, due to the disposition of Plant Mankato in the first quarter 2020.

•PPA energy revenues decreased $20 million, or 6%, due to a $29 million decrease in sales from natural gas facilities resulting from a $26 million decrease in the volume of KWHs sold due to reduced demand and a $3 million decrease in the average cost of fuel and purchased power. This decrease was partially offset by a $9 million increase in sales from a fuel cell project acquired in late 2019.

•Non-PPA revenues decreased $17 million, or 17%, due to a $20 million decrease in the market price of energy, partially offset by a $3 million increase in the volume of KWHs sold through short-term sales.

For year-to-date 2020, total operating revenues were $1.3 billion, reflecting a $190 million, or 12%, decrease from the corresponding period in 2019. The decrease in operating revenues was primarily due to the following:

•PPA capacity revenues decreased $87 million, or 23%, primarily due to decreases of $60 million related to the dispositions of Plant Nacogdoches in the second quarter 2019 and Plant Mankato in the first quarter 2020 and $24 million from the contractual expiration of an affiliate natural gas PPA.

•PPA energy revenues decreased $63 million, or 7%, due to a $115 million decrease in sales from natural gas facilities resulting from a $64 million decrease in the volume of KWHs sold due to decreased demand and a $51 million decrease in the price of fuel and purchased power. This decrease was partially offset by increases of $22 million in sales primarily driven by the volume of KWHs generated by solar and wind facilities and $29 million in sales from a fuel cell project acquired in late 2019.

•Non-PPA revenues decreased $41 million, or 15%, due to a $95 million decrease in the market price of energy, partially offset by a $54 million increase in the volume of KWHs sold through short-term sales.

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Fuel and Purchased Power Expenses

Details of Southern Power's generation and purchased power were as follows:

	Third Quarter 2020	Third Quarter 2019	Year-to-Date 2020	Year-to-Date 2019
	(in billions of KWHs)
Generation	12.3	13.8	34.3	35.7
Purchased power	0.7	0.8	2.3	2.5
Total generation and purchased power	13.0	14.6	36.6	38.2
Total generation and purchased power, excluding solar, wind, and tolling agreements	7.4	8.6	21.9	22.3

Southern Power's PPAs for natural gas generation generally provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing Southern Power for substantially all of the cost of fuel relating to the energy delivered under such PPAs. Consequently, changes in such fuel costs are generally accompanied by a corresponding change in related fuel revenues and do not have a significant impact on net income. Southern Power is responsible for the cost of fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the wholesale market or into the Southern Company power pool for capacity owned directly by Southern Power.

Purchased power expenses will vary depending on demand, availability, and the cost of generating resources throughout the Southern Company system and other contract resources. Load requirements are submitted to the Southern Company power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power, an affiliate company, or external parties. Such purchased power costs are generally recovered through PPA revenues.

Details of Southern Power's fuel and purchased power expenses were as follows:

	Third Quarter 2020 vs. Third Quarter 2019			Year-to-Date 2020 vs. Year-to-Date 2019
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	(29)	(17.5)	$	(103)	(22.9)
Purchased power	(7)		(26.9)	(30)		(36.6)
Total fuel and purchased power expenses	$	(36)		$	(133)

In the third quarter 2020, total fuel and purchased power expenses decreased $36 million, or 19%, compared to the corresponding period in 2019. Fuel expense decreased $29 million due to a $26 million decrease associated with the volume of KWHs generated and a $3 million decrease in the average cost of fuel per KWH generated. Purchased power expense decreased $7 million due to a $6 million decrease associated with the average cost of purchased power and a $1 million decrease associated with the volume of KWHs purchased.

For year-to-date 2020, total fuel and purchased power expenses decreased $133 million, or 25%, compared to the corresponding period in 2019. Fuel expense decreased $103 million due to a $97 million decrease in the average cost of fuel per KWH generated and a $6 million decrease associated with the volume of KWHs generated. Purchased power expense decreased $30 million due to a $22 million decrease associated with the average cost of purchased power and an $8 million decrease associated with the volume of KWHs purchased.

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(Gain) Loss on Dispositions, Net

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$—	N/M	$(16)	N/M

N/M - Not meaningful

For year-to-date 2020, gain on dispositions, net was $39 million compared to $23 million for the corresponding period in 2019, reflecting the sale of Plant Mankato in the first quarter 2020 and the sale of Plant Nacogdoches in the second quarter 2019. See Note (K) to the Condensed Financial Statements herein and Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power – Sales of Natural Gas and Biomass Plants" for additional information.

Interest Expense, Net of Amounts Capitalized

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(7)	(16.3)	$(13)	(10.2)

In the third quarter 2020, interest expense, net of amounts capitalized was $36 million compared to $43 million for the corresponding period in 2019. For year-to-date 2020, interest expense, net of amounts capitalized was $114 million compared to $127 million for the corresponding period in 2019. The decreases were primarily due to lower outstanding debt. See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein for additional information.

Other Income (Expense), Net

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$7	116.7	$(29)	(60.4)

In the third quarter 2020, other income (expense), net was $13 million compared to $6 million for the corresponding period in 2019. The increase was primarily due to the resolution of certain contingencies in the third quarter 2020 associated with the Roserock solar facility litigation settlement in 2019.

For year-to-date 2020, other income (expense), net was $19 million compared to $48 million for the corresponding period in 2019. The decrease was primarily due to a $36 million gain arising from the Roserock solar facility litigation settlement in the second quarter 2019, partially offset by the resolution of certain related contingencies in the third quarter 2020.

See Note 3 to the financial statements in Item 8 of the Form 10-K under "General Litigation Matters – Southern Power" for additional information.

Income Taxes (Benefit)

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(5)	(26.3)	$68	165.9

For year-to-date 2020, income tax expense was $27 million compared to a $41 million benefit for the corresponding period in 2019. The change was primarily due to a $75 million income tax benefit in 2019 resulting from ITCs recognized upon the sale of Plant Nacogdoches, partially offset by a decrease in income tax expense as a result of lower pre-tax earnings. See Notes (G) and (K) to the Condensed Financial Statements herein for additional information.

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Net Income Attributable to Noncontrolling Interests

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$3	N/M	$(23)	N/M

For year-to-date 2020, net income attributable to noncontrolling interests was $3 million compared to $26 million for the corresponding period in 2019. The change was primarily due to an allocation of approximately $26 million of income to the noncontrolling interest partner related to the Roserock solar facility litigation settlement in the second quarter 2019. See Note 3 to the financial statements in Item 8 of the Form 10-K under "General Litigation Matters – Southern Power" for additional information.

Southern Company Gas

Operating Metrics

Southern Company Gas continues to focus on several operating metrics, including Heating Degree Days, customer count, and volumes of natural gas sold.

Southern Company Gas measures weather and the effect on its business using Heating Degree Days. Generally, increased Heating Degree Days result in higher demand for natural gas on Southern Company Gas' distribution system. Southern Company Gas has various regulatory mechanisms, such as weather and revenue normalization and straight-fixed-variable rate design, which limit its exposure to weather changes within typical ranges in each of its utility's respective service territory, including Nicor Gas following the approval of a revenue decoupling mechanism for residential customers in its base rate case that concluded in 2019. Southern Company Gas also utilizes weather hedges to limit the negative income impacts in the event of warmer-than-normal weather.

The number of customers served by gas distribution operations and gas marketing services can be impacted by natural gas prices, economic conditions, and competition from alternative fuels. Gas distribution operations and gas marketing services' customers are primarily located in Georgia, Illinois, and Ohio.

Southern Company Gas' natural gas volume metrics for gas distribution operations and gas marketing services illustrate the effects of weather and customer demand for natural gas. Wholesale gas services' physical sales volumes represent the daily average natural gas volumes sold to its customers.

Seasonality of Results

During the Heating Season, natural gas usage and operating revenues are generally higher as more customers are connected to the gas distribution systems and natural gas usage is higher in periods of colder weather. Occasionally in the summer, wholesale gas services' operating revenues are impacted due to peak usage by power generators in response to summer energy demands. Southern Company Gas' base operating expenses, excluding cost of natural gas, bad debt expense, and certain incentive compensation costs, are incurred relatively evenly throughout the year. Seasonality also affects the comparison of certain balance sheet items across quarters, including receivables, unbilled revenues, natural gas for sale, and notes payable. However, these items are comparable when reviewing Southern Company Gas' annual results. Thus, Southern Company Gas' operating results for the interim periods presented are not necessarily indicative of annual results and can vary significantly from quarter to quarter.

Net Income (Loss)

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$43	148.3	$13	3.7

In the third quarter 2020, net income was $14 million compared to a $29 million net loss for the corresponding period in 2019. This increase was primarily due to a $65 million after-tax impairment charge in 2019 related to a natural gas storage facility in Louisiana, partially offset by a $36 million decrease at wholesale gas services in 2020

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as a result of lower commercial activity and derivative losses. Also contributing to the increase was a $9 million increase at gas distribution operations primarily due to base rate increases for Nicor Gas and Atlanta Gas Light and continued investment in infrastructure replacement programs, partially offset by reduced flowback of excess deferred income taxes at Atlanta Gas Light in 2020.

For year-to-date 2020, net income was $360 million compared to $347 million for the corresponding period in 2019. This increase was primarily due to a $65 million after-tax impairment charge in 2019 related to a natural gas storage facility in Louisiana and a $56 million increase at gas distribution operations primarily due to base rate increases for Nicor Gas and Atlanta Gas Light and continued investment in infrastructure replacement programs, partially offset by reduced flowback of excess deferred income taxes at Atlanta Gas Light in 2020. The increase was partially offset by a $106 million decrease at wholesale gas services in 2020 primarily due to lower commercial activity and lower derivative gains.

See Note 2 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.

Natural Gas Revenues, including Alternative Revenue Programs

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(21)	(4.2)	$(299)	(11.2)

In the third quarter 2020, natural gas revenues, including alternative revenue programs, were $477 million compared to $498 million for the corresponding period in 2019. For year-to-date 2020, natural gas revenues, including alternative revenue programs, were $2.4 billion compared to $2.7 billion for the corresponding period in 2019.

Details of the changes in natural gas revenues, including alternative revenue programs, were as follows:

	Third Quarter 2020				Year-to-Date 2020
	(in millions)		(% change)		(in millions)		(% change)
Natural gas revenues – prior year	$	498			$	2,661
Estimated change resulting from –
Infrastructure replacement programs and base rate changes	34		6.8	%	153		5.7	%
Gas costs and other cost recovery	(8)		(1.6)		(298)		(11.2)
Weather	2		0.4		(6)		(0.2)
Wholesale gas services	(49)		(9.8)		(151)		(5.6)
Other	—		—		3		0.1
Natural gas revenues – current year	$	477	(4.2)	%	$	2,362	(11.2)	%

Revenues from infrastructure replacement programs and base rate changes increased in the third quarter and year-to-date 2020 compared to the corresponding periods in 2019 primarily due to base rate increases at Nicor Gas and Atlanta Gas Light and continued investments recovered through infrastructure replacement programs. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" in Item 8 of the Form 10-K for additional information.

Revenues associated with gas costs and other cost recovery decreased in the third quarter and year-to-date 2020 compared to the corresponding periods in 2019 primarily due to lower natural gas prices. The year-to-date decrease also reflects lower sales volumes in 2020 compared to the corresponding period in 2019 primarily as a result of warmer weather. Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations. See "Cost of Natural Gas" herein for additional information. Revenue impacts from weather and customer growth are described further below.

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AND RESULTS OF OPERATIONS (Continued)

Revenues from wholesale gas services decreased in the third quarter 2020 compared to the corresponding period in 2019 due to decreased commercial activity as a result of milder weather and derivative losses and for year-to-date 2020 compared to the corresponding period in 2019 primarily due to decreased commercial activity as a result of warmer weather and a decrease in derivative gains. See "Segment Information – Wholesale Gas Services" herein for additional information.

Southern Company Gas hedged the majority of its exposure to warmer-than-normal weather in Illinois for gas distribution operations and in Illinois and Georgia for gas marketing services. During Heating Season, natural gas usage and operating revenues are generally higher. Weather typically does not have a significant net income impact other than during the Heating Season. 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			2020 vs. normal		2020 vs. 2019		Year-to-Date			2020 vs. normal		2020 vs. 2019
	Normal(*)	2020	2019	colder		colder		Normal(*)	2020	2019	(warmer)		(warmer)
	(in thousands)							(in thousands)
Illinois	54	54	2	—	%	N/M		3,773	3,548	3,958	(6.0)	%	(10.4)	%
Georgia	2	15	—	N/M		—	%	1,530	1,294	1,298	(15.4)	%	(0.3)	%

(*)Normal represents the 10-year average from January 1, 2010 through September 30, 2019 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.

The following table provides the number of customers served by Southern Company Gas at September 30, 2020 and 2019:

	September 30,
	2020		2019		2020 vs. 2019
	(in thousands, except market share %)				(% change)
Gas distribution operations	4,258		4,208		1.2	%
Gas marketing services
Energy customers(*)	659		611		7.9	%
Market share of energy customers in Georgia	28.9	%	28.5	%	1.4	%

(*)Gas marketing services' customers are primarily located in Georgia, Ohio, and Illinois. Also included as of September 30, 2020 were approximately 50,000 customers in Ohio contracted through an annual auction process to serve for 12 months beginning April 1, 2020.

Southern Company Gas anticipates continued customer growth as it expects continued low natural gas prices. The number of customers served by Southern Company Gas' natural gas distribution utilities at September 30, 2020 was positively impacted by the suspension of disconnections during the COVID-19 pandemic, which resulted in a higher than historical average year-over-year change. Southern Company Gas uses a variety of targeted marketing programs to attract new customers and to retain existing customers.

Cost of Natural Gas

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(8)	(10.1)	$(302)	(31.6)

Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations. Cost of natural gas at gas distribution operations represented 80% and 86% of total cost

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AND RESULTS OF OPERATIONS (Continued)

of natural gas for the third quarter and year-to-date 2020, 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 2020, cost of natural gas was $71 million compared to $79 million for the corresponding period in 2019. This decrease reflects an 11.3% decrease in natural gas prices in the third quarter 2020 compared to the corresponding period in 2019.

For year-to-date 2020, cost of natural gas was $654 million compared to $956 million for the corresponding period in 2019. This decrease reflects a 29.6% decrease in natural gas prices compared to 2019 and decreased volumes primarily as a result of warmer weather for year-to-date 2020 compared to the corresponding period in 2019.

The following table details the volumes of natural gas sold during all periods presented.

	Third Quarter		2020 vs. 2019		Year-to-Date		2020 vs. 2019
	2020	2019			2020	2019
Gas distribution operations (mmBtu in millions)
Firm	68	66	3.0	%	425	462	(8.0)	%
Interruptible	21	22	(4.5)		67	68	(1.5)
Total	89	88	1.1	%	492	530	(7.2)	%
Wholesale gas services (mmBtu in millions/day)
Daily physical sales	7.1	6.3	12.7	%	6.8	6.3	7.9	%
Gas marketing services (mmBtu in millions)
Firm:
Georgia	3	3	—	%	21	22	(4.5)	%
Illinois	1	1	—		6	8	(25.0)
Ohio and other	2	1	100.0		9	11	(18.2)
Interruptible large commercial and industrial	3	3	—		10	10	—
Total	9	8	12.5	%	46	51	(9.8)	%

Other Operations and Maintenance Expenses

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$9	4.3	$54	8.4

In the third quarter 2020, other operations and maintenance expenses were $217 million compared to $208 million for the corresponding period in 2019. For year-to-date 2020, other operations and maintenance expenses were $696 million compared to $642 million for the corresponding period in 2019. These increases were primarily due to increases in compensation and benefit expenses and pipeline repair, compliance, and maintenance activities. The year-to-date 2020 increase also reflects an increase in expenses passed through directly to customers primarily related to bad debt.

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AND RESULTS OF OPERATIONS (Continued)

Depreciation and Amortization

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$4	3.3	$9	2.5

For year-to-date 2020, depreciation and amortization was $368 million compared to $359 million for the corresponding period in 2019. The increase was primarily due to continued infrastructure investments at gas distribution operations.

Taxes Other Than Income Taxes

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$2	6.1	$(7)	(4.3)

For year-to-date 2020, taxes other than income taxes were $154 million compared to $161 million for the corresponding period in 2019. The decrease primarily relates to a decrease in revenue tax expenses as a result of lower natural gas revenues at Nicor Gas. These revenue tax expenses are passed through directly to customers and have no impact on net income.

Impairment Charges

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(92)	(100.0)	$(92)	(100.0)

In the third quarter 2019, a $92 million impairment charge was recorded related to a natural gas storage facility in Louisiana. See Note 3 to the financial statements under "Other Matters – Southern Company Gas – Natural Gas Storage Facilities" in Item 8 of the Form 10-K for additional information.

Earnings from Equity Method Investments

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$(2)	(5.7)	$(9)	(7.8)

For year-to-date 2020, earnings from equity method investments were $106 million compared to $115 million for the corresponding period in 2019. The decrease primarily relates to lower earnings at SNG due to lower demand and firm revenues, the sale of Atlantic Coast Pipeline in the first quarter 2020, and the sale of Triton in the second quarter 2019. See Note (E) to the Condensed Financial Statements herein for additional information.

Other Income (Expense), Net

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$7	140.0	$17	106.3

In the third quarter 2020, other income (expense), net was $12 million compared to $5 million for the corresponding period in 2019. For year-to-date 2020, other income (expense), net was $33 million compared to $16 million for the corresponding period in 2019. These increases were primarily due to increases in non-service cost-related retirement benefits income. See Note (H) to the Condensed Financial Statements herein for additional information.

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AND RESULTS OF OPERATIONS (Continued)

Income Taxes (Benefit)

Third Quarter 2020 vs. Third Quarter 2019		Year-to-Date 2020 vs. Year-to-Date 2019
(change in millions)	(% change)	(change in millions)	(% change)
$25	113.6	$37	60.7

In the third quarter 2020, income taxes were $3 million compared to a $22 million benefit for the corresponding period in 2019. For year-to-date 2020, income taxes were $98 million compared to $61 million for the corresponding period in 2019. These increases were primarily due to a decrease in the flowback of excess deferred income taxes at Atlanta Gas Light as authorized by the Georgia PSC and higher pre-tax earnings. The year-to-date 2020 increase also includes the reversal of a federal income tax valuation allowance in connection with the sale of Triton in 2019. See Note (G) to the Condensed Financial Statements herein for additional information.

Performance and Non-GAAP Measures

Adjusted operating margin is a non-GAAP measure that is calculated as operating revenues less cost of natural gas, cost of other sales, and revenue tax expense. Adjusted operating margin excludes other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, and impairment charges, which are included in the calculation of operating income as calculated in accordance with GAAP and reflected in the statements of income. The presentation of adjusted operating margin is believed to provide useful information regarding the contribution resulting from base rate changes, infrastructure replacement programs and capital projects, and customer growth at gas distribution operations since the cost of natural gas and revenue tax expense can vary significantly and are generally billed directly to customers. Southern Company Gas further believes that utilizing adjusted operating margin at gas pipeline investments, wholesale gas services, and gas marketing services allows it to focus on a direct measure of performance before overhead costs. The applicable reconciliation of operating income to adjusted operating margin is provided herein.

Adjusted operating margin should not be considered an alternative to, or a more meaningful indicator of, Southern Company Gas' operating performance than operating income as determined in accordance with GAAP. In addition, Southern Company Gas' adjusted operating margin may not be comparable to similarly titled measures of other companies.

Detailed variance explanations of Southern Company Gas' financial performance are provided herein.

Reconciliations of operating income to adjusted operating margin are as follows:

	Third Quarter 2020		Third Quarter 2019		Year-to-Date 2020		Year-to-Date 2019
	(in millions)
Operating Income	$	29	$	(35)	$	490	$	451
Other operating expenses(a)	377		454		1,218		1,254
Revenue taxes(b)	(10)		(9)		(77)		(85)
Adjusted Operating Margin	$	396	$	410	$	1,631	$	1,620

(a)Includes other operations and maintenance, depreciation and amortization, taxes other than income taxes, and impairment charges.

(b)Nicor Gas' revenue tax expenses, which are passed through directly to customers.

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Segment Information

Adjusted operating margin, operating expenses, and net income for each segment are provided in the table below. See Note (L) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.

	Third Quarter 2020						Third Quarter 2019
	Adjusted Operating Margin(*)		Operating Expenses(*)		Net Income (Loss)		Adjusted Operating Margin(*)		Operating Expenses(*)		Net Income (Loss)(b)
	(in millions)						(in millions)
Gas distribution operations	$	412	$	317	$	46	$	376	$	294	$	37
Gas pipeline investments	8		3		23		8		3		6
Wholesale gas services	(51)		11		(45)		(3)		11		(9)
Gas marketing services	21		27		(3)		21		28		(4)
All other	8		11		(7)		9		110		(59)
Intercompany eliminations	(2)		(2)		—		(1)		(1)		—
Consolidated	$	396	$	367	$	14	$	410	$	445	$	(29)

(*)Adjusted operating margin and operating expenses are adjusted for Nicor Gas' revenue tax expenses, which are passed through directly to customers.

	Year-to-Date 2020						Year-to-Date 2019
	Adjusted Operating Margin(*)		Operating Expenses(*)		Net Income (Loss)		Adjusted Operating Margin(*)		Operating Expenses(*)		Net Income (Loss)
	(in millions)						(in millions)
Gas distribution operations	$	1,448	$	971	$	284	$	1,294	$	895	$	228
Gas pipeline investments	24		9		74		24		9		63
Wholesale gas services	(20)		39		(45)		122		40		61
Gas marketing services	163		85		59		163		90		54
All other	21		42		(12)		22		140		(59)
Intercompany eliminations	(5)		(5)		—		(5)		(5)		—
Consolidated	$	1,631	$	1,141	$	360	$	1,620	$	1,169	$	347

(*)Adjusted operating margin and operating expenses are adjusted for Nicor Gas' revenue tax expenses, which are passed through directly to customers.

Gas Distribution Operations

Gas distribution operations is the largest component of Southern Company Gas' business and is subject to regulation and oversight by 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 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.

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AND RESULTS OF OPERATIONS (Continued)

In the third quarter 2020, net income increased $9 million, or 24.3%, compared to the corresponding period in 2019. The $36 million increase in adjusted operating margin primarily reflects base rate increases for Nicor Gas and Atlanta Gas Light and continued investments recovered through infrastructure replacement programs. The $23 million increase in operating expenses includes increases for compensation and benefit expenses and pipeline repair and maintenance activities, as well as higher depreciation primarily due to additional assets placed in service. The $8 million increase in other income is primarily due to an increase in non-service cost-related retirement benefits income. Income tax expense increased $12 million primarily due to higher pre-tax earnings and a decrease in the flowback of excess deferred income taxes at Atlanta Gas Light as authorized by the Georgia PSC.

For year-to-date 2020, net income increased $56 million or 24.6%, compared to the corresponding period in 2019. The $154 million increase in adjusted operating margin primarily reflects base rate increases for Nicor Gas and Atlanta Gas Light and continued investments recovered through infrastructure replacement programs, partially offset by warmer weather, net of weather normalization mechanisms. The $76 million increase in operating expenses includes increases for compensation and benefit expenses and pipeline compliance and maintenance activities, as well as bad debt costs passed through directly to customers. The increase also reflects higher depreciation primarily due to additional assets placed in service, partially offset by lower revenue tax expense. The $20 million increase in other income is primarily due to an increase in non-service cost-related retirement benefits income. The $43 million increase in income tax expense is primarily due to higher pre-tax earnings and a decrease in the flowback of excess deferred income taxes at Atlanta Gas Light as authorized by the Georgia PSC.

See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein for additional information.

Gas Pipeline Investments

Gas pipeline investments consists primarily of joint ventures in natural gas pipeline investments including SNG, PennEast Pipeline, Dalton Pipeline, and Atlantic Coast Pipeline (until its sale on March 24, 2020). See Notes (E) and (K) to the Condensed Financial Statements under "Southern Company Gas" herein and Note 7 to the financial statements in Item 8 of the Form 10-K for additional information.

In the third quarter 2020, net income increased $17 million, or 283.3%, compared to the corresponding period in 2019. This increase primarily relates to an $18 million decrease in income taxes primarily related to a 2019 increase associated with changes in state apportionment rates.

For year-to-date 2020, net income increased $11 million, or 17.5%, compared to the corresponding period in 2019. This increase primarily relates to a $5 million decrease in interest expense, net of amounts capitalized and a $21 million decrease in income taxes primarily related to a 2019 increase associated with changes in state apportionment rates in 2019, partially offset by a $15 million decrease in earnings primarily at SNG.

Wholesale Gas Services

Wholesale gas services is involved in asset management and optimization, storage, transportation, producer and peaking services, natural gas supply, natural gas services, and wholesale gas marketing. Southern Company Gas has positioned the business to generate positive economic earnings on an annual basis even under low volatility market conditions that can result from a number of factors. When market price volatility increases, wholesale gas services is well positioned to capture significant value and generate stronger results. Operating expenses primarily reflect employee compensation and benefits.

In the third quarter 2020, net income decreased $36 million, or 400.0%, compared to the corresponding period in 2019. This decrease primarily relates to a $48 million decrease in adjusted operating margin, partially offset by a $12 million decrease in income tax expense due to lower pre-tax earnings.

For year-to-date 2020, net income decreased $106 million, or 173.8%, compared to the corresponding period in 2019. This decrease primarily relates to a $142 million decrease in adjusted operating margin, partially offset by a $34 million decrease in income tax expense due to lower pre-tax earnings.

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AND RESULTS OF OPERATIONS (Continued)

Details of the changes in adjusted operating margin are provided in the table below.

	Third Quarter 2020		Third Quarter 2019		Year-to-Date 2020		Year-to-Date 2019
	(in millions)
Commercial activity recognized	$	(23)	$	2	$	(55)	$	43
Gain (loss) on storage derivatives	(21)		2		(33)		7
Gain (loss) on transportation and forward commodity derivatives	(7)		(4)		69		68
LOCOM adjustments, net of current period recoveries	—		—		—		(6)
Purchase accounting adjustments to fair value inventory and contracts	—		(3)		(1)		10
Adjusted operating margin	$	(51)	$	(3)	$	(20)	$	122

Change in Commercial Activity

The commercial activity at wholesale gas services includes recognition of storage and transportation values that were generated in prior periods, which reflect the impact of prior period hedge gains and losses as associated physical transactions occur. The decrease in commercial activity in the third quarter and year-to-date 2020 compared to the corresponding periods in 2019 was primarily due to warmer-than-normal weather conditions and tightening transportation spreads.

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. Forward storage or time spreads applicable to the locations of wholesale gas services' specific storage positions in 2020 resulted in storage derivative losses. Transportation and forward commodity derivative losses for the third quarter 2020 are a result of widening transportation spreads. Transportation and forward commodity derivative gains for year-to-date 2020 are primarily the result of narrowing transportation spreads due to supply constraints and increases in natural gas supply, which impacted forward prices at natural gas receipt and delivery points, primarily in the Northeast and Midwest regions.

Withdrawal Schedule and Physical Transportation Transactions

The expected natural gas withdrawals from storage and expected offset to prior hedge losses/gains associated with the transportation portfolio of wholesale gas services are presented in the following table, along with the net operating revenues expected at the time of withdrawal from storage and the physical flow of natural gas between contracted transportation receipt and delivery points. Wholesale gas services' expected net operating revenues exclude storage and transportation demand charges, as well as other variable fuel, withdrawal, receipt, and delivery charges, and exclude estimated profit sharing under asset management agreements. Further, the amounts that are realizable in future periods are based on the inventory withdrawal schedule, planned physical flow of natural gas between the transportation receipt and delivery points, and forward natural gas prices at September 30, 2020. A portion of wholesale gas services' storage inventory and transportation capacity is economically hedged with futures contracts, which results in the realization of substantially fixed net operating revenues.

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AND RESULTS OF OPERATIONS (Continued)

	Storage withdrawal schedule
	Total storage(a)	Expected net operating gains(b)		Physical transportation transactions – expected net operating losses(c)
	(in mmBtu in millions)	(in millions)		(in millions)
2020	10	$	10	$	(5)
2021 and thereafter	46	60		(64)
Total at September 30, 2020	56	$	70	$	(69)

(a)At September 30, 2020, the WACOG of wholesale gas services' expected natural gas withdrawals from storage was $1.72 per mmBtu.

(b)Represents expected operating gains from planned storage withdrawals associated with existing inventory positions and could change as wholesale gas services adjusts its daily injection and withdrawal plans in response to changes in future market conditions and forward NYMEX price fluctuations.

(c)Represents the transportation derivative gains and (losses) that will be settled during the period and the physical transportation transactions that offset the derivative gains and losses previously recognized.

The unrealized storage and transportation derivative gains do not change the underlying economic value of wholesale gas services' storage and transportation positions and will be reversed when the related transactions occur and are recognized. For more information on wholesale gas services' energy marketing and risk management activities, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" in Item 7 of the Form 10-K.

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.

For the third quarter and year-to-date 2020, net loss decreased $1 million, or 25%, and net income increased $5 million, or 9%, respectively, compared to the corresponding periods in 2019. These changes primarily relate to decreases in operating expenses.

All Other

All other includes natural gas storage businesses, fuels operations through the sale of Southern Company Gas' interest in Pivotal LNG on March 24, 2020, the investment in Triton through its sale on May 29, 2019, AGL Services Company, and Southern Company Gas Capital, as well as various corporate operating expenses that are not allocated to the reportable segments and interest income (expense) associated with affiliate financing arrangements. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information on the sale of its interest in Pivotal LNG.

In the third quarter 2020, net loss decreased $52 million compared to the corresponding period in 2019. This decrease primarily reflects a $99 million decrease in operating expenses primarily related to an impairment charge in 2019 related to a natural gas storage facility in Louisiana, partially offset by a $42 million increase in income taxes associated with changes in state apportionment rates in 2019 and the reversal of a related federal income tax valuation allowance in connection with the sale of Triton in 2019.

For year-to-date 2020, net loss decreased $47 million compared to the corresponding period in 2019. This decrease includes a $98 million decrease in operating expenses primarily related to an impairment charge in 2019 related to a natural gas storage facility in Louisiana and a $6 million increase in earnings from equity method investments primarily due to a pre-tax loss on the sale of Triton in 2019, partially offset by a $48 million increase in income taxes associated with changes in state apportionment rates in 2019 and the reversal of a related federal income tax valuation allowance in connection with the sale of Triton in 2019, a $3 million decrease in other income (expenses), and a $5 million increase in interest expense, net of amounts capitalized.

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Segment Reconciliations

Reconciliations of operating income to adjusted operating margin for the third quarter and year-to-date 2020 and 2019 are reflected in the following tables. See Note (L) to the Condensed Financial Statements herein for additional information.

	Third Quarter 2020
	Gas Distribution Operations		Gas Pipeline Investments		Wholesale Gas Services		Gas Marketing Services		All Other		Intercompany Elimination		Consolidated
	(in millions)
Operating Income (Loss)	$	95	$	5	$	(62)	$	(6)	$	(3)	$	—	$	29
Other operating expenses(a)	327		3		11		27		11		(2)		377
Revenue tax expense(b)	(10)		—		—		—		—		—		(10)
Adjusted Operating Margin	$	412	$	8	$	(51)	$	21	$	8	$	(2)	$	396

	Third Quarter 2019
	Gas Distribution Operations		Gas Pipeline Investments		Wholesale Gas Services		Gas Marketing Services		All Other		Intercompany Elimination		Consolidated
	(in millions)
Operating Income (Loss)	$	82	$	5	$	(14)	$	(7)	$	(101)	$	—	$	(35)
Other operating expenses(a)	303		3		11		28		110		(1)		454
Revenue tax expense(b)	(9)		—		—		—		—		—		(9)
Adjusted Operating Margin	$	376	$	8	$	(3)	$	21	$	9	$	(1)	$	410

	Year-to-Date 2020
	Gas Distribution Operations		Gas Pipeline Investments		Wholesale Gas Services		Gas Marketing Services		All Other		Intercompany Elimination		Consolidated
	(in millions)
Operating Income (Loss)	$	477	$	15	$	(59)	$	78	$	(21)	$	—	$	490
Other operating expenses(a)	1,048		9		39		85		42		(5)		1,218
Revenue tax expense(b)	(77)		—		—		—		—		—		(77)
Adjusted Operating Margin	$	1,448	$	24	$	(20)	$	163	$	21	$	(5)	$	1,631

	Year-to-Date 2019
	Gas Distribution Operations		Gas Pipeline Investments		Wholesale Gas Services		Gas Marketing Services		All Other		Intercompany Elimination		Consolidated
	(in millions)
Operating Income (Loss)	$	399	$	15	$	82	$	73	$	(118)	$	—	$	451
Other operating expenses(a)	980		9		40		90		140		(5)		1,254
Revenue tax expense(b)	(85)		—		—		—		—		—		(85)
Adjusted Operating Margin	$	1,294	$	24	$	122	$	163	$	22	$	(5)	$	1,620

(a)Includes other operations and maintenance, depreciation and amortization, taxes other than income taxes, and impairment charges.

(b)Nicor Gas' revenue tax expenses, which are passed through directly to customers.

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AND RESULTS OF OPERATIONS (Continued)

FUTURE EARNINGS POTENTIAL

Each Registrant's results of operations are not necessarily indicative of its future earnings potential. Recent disposition activities described under "Acquisitions and Dispositions" herein, in Note (K) to the Condensed Financial Statements herein, and in Note 15 to the financial statements in Item 8 of the Form 10-K will impact future earnings for the applicable Registrants. The level of the Registrants' future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Registrants' primary businesses of selling electricity and/or distributing natural gas, as described further herein.

For the traditional electric operating companies, these factors include the ability to maintain constructive regulatory environments that allow for the timely recovery of prudently-incurred costs during a time of increasing costs, continued customer growth, and the trend of reduced electricity usage per customer, especially in residential and commercial markets. Other major factors include completing construction of Plant Vogtle Units 3 and 4 and related cost recovery proceedings for Georgia Power and the ability to prevail against legal challenges associated with the Kemper County energy facility for Mississippi Power.

Earnings in the electricity business will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions, which could contribute to a net reduction in customer usage.

Global and U.S. economic conditions have been significantly affected by a series of demand and supply shocks that have caused a global and national economic recession. Most prominently, the COVID-19 pandemic has negatively impacted global supply chains and global demand for goods and services and public policy responses of social distancing and closing non-essential businesses have further restricted economic activity. The drivers, speed, and depth of this economic contraction are unprecedented and have reduced energy demand across the Southern Company system's service territory, primarily in the commercial and industrial classes. The negative impacts, which started in late-March 2020, of the COVID-19 pandemic and related recession on the Southern Company system's retail electric sales began to improve in the middle of May 2020; however, retail electric revenues have declined slightly compared to 2019. Recovery is expected to continue for the remainder of 2020 and into 2021, but responses to the COVID-19 pandemic by both customers and governments could significantly affect the pace of recovery. The ultimate extent of the negative impact on revenues depends on the depth and duration of the economic contraction in the Southern Company system's service territory and cannot be determined at this time. See RESULTS OF OPERATIONS herein for information on COVID-19-related impacts on energy demand in the Southern Company system's service territory during the first nine months of 2020.

The traditional electric operating companies have established installment payment plans to allow customers to repay over a period of time past due accounts resulting from the COVID-19 pandemic. See "Regulatory Matters" herein for additional information on the status of disconnections and the deferral of costs resulting from the COVID-19 pandemic at Georgia Power, Mississippi Power, and the natural gas distribution utilities. The ultimate outcome of these matters cannot be determined at this time.

The level of future earnings for Southern Power's competitive wholesale electric business depends on numerous factors including Southern Power's ability to execute its growth strategy through the development or acquisition of renewable facilities and other energy projects while containing costs, as well as regulatory matters, creditworthiness of customers, total electric generating capacity available in Southern Power's market areas, and Southern Power's ability to successfully remarket capacity as current contracts expire. In addition, renewable portfolio standards, transmission constraints, cost of generation from units within the Southern Company power pool, and operational limitations could influence Southern Power's future earnings.

The level of future earnings for Southern Company Gas' primary business of distributing natural gas and its complementary businesses in the gas pipeline investments, wholesale gas services, 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, the completion and subsequent operation of ongoing infrastructure and other construction projects, creditworthiness of customers,

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and Southern Company Gas' ability to optimize its transportation and storage positions and to re-contract storage rates at favorable prices. 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 and wholesale gas services businesses to capture value from locational and seasonal spreads. Additionally, changes in commodity prices subject a portion of Southern Company Gas' operations to earnings variability. Over the longer term, volatility is expected to be low to moderate and locational and/or transportation spreads are expected to decrease as new pipelines are built to reduce the existing supply constraints in the shale areas of the Northeast U.S. To the extent these pipelines are further delayed or not built, volatility could increase. See "Construction Programs" herein for additional information on permitting challenges experienced by the PennEast Pipeline. Additional economic factors may contribute to this environment, including a significant drop in oil and natural gas prices, which could lead to consolidation of natural gas producers or reduced levels of natural gas production. In addition, if the COVID-19 pandemic results in a continued economic downturn for a sustained period, demand for natural gas may decrease, resulting in further downward pressure on natural gas prices and lower volatility in the natural gas markets on a longer-term basis.

Earnings for both the electricity and natural gas businesses are subject to a variety of other factors. These factors include weather, competition, developing new and maintaining existing energy contracts and associated load requirements with wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the prices of electricity and natural gas, and the price elasticity of demand. Demand for electricity and natural gas in the Registrants' service territories is primarily driven by the pace of economic growth or decline that may be affected by changes in regional and global economic conditions, which may impact future earnings.

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. In addition, Southern Power and Southern Company Gas regularly consider and evaluate joint development arrangements as well as acquisitions and dispositions of businesses and assets as part of their business strategies.

For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL in Item 7 of the Form 10-K and RISK FACTORS in Item 1A herein.

Acquisitions and Dispositions

See Note 15 to the financial statements in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements herein for additional information.

Alabama Power

On August 31, 2020, Alabama Power completed the Autauga Combined Cycle Acquisition. See "Regulatory Matters – Alabama Power" herein and Note (K) to the Condensed Financial Statements under "Alabama Power" herein for additional information.

Southern Power

On January 17, 2020, Southern Power completed the sale of its equity interests in Plant Mankato (including the 385-MW expansion unit completed in May 2019) to a subsidiary of Xcel for a purchase price of approximately $663 million, including final working capital adjustments. The sale resulted in a gain of approximately $39 million ($23 million after tax). Pre-tax income for Plant Mankato was immaterial for all periods presented.

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In March 2020, Southern Power entered into an agreement to acquire a controlling membership interest in an approximately 300-MW wind facility located in South Dakota. The acquisition is subject to FERC approval and certain other customary conditions to closing, including commercial operation of the facility, which is expected to occur in the first quarter 2021. The facility's output is contracted under two long-term PPAs. The ultimate outcome of this matter cannot be determined at this time.

On May 1, 2020, Southern Power purchased a controlling interest in the 56-MW Beech Ridge II wind facility located in Greenbrier County, West Virginia from Invenergy Renewables LLC. The facility's output is contracted under a 12-year PPA. See Note (K) to the Condensed Financial Statements herein for additional information.

Southern Power continues to evaluate and refine the deployment of the remaining wind turbine equipment purchased in 2016 and 2017 to development and construction projects. During the nine months ended September 30, 2020, certain wind turbine equipment was sold, resulting in an immaterial gain.

Southern Company Gas

On March 24, 2020, Southern Company Gas completed the sale of its interests in Pivotal LNG and Atlantic Coast Pipeline to Dominion Modular LNG Holdings, Inc. and Dominion Atlantic Coast Pipeline, LLC, respectively, with aggregate proceeds of $178 million, including working capital adjustments. The loss associated with the transactions was immaterial. Southern Company Gas also expects to receive payments in February 2021 and September 2021 of $5 million each contingent upon Dominion Modular LNG Holdings, Inc. meeting certain milestones related to Pivotal LNG. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.

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 "Environmental Remediation" herein, for additional information.

Environmental Laws and Regulations

Water Quality

On October 13, 2020, the EPA published the final effluent limitations guidelines reconsideration rule, which extends the latest applicability date to comply with the generally applicable limits for both flue gas desulfurization wastewater and bottom ash transport water to December 31, 2025. The rule also provides exemptions for low utilization of electric generating units and permanent cessation of coal combustion. The impact of the final rule on the traditional electric operating companies and SEGCO will depend on the incorporation of these new requirements into each generating unit's National Pollutant Discharge Elimination System permit and the outcome of any legal challenges and cannot be determined at this time.

Coal Combustion Residuals

On August 28, 2020, the EPA published the final Part A CCR Rule that requires facilities to cease placement of both CCR and non-CCR waste in unlined surface impoundments as soon as technically feasible, but no later than April 11, 2021. The rule allows extensions beyond April 11, 2021, provided certain conditions are met. Impacts to the Southern Company system are expected to be limited, as the traditional electric operating companies and SEGCO stopped sending coal ash from most of their generating units to unlined ponds in April 2019 and expect to stop sending coal ash from the remaining generating units within the timeframes allowed in the rule.

In June 2020, Alabama Power recorded an increase of approximately $462 million to its AROs related to the CCR Rule and the related state rule primarily due to management's completion of a feasibility study and the related cost estimates during the second quarter 2020 for one of its ash ponds. Alabama Power's increase also reflects costs associated with the addition of a water treatment system to the design of another ash pond. The additional estimated

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costs to close these ash ponds under the planned closure-in-place methodology primarily relate to inputs from contractor bids, design revisions, and changes in the expected volume of ash handling.

During the third quarter 2020, Georgia Power completed an assessment of its plans to close the ash ponds at all of its generating plants in compliance with the CCR Rule and the related state rule. The related cost estimates were further refined, including updates to long-term post-closure care requirements, market pricing, and timing of future cash outlays. As a result, in September 2020, Georgia Power recorded an increase of approximately $411 million to its AROs related to the CCR Rule and the related state rule.

The traditional electric operating companies expect to continue updating their cost estimates and ARO liabilities periodically as additional information related to ash pond closure methodologies, schedules, and/or costs becomes available, and the changes could be material. Additionally, the closure designs and plans in the States of Alabama and Georgia are subject to approval by environmental regulatory agencies. Absent continued recovery of ARO costs through regulated rates, results of operations, cash flows, and financial condition for Southern Company and the traditional electric operating companies could be materially impacted. See Note 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 – Integrated Resource Plan" for additional information. The ultimate outcome of these matters cannot be determined at this time. See Note 6 to the financial statements in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.

Regulatory Matters

See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.

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.

Petition for Certificate of Convenience and Necessity

On August 14, 2020, the Alabama PSC issued its order regarding Alabama Power's petition for a CCN, which authorized Alabama Power to (i) construct an approximately 720-MW combined cycle facility at Alabama Power's Plant Barry (Plant Barry Unit 8), which is expected to be placed in service by the end of 2023, (ii) complete the Autauga Combined Cycle Acquisition, which occurred on August 31, 2020, (iii) purchase approximately 240 MWs of combined cycle generation under a long-term PPA, which began on September 1, 2020, and (iv) pursue up to approximately 200 MWs of cost-effective demand-side management and distributed energy resource programs.

The Alabama PSC authorized the recovery of actual costs for the construction of Plant Barry Unit 8 up to 5% above the estimated in-service cost of $652 million. In so doing, it recognized the potential for developments that could cause the project costs to exceed the capped amount, in which case Alabama Power would provide documentation to the Alabama PSC to explain and justify potential recovery of the additional costs.

The Alabama PSC further directed that the proposed solar generation of approximately 400 MWs, coupled with battery energy storage systems (solar/battery systems), be evaluated under an existing Renewable Generation Certificate (RGC) issued by the Alabama PSC in September 2015. The contracts proposed in the CCN petition expired on July 31, 2020. Any future requests for solar/battery systems will be evaluated under the RGC process.

Energy Alabama, Gasp, Inc., and the Sierra Club filed petitions for reconsideration and rehearing with the Alabama PSC. Alabama PSC action on these petitions is expected by November 10, 2020. Upon issuance of a written order reflecting such action, affected parties would have 30 days to pursue an appeal through the State of Alabama court system.

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Alabama Power expects to recover all approved costs associated with the CCN through existing rate mechanisms as outlined in Note 2 to the financial statements in Item 8 of the Form 10-K.

The ultimate outcome of these matters cannot be determined at this time.

Rate ECR

On August 7, 2020, the Alabama PSC issued an order authorizing Alabama Power to reduce its over-collected fuel balance by $100 million and return that amount to customers in the form of bill credits for the billing month of October 2020. Any portion of the $100 million undistributed following the bill credit process will remain in the Rate ECR regulatory liability for the benefit of customers.

Rate NDR

In the third quarter 2020, Alabama Power recorded $44 million against the NDR for damages incurred to its transmission and distribution facilities from Hurricane Sally. The NDR balance available for storm damages was $51 million as of September 30, 2020. If the balance falls below $50 million, a reserve establishment charge would be activated (and the ongoing reserve maintenance charge concurrently suspended) until the reserve balance reaches $75 million.

Georgia Power

Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through an alternate rate plan, which includes traditional base tariffs, Demand-Side Management tariffs, the ECCR tariff, and Municipal Franchise Fee tariffs. In addition, financing costs on certified construction costs of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a separate fuel cost recovery tariff.

Rate Plans

2019 ARP

In accordance with the terms of the 2019 ARP, on October 1, 2020, Georgia Power filed the following tariff adjustments to become effective January 1, 2021 pending approval by the Georgia PSC:

•increase traditional base tariffs by approximately $120 million;

•increase the ECCR tariff by approximately $2 million;

•decrease Demand-Side Management tariffs by approximately $15 million; and

•increase Municipal Franchise Fee tariffs by approximately $4 million.

The ultimate outcome of this matter cannot be determined at this time.

2013 ARP

In 2019, Georgia Power's retail ROE exceeded 12.00% and, under the modified sharing mechanism pursuant to the 2019 ARP, Georgia Power reduced regulatory assets by approximately $60 million and accrued refunds for retail customers of approximately $60 million. On September 1, 2020, the Georgia PSC authorized Georgia Power to issue customers bill credits prior to final review of the 2019 Annual Surveillance Report by the staff of the Georgia PSC. Georgia Power issued the bill credits in October 2020.

Deferral of Incremental COVID-19 Costs

On April 7, 2020 and June 2, 2020, in response to the COVID-19 pandemic, the Georgia PSC approved orders directing Georgia Power to continue its previous, voluntary suspension of customer disconnections through July 14, 2020 and to defer the resulting incremental bad debt as a regulatory asset. On June 16, 2020 and July 7, 2020, the Georgia PSC approved orders establishing a methodology for identifying incremental bad debt and allowing the

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deferral of other incremental costs associated with the COVID-19 pandemic. The period over which such costs will be recovered is expected to be determined in Georgia Power's next base rate case. At September 30, 2020, the incremental costs deferred totaled approximately $38 million. The ultimate outcome of this matter cannot be determined at this time.

Integrated Resource Plan

On March 5, 2020, the Sierra Club filed a petition for judicial review in the Superior Court of Fulton County to appeal the Georgia PSC's decision in the 2019 ARP allowing Georgia Power to recover compliance costs for CCR AROs. Georgia Power intervened in the appeal on June 22, 2020. The ultimate outcome of this matter cannot be determined at this time.

Fuel Cost Recovery

On May 28, 2020, the Georgia PSC approved a stipulation agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors to lower total fuel billings by approximately $740 million over a two-year period effective June 1, 2020. In addition, Georgia Power further lowered fuel billings by approximately $44 million under an interim fuel rider effective June 1, 2020 through September 30, 2020. Georgia Power continues to be allowed to adjust its fuel cost recovery rates under an interim fuel rider prior to its next fuel case if the under or over recovered fuel balance exceeds $200 million. Georgia Power is scheduled to file its next fuel case no later than February 28, 2023.

Mississippi Power

Mississippi Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Mississippi PSC. Mississippi Power's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased power, ad valorem taxes, property damage, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are expected to be recovered through Mississippi Power's base rates.

2019 Base Rate Case

On March 17, 2020, the Mississippi PSC approved the Mississippi Power Rate Case Settlement Agreement between Mississippi Power and the Mississippi Public Utilities Staff related to Mississippi Power's base rate case filed in November 2019.

Under the terms of the Mississippi Power Rate Case Settlement Agreement, annual retail rates decreased approximately $16.7 million, or 1.85%, effective for the first billing cycle of April 2020, based on a test year period of January 1, 2020 through December 31, 2020, a 53% average equity ratio, an allowed maximum actual equity ratio of 55% by the end of 2020, and a 7.57% return on investment.

Additionally, the approved Mississippi Power Rate Case Settlement Agreement: (i) established common amortization periods of four years for regulatory assets and three years for regulatory liabilities included in the approved revenue requirement, including those related to unprotected deferred income taxes; (ii) established new depreciation rates reflecting an annual increase in depreciation of approximately $10 million; and (iii) excluded certain compensation costs totaling approximately $3.9 million. It also eliminated separate rates for costs associated with Plant Ratcliffe and energy efficiency initiatives and includes such costs in the PEP, ECO Plan, and ad valorem tax adjustment factor, as applicable. In accordance with the previous order of the Mississippi PSC suspending the operation of PEP and the ECO Plan for 2018 through 2020, Mississippi Power plans to resume PEP proceedings and ECO Plan filings for 2021.

Performance Evaluation Plan

On July 24, 2020, the Mississippi PSC approved Mississippi Power's July 14, 2020 filing of its PEP compliance rate clause reflecting revisions agreed to in the Mississippi Power Rate Case Settlement Agreement. These revisions

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include, among other things, changing the filing date for the annual PEP rate filing from November of the immediately preceding year to March of the current year, utilizing a historic test year adjusted for "known and measurable" changes, using discounted cash flow and regression formulas to determine base return on equity, and moving all embedded ad valorem property taxes currently collected in PEP to the ad valorem tax adjustment clause.

Deferral of Incremental COVID-19 Costs

On April 14, 2020 and May 12, 2020, in order to mitigate the economic impact of the COVID-19 pandemic on customers, the Mississippi PSC approved orders directing Mississippi Power to continue its previous, voluntary suspension of customer disconnections through May 26, 2020 and to defer as a regulatory asset all necessary and reasonable incremental costs or expenses to plan, prepare, stage, or react to protect and keep safe its employees and customers, and to reliably operate its utility system during the COVID-19 pandemic. The period over which such costs will be recovered is expected to be determined in a future PEP filing. At September 30, 2020, the incremental costs deferred totaled approximately $2 million. The ultimate outcome of this matter cannot be determined at this time.

Municipal and Rural Associations Tariff

On June 25, 2020, the FERC accepted Mississippi Power's April 27, 2020 request for an increase in wholesale base revenues under the MRA tariff as agreed upon in a settlement agreement reached with its wholesale customers. The MRA settlement agreement resulted in a $2 million annual increase in base rates effective June 1, 2020.

Southern Company Gas

The natural gas distribution utilities are subject to regulation and oversight by their respective state regulatory agencies for the rates charged to their customers and other matters. With the exception of Atlanta Gas Light, which does not sell natural gas to end-use customers, the natural gas distribution utilities are authorized by the relevant regulatory agencies in the states in which they serve to use natural gas cost recovery mechanisms that adjust rates to reflect changes in the wholesale cost of natural gas and ensure recovery of all costs prudently incurred in purchasing natural gas for customers. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on revenues or net income, but will affect cash flows. In addition to natural gas cost recovery mechanisms, there are other cost recovery mechanisms, such as regulatory riders, which vary by utility but allow recovery of certain costs, such as those related to infrastructure replacement programs, as well as environmental remediation, energy efficiency plans, and bad debt.

The natural gas distribution utilities have various regulatory mechanisms to recover bad debt expense, which will mitigate potential increases in bad debt expense as a result of the COVID-19 pandemic. Nicor Gas fully recovers its bad debt expenses, both the gas and non-gas portions, through its purchased gas adjustment mechanism and separate bad debt rider. Virginia Natural Gas and Chattanooga Gas recover the gas portion of bad debt expense through their purchased gas adjustment mechanisms and the non-gas portion of bad debt expense through their base rates in accordance with established benchmarks. Atlanta Gas Light does not have material bad debt expense because its receivables are from Marketers, rather than end-use customers. Its tariff allows it to obtain credit security support from the Marketers in an amount equal to at least two times their estimated highest bill.

Rate Proceedings

On June 1, 2020, Virginia Natural Gas filed a general rate case with the Virginia Commission seeking an increase in rates of $49.6 million primarily to recover investments and increased costs associated with infrastructure, technology, and workforce development. The requested increase is based on a projected 12-month test year beginning November 1, 2020, a ROE of 10.35%, and an equity ratio of 54%. Rate adjustments are expected to be effective November 1, 2020, subject to refund. The Virginia Commission is expected to rule on the requested increase in the second quarter 2021.

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On July 1, 2020, Atlanta Gas Light filed its 2020 GRAM filing with the Georgia PSC. The filing requests an annual base rate increase of $37.6 million based on the projected 12-month period beginning January 1, 2021, which does not exceed the 5% limitation established by the Georgia PSC in its December 2019 approval of Atlanta Gas Light's general base rate case. Resolution of the 2020 GRAM filing is expected by December 31, 2020, with rates effective January 1, 2021.

The ultimate outcome of these matters cannot be determined at this time.

Deferral of Incremental COVID-19 Costs

Atlanta Gas Light

On April 30, 2020, in response to the COVID-19 pandemic, the Georgia PSC approved orders directing Atlanta Gas Light to continue its previous, voluntary suspension of customer disconnections. On June 22, 2020, the Georgia PSC ordered Atlanta Gas Light to resume customer disconnections beginning July 1, 2020, with exceptions for customers still covered by a shelter-in-place order. The orders provide the Marketers, including SouthStar, with a mechanism to receive credits from Atlanta Gas Light for the base rates it charged to the Marketers of non-paying customers during the suspension. Atlanta Gas Light expects to recover these credits through the annual revenue true-up process within its future GRAM filings, which would impact rates starting on January 1, 2022. The ultimate outcome of this matter cannot be determined at this time.

Nicor Gas

On March 18, 2020, in response to the COVID-19 pandemic, the Illinois Commission issued an order directing utilities to cease disconnections for non-payment and to suspend the imposition of late payment fees or penalties. In response to this order, on March 27, 2020, Nicor Gas and other utilities in Illinois filed their plans seeking cost recovery and providing more flexible credit and collection plans.

On June 18, 2020, the Illinois Commission approved a stipulation pursuant to which the utilities will provide more flexible credit and collection procedures to assist customers with financial hardship and which authorizes a special purpose rider for recovery of the following COVID-19 pandemic-related impacts: incremental costs directly associated with the COVID-19 pandemic, net of the offset for COVID-19 pandemic-related credits received, foregone late fees, foregone reconnection charges, and the costs associated with a bill payment assistance program. Nicor Gas resumed late payment fees on July 27, 2020 and, on October 1, 2020, began recovery of the COVID-19 pandemic-related impacts through the special purpose rider, which will continue over a 24-month period. In response to an Illinois Commission request, Nicor Gas will continue to voluntarily suspend residential customer disconnections for non-payment through March 31, 2021. At September 30, 2020, Nicor Gas' related regulatory asset was $13 million.

Virginia Natural Gas

In response to the COVID-19 pandemic, the Virginia Commission issued orders requiring Virginia Natural Gas to suspend disconnections beginning on March 16, 2020 and also to suspend late payment and reconnection fees beginning on April 9, 2020, both of which expired on October 5, 2020. On April 29, 2020, the Virginia Commission authorized Virginia Natural Gas to defer the following COVID-19 pandemic-related costs as a regulatory asset: incremental uncollectible expense incurred, suspended late fees, suspended reconnection charges, carrying costs, and other incremental prudently incurred costs associated with the COVID-19 pandemic. Specific recovery of the amounts deferred in a regulatory asset will be addressed in a future rate proceeding. At September 30, 2020, Virginia Natural Gas' related regulatory asset was $1 million. The ultimate outcome of this matter cannot be determined at this time.

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Construction Programs

Overview

The Subsidiary Registrants 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, 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 "Nuclear Construction" herein for additional information. Also see Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Alabama Power" for information regarding Alabama Power's construction of Plant Barry Unit 8.

While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. See "Southern Power" herein, "Acquisitions and Dispositions – Southern Power" herein, and Note (K) to the Condensed Financial Statements under "Southern Power" herein, as well as Note 15 to the financial statements under "Southern Power" in Item 8 of the Form 10-K, for additional information about costs relating to Southern Power's acquisitions that involve 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 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 "Southern Company Gas" herein for additional information regarding infrastructure improvement programs at the natural gas distribution utilities and the PennEast Pipeline construction project.

See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information regarding the Registrants' capital requirements for their construction programs.

Nuclear Construction

See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding Georgia Power's construction of Plant Vogtle Units 3 and 4, the joint ownership agreements and related funding agreement, VCM reports, and the NCCR tariff.

In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4, 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 begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement. In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.

In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into several transitional arrangements to allow construction to continue. In July 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into the Vogtle Services Agreement, whereby Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis. The Vogtle Services Agreement provides that it will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.

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In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, executed the Bechtel Agreement, a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.

See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for information on the Amended and Restated Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.

Cost and Schedule

Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 by the expected in-service dates of November 2021 and November 2022, respectively, is as follows:

	(in billions)
Base project capital cost forecast(a)(b)	$	8.4
Construction contingency estimate	0.1
Total project capital cost forecast(a)(b)	8.5
Net investment as of September 30, 2020(b)	(6.9)
Remaining estimate to complete(a)	$	1.6

(a)    Excludes financing costs expected to be capitalized through AFUDC of approximately $240 million, of which $71 million had been accrued through September 30, 2020.

(b)    Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds.

Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.0 billion, of which $2.5 billion had been incurred through September 30, 2020.

As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of engineering support, commodity installation, system turnovers and related test results, and workforce statistics.

As of June 30, 2020, assignments of contingency exceeded the remaining balance of the $366 million construction contingency originally established in the second quarter 2018 by approximately $34 million. This contingency was used to address cost risks related to construction productivity, including the April 2020 reduction in workforce designed to mitigate impacts of the COVID-19 pandemic described below; craft labor incentives; adding resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement, among other factors. As a result of these factors, Georgia Power established $115 million of additional construction contingency as of June 30, 2020 for further potential risks including, among other factors, construction productivity and expected impacts of the COVID-19 pandemic; additional resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement.

After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income

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of $149 million ($111 million after tax) for the increase in the total project capital cost forecast as of June 30, 2020. As and when these amounts are spent, Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery.

During the third quarter 2020, approximately $5 million of the construction contingency established in the second quarter 2020 was assigned to the base capital cost forecast for cost risks primarily associated with construction productivity and field support.

In April 2019, Southern Nuclear established aggressive target values for monthly construction production and system turnover activities as part of a strategy to maintain and, where possible, build margin to the regulatory-approved in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4. Through early 2020, the project faced challenges with the April 2019 aggressive strategy targets including, but not limited to, electrical and pipefitting labor productivity and work package closure rates, which resulted in a backlog of activities and completion percentages below the April 2019 aggressive strategy targets.

In February 2020, Southern Nuclear updated its cost and schedule forecast, which, at that time, did not change the total project capital cost forecast and confirmed the expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4. This update included initiatives to improve productivity while refining and extending system turnover plans and certain near-term milestone dates. Other milestone dates did not change. Achievement of the February 2020 aggressive site work plan relied on meeting increased monthly production and activity target values during 2020.

In mid-March 2020, Southern Nuclear began implementing policies and procedures designed to mitigate the risk of transmission of COVID-19 at the construction site, including worker distancing measures, isolating individuals who have tested positive for COVID-19, are showing symptoms consistent with COVID-19, are being tested for COVID-19, or have been in close contact with such persons, requiring self-quarantine, and adopting additional precautionary measures.

In April 2020, Georgia Power, acting for itself and as agent for the other Vogtle Owners, announced a reduction in workforce at Plant Vogtle Units 3 and 4, which totaled approximately 20% of the then-existing site workforce. This reduction in workforce was a mitigation action intended to address the impact of the COVID-19 pandemic on the Plant Vogtle Units 3 and 4 workforce and construction site, including challenges with labor productivity that were exacerbated by the impact of the COVID-19 pandemic. The April 2020 workforce reduction was intended to provide operational efficiencies by increasing productivity of the remaining workforce and reducing workforce fatigue and absenteeism. Further, it was also intended to allow for increased social distancing by the workforce and facilitate compliance with the recommendations from the Centers for Disease Control and Prevention. The April 2020 workforce reduction did reduce absenteeism, providing an improvement in operational efficiency and allowing for increased social distancing. From the initial peak in April 2020, the number of active cases at the site declined significantly during May and early June, but began increasing again from mid-June through July, and continued to impact productivity levels and pace of activity completion. As a result of these factors, overall production improvements were not achieved at the levels anticipated, contributing to the June 30, 2020 allocation of, and increase in, construction contingency described above. Through mid-July 2020, Unit 3 mechanical, electrical, and subcontract activities continued to build a backlog to Southern Nuclear's February 2020 aggressive site work plan.

To address these issues, in July 2020, Southern Nuclear updated its aggressive site work plan for both Unit 3 and Unit 4. Through October 2020, the project has faced challenges in meeting the July 2020 aggressive site work plan targets including, but not limited to, overall construction and subcontractor labor productivity, which has resulted in a backlog of activities and completion percentages below the July 2020 aggressive site work plan targets. In addition, while the number of active COVID-19 cases at the site has declined since July 2020, the COVID-19 pandemic continues to impact productivity and the pace of activity completion. After considering these factors, Southern Nuclear has further extended milestone dates from the July 2020 aggressive site work plan. Achievement of these extended milestone dates depends on absenteeism rates continuing to normalize and overall construction productivity and production levels, including subcontractors, significantly improving and being sustained above pre-pandemic levels. In addition, appropriate levels of craft laborers, particularly electrical and pipefitter craft labor,

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need to be added and maintained. Georgia Power still expects to achieve the regulatory-approved in-service dates of November 2021 and November 2022 for Plant Vogtle Units 3 and 4, respectively. Southern Nuclear and Georgia Power continue to believe that pursuit of an aggressive site work plan is an appropriate strategy to achieve completion of the units by their regulatory-approved in-service dates.

As construction, including subcontract work, continues and testing and system turnover activities increase, challenges with management of contractors and vendors; subcontractor performance; supervision of craft labor and related productivity, particularly in the installation of electrical, mechanical, and instrumentation and controls commodities, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, installation, system turnover, and the initial testing and start-up, including any required engineering changes or any remediation related thereto, of plant systems, structures, or components (some of which are based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale), any of which may require additional labor and/or materials; or other issues could arise and change the projected schedule and estimated cost.

In addition, the continuing effects of the COVID-19 pandemic could further disrupt or delay construction, testing, supervisory, and support activities at Plant Vogtle Units 3 and 4. Georgia Power's proportionate share of the estimated incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is currently estimated to be between $70 million and $115 million, which is included in the total project capital cost forecast and assumes (i) absenteeism rates continue to normalize and (ii) the intended productivity efficiencies and production targets assumed in Southern Nuclear's July 2020 aggressive site work plan are realized in the coming months. However, the ultimate impact of the COVID-19 pandemic on the construction schedule and budget for Plant Vogtle Units 3 and 4 cannot be determined at this time.

There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel, may arise, which may result in additional license amendments or require other resolution. As part of the aggressive site work plan, in January 2020, Southern Nuclear notified the NRC of its intent to load fuel in 2020. On June 15, 2020, the NRC rejected Nuclear Watch South's April 20, 2020 petition requesting a hearing and challenging the closure of certain ITAAC. On August 10, 2020, the Atomic Safety and Licensing Board rejected the Blue Ridge Environmental Defense League's (BREDL) May 11, 2020 petition challenging a license amendment request. The staff of the NRC has issued the requested amendment to the combined construction and operating license for Plant Vogtle Unit 3. BREDL appealed the Atomic Safety and Licensing Board decision to the NRC. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.

The ultimate outcome of these matters cannot be determined at this time. However, any extension of the regulatory-approved project schedule is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $10 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.

Joint Owner Contracts

In November 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 to provide for, among other conditions, additional Vogtle Owner approval requirements.

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Effective in August 2018, the Vogtle Owners further amended the joint ownership agreements to clarify and provide procedures for certain provisions of the joint ownership agreements related to adverse events that require the vote of the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 to continue construction (as amended, and together with the November 2017 amendment, the Vogtle Joint Ownership Agreements). The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.

As a result of an increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs in conjunction with the nineteenth VCM report in 2018, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. In September 2018, the Vogtle Owners unanimously voted to continue construction of Plant Vogtle Units 3 and 4.

Amendments to the Vogtle Joint Ownership Agreements

In connection with the vote to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and MEAG Power's wholly-owned subsidiaries MEAG Power SPVJ, LLC (MEAG SPVJ), MEAG Power SPVM, LLC (MEAG SPVM), and MEAG Power SPVP, LLC (MEAG SPVP) to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners, including additional amendments to the Vogtle Joint Ownership Agreements and the purchase of PTCs from the other Vogtle Owners at pre-established prices, and (ii) a term sheet (MEAG Term Sheet) with MEAG Power and MEAG SPVJ to provide up to $300 million of funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. In January 2019, Georgia Power, MEAG Power, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. In February 2019, Georgia Power, the other Vogtle Owners, and MEAG Power's wholly-owned subsidiaries MEAG SPVJ, MEAG SPVM, and MEAG SPVP entered into certain amendments to the Vogtle Joint Ownership Agreements to implement the provisions of the Vogtle Owner Term Sheet (Global Amendments).

As previously disclosed, pursuant to the Global Amendments: (i) each Vogtle Owner must pay its proportionate share of qualifying construction costs for Plant Vogtle Units 3 and 4 based on its ownership percentage up to the estimated cost at completion (EAC) for Plant Vogtle Units 3 and 4 which formed the basis of Georgia Power's forecast of $8.4 billion in the nineteenth VCM plus $800 million; (ii) Georgia Power will be responsible for 55.7% of actual qualifying construction costs between $800 million and $1.6 billion over the EAC in the nineteenth VCM (resulting in $80 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests; and (iii) Georgia Power will be responsible for 65.7% of qualifying construction costs between $1.6 billion and $2.1 billion over the EAC in the nineteenth VCM (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests. If the EAC is revised and exceeds the EAC in the nineteenth VCM by more than $2.1 billion, each of the other Vogtle Owners will have a one-time option at the time the project budget forecast is so revised to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100% of such Vogtle Owner's remaining share of total construction costs in excess of the EAC in the nineteenth VCM plus $2.1 billion.

In addition, pursuant to the Global Amendments, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including, among other events: (i) the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power's public announcement of its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 or the Georgia PSC determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Vogtle Owners pursuant to the Global Amendments described above

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and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Georgia PSC for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates; and (iv) an incremental extension of one year or more over the most recently approved schedule.

The ultimate outcome of these matters cannot be determined at this time.

Regulatory Matters

In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. At September 30, 2020, Georgia Power had recovered approximately $2.5 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 will not record AFUDC related to any capital costs in excess of the total deemed reasonable by the Georgia PSC (currently $7.3 billion) and not requested for rate recovery. On October 1, 2020, Georgia Power filed a request to decrease the NCCR tariff by $142 million annually, effective January 1, 2021, pending Georgia PSC approval.

Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 of each year. In 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.

In 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) Georgia Power's seventeenth VCM report and modified the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.68 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and related customer refunds) was found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap and that prudence decisions on cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective Unit is commercially

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operational. The ROE reductions negatively impacted earnings by approximately $75 million in 2019 and are estimated to have negative earnings impacts of approximately $145 million, $255 million, and $200 million in 2020, 2021, and 2022, respectively. In its January 11, 2018 order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.

In February 2018, Georgia Interfaith Power & Light, Inc. (GIPL) and Partnership for Southern Equity, Inc. (PSE) filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. In March 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's decision and denial of Georgia Watch's motion for reconsideration. In December 2018, the Fulton County Superior Court granted Georgia Power's motion to dismiss the two appeals. In January 2019, GIPL, PSE, and Georgia Watch filed an appeal of this decision with the Georgia Court of Appeals. In October 2019, the Georgia Court of Appeals issued an opinion affirming the Fulton County Superior Court's ruling that the Georgia PSC's January 11, 2018 order was not a final, appealable decision. In addition, the Georgia Court of Appeals remanded the case to the Fulton County Superior Court to clarify its ruling as to whether the petitioners showed that review of the Georgia PSC's final order would not provide them an adequate remedy. On April 21, 2020, the Fulton County Superior Court granted Georgia Power's motion to dismiss the two appeals. The petitioners filed a notice of appeal of the dismissal on May 20, 2020, which was withdrawn on August 20, 2020. This matter is now concluded.

The Georgia PSC has approved 22 VCM reports covering the periods through December 31, 2019, including total construction capital costs incurred through that date of $7.4 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds). Georgia Power filed its twenty-third VCM report with the Georgia PSC on August 31, 2020, which reflects the capital cost forecast discussed above and requests approval of $701 million of construction capital costs incurred from January 1, 2020 through June 30, 2020.

See RISK FACTORS in Item 1A herein and in the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world.

The ultimate outcome of these matters cannot be determined at this time.

Southern Power

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Construction Programs – Southern Power" in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information.

During the nine months ended September 30, 2020, Southern Power completed construction of and placed in service the Reading wind facility, continued construction of the Skookumchuck wind facility, and commenced construction of the Garland and Tranquillity battery energy storage facilities. Total aggregate construction costs, excluding acquisition costs, are expected to be between $475 million and $545 million for the facilities under construction. At September 30, 2020, total costs of construction incurred for these projects were $244 million and are included in CWIP. The ultimate outcome of these matters cannot be determined at this time.

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Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Actual/Expected COD	PPA Counterparties	PPA Contract Period
Projects Completed During the Nine Months Ended September 30, 2020
Reading(a)	Wind	200	Osage and Lyon Counties, KS	May 2020	Royal Caribbean Cruises LTD	12 years
Projects Under Construction as of September 30, 2020
Skookumchuck(b)	Wind	136	Lewis and Thurston Counties, WA	November 2020	Puget Sound Energy	20 years
Garland Solar Storage(c)	Battery energy storage system	88	Kern County, CA	Second quarter 2021	Southern California Edison	20 years
Tranquillity Solar Storage(c)	Battery energy storage system	72	Fresno County, CA	Second quarter 2021	Southern California Edison	20 years

(a)In 2018, Southern Power purchased 100% of the membership interests of the Reading facility pursuant to a joint development arrangement. At the time the facility was placed in service, Southern Power recorded an operating lease right-of-use asset and an operating lease liability, each in the amount of $24 million. In June 2020, Southern Power completed a tax equity transaction whereby it received $156 million and now owns 100% of the Class B membership interests.

(b)In October 2019, Southern Power purchased 100% of the membership interests of the Skookumchuck facility pursuant to a joint development arrangement. Southern Power expects to complete a tax equity transaction upon commercial operation and retain the Class B membership interests. Shortly after the completed tax equity transaction, Southern Power may sell a noncontrolling interest in these Class B membership interests to another partner. Southern Power would retain the controlling ownership interest in the facility. The ultimate outcome of these matters cannot be determined at this time.

(c)Prior to commercial operation, Southern Power may enter into one or more partnerships, in which case it would ultimately own less than 100% of the Class B membership interests, but would retain ownership of the controlling interest. The ultimate outcome of this matter cannot be determined at this time.

Southern Company Gas

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Construction Programs – Southern Company Gas" in Item 7 of the Form 10-K for additional information.

Infrastructure Replacement Programs and Capital Projects

In addition to capital expenditures recovered through base rates by each of the natural gas distribution utilities, Nicor Gas and Virginia Natural Gas have separate rate riders that provide timely recovery of capital expenditures for specific infrastructure replacement programs. Infrastructure expenditures incurred under these programs in the first nine months of 2020 were as follows:

Utility	Program	Year-to-Date 2020
		(in millions)
Nicor Gas	Investing in Illinois	$	294
Virginia Natural Gas	Steps to Advance Virginia's Energy (SAVE)	37
Total		$	331

In December 2019, Virginia Natural Gas filed an application with the Virginia Commission for a 24.1-mile header improvement project to improve resiliency and increase the supply of natural gas delivered to energy suppliers, including Virginia Natural Gas. On June 26, 2020, the Virginia Commission issued an order requiring Virginia Natural Gas to submit additional information by December 31, 2020 related to the financing plans of the project's primary customer before ruling on the December 2019 application. The ultimate outcome of this matter cannot be determined at this time.

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See Note 2 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" in Item 8 of the Form 10-K for additional information.

Pipeline Construction Projects

On March 24, 2020, Southern Company Gas completed the sale of its interest in Atlantic Coast Pipeline. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.

On February 20, 2020, the FERC approved a two-year extension for PennEast Pipeline to complete the project by January 19, 2022.

In September 2019, an appellate court ruled that the PennEast Pipeline does not have federal eminent domain authority over lands in which a state has property rights interests. On June 29, 2020, the U.S. Supreme Court requested the U.S. Solicitor General to provide an opinion on PennEast Pipeline's petition for a writ of certiorari seeking its review of the appellate court's decision.

Expected project costs related to the PennEast Pipeline for Southern Company Gas total approximately $300 million, excluding financing costs. The ultimate outcome of the PennEast Pipeline construction project cannot be determined at this time; however, any work delays, whether caused by judicial or regulatory action, abnormal weather, or other conditions, may result in additional cost or schedule modifications or, ultimately, in project cancellation, any of which could result in impairment of Southern Company Gas' investment and could have a significant impact on Southern Company's financial statements and a material impact on Southern Company Gas' financial statements.

See Notes 3 and 7 to the financial statements in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements herein under "Southern Company Gas" for additional information.

Southern Power's Power Sales Agreements

See BUSINESS – "The Southern Company System – Southern Power" in Item 1 of the Form 10-K and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Southern Power's Power Sales Agreements" in Item 7 of the Form 10-K for additional information regarding Southern Power's PPAs. Generally, under the solar and wind generation PPAs, the purchasing party retains the right to keep or resell the renewable energy credits.

During the first quarter 2020, Southern Power received $15 million from Pacific Gas & Electric Company (PG&E) in accordance with a November 2019 bankruptcy court order granting payment of certain transmission interconnections. PG&E emerged from bankruptcy on July 1, 2020 and Southern Power's PPAs and transmission interconnection agreements continue in effect unchanged.

Tax Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" in Item 7 of the Form 10-K and Note (G) to the Condensed Financial Statements herein for additional information.

On March 20, 2020 and April 9, 2020, the Treasury Department and the Internal Revenue Service issued Notices 2020-18 and 2020-23, respectively, providing relief to taxpayers by postponing to July 15, 2020 a variety of tax form filings and payment obligations that were due before July 15, 2020. Associated interest, additions to tax, and penalties for late filing or late payment were also suspended until July 16, 2020. These provisions had a modest positive impact on the Registrants' liquidity. However, Southern Power's expected utilization of tax credits in the first half of 2020 was delayed until July 15, 2020.

General Litigation Matters

The Registrants are involved in various other matters being litigated and regulatory matters that could affect future earnings. The ultimate outcome of such pending or potential litigation or regulatory matters against each Registrant

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and any subsidiaries cannot be determined at this time; however, for current proceedings not specifically reported herein or in Notes (B) and (C) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such Registrant's financial statements. See Notes (B) and (C) to the Condensed Financial Statements for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

The Registrants believe the pending legal challenges discussed below have no merit; however, the ultimate outcome of these matters cannot be determined at this time.

Southern Company

In January 2017, a securities class action complaint was filed in the U.S. District Court for the Northern District of Georgia by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint names as defendants Southern Company, certain of its current and former officers, and certain former Mississippi Power officers and alleges that the defendants made materially false and misleading statements regarding the Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. In 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. Also in 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition. In 2018, the court issued an order dismissing certain claims against certain officers of Southern Company and Mississippi Power and dismissing the allegations related to a number of the statements that plaintiffs challenged as being false or misleading. In 2018, the court denied the defendants' motion for reconsideration and also denied a motion to certify the issue for interlocutory appeal. In the third quarter 2019, the court certified the plaintiffs' proposed class and the defendants filed a petition for interlocutory appeal of the class certification order with the U.S. Court of Appeals for the Eleventh Circuit. In December 2019, the U.S. District Court for the Northern District of Georgia entered an order staying all deadlines in the case pending mediation. The stay automatically expired on March 31, 2020; however, in light of the COVID-19 pandemic, the U.S. District Court for the Northern District of Georgia vacated all existing discovery deadlines until June 15, 2020. On June 30, 2020, the court entered a revised scheduling order, which resumed discovery and set out remaining case deadlines. On August 15, 2020, the parties reached a settlement. On September 8, 2020, the plaintiffs filed a stipulation of settlement and motion for preliminary approval to resolve the case on a class-wide basis, which the court granted on October 1, 2020. The settlement amount will be paid entirely through existing insurance policies and is not expected to have a material impact on Southern Company's financial statements.

In February 2017, Jean Vineyard and Judy Mesirov each filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its current and former officers, and certain former Mississippi Power officers. In 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. In 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the securities class action. On September 25, 2020, the plaintiffs filed a status report noting the settlement of the securities class action and informing the court that the parties have scheduled mediation of this case later in the fourth quarter 2020.

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In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, Georgia that names as defendants Southern Company, certain of its directors, certain of its current and former officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. In 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the securities class action. In August 2019, the court granted a motion filed by the plaintiff in July 2019 to substitute a new named plaintiff, Martin J. Kobuck, in place of Helen E. Piper Survivor's Trust. On September 30, 2020, the plaintiffs filed a status report noting the settlement of the securities class action and informing the court that the parties have scheduled mediation of this case later in the fourth quarter 2020.

Georgia Power

In 2011, plaintiffs filed a putative class action against Georgia Power in the Superior Court of Fulton County, Georgia alleging that Georgia Power's collection in rates of amounts for municipal franchise fees (which fees are paid to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state law claims. This case has been ruled upon and appealed numerous times over the last several years. In one recent appeal, the Georgia Supreme Court remanded the case and noted that the trial court could refer the matter to the Georgia PSC to interpret its tariffs. Following a motion by Georgia Power, in February 2019, the Superior Court of Fulton County ordered the parties to submit petitions to the Georgia PSC for a declaratory ruling and also conditionally certified the proposed class. In March 2019, Georgia Power and the plaintiffs filed petitions with the Georgia PSC seeking confirmation of the proper application of the municipal franchise fee schedule pursuant to the Georgia PSC's orders. Also in March 2019, Georgia Power appealed the class certification decision to the Georgia Court of Appeals. In October 2019, the Georgia PSC issued an order that found Georgia Power has appropriately implemented the municipal franchise fee schedule. On March 11, 2020, the Georgia Court of Appeals vacated the Superior Court of Fulton County's February 2019 order granting conditional class certification. The Court of Appeals remanded the case to the Superior Court of Fulton County for further proceedings. In September 2020, the plaintiffs and Georgia Power each filed motions for summary judgment on all claims and the plaintiffs renewed their motion for class certification. The amount of any possible losses cannot be calculated at this time because, among other factors, it is unknown whether a class will be certified, the ultimate composition of any class, and whether any losses would be subject to recovery from any municipalities.

On July 29, 2020, a group of individual plaintiffs filed a complaint in the Superior Court of Fulton County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater, surface water, and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages, a medical monitoring fund, and injunctive relief.

Mississippi Power

In May 2018, Southern Company and Mississippi Power received a notice of dispute and arbitration demand filed by Martin Product Sales, LLC (Martin) based on two agreements, both related to Kemper IGCC byproducts for which Mississippi Power provided termination notices in 2017. Martin alleges breach of contract, breach of good faith and fair dealing, fraud and misrepresentation, and civil conspiracy and makes a claim for damages in the amount of approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest. A portion of the claim for damages was on behalf of Martin Transport, Inc. (Martin Transport), an affiliate of Martin. In May 2019, the arbitration panel denied Mississippi Power's and Southern Company's motions to dismiss. In September 2019, Martin Transport filed a separate complaint against Mississippi Power in the Circuit Court of Kemper County, Mississippi alleging claims of fraud, negligent misrepresentation, promissory estoppel,

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and equitable estoppel, each arising out of the same alleged facts and circumstances that underlie Martin's arbitration demand. Martin Transport seeks compensatory damages of $5 million and punitive damages of $50 million. In November 2019, Martin Transport's claim was combined with the Martin arbitration case and the separate court case was dismissed. In December 2019, Southern Company and Mississippi Power each filed motions for summary judgment on all claims. On February 17, 2020, the arbitration panel granted Southern Company's motion and dismissed Southern Company from the arbitration. On March 12, 2020, the arbitration panel denied Mississippi Power's motions for summary judgment. During the third quarter 2020, the plaintiffs reduced their claim for damages to approximately $76 million. On October 12, 2020, the arbitration panel issued a unanimous award in favor of Mississippi Power on all claims. This matter is now concluded.

In November 2018, Ray C. Turnage and 10 other individual plaintiffs filed a putative class action complaint against Mississippi Power and the three then-serving members of the Mississippi PSC in the U.S. District Court for the Southern District of Mississippi. Mississippi Power received Mississippi PSC approval in 2013 to charge a mirror CWIP rate premised upon including in its rate base pre-construction and construction costs for the Kemper IGCC prior to placing the Kemper IGCC into service. The Mississippi Supreme Court reversed that approval and ordered Mississippi Power to refund the amounts paid by customers under the previously-approved mirror CWIP rate. The plaintiffs allege that the initial approval process, and the amount approved, were improper. They also allege that Mississippi Power underpaid customers by up to $23.5 million in the refund process by applying an incorrect interest rate. The plaintiffs seek to recover, on behalf of themselves and their putative class, actual damages, punitive damages, pre-judgment interest, post-judgment interest, attorney's fees, and costs. In response to Mississippi Power and the Mississippi PSC each filing a motion to dismiss, the plaintiffs filed an amended complaint in March 2019. The amended complaint included four additional plaintiffs and additional claims for gross negligence, reckless conduct, and intentional wrongdoing. Mississippi Power and the Mississippi PSC have each filed a motion to dismiss the amended complaint. On March 27, 2020, the Mississippi PSC's motion to dismiss was granted. Also on March 27, 2020, the plaintiffs filed a motion seeking to name the new members of the Mississippi PSC, the Mississippi Development Authority, and Southern Company as additional defendants and add a cause of action against all defendants based on a dormant commerce clause theory under the U.S. Constitution. On April 9, 2020 and April 10, 2020, Mississippi Power and the Mississippi PSC, respectively, filed responses opposing the motion for leave to file a second amended complaint. On May 26, 2020, the court granted Mississippi Power's motion to dismiss the first amended complaint filed in 2019. On July 6, 2020, the plaintiffs filed a motion for revision of the court's decision. The plaintiffs' motion for leave to file a second amended complaint also remains pending before the court. On July 28, 2020, the plaintiffs filed a motion for leave to file a third amended complaint, which includes the same federal claims as the proposed second amended complaint, as well as several additional state law claims based on the allegation that Mississippi Power failed to disclose the annual percentage rate of interest applicable to refunds. An adverse outcome in this proceeding could have a material impact on Mississippi Power's financial statements.

See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility" in Item 8 of the Form 10-K for additional information.

Other Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" in Item 7 of the Form 10-K for additional information.

Southern Company

See Notes 1 and 3 under "Leveraged Leases" and "Other Matters – Southern Company," respectively, in Item 8 of the Form 10-K for discussion of challenges associated with a leveraged lease agreement with a subsidiary of Southern Holdings. While all required lease payments through September 30, 2020 have been paid in full, the operational and remarketing risks and the resulting cash liquidity challenges persist and significant concerns continue regarding the lessee's ability to make the remaining required semi-annual lease payments to the Southern Holdings subsidiary through the term of the lease.

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In its annual impairment analysis of the expected residual value of the generation assets and the overall collectability of the related lease receivable, Southern Company uses multiple scenarios of long-term market energy prices to estimate the cash flows expected to be received from remarketing the generation assets following the expiration of the existing PPA in 2032 and the residual value of the generation assets at the end of the lease in 2047. Southern Company received the latest annual forecasts of natural gas prices during the second quarter 2020 and considered the significant decline in forecasted prices to be an indicator of potential impairment that required an interim impairment assessment. Accordingly, consistent with prior years, Southern Company evaluated the recoverability of the lease receivable and the expected residual value of the generation assets under various natural gas price scenarios. Based on the current forecasts of energy prices in the years following the expiration of the existing PPA, Southern Company concluded that it is no longer probable that any of the associated rental payments will be received, because it is no longer probable the generation assets will be successfully remarketed and continue to operate after that date. During the second quarter 2020, Southern Company revised the estimated cash flows to be received under the leveraged lease to reflect this conclusion, which resulted in a full impairment of the lease investment and a pre-tax charge to earnings of $154 million ($74 million after tax).

If any future lease payment due prior to the expiration of the associated PPA is not paid in full, the Southern Holdings subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. Failure to make the required payment to the debtholders could represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the generation assets, in effect terminating the lease. As the remaining amount of the lease investment was charged against earnings in the second quarter 2020, termination would not be expected to result in additional charges. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments and meet its obligations associated with a future closure or retirement of the generation assets and associated properties, including the dry ash landfill.

Mississippi Power

Kemper County Energy Facility

See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility" in Item 8 of the Form 10-K for additional information.

As the mining permit holder, Liberty Fuels Company, LLC has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities related to the lignite mine and equipment and mineral reserves located around the Kemper County energy facility site. As a result of the abandonment of the Kemper IGCC, final mine reclamation began in 2018 and is expected to be substantially completed in 2020, with monitoring expected to continue through 2027. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.

For year-to-date 2020, Mississippi Power recorded pre-tax (and after-tax) charges to income totaling $2 million primarily associated with abandonment and related closure costs and ongoing period costs, net of salvage proceeds, for the mine and gasifier-related assets at the Kemper County energy facility. Dismantlement of the abandoned gasifier-related assets and site restoration activities are expected to be completed in 2025. The additional pre-tax period costs associated with dismantlement and site restoration activities, including related costs for compliance and safety, ARO accretion, and property taxes, net of salvage, are estimated to total $3 million for the remainder of 2020 and $10 million to $15 million annually for 2021 through 2025.

In December 2019, Mississippi Power transferred ownership of the CO2 pipeline to an unrelated gas pipeline company, with no resulting impact on income. In conjunction with the transfer of the CO2 pipeline, the parties agreed to enter into a 15-year firm transportation agreement, which is expected to be signed by the end of 2020, providing for the conversion by the pipeline company of the CO2 pipeline to a natural gas pipeline to be used for the delivery of natural gas to Plant Ratcliffe. The agreement is expected to be treated as a finance lease for accounting purposes upon commencement.

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On September 3, 2020, Mississippi Power and Southern Company executed an agreement with the DOE completing Mississippi Power's request for property closeout certification under the contract related to the DOE grants received for the Kemper County energy facility, which enables Mississippi Power to proceed with full dismantlement of the abandoned gasifier-related assets and site restoration activities. The execution of the agreement had no material impact on Mississippi Power's financial statements. In connection with the DOE closeout discussions, in April 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power of an investigation related to the $387 million of DOE grants received. The ultimate outcome of this matter cannot be determined at this time; however, it could have a material impact on Southern Company's and Mississippi Power's financial statements.

Plant Daniel

In conjunction with Southern Company's sale of Gulf Power, Mississippi Power and Gulf Power agreed to seek a restructuring of their 50% undivided ownership interests in Plant Daniel such that each of them would, after the restructuring, own 100% of a generating unit. On April 24, 2020, Mississippi Power and Gulf Power amended the terms of the agreement to extend the deadline from May 1, 2020 to August 1, 2020 for Mississippi Power to notify Gulf Power of which generating unit it has selected for 100% ownership. The parties agreed not to select a specific unit by August 1, 2020 and are continuing negotiations on a mutually acceptable revised operating agreement. The impacts of operating the units on an individual basis continue to be evaluated by Mississippi Power and any transfer of ownership would be subject to approval by the FERC and the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time.

ACCOUNTING POLICIES

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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" in Item 7 of the Form 10-K for a complete discussion of the Registrants' critical accounting policies and estimates.

Estimated Cost, Schedule, and Rate Recovery for the Construction of Plant Vogtle Units 3 and 4

(Southern Company and Georgia Power)

In the second quarter 2018, Georgia Power revised its base capital cost forecast and contingency to complete construction and start-up of Plant Vogtle Units 3 and 4 to $8.0 billion and $0.4 billion, respectively, for a total project capital cost forecast of $8.4 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds). Through the second quarter 2020, assignments of construction contingency to the base capital cost forecast exceeded the amount originally established in the second quarter 2018 by approximately $34 million. As a result, Georgia Power established $115 million of additional construction contingency as of June 30, 2020.

After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018 and a total pre-tax charge to income of $149 million ($111 million after tax) in the second quarter 2020.

In July 2020, Southern Nuclear updated its aggressive site work plan for both Unit 3 and Unit 4. In October 2020, Southern Nuclear further extended milestone dates from the July 2020 aggressive site work plan. Achievement of these extended milestone dates depends on absenteeism rates continuing to normalize and overall construction productivity and production levels, including subcontractors, significantly improving and being sustained above

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pre-pandemic levels. In addition, appropriate levels of craft laborers, particularly electrical and pipefitter craft labor, need to be added and maintained. Georgia Power still expects to achieve the regulatory-approved in-service dates of November 2021 and November 2022 for Plant Vogtle Units 3 and 4, respectively. The continuing effects of the COVID-19 pandemic and other factors could further disrupt or delay construction, testing, supervisory, and support activities at Plant Vogtle Units 3 and 4.

The ultimate impact of these matters on the construction schedule and budget for Plant Vogtle Units 3 and 4 cannot be determined at this time. See Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information.

Recently Issued Accounting Standards

On March 12, 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (ASU 2020-04) providing temporary guidance to ease the potential burden in accounting for reference rate reform primarily resulting from the discontinuation of LIBOR, which is currently expected to occur on December 31, 2021. The amendments in ASU 2020-04 are elective and apply to all entities that have contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued. The new guidance provides the following optional expedients: (i) simplifies accounting analyses under current GAAP for contract modifications; (ii) simplifies the assessment of hedge effectiveness and allows hedging relationships affected by reference rate reform to continue; and (iii) allows a one-time election to sell or transfer debt securities classified as held to maturity that reference a rate affected by reference rate reform. An entity may elect to apply the amendments prospectively from March 12, 2020 through December 31, 2022 by accounting topic.

The Registrants currently reference LIBOR for certain debt and hedging arrangements. Contract language has been, or is expected to be, incorporated into each of these agreements to address the transition to an alternative rate for agreements that will be in place at the transition date. While existing effective hedging relationships are expected to continue, the Registrants will continue to evaluate the provisions of ASU 2020–04 and the impacts of transitioning to an alternative rate. The ultimate outcome of the transition cannot be determined at this time, but is not expected to have a material impact on the Registrants' financial statements. See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein and Note (J) to the Condensed Financial Statements under "Interest Rate Derivatives" herein for additional information.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" in Item 7 of the Form 10-K for additional information. The financial condition of each Registrant remained stable at September 30, 2020. The Registrants have maintained adequate access to capital throughout 2020, including through a period of volatility in the short-term financial markets during the first quarter. As a precautionary measure, in the first quarter 2020, Southern Company, Georgia Power, Mississippi Power, and Southern Company Gas increased their outstanding short-term debt while also increasing cash and cash equivalents by taking actions such as entering into new bank term loans, entering into and funding new committed and uncommitted credit facilities, and funding existing uncommitted credit facilities. During the third quarter 2020, most of these additional borrowings were repaid. No material changes occurred in the terms of the applicable Registrants' bank credit arrangements or their interest expense on short-term debt as a result of these actions.

The Registrants have experienced no material counterparty credit losses as a result of the volatility in the financial markets. The Registrants intend to continue to monitor their access to short-term and long-term capital markets as well as their bank credit arrangements to meet future capital and liquidity needs. The impact on future financing costs as a result of continued financial market volatility cannot be determined at this time. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein and Note (K) to the Condensed Financial Statements herein for additional information.

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AND RESULTS OF OPERATIONS (Continued)

At the end of the third quarter 2020, the market price of Southern Company's common stock was $54.22 per share (based on the closing price as reported on the NYSE) and the book value was $26.78 per share, representing a market-to-book ratio of 202%, compared to $63.70, $26.11, and 244%, respectively, at the end of 2019. Southern Company's common stock dividend for the third quarter 2020 was $0.64 per share compared to $0.62 per share in the third quarter 2019.

Analysis of Cash Flows

Net cash flows provided from (used for) operating, investing, and financing activities for the nine months ended September 30, 2020 and 2019 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, 2020
Operating activities	$	5,220	$	1,229	$	2,125	$	186	$	774	$	1,122
Investing activities	(4,892)		(1,591)		(2,526)		(200)		424		(973)
Financing activities	1,077		505		867		(214)		(1,060)		(37)
Nine Months Ended September 30, 2019
Operating activities	$	4,881	$	1,471	$	2,365	$	242	$	1,221	$	1,049
Investing activities	(1,073)		(1,439)		(2,793)		(198)		36		(989)
Financing activities	(2,392)		992		765		(69)		(1,070)		(68)

Fluctuations in cash flows from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

Southern Company

Net cash provided from operating activities increased $0.3 billion for the nine months ended September 30, 2020 as compared to the corresponding period in 2019 primarily due to the timing of vendor payments as well as lower income tax payments, partially offset by the timing of receivable collections and customer bill credits issued in 2020 by Alabama Power and Georgia Power. See Note 2 to the financial statements under "Alabama Power" and "Georgia Power" in Item 8 of the Form 10-K for additional information.

The net cash used for investing activities for the nine months ended September 30, 2020 was primarily due to the Subsidiary Registrants' construction programs, partially offset by proceeds from the sale transactions described in Note (K) to the Condensed Financial Statements herein.

The net cash provided from financing activities for the nine months ended September 30, 2020 was primarily due to net issuances of long-term debt, partially offset by common stock dividend payments and net repayments of short-term bank debt and commercial paper.

Alabama Power

Net cash provided from operating activities decreased $242 million for the nine months ended September 30, 2020 as compared to the corresponding period in 2019 primarily due to payments related to ARO settlements, purchases of materials and supplies, and Rate RSE customer refunds. See Note 2 to the financial statements under "Alabama Power – Rate RSE" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.

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The net cash used for investing activities for the nine months ended September 30, 2020 was primarily due to gross property additions.

The net cash provided from financing activities for the nine months ended September 30, 2020 was primarily due to capital contributions from Southern Company and a long-term debt issuance, partially offset by common stock dividend payments.

Georgia Power

Net cash provided from operating activities decreased $240 million for the nine months ended September 30, 2020 as compared to the corresponding period in 2019 primarily due to higher income tax payments and customer bill credits issued in 2020 associated with Tax Reform and 2018 earnings in excess of the allowed retail ROE range, partially offset by the timing of vendor payments. See Note 2 to the financial statements under "Georgia Power – Rate Plans" in Item 8 of the Form 10-K for additional information.

The net cash used for investing activities for the nine months ended September 30, 2020 was primarily due to gross property additions, including approximately $1.0 billion related to the construction of Plant Vogtle Units 3 and 4. See FUTURE EARNINGS POTENTIAL – "Construction Programs – Nuclear Construction" herein for additional information on construction of Plant Vogtle Units 3 and 4.

The net cash provided from financing activities for the nine months ended September 30, 2020 was primarily due to capital contributions from Southern Company, net issuances of senior notes, and borrowings from the FFB for construction of Plant Vogtle Units 3 and 4, partially offset by common stock dividend payments and net repayment of short-term borrowings.

Mississippi Power

Net cash provided from operating activities decreased $56 million for the nine months ended September 30, 2020 as compared to the corresponding period in 2019 primarily due to the timing of vendor payments, decreased fuel cost recovery, and higher income tax payments.

The net cash used for investing activities for the nine months ended September 30, 2020 was primarily due to gross property additions.

The net cash used for financing activities for the nine months ended September 30, 2020 was primarily due to the repayment of senior notes at maturity, redemption of pollution control revenue bonds, and repayment of short-term borrowings, partially offset by debt issuances and capital contributions from Southern Company.

Southern Power

Net cash provided from operating activities decreased $447 million for the nine months ended September 30, 2020 as compared to the corresponding period in 2019 primarily due to a reduction in the utilization of tax credits in 2020.

The net cash provided from investing activities for the nine months ended September 30, 2020 was primarily due to proceeds from the disposition of Plant Mankato, partially offset by the acquisition of the Beech Ridge II wind facility and ongoing construction activities. See Note (K) to the Condensed Financial Statement under "Southern Power" herein for additional information.

The net cash used for financing activities for the nine months ended September 30, 2020 was primarily due to net repayments of short-term bank debt and commercial paper, the repayment of senior notes at maturity, distributions to non-controlling interests, and common stock dividend payments, partially offset by contributions from non-controlling interests.

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Southern Company Gas

Net cash provided from operating activities increased $73 million for the nine months ended September 30, 2020 as compared to the corresponding period in 2019 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, 2020 was primarily due to construction of transportation and distribution assets recovered through base rates and infrastructure investments recovered through replacement programs at gas distribution operations and capital contributed to equity method investments, partially offset by proceeds from the sale of interests in Pivotal LNG and Atlantic Coast Pipeline. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.

The net cash used for financing activities for the nine months ended September 30, 2020 was primarily due to net repayments of short-term borrowings and common stock dividend payments, partially offset by debt issuances and capital contributions from Southern Company.

Significant Balance Sheet Changes

Southern Company

Significant balance sheet changes for the nine months ended September 30, 2020 included:

•an increase of $5.2 billion in long-term debt (including amounts due within one year) related to new issuances;

•an increase of $3.3 billion in total property, plant, and equipment primarily related to the Subsidiary Registrants' construction programs;

•a decrease of $1.9 billion in notes payable related to net repayments of short-term bank debt and commercial paper;

•an increase of $1.4 billion in cash and cash equivalents primarily related to Southern Company's redemption of $1.0 billion of junior subordinated notes in October 2020;

•increases of $0.9 billion and $0.8 billion in AROs and regulatory assets associated with AROs, respectively, primarily related to cost estimate updates at Alabama Power and Georgia Power for ash pond facilities;

•a decrease of $0.8 billion in assets held for sale related to the completion of Southern Power's sale of Plant Mankato and Southern Company Gas' sale of its interests in Pivotal LNG and Atlantic Coast Pipeline; and

•an increase of $0.5 billion in accumulated deferred income taxes related to the utilization of tax credits in 2020.

See "Financing Activities" herein and Notes (A) and (K) to the Condensed Financial Statements herein for additional information.

Alabama Power

Significant balance sheet changes for the nine months ended September 30, 2020 included:

•an increase of $960 million in common stockholder's equity primarily due to capital contributions from Southern Company;

•an increase of $949 million in total property, plant, and equipment primarily related to the Autauga Combined Cycle Acquisition, construction of distribution and transmission facilities, and the installation of equipment to comply with environmental standards;

•an increase of $597 million in long-term debt (including securities due within one year) primarily due to an increase in outstanding senior notes; and

•increases of $456 million and $418 million in regulatory assets associated with AROs and AROs, respectively, primarily related to cost estimate updates for certain ash pond facilities.

See "Financing Activities – Alabama Power" herein and Notes (A) and (K) to the Condensed Financial Statements under "Asset Retirement Obligations" and "Alabama Power," respectively, herein for additional information.

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Georgia Power

Significant balance sheet changes for the nine months ended September 30, 2020 included:

•an increase of $1.7 billion in total property, plant, and equipment primarily related to the construction of generation, transmission, and distribution facilities;

•an increase of $1.6 billion in common stockholder's equity primarily due to capital contributions from Southern Company;

•an increase of $1.0 billion in long-term debt (including securities due within one year) primarily due to a net increase in outstanding senior notes and borrowings from the FFB for construction of Plant Vogtle Units 3 and 4; and

•increases of $468 million and $397 million in AROs and regulatory assets associated with AROs, respectively, primarily due to cost estimate updates for ash pond closures.

See "Financing Activities – Georgia Power" herein and Notes (A) and (B) to the Condensed Financial Statements under "Asset Retirement Obligations" and "Georgia Power – Nuclear Construction," respectively, herein for additional information.

Mississippi Power

Significant balance sheet changes for the nine months ended September 30, 2020 included:

•a decrease of $228 million in cash and cash equivalents and a decrease of $187 million in long-term debt (including amounts due within one year) primarily related to the repayment of senior notes at maturity;

•an increase of $108 million in common stockholder's equity primarily from net income and capital contributions from Southern Company, partially offset by dividends paid to Southern Company; and

•a decrease of $53 million in deferred credits related to income taxes due to reclassifying certain amounts to other regulatory liabilities, current for the expected flowback of excess deferred income taxes.

See "Financing Activities – Mississippi Power" herein for additional information.

Southern Power

Significant balance sheet changes for the nine months ended September 30, 2020 included:

•a decrease of $618 million in assets held for sale (of which $17 million related to current assets) due to completion of the sale of Plant Mankato;

•a decrease of $549 million in notes payable due to net repayments of short-term bank debt and commercial paper;

•an increase of $330 million in property, plant, and equipment in service and a decrease of $180 million in construction work in progress primarily due to wind facilities acquired or placed in service;

•a decrease of $320 million in accumulated deferred income tax assets primarily related to the utilization of tax credits in 2020; and

•a decrease of $299 million in securities due within one year primarily related to the maturity of senior notes.

See FUTURE EARNINGS POTENTIAL – "Tax Matters" herein, "Financing Activities – Southern Power" herein, and Note (K) to the Condensed Financial Statements herein for additional information.

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Southern Company Gas

Significant balance sheet changes for the nine months ended September 30, 2020 included:

•an increase of $789 million in total property, plant, and equipment primarily related to the construction of transportation and distribution assets recovered through base rates and infrastructure investments recovered through replacement programs;

•an increase of $616 million in long-term debt (including securities due within one year) due to the issuance of senior notes and mortgage bonds;

•a decrease of $500 million in notes payable due to net repayments of short-term borrowings;

•an increase of $179 million in common stockholder's equity primarily from net income and capital contributions from Southern Company, partially offset by dividends paid to Southern Company;

•a decrease of $171 million in assets held for sale due to the completed sale of interests in Pivotal LNG and Atlantic Coast Pipeline;

•a decrease of $123 million in unbilled revenues due to seasonality;

•an increase of $111 million in cash and cash equivalents primarily from long-term debt issuance proceeds;

•a decrease of $109 million in customer accounts receivable due to the timing of collections; and

•decreases of $100 million and $81 million in energy marketing receivables and payables, respectively, due to lower natural gas prices and volumes of natural gas sold.

See "Financing Activities – Southern Company Gas" herein and Note (K) to the Condensed Financial Statements herein for additional information.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements" and "Contractual Obligations" in Item 7 of the Form 10-K for a description of the Registrants' capital requirements and contractual obligations. The following table provides the applicable Registrants' maturities and announced redemptions of long-term debt through September 30, 2021:

At September 30, 2020:	Southern Company		Alabama Power		Georgia Power		Southern Power		Southern Company Gas
	(in millions)
Securities due within one year	$	4,378	$	496	$	531	$	525	$	334

See "Sources of Capital" and "Financing Activities" herein for additional information.

In October 2020, Alabama Power's Board of Directors approved updates to its construction program that is currently estimated to total $1.9 billion for 2021, $1.8 billion for 2022, $1.7 billion for 2023, $1.6 billion for 2024, and $1.6 billion for 2025. These amounts include capital expenditures related to Plant Barry Unit 8 and contractual purchase commitments for nuclear fuel and capital expenditures covered under LTSAs. These amounts also include estimated capital expenditures to comply with environmental laws and regulations, but do not include any potential compliance costs associated with pending regulation of CO2 emissions from fossil fuel-fired electric generating units. Estimated capital expenditures to comply with environmental laws and regulations included in these amounts are approximately $83 million for 2021, $98 million for 2022, $86 million for 2023, $99 million for 2024, and $70 million for 2025. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Alabama Power" herein for information on Alabama Power's construction of Plant Barry Unit 8.

As a result of the second quarter 2020 increase in Alabama Power's AROs discussed herein under FUTURE EARNINGS POTENTIAL – "Environmental Matters," Alabama Power's costs through 2025 associated with closure and monitoring of ash ponds and landfills in accordance with the CCR Rule and the related state rule are currently estimated to be approximately $263 million for 2020, $247 million for 2021, $301 million for 2022, $330 million for 2023, $326 million for 2024, and $311 million for 2025. These costs are reflected in Alabama Power's

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ARO liabilities and are based on closure-in-place for all of its ash ponds. These anticipated costs are likely to change, and could change materially, as assumptions and details pertaining to closure are refined and compliance activities continue. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements herein for additional information.

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 under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K, Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein, and Item 1A herein for information regarding Plant Vogtle Units 3 and 4 and additional factors that may impact construction expenditures.

The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; state regulatory agency approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; abnormal weather; delays in construction due to judicial or regulatory action; storm impacts; and the cost of capital. The continued COVID-19 pandemic could also impair the ability to develop, construct, and operate facilities, as discussed further in Item 1A herein. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Additionally, Southern Power's planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power's ability to execute its growth strategy. See Note 15 to the financial statements under "Southern Power" in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding Southern Power's plant acquisitions and construction projects.

Sources of Capital

Southern Company intends to meet its future capital needs through operating cash flows, borrowings from financial institutions, and debt and equity issuances in the capital markets. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings. Southern Company does not expect to issue any equity in the capital markets through 2024.

The Subsidiary Registrants plan to obtain the funds to meet their future capital needs from sources similar to those they used in the past, which were primarily from operating cash flows, external securities issuances, borrowings from financial institutions, and equity contributions from Southern Company. In addition, Georgia Power plans to utilize borrowings from the FFB (as discussed further in Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K) and Southern Power plans to utilize tax equity partnership contributions (as discussed further herein).

The traditional electric operating companies and the natural gas distribution utilities have experienced a reduction in operating cash flows as a result of the temporary suspension of disconnections for non-payment by customers resulting from the COVID-19 pandemic and the related overall economic contraction. To date, this reduction of operating cash flows has not had a material impact on the liquidity of any of the Registrants, and, during the third quarter 2020, most of the temporary measures in place expired. The U.S. House of Representatives has passed the Heroes Act, which would prohibit creditors, including utilities, from collecting consumer debts that are or become past-due, imposing late fees, or disconnecting customers for nonpayment. If the Heroes Act becomes law, its restrictions would apply until 120 days after the end of the presidential declared emergency related to the COVID-19 pandemic. The ultimate extent of the negative impact on the Registrants' liquidity depends on resolution of the Heroes Act and the duration of the COVID-19 pandemic and cannot be determined at this time. See Note (B)

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AND RESULTS OF OPERATIONS (Continued)

to the Condensed Financial Statements herein for information regarding suspended disconnections for non-payment by the traditional electric operating companies and the natural gas distribution utilities.

The amount, type, and timing of any financings in 2020, as well as in subsequent years, will be contingent on investment opportunities and the Registrants' capital requirements and will depend upon prevailing market conditions, regulatory approvals (for the Subsidiary Registrants), and other factors. See "Capital Requirements and Contractual Obligations" 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. In June 2020, Southern Power obtained tax equity funding for the Reading wind project and received proceeds of $156 million. In addition, during the first nine months of 2020, Southern Power received tax equity funding totaling $16 million from existing partnerships. See Note 1 to the financial statements under "General" in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information.

By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. At September 30, 2020, the amount of subsidiary retained earnings restricted to dividend totaled $1.1 billion. This restriction did not impact Southern Company Gas' ability to meet its cash obligations, nor does management expect such restriction to materially impact Southern Company Gas' ability to meet its currently anticipated cash obligations.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" in Item 7 of the Form 10-K for additional information.

The Registrants' current liabilities frequently exceed their current assets because of long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs. See "Financing Activities" herein for information on financing activities that occurred subsequent to September 30,

2020. The following table shows the amount by which current liabilities exceeded current assets at September 30, 2020 for the applicable Registrants:

At September 30, 2020	Southern Company		Georgia Power		Mississippi Power		Southern Company Gas
	(in millions)
Current liabilities in excess of current assets	$	1,176	$	612	$	65	$	286

The Registrants believe the need for working capital can be adequately met by utilizing operating cash flows, as well as commercial paper, lines of credit, and short-term bank notes, as market conditions permit. In addition, under certain circumstances, the Subsidiary Registrants may utilize equity contributions and/or loans from Southern Company.

Bank Credit Arrangements

At September 30, 2020, the Registrants' unused committed credit arrangements with banks were as follows:

At September 30, 2020	Southern Company parent		Alabama Power		Georgia Power		Mississippi Power		Southern  Power(a)		Southern Company Gas(b)		SEGCO		Southern Company
	(in millions)
Unused committed credit	$	1,999	$	1,328	$	1,728	$	250	$	591	$	1,745	$	30	$	7,671

(a)At September 30, 2020, Southern Power also had two continuing letters of credit facilities for standby letters of credit, of which $63 million was unused. Southern Power's subsidiaries are not parties to its bank credit arrangement or to the letter of credit facilities.

(b)Includes $1.245 billion and $500 million at Southern Company Gas Capital and Nicor Gas, respectively.

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AND RESULTS OF OPERATIONS (Continued)

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, 2020 was approximately $1.4 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia Power, and $34 million at Mississippi Power). In addition, at September 30, 2020, Georgia Power had approximately $257 million of fixed rate revenue bonds outstanding that are required to be remarketed within the next 12 months.

See Note 8 to the financial statements under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.

Short-term Borrowings

The Registrants, Nicor Gas, and SEGCO make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Southern Power's subsidiaries are not issuers or obligors under its commercial paper program. Commercial paper and short-term bank term loans are included in notes payable in the balance sheets. Details of the Registrants' short-term borrowings were as follows:

	Short-term Debt at September 30, 2020				Short-term Debt During the Period(*)
	Amount Outstanding		Weighted Average Interest Rate		Average Amount Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
Southern Company	$	171	0.9	%	$	958	1.2	%	$	1,272
Alabama Power	—		—		7		0.2		80
Georgia Power	—		—		347		1.4		465
Mississippi Power	—		—		1		0.2		10
Southern Power	—		—		19		0.3		114
Southern Company Gas:
Southern Company Gas Capital	$	150	1.0	%	$	273	1.0	%	$	464
Nicor Gas	—		—		21		0.2		82
Southern Company Gas Total	$	150	1.0	%	$	294	0.9	%

(*)Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2020.

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AND RESULTS OF OPERATIONS (Continued)

Financing Activities

The following table outlines the Registrants' long-term debt financing activities for the first nine months of 2020:

	Senior Notes				Revenue Bonds				Other Long-Term Debt
Company	Issuances		Maturities, Redemptions, and Repurchases		Issuances/ Remarketings		Maturities, Redemptions, and Repurchases		Issuances		Redemptions and Maturities(a)
	(in millions)
Southern Company parent	$	1,000	$	600	$	—	$	—	$	3,000	$	—
Alabama Power	600		—		87		87		—		—
Georgia Power	1,500		950		53		148		519		65
Mississippi Power	—		275		34		41		100		—
Southern Power	—		300		—		—		—		—
Southern Company Gas	500		—		—		—		150		—
Other	—		—		—		—		—		12
Elimination(b)	—		—		—		—		—		(6)
Southern Company	$	3,600	$	2,125	$	174	$	276	$	3,769	$	71

(a)Includes reductions in finance lease obligations resulting from cash payments under finance leases and, for Georgia Power, principal amortization payments for FFB borrowings.

(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 2020, Southern Company issued approximately 3.0 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $63 million.

In January 2020, Southern Company issued $1.0 billion aggregate principal amount of Series 2020A 4.95% Junior Subordinated Notes due January 30, 2080.

In March 2020, Southern Company borrowed $250 million pursuant to a short-term uncommitted bank credit arrangement, bearing interest at a rate agreed upon by Southern Company and the bank from time to time. In April 2020 and September 2020, Southern Company repaid $50 million and $200 million, respectively, of the $250 million borrowed.

Also in March 2020, Southern Company entered into a $75 million short-term floating rate bank loan bearing interest based on one-month LIBOR, which it repaid in September 2020.

In April 2020, Southern Company issued $1.0 billion aggregate principal amount of Series 2020A 3.70% Senior Notes due April 30, 2030.

In May 2020, Southern Company redeemed all $600 million aggregate principal amount of its Series 2015A 2.750% Senior Notes due June 15, 2020.

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AND RESULTS OF OPERATIONS (Continued)

In September 2020, Southern Company issued $1.25 billion aggregate principal amount of Series 2020B 4.00% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due January 15, 2051 and $750 million aggregate principal amount of Series 2020C 4.20% Junior Subordinated Notes due October 15, 2060.

Subsequent to September 30, 2020, Southern Company redeemed all of its $1.0 billion aggregate principal amount outstanding of Series 2015A 6.25% Junior Subordinated Notes due October 15, 2075.

Alabama Power

In March 2020, Alabama Power purchased and held approximately $87 million aggregate principal amount of The Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Plant Barry Project), Series 2007-A, which were remarketed to the public in June 2020.

In August 2020, Alabama Power issued $600 million aggregate principal amount of Series 2020A 1.45% Senior Notes due September 15, 2030.

Subsequent to September 30, 2020, Alabama Power repaid at maturity $250 million aggregate principal amount of its Series 2010A 3.375% Senior Notes.

Georgia Power

In January 2020, Georgia Power issued $700 million aggregate principal amount of Series 2020A 2.10% Senior Notes due July 30, 2023, $500 million aggregate principal amount of Series 2020B 3.70% Senior Notes due January 30, 2050, and an additional $300 million aggregate principal amount of Series 2019B 2.65% Senior Notes due September 15, 2029.

In February 2020, Georgia Power redeemed all $500 million aggregate principal amount of its Series 2017C 2.00% Senior Notes due September 8, 2020.

Also in February 2020, Georgia Power purchased and held approximately $28 million, $49 million, and $18 million aggregate principal amounts of Development Authority of Monroe County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), Second Series 2006, First Series 2012, and First Series 2013, respectively, which may be remarketed to the public at a later date.

In March 2020, Georgia Power repaid at maturity $450 million aggregate principal amount of its Series 2017A 2.00% Senior Notes.

Also in March 2020, Georgia Power purchased and subsequently remarketed to the public approximately $53 million of pollution control revenue bonds.

Also in March 2020, Georgia Power borrowed $200 million pursuant to a $250 million short-term uncommitted bank credit arrangement, bearing interest at a rate agreed upon by Georgia Power and the bank from time to time. In April 2020, Georgia Power borrowed the remaining $50 million pursuant to this bank credit arrangement. In September 2020, Georgia Power repaid the full $250 million.

Also in March 2020, Georgia Power extended one of its $125 million short-term floating rate bank loans to a long-term term loan, which matures in June 2021.

In June 2020, Georgia Power extended its other $125 million short-term floating rate bank loan to mature in December 2020. In September 2020, Georgia Power repaid this $125 million bank loan.

Also in June 2020, Georgia Power made additional borrowings under the FFB Credit Facilities in an aggregate principal amount of $519 million at an interest rate of 1.652% through the final maturity date of February 20, 2044. The proceeds were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4. During the nine months ended September 30, 2020, Georgia Power made principal amortization payments of $55 million under the FFB Credit Facilities. At September 30, 2020, the outstanding principal balance under the FFB Credit Facilities was $4.3 billion. See Note 8 to the financial statements under "Long-Term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for additional information.

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AND RESULTS OF OPERATIONS (Continued)

Mississippi Power

In February 2020, Mississippi Power entered into $60 million and $15 million floating rate bank term loans, which mature in December 2021 and January 2022, respectively, each bearing interest based on one-month LIBOR.

In March 2020, Mississippi Power entered into a $125 million revolving credit arrangement that matures in March 2023 and borrowed $40 million (short term) and $25 million (long term) pursuant to the arrangement, each bearing interest based on one-month LIBOR. In May 2020, Mississippi Power repaid the $40 million short-term portion.

In March 2020, Mississippi Power repaid at maturity the remaining $275 million aggregate principal amount of its Series 2018A Floating Rate Senior Notes.

In April 2020, Mississippi Power purchased and held approximately $11 million, $14 million, and $9 million aggregate principal amount of Mississippi Business Finance Corporation Solid Waste Disposal Facilities Revenue Bonds, Series 1995 (Mississippi Power Company Project), Solid Waste Disposal Facilities Revenue Refunding Bonds, Series 1998 (Mississippi Power Company Project), and Revenue Bonds, Series 1999 (Mississippi Power Company Project), respectively, which were remarketed to the public in May 2020.

Also in April 2020, Mississippi Power redeemed approximately $7 million aggregate principal amount of The Industrial Development Board of the City of Eutaw, Alabama Pollution Control Revenue Refunding Bonds, Series 1992 (Mississippi Power Greene County Plant Project) due December 1, 2020.

Southern Power

In February 2020, Southern Power repaid its $100 million short-term floating rate bank loan entered into in December 2019.

In June 2020, Southern Power repaid at maturity $300 million aggregate principal amount of its Series 2015B 2.375% Senior Notes.

Southern Company Gas

In March 2020, Southern Company Gas Capital, as borrower, and Southern Company Gas, as guarantor, entered into a $150 million short-term floating rate bank loan bearing interest based on one-month LIBOR.

Also in March 2020, Southern Company Gas Capital borrowed approximately $95 million pursuant to a short-term uncommitted bank credit arrangement, guaranteed by Southern Company Gas, bearing interest at a rate agreed upon by Southern Company Gas Capital and the bank from time to time. In August 2020, Southern Company Gas Capital repaid the outstanding balance.

In August 2020, Southern Company Gas Capital, as borrower, and Southern Company Gas, as guarantor, issued $500 million aggregate principal amount of Series 2020A 1.75% Senior Notes due January 15, 2031.

Also in August 2020, Nicor Gas issued $150 million aggregate principal amount of first mortgage bonds in a private placement and entered into an agreement to issue an additional $175 million aggregate principal amount of first mortgage bonds in November 2020.

Credit Rating Risk

At September 30, 2020, 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 subsidiaries to BBB and/or Baa2 or below. These contracts are for physical electricity and natural gas purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, interest rate management, and, for Georgia Power, construction of new generation at Plant Vogtle Units 3 and 4.

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AND RESULTS OF OPERATIONS (Continued)

The maximum potential collateral requirements under these contracts at September 30, 2020 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	$	36	$	1	$	—	$	—	$	35	$	—
At BBB- and/or Baa3	413		2		61		1		351		—
At BB+ and/or Ba1 or below	1,935		372		956		315		1,195		9

(*)Southern Power has PPAs that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power's credit. The PPAs require credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses resulting from a credit downgrade. Southern Power had $105 million of cash collateral posted related to PPA requirements at September 30, 2020.

The potential collateral requirement amounts in the previous table for the traditional electric operating companies and Southern Power include 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 the Registrants to access capital markets and would be likely to impact the cost at which they do so.

On August 27, 2020, Moody's upgraded Mississippi Power's senior unsecured long-term debt rating to Baa1 from Baa2 and revised its rating outlook to stable from positive.

On September 25, 2020, Fitch upgraded Mississippi Power's senior unsecured long-term debt rating to A- from BBB+ and revised its rating outlook to stable from positive.

Also on September 25, 2020, Fitch revised the ratings outlook of Southern Company and its subsidiaries (excluding Georgia Power and Mississippi Power) to stable from negative.

Market Price Risk

Other than the Southern Company Gas items discussed below, there were no material changes to the Registrants' disclosures about market price risk during the third quarter 2020. 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" in Item 7 of the Form 10-K. Also see "Overview" herein for information on volatility in the financial markets that has occurred at certain periods during 2020 resulting from the COVID-19 pandemic and Notes (I) and (J) to the Condensed Financial Statements herein for information relating to derivative instruments.

Southern Company Gas is exposed to market risks, including commodity price risk, interest rate risk, and weather risk. Due to various cost recovery mechanisms, the natural gas distribution utilities that sell natural gas directly to end-use customers continue to have limited exposure to market volatility of natural gas prices. Certain of the natural gas distribution utilities may manage fuel-hedging programs implemented per the guidelines of their respective state regulatory agencies to hedge the impact of market fluctuations in natural gas prices for customers. In addition, certain non-regulated operations routinely utilize various types of derivative instruments to economically hedge certain commodity price and 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 may not be designated, for hedge accounting treatment.

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AND RESULTS OF OPERATIONS (Continued)

For the periods presented below, the changes in net fair value of Southern Company Gas' derivative contracts were as follows:

	Third Quarter 2020		Third Quarter 2019		Year-to-Date 2020		Year-to-Date 2019
	(in millions)
Contracts outstanding at beginning of period, assets (liabilities), net	$	26	$	(90)	$	72	$	(167)
Contracts realized or otherwise settled	(8)		7		(107)		7
Current period changes(*)	—		(13)		53		64
Contracts outstanding at the end of period, assets (liabilities), net	$	18	$	(96)	$	18	$	(96)
Netting of cash collateral	70		166		70		166
Cash collateral and net fair value of contracts outstanding at end of period	$	88	$	70	$	88	$	70

(*)Current period changes also include the fair value of new contracts entered into during the period, if any.

The maturities of Southern Company Gas' derivative contracts at September 30, 2020 were as follows:

			Fair Value Measurements
			September 30, 2020
	Total Fair Value		Maturity
			Year 1		Years 2 & 3		Years 4 and thereafter
	(in millions)
Level 1(a)	$	(33)	$	(14)	$	(35)	$	16
Level 2(b)	9		6		1		2
Level 3(c)	42		—		11		31
Fair value of contracts outstanding at end of period(d)	$	18	$	(8)	$	(23)	$	49

(a)Valued using NYMEX futures prices.

(b)Valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers.

(c)Valued using a combination of observable and unobservable inputs.

(d)Excludes cash collateral of $70 million.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk.

During the nine months ended September 30, 2020, there were no material changes to Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, and Southern Power's disclosures about market risk. For additional market risk disclosures relating to Southern Company Gas, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" 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" 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.

There have been no changes in Southern Company's, Alabama Power's, Georgia Power's, Mississippi 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 2020 that have materially affected or are reasonably likely to materially affect Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, or Southern Company Gas' internal control over financial reporting.

In July 2020, Southern Power implemented new financial accounting and reporting systems. As a result, there were certain changes to processes and procedures, which resulted in changes to Southern Power's 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 include automation of previously manual controls. These changes in internal controls were not made in response to an identified internal control deficiency.

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PART II — OTHER INFORMATION

Item 1. Legal Proceedings.

See the Notes to the Condensed Financial Statements herein for information regarding certain legal and administrative proceedings in which the Registrants are involved.

Item 1A. Risk Factors.

See RISK FACTORS in Item 1A of the Form 10-K for a discussion of the risk factors of the Registrants. Except as described below, there have been no material changes to these risk factors from those previously disclosed in the Form 10-K.

The Registrants are subject to risks related to the COVID-19 pandemic, including, but not limited to, disruption to the construction of Plant Vogtle Units 3 and 4 for Southern Company and Georgia Power.

COVID-19 has been declared a pandemic by the World Health Organization and the Centers for Disease Control and Prevention and has spread globally, including throughout the United States. In response, most jurisdictions, including in the United States, have instituted restrictions on travel, public gatherings, and non-essential business operations. While some jurisdictions, including some in the Southern Company system's service territory, have relaxed these restrictions, many of these restrictions remain and there is no guarantee restrictions will not be reimposed in the future. These restrictions have significantly disrupted economic activity in the service territories of the traditional electric operating companies and the natural gas distribution utilities and caused volatility in capital markets at certain periods during 2020. For example, retail electric revenues have declined slightly compared to 2019, as discussed further in RESULTS OF OPERATIONS – "Southern Company – Retail Electric Revenues" in Item 2 herein. In addition, the traditional electric operating companies and the natural gas distribution utilities temporarily suspended disconnections for non-payment by customers and waived late fees for certain periods. The U.S. House of Representatives has passed the Heroes Act, which would prohibit creditors, including utilities, from collecting consumer debts that are or become past-due, imposing late fees, or disconnecting customers for nonpayment. If the Heroes Act becomes law, its restrictions would apply until 120 days after the end of the presidential declared emergency related to the COVID-19 pandemic. The effects of the continued COVID-19 pandemic and related responses could include extended disruptions to supply chains and capital markets, further reduced labor availability and productivity, and a prolonged reduction in economic activity. These effects could have a variety of adverse impacts on the Registrants, including continued reduced demand for energy, particularly from commercial and industrial customers, reduced cash flows and liquidity, impairment of goodwill or long-lived assets, reductions in investments recorded at fair value, and further impairment of the ability of the Registrants to develop, construct, and operate facilities, including electric generation, transmission, and distribution assets, to perform necessary corporate and customer service functions, and to access funds from financial institutions and capital markets. In addition, the COVID-19 pandemic could cause delays or cancellations of regulatory proceedings.

Further, the effects of the COVID-19 pandemic could further disrupt or delay construction, testing, supervisory, and support activities at Plant Vogtle Units 3 and 4. In mid-March 2020, Southern Nuclear began implementing policies and procedures designed to mitigate the risk of transmission of COVID-19 at the construction site, including worker distancing measures, isolating individuals who have tested positive for COVID-19, are showing symptoms consistent with COVID-19, are being tested for COVID-19, or have been in close contact with such persons, requiring self-quarantine, and adopting additional precautionary measures. In April 2020, Georgia Power announced a reduction in workforce at Plant Vogtle Units 3 and 4, which totaled approximately 20% of the then-existing site workforce. This reduction in workforce was a mitigation action intended to address the impact of the COVID-19 pandemic on the Plant Vogtle Units 3 and 4 workforce and construction site, including challenges with labor productivity that were exacerbated by the impact of the COVID-19 pandemic. The April 2020 workforce reduction was intended to provide operational efficiencies by increasing productivity of the remaining workforce and reducing workforce fatigue and absenteeism. Further, it was also intended to allow for increased social distancing by the workforce and facilitate compliance with the recommendations from the Centers for Disease Control and Prevention. The April 2020 workforce reduction did reduce absenteeism, providing an improvement in operational efficiency and allowing for increased social distancing. From the initial peak in April 2020, the number of active cases at the site declined significantly during May and early June, but began increasing again from mid-June

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through July. While the number of active cases at the site has declined since July 2020, the COVID-19 pandemic continues to impact productivity and the pace of activity completion. These factors contributed to the June 30, 2020 allocation of, and increase in, construction contingency described in Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein. Georgia Power's proportionate share of the estimated incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is currently estimated to be between $70 million and $115 million, which is included in the total project capital cost forecast and assumes (i) absenteeism rates continue to normalize and (ii) the intended productivity efficiencies and production targets assumed in Southern Nuclear's July 2020 aggressive site work plan are realized in the coming months. However, the ultimate impact of the COVID-19 pandemic on the construction schedule and budget for Plant Vogtle Units 3 and 4 cannot be determined at this time.

Item 6. Exhibits.

The exhibits below with an asterisk (*) preceding the exhibit number are filed herewith. The remaining exhibits have previously been filed with the SEC and are incorporated herein by reference. The exhibits marked with a pound sign (#) are management contracts or compensatory plans or arrangements.

(4) Instruments Describing Rights of Security Holders, Including Indentures
Southern Company
(a)1	-	Ninth Supplemental Indenture to Junior Subordinated Note Indenture dated as of September 18, 2020, providing for the issuance of the Series 2020B 4.00% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due January 15, 2051. (Designated in Form 8-K dated September 15, 2020, File No. 1-3526, as Exhibit 4.4(a))
(a)2	-	Tenth Supplemental Indenture to Junior Subordinated Note Indenture dated as of September 18, 2020, providing for the issuance of the Series 2020C 4.20% Junior Subordinated Notes due October 15, 2060. (Designated in Form 8-K dated September 15, 2020, File No. 1-3526, as Exhibit 4.4(b))
Alabama Power
(b)	-	Sixtieth Supplemental Indenture to Senior Note Indenture dated as of August 27, 2020, providing for the issuance of the Series 2020A 1.45% Senior Notes due September 15, 2030. (Designated in Form 8-K dated August 24, 2020, File No. 1-3164, as Exhibit 4.6)
Southern Company Gas
(f)1	-	Southern Company Gas Capital Corporation's Series 2020A 1.750% Senior Notes due January 15, 2031, Form of Note. (Designated in Form 8-K dated August 17, 2020, File No. 1-14174, as Exhibit 4.1)
(f)2	-	Southern Company Gas' Guarantee related to the Series 2020A 1.750% Senior Notes due January 15, 2031, Form of Guarantee. (Designated in Form 8-K dated August 17, 2020, File No. 1-14174, as Exhibit 4.3)
(24) Power of Attorney and Resolutions
Southern Company
(a)	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2019, File No. 1-3526 as Exhibit 24(a).)
Alabama Power
(b)	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2019, File No. 1-3164 as Exhibit 24(b).)

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	Georgia Power
	(c)	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2019, File No. 1-6468 as Exhibit 24(c).)
	Mississippi Power
	(d)	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2019, File No. 001-11229 as Exhibit 24(d).)
	Southern Power
	(e)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2019, File No. 001-37803 as Exhibit 24(e).)
	(e)2	-	Power of Attorney of Christopher Cummiskey. (Designated in the Form 10-Q for the quarter ended June 30, 2020, File No. 001-37803 as Exhibit 24(e)2.)
	Southern Company Gas
	(f)	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2019, File No. 1-14174 as Exhibit 24(f).)
	(31) Section 302 Certifications
	Southern Company
*	(a)1	-	Certificate of Southern Company's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*	(a)2	-	Certificate of Southern Company's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	Alabama Power
*	(b)1	-	Certificate of Alabama Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*	(b)2	-	Certificate of Alabama Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	Georgia Power
*	(c)1	-	Certificate of Georgia Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*	(c)2	-	Certificate of Georgia Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	Mississippi Power
*	(d)1	-	Certificate of Mississippi Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*	(d)2	-	Certificate of Mississippi Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	Southern Power
*	(e)1	-	Certificate of Southern Power Company's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*	(e)2	-	Certificate of Southern Power Company's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	Southern Company Gas
*	(f)1	-	Certificate of Southern Company Gas' Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

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*	(f)2	-	Certificate of Southern Company Gas' Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	(32) Section 906 Certifications
	Southern Company
*	(a)	-	Certificate of Southern Company's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
	Alabama Power
*	(b)	-	Certificate of Alabama Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
	Georgia Power
*	(c)	-	Certificate of Georgia Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
	Mississippi Power
*	(d)	-	Certificate of Mississippi Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
	Southern Power
*	(e)	-	Certificate of Southern Power Company's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
	Southern Company Gas
*	(f)	-	Certificate of Southern Company Gas' Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
	(101) Interactive Data Files
*	INS	-	XBRL Instance Document – 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.

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THE SOUTHERN COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

	THE SOUTHERN COMPANY
By	Thomas A. Fanning
	Chairman, President, and Chief Executive Officer
	(Principal Executive Officer)
By	Andrew W. Evans
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: October 28, 2020

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ALABAMA POWER COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

	ALABAMA POWER COMPANY
By	Mark A. Crosswhite
	Chairman, President, and Chief Executive Officer
	(Principal Executive Officer)
By	Philip C. Raymond
	Executive Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: October 28, 2020

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GEORGIA POWER COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

	GEORGIA POWER COMPANY
By	W. Paul Bowers
	Chairman, President, and Chief Executive Officer
	(Principal Executive Officer)
By	David 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 28, 2020

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MISSISSIPPI POWER COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

	MISSISSIPPI POWER COMPANY
By	Anthony L. Wilson
	Chairman, President, and Chief Executive Officer
	(Principal Executive Officer)
By	Moses H. Feagin
	Senior Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: October 28, 2020

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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	Christopher Cummiskey
	Chief Executive Officer
	(Principal Executive Officer)
By	Elliott L. Spencer
	Senior Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: October 28, 2020

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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	Kimberly S. Greene
	Chairman, President, and Chief Executive Officer
	(Principal Executive Officer)
By	Daniel S. Tucker
	Executive Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: October 28, 2020

191

EX-31.A1

Exhibit 31(a)1

THE SOUTHERN COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Thomas A. Fanning, certify that:

1.I have reviewed this quarterly report on Form 10-Q of The Southern Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  October 28, 2020

/s/Thomas A. Fanning

Thomas A. Fanning

Chairman, President and
Chief Executive Officer

EX-31.A2

Exhibit 31(a)2

THE SOUTHERN COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Andrew W. Evans, certify that:

1.I have reviewed this quarterly report on Form 10-Q of The Southern Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 28, 2020

/s/Andrew W. Evans

Andrew W. Evans

Executive Vice President and Chief Financial Officer

EX-31.B1

Exhibit 31(b)1

ALABAMA POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Mark A. Crosswhite, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Alabama Power Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  October 28, 2020

/s/Mark A. Crosswhite

Mark A. Crosswhite

Chairman, President and Chief Executive Officer

EX-31.B2

Exhibit 31(b)2

ALABAMA POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Philip C. Raymond, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Alabama Power Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  October 28, 2020

/s/Philip C. Raymond

Philip C. Raymond

Executive Vice President, Chief Financial Officer
and Treasurer

EX-31.C1

Exhibit 31(c)1

GEORGIA POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, W. Paul Bowers, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Georgia Power Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  October 28, 2020

/s/W. Paul Bowers

W. Paul Bowers

Chairman, President and Chief Executive Officer

EX-31.C2

Exhibit 31(c)2

GEORGIA POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, David P. Poroch, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Georgia Power Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  October 28, 2020

/s/David P. Poroch

David P. Poroch

Executive Vice President, Chief Financial Officer and Treasurer

EX-31.D1

Exhibit 31(d)1

MISSISSIPPI POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Anthony L. Wilson, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Mississippi Power Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  October 28, 2020

/s/Anthony L. Wilson

Anthony L. Wilson

Chairman, President and
Chief Executive Officer

EX-31.D2

Exhibit 31(d)2

MISSISSIPPI POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Moses H. Feagin, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Mississippi Power Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  October 28, 2020

/s/Moses H. Feagin

Moses H. Feagin

Senior Vice President, Treasurer and
Chief Financial Officer

EX-31.E1

Exhibit 31(e)1

SOUTHERN POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Christopher Cummiskey, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Southern Power Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   October 28, 2020

/s/Christopher Cummiskey

Christopher Cummiskey

Chief Executive Officer

EX-31.E2

Exhibit 31(e)2

SOUTHERN POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Elliott L. Spencer, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Southern Power Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  October 28, 2020

/s/Elliott L. Spencer

Elliott L. Spencer

Senior Vice President, Chief
Financial Officer and Treasurer

EX-31.F1

Exhibit 31(f)1

SOUTHERN COMPANY GAS

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Kimberly S. Greene, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Southern Company Gas;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  October 28, 2020

/s/Kimberly S. Greene

Kimberly S. Greene

Chairman, President and Chief Executive Officer

EX-31.F2

Exhibit 31(f)2

SOUTHERN COMPANY GAS

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Daniel S. Tucker, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Southern Company Gas;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  October 28, 2020

/s/Daniel S. Tucker

Daniel S. Tucker

Executive Vice President, Chief Financial
Officer and Treasurer

EX-32.A

Exhibit 32(a)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of The Southern Company for the quarter ended September 30, 2020, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1)such Quarterly Report on Form 10-Q of The Southern Company for the quarter ended September 30, 2020, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)the information contained in such Quarterly Report on Form 10-Q of The Southern Company for the quarter ended September 30, 2020, fairly presents, in all material respects, the financial condition and results of operations of The Southern Company.

/s/Thomas A. Fanning

Thomas A. Fanning

Chairman, President and
Chief Executive Officer

/s/Andrew W. Evans

Andrew W. Evans

Executive Vice President and
Chief Financial Officer

October 28, 2020

EX-32.B

Exhibit 32(b)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Alabama Power Company for the quarter ended September 30, 2020, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1)such Quarterly Report on Form 10-Q of Alabama Power Company for the quarter ended September 30, 2020, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)the information contained in such Quarterly Report on Form 10-Q of Alabama Power Company for the quarter ended September 30, 2020, fairly presents, in all material respects, the financial condition and results of operations of Alabama Power Company.

/s/Mark A. Crosswhite

Mark A. Crosswhite

Chairman, President and Chief Executive Officer

/s/Philip C. Raymond

Philip C. Raymond

Executive Vice President,
Chief Financial Officer and Treasurer

October 28, 2020

EX-32.C

Exhibit 32(c)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Georgia Power Company for the quarter ended September 30, 2020, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1)such Quarterly Report on Form 10-Q of Georgia Power Company for the quarter ended September 30, 2020, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)the information contained in such Quarterly Report on Form 10-Q of Georgia Power Company for the quarter ended September 30, 2020, fairly presents, in all material respects, the financial condition and results of operations of Georgia Power Company.

/s/W. Paul Bowers

W. Paul Bowers

Chairman, President and Chief Executive Officer

/s/David P. Poroch

David P. Poroch

Executive Vice President, Chief Financial Officer and Treasurer

October 28, 2020

EX-32.D

Exhibit 32(d)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Mississippi Power Company for the quarter ended September 30, 2020, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1)such Quarterly Report on Form 10-Q of Mississippi Power Company for the quarter ended September 30, 2020, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)the information contained in such Quarterly Report on Form 10-Q of Mississippi Power Company for the quarter ended September 30, 2020, fairly presents, in all material respects, the financial condition and results of operations of Mississippi Power Company.

/s/Anthony L. Wilson

Anthony L. Wilson

Chairman, President and Chief Executive Officer

/s/Moses H. Feagin

Moses H. Feagin

Senior Vice President, Treasurer and
Chief Financial Officer

October 28, 2020

EX-32.E

Exhibit 32(e)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Southern Power Company for the quarter ended September 30, 2020, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1)such Quarterly Report on Form 10-Q of Southern Power Company for the quarter ended September 30, 2020, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)the information contained in such Quarterly Report on Form 10-Q of Southern Power Company for the quarter ended September 30, 2020, fairly presents, in all material respects, the financial condition and results of operations of Southern Power Company.

/s/Christopher Cummiskey

Christopher Cummiskey

Chief Executive Officer

/s/Elliott L. Spencer

Elliott L. Spencer

Senior Vice President, Chief Financial Officer and Treasurer

October 28, 2020

EX-32.F

Exhibit 32(f)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Southern Company Gas for the quarter ended September 30, 2020, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1)such Quarterly Report on Form 10-Q of Southern Company Gas for the quarter ended September 30, 2020, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)the information contained in such Quarterly Report on Form 10-Q of Southern Company Gas for the quarter ended September 30, 2020, fairly presents, in all material respects, the financial condition and results of operations of Southern Company Gas.

/s/Kimberly S. Greene

Kimberly S. Greene

Chairman, President and Chief Executive Officer

/s/Daniel S. Tucker

Daniel S. Tucker

Executive Vice President, Chief Financial

Officer and Treasurer

October 28, 2020

XML

Cover Page	9 Months Ended
	Sep. 30, 2020 shares
Document Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2020
Document Transition Report	false
Entity File Number	1-3526
Entity Registrant Name	The Southern Company
Entity Tax Identification Number	58-0690070
Entity Incorporation, State or Country Code	DE
Entity Address, Address Line One	30 Ivan Allen Jr. Boulevard, N.W.
Entity Address, City or Town	Atlanta
Entity Address, State or Province	GA
Entity Address, Postal Zip Code	30308
City Area Code	404
Local Phone Number	506-5000
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (in shares)	1,056,241,993
Entity Central Index Key	0000092122
Amendment Flag	false
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
Entity Emerging Growth Company	false
Entity Small Business	false
Common Stock, par value $5 per share
Document Information [Line Items]
Title of 12(b) Security	Common Stock, par value $5 per share
Trading Symbol	SO
Security Exchange Name	NYSE
Series 2015A 6.25% Junior Subordinated Notes due 2075
Document Information [Line Items]
Title of 12(b) Security	Series 2015A 6.25% Junior Subordinated Notes due 2075
Trading Symbol	SOJA
Security Exchange Name	NYSE
Series 2016A 5.25% Junior Subordinated Notes due 2076
Document Information [Line Items]
Title of 12(b) Security	Series 2016A 5.25% Junior Subordinated Notes due 2076
Trading Symbol	SOJB
Security Exchange Name	NYSE
Series 2017B 5.25% Junior Subordinated Notes due 2077
Document Information [Line Items]
Title of 12(b) Security	Series 2017B 5.25% Junior Subordinated Notes due 2077
Trading Symbol	SOJC
Security Exchange Name	NYSE
2019 Series A Corporate Units
Document Information [Line Items]
Title of 12(b) Security	2019 Series A Corporate Units
Trading Symbol	SOLN
Security Exchange Name	NYSE
Series 2020A 4.95% Junior Subordinated Notes due 2080
Document Information [Line Items]
Title of 12(b) Security	Series 2020A 4.95% Junior Subordinated Notes due 2080
Trading Symbol	SOJD
Security Exchange Name	NYSE
Series 2020C 4.20% Junior Subordinated Notes due 2060
Document Information [Line Items]
Title of 12(b) Security	Series 2020C 4.20% Junior Subordinated Notes due 2060
Trading Symbol	SOJE
Security Exchange Name	NYSE
ALABAMA POWER CO
Document Information [Line Items]
Entity File Number	1-3164
Entity Registrant Name	Alabama Power Company
Entity Tax Identification Number	63-0004250
Entity Incorporation, State or Country Code	AL
Entity Address, Address Line One	600 North 18th Street
Entity Address, City or Town	Birmingham
Entity Address, State or Province	AL
Entity Address, Postal Zip Code	35203
City Area Code	205
Local Phone Number	257-1000
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (in shares)	30,537,500
Entity Central Index Key	0000003153
Entity Emerging Growth Company	false
Entity Small Business	false
ALABAMA POWER CO | 5.00% Series Class A Preferred Stock
Document Information [Line Items]
Title of 12(b) Security	5.00% Series Class A Preferred Stock
Trading Symbol	ALP PR Q
Security Exchange Name	NYSE
GEORGIA POWER CO
Document Information [Line Items]
Entity File Number	1-6468
Entity Registrant Name	Georgia Power Company
Entity Tax Identification Number	58-0257110
Entity Incorporation, State or Country Code	GA
Entity Address, Address Line One	241 Ralph McGill Boulevard, N.E.
Entity Address, City or Town	Atlanta
Entity Address, State or Province	GA
Entity Address, Postal Zip Code	30308
City Area Code	404
Local Phone Number	506-6526
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (in shares)	9,261,500
Entity Central Index Key	0000041091
Entity Emerging Growth Company	false
Entity Small Business	false
GEORGIA POWER CO | Series 2017A 5.00% Junior Subordinated Notes due 2077
Document Information [Line Items]
Title of 12(b) Security	Series 2017A 5.00% Junior Subordinated Notes due 2077
Trading Symbol	GPJA
Security Exchange Name	NYSE
MISSISSIPPI POWER CO
Document Information [Line Items]
Entity File Number	001-11229
Entity Registrant Name	Mississippi Power Company
Entity Tax Identification Number	64-0205820
Entity Incorporation, State or Country Code	MS
Entity Address, Address Line One	2992 West Beach Boulevard
Entity Address, City or Town	Gulfport
Entity Address, State or Province	MS
Entity Address, Postal Zip Code	39501
City Area Code	228
Local Phone Number	864-1211
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (in shares)	1,121,000
Entity Central Index Key	0000066904
Entity Emerging Growth Company	false
Entity Small Business	false
SOUTHERN POWER CO
Document Information [Line Items]
Entity File Number	001-37803
Entity Registrant Name	Southern Power Company
Entity Tax Identification Number	58-2598670
Entity Incorporation, State or Country Code	DE
Entity Address, Address Line One	30 Ivan Allen Jr. Boulevard, N.W.
Entity Address, City or Town	Atlanta
Entity Address, State or Province	GA
Entity Address, Postal Zip Code	30308
City Area Code	404
Local Phone Number	506-5000
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (in shares)	1,000
Entity Central Index Key	0001160661
Entity Emerging Growth Company	false
Entity Small Business	false
SOUTHERN POWER CO | Series 2016A 1.000% Senior Notes due 2022
Document Information [Line Items]
Title of 12(b) Security	Series 2016A 1.000% Senior Notes due 2022
Trading Symbol	SO/22B
Security Exchange Name	NYSE
SOUTHERN POWER CO | Series 2016B 1.850% Senior Notes due 2026
Document Information [Line Items]
Title of 12(b) Security	Series 2016B 1.850% Senior Notes due 2026
Trading Symbol	SO/26A
Security Exchange Name	NYSE
SOUTHERN Co GAS
Document Information [Line Items]
Entity File Number	1-14174
Entity Registrant Name	Southern Company Gas
Entity Tax Identification Number	58-2210952
Entity Incorporation, State or Country Code	GA
Entity Address, Address Line One	Ten Peachtree Place, N.E.
Entity Address, City or Town	Atlanta
Entity Address, State or Province	GA
Entity Address, Postal Zip Code	30309
City Area Code	404
Local Phone Number	584-4000
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (in shares)	100
Entity Central Index Key	0001004155
Entity Emerging Growth Company	false
Entity Small Business	false

XML

Condensed Consolidated Statements of Income (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Operating Revenues:
Operating revenues	$ 5,620	$ 5,995	$ 15,258	$ 16,505
Operating Expenses:
Total cost of sales	71	79	654	956
Other operations and maintenance	1,286	1,296	3,785	3,898
Depreciation and amortization	889	760	2,619	2,267
Taxes other than income taxes	304	303	932	931
Estimated loss on Plant Vogtle Units 3 and 4	0	0	149	0
Impairment charges	0	110	0	142
(Gain) loss on dispositions, net	0	(6)	(39)	(2,512)
Total operating expenses	3,785	3,982	11,102	9,459
Operating Income (Loss)	1,835	2,013	4,156	7,046
Other Income and (Expense):
Allowance for equity funds used during construction	38	33	106	96
Earnings from equity method investments	33	39	105	120
Interest expense, net of amounts capitalized	(443)	(434)	(1,343)	(1,294)
Impairment of leveraged lease	0	0	(154)	0
Other income (expense), net	113	61	319	239
Total other income and (expense)	(259)	(301)	(967)	(839)
Earnings (Loss) Before Income Taxes	1,576	1,712	3,189	6,207
Income taxes (benefit)	293	367	443	1,872
Consolidated Net Income	1,283	1,345	2,746	4,335
Dividends on preferred stock of subsidiaries	4	4	11	11
Net income attributable to noncontrolling interests	28	25	3	26
Net Income	$ 1,251	$ 1,316	$ 2,732	$ 4,298
Earnings per share -
Basic (in dollars per share)	$ 1.18	$ 1.26	$ 2.58	$ 4.12
Diluted (in dollars per share)	$ 1.18	$ 1.25	$ 2.57	$ 4.09
Average number of shares of common stock outstanding (in millions)
Basic (in shares)	1,058	1,048	1,058	1,043
Diluted (in shares)	1,064	1,057	1,064	1,051
Cost, Product and Service [Extensible List]			us-gaap:NaturalGasUsRegulatedMember
Retail electric revenues
Operating Revenues:
Operating revenues	$ 4,243	$ 4,512	$ 10,503	$ 11,136
Wholesale electric revenues
Operating Revenues:
Operating revenues	584	625	1,473	1,667
Other electric revenues
Operating Revenues:
Operating revenues	164	163	484	492
Natural gas
Operating Revenues:
Operating revenues	477	498	2,362	2,661
Operating Expenses:
Total cost of sales	71	79	654	956
Other
Operating Revenues:
Operating revenues	152	197	436	549
Operating Expenses:
Total cost of sales	72	114	201	316
Fuel
Operating Expenses:
Total cost of sales	933	1,072	2,190	2,836
Purchased power
Operating Expenses:
Total cost of sales	230	254	611	625
Alternative revenue programs
Operating Revenues:
Operating revenues	(1)	0	6	0
ALABAMA POWER CO
Operating Revenues:
Operating revenues	1,729	1,841	4,445	4,762
Operating Expenses:
Other operations and maintenance	387	409	1,078	1,221
Depreciation and amortization	205	195	606	593
Taxes other than income taxes	103	101	311	301
Total operating expenses	1,109	1,165	2,962	3,303
Operating Income (Loss)	620	676	1,483	1,459
Other Income and (Expense):
Allowance for equity funds used during construction	12	13	34	41
Interest expense, net of amounts capitalized	(84)	(83)	(255)	(248)
Other income (expense), net	30	11	78	36
Total other income and (expense)	(42)	(59)	(143)	(171)
Earnings (Loss) Before Income Taxes	578	617	1,340	1,288
Income taxes (benefit)	130	144	307	295
Consolidated Net Income	448	473	1,033	993
Dividends on preferred stock of subsidiaries	4	4	11	11
Net Income	444	469	1,022	982
ALABAMA POWER CO | Retail electric revenues
Operating Revenues:
Operating revenues	1,575	1,694	4,003	4,286
ALABAMA POWER CO | Wholesale electric revenues
Operating Revenues:
Operating revenues	73	71	184	194
ALABAMA POWER CO | Wholesale revenues, affiliates
Operating Revenues:
Operating revenues	11	2	36	66
ALABAMA POWER CO | Other
Operating Revenues:
Operating revenues	70	74	222	216
ALABAMA POWER CO | Fuel
Operating Expenses:
Total cost of sales	306	310	721	864
ALABAMA POWER CO | Purchased power
Operating Expenses:
Total cost of sales	64	77	153	160
ALABAMA POWER CO | Purchased power, affiliates
Operating Expenses:
Total cost of sales	44	73	93	164
GEORGIA POWER CO
Operating Revenues:
Operating revenues	2,617	2,755	6,371	6,706
Operating Expenses:
Other operations and maintenance	483	473	1,411	1,385
Depreciation and amortization	358	250	1,064	733
Taxes other than income taxes	123	127	344	348
Estimated loss on Plant Vogtle Units 3 and 4	0	0	149	0
Total operating expenses	1,620	1,594	4,596	4,451
Operating Income (Loss)	997	1,161	1,775	2,255
Other Income and (Expense):
Allowance for equity funds used during construction			63	49
Interest expense, net of amounts capitalized	(106)	(103)	(322)	(304)
Other income (expense), net	54	36	156	113
Total other income and (expense)	(52)	(67)	(166)	(191)
Earnings (Loss) Before Income Taxes	945	1,094	1,609	2,064
Income taxes (benefit)	172	255	198	466
Consolidated Net Income	773	839	1,411	1,598
GEORGIA POWER CO | Retail electric revenues
Operating Revenues:
Operating revenues	2,435	2,567	5,870	6,181
GEORGIA POWER CO | Wholesale electric revenues
Operating Revenues:
Operating revenues	34	39	85	107
GEORGIA POWER CO | Other
Operating Revenues:
Operating revenues	148	149	416	418
GEORGIA POWER CO | Fuel
Operating Expenses:
Total cost of sales	368	443	826	1,132
GEORGIA POWER CO | Purchased power
Operating Expenses:
Total cost of sales	146	151	409	393
GEORGIA POWER CO | Purchased power, affiliates
Operating Expenses:
Total cost of sales	142	150	393	460
MISSISSIPPI POWER CO
Operating Revenues:
Operating revenues	336	370	895	970
Operating Expenses:
Other operations and maintenance	62	72	202	204
Depreciation and amortization	47	48	135	144
Taxes other than income taxes	31	30	90	85
Total operating expenses	249	277	711	767
Operating Income (Loss)	87	93	184	203
Other Income and (Expense):
Interest expense, net of amounts capitalized	(14)	(17)	(45)	(52)
Other income (expense), net	6	4	19	15
Total other income and (expense)	(8)	(13)	(26)	(37)
Earnings (Loss) Before Income Taxes	79	80	158	166
Income taxes (benefit)	12	15	20	27
Consolidated Net Income	67	65	138	139
MISSISSIPPI POWER CO | Retail electric revenues
Operating Revenues:
Operating revenues	232	251	630	669
MISSISSIPPI POWER CO | Wholesale electric revenues
Operating Revenues:
Operating revenues	61	64	164	178
MISSISSIPPI POWER CO | Wholesale revenues, affiliates
Operating Revenues:
Operating revenues	36	51	82	109
MISSISSIPPI POWER CO | Other
Operating Revenues:
Operating revenues	7	4	19	14
MISSISSIPPI POWER CO | Fuel
Operating Expenses:
Total cost of sales	103	121	266	319
MISSISSIPPI POWER CO | Purchased power
Operating Expenses:
Total cost of sales	6	6	18	15
SOUTHERN POWER CO
Operating Revenues:
Operating revenues	523	574	1,337	1,527
Operating Expenses:
Other operations and maintenance	89	85	245	250
Depreciation and amortization	129	120	367	357
Taxes other than income taxes	10	10	29	32
(Gain) loss on dispositions, net	0	0	(39)	(23)
Total operating expenses	384	407	1,000	1,147
Operating Income (Loss)	139	167	337	380
Other Income and (Expense):
Interest expense, net of amounts capitalized	(36)	(43)	(114)	(127)
Other income (expense), net	13	6	19	48
Total other income and (expense)	(23)	(37)	(95)	(79)
Earnings (Loss) Before Income Taxes	116	130	242	301
Income taxes (benefit)	14	19	27	(41)
Consolidated Net Income	102	111	215	342
Net income attributable to noncontrolling interests	28	25	3	26
Net Income	74	86	212	316
SOUTHERN POWER CO | Wholesale electric revenues
Operating Revenues:
Operating revenues	418	455	1,047	1,197
SOUTHERN POWER CO | Wholesale revenues, affiliates
Operating Revenues:
Operating revenues	101	116	279	320
SOUTHERN POWER CO | Other
Operating Revenues:
Operating revenues	4	3	11	10
SOUTHERN POWER CO | Fuel
Operating Expenses:
Total cost of sales	137	166	346	449
SOUTHERN POWER CO | Purchased power
Operating Expenses:
Total cost of sales	19	26	52	82
SOUTHERN Co GAS
Operating Revenues:
Operating revenues	477	498	2,362	2,661
Operating Expenses:
Other operations and maintenance	217	208	696	642
Depreciation and amortization	125	121	368	359
Taxes other than income taxes	35	33	154	161
Impairment charges	0	92	0	92
Total operating expenses	448	533	1,872	2,210
Operating Income (Loss)	29	(35)	490	451
Other Income and (Expense):
Earnings from equity method investments	33	35	106	115
Interest expense, net of amounts capitalized	(57)	(56)	(171)	(174)
Other income (expense), net	12	5	33	16
Total other income and (expense)	(12)	(16)	(32)	(43)
Earnings (Loss) Before Income Taxes	17	(51)	458	408
Income taxes (benefit)	3	(22)	98	61
Consolidated Net Income	14	(29)	360	347
Net Income	14	(29)	360	347
SOUTHERN Co GAS | Natural gas
Operating Revenues:
Operating revenues	478	498	2,356	2,661
Operating Expenses:
Total cost of sales	71	79	654	956
SOUTHERN Co GAS | Alternative revenue programs
Operating Revenues:
Operating revenues	$ (1)	$ 0	$ 6	$ 0

XML

Condensed Consolidated Statements of Income (Unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Revenues	$ 5,620	$ 5,995	$ 15,258	$ 16,505
Cost, Product and Service [Extensible List]			us-gaap:NaturalGasUsRegulatedMember
Alternative revenue programs
Revenues	(1)	0	$ 6	0
SOUTHERN Co GAS
Revenues	477	498	2,362	2,661
Revenue taxes collected	10	10	79	88
SOUTHERN Co GAS | Alternative revenue programs
Revenues	$ (1)	$ 0	$ 6	$ 0

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Net income	$ 1,283	$ 1,345	$ 2,746	$ 4,335
Qualifying hedges:
Changes in fair value, net of tax	49	(92)	(26)	(152)
Reclassification adjustment for amounts included in net income, net of tax	(32)	50	(3)	74
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax	3	1	6	2
Total other comprehensive income (loss)	20	(41)	(23)	(76)
Comprehensive Income	1,303	1,304	2,723	4,259
Dividends on preferred stock of subsidiaries	4	4	11	11
Comprehensive income attributable to noncontrolling interests	28	25	3	26
Comprehensive Income (Loss) Attributable to Parent	1,271	1,275	2,709	4,222
ALABAMA POWER CO
Net income	448	473	1,033	993
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax	1	1	3	3
Pension and other postretirement benefit plans:
Total other comprehensive income (loss)	1	1	3	3
Comprehensive Income	449	474	1,036	996
Dividends on preferred stock of subsidiaries	4	4	11	11
GEORGIA POWER CO
Net income	773	839	1,411	1,598
Qualifying hedges:
Changes in fair value, net of tax	0	(35)	(2)	(62)
Reclassification adjustment for amounts included in net income, net of tax	2	0	4	1
Pension and other postretirement benefit plans:
Total other comprehensive income (loss)	2	(35)	2	(61)
Comprehensive Income	775	804	1,413	1,537
MISSISSIPPI POWER CO
Net income	67	65	138	139
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax	0	0	1	1
Pension and other postretirement benefit plans:
Total other comprehensive income (loss)	0	0	1	1
Comprehensive Income	67	65	139	140
SOUTHERN POWER CO
Net income	102	111	215	342
Qualifying hedges:
Changes in fair value, net of tax	44	(53)	(6)	(84)
Reclassification adjustment for amounts included in net income, net of tax	(36)	45	(24)	64
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax	0	0	2	0
Total other comprehensive income (loss)	8	(8)	(28)	(20)
Comprehensive Income	110	103	187	322
Comprehensive income attributable to noncontrolling interests	28	25	3	26
Comprehensive Income (Loss) Attributable to Parent	82	78	184	296
SOUTHERN Co GAS
Net income	14	(29)	360	347
Qualifying hedges:
Changes in fair value, net of tax	4	(3)	(17)	(6)
Reclassification adjustment for amounts included in net income, net of tax	1	0	7	0
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax	0	0	0	(1)
Total other comprehensive income (loss)	5	(3)	(10)	(7)
Comprehensive Income	$ 19	$ (32)	$ 350	$ 340

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Qualifying hedges:
Changes in fair value, tax	$ 17	$ (33)	$ (9)	$ (54)
Reclassification adjustment for amounts included in net income, tax	(11)	17	(1)	25
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, tax	(1)	0	(3)	0
ALABAMA POWER CO
Qualifying hedges:
Reclassification adjustment for amounts included in net income, tax	0	0	1	1
GEORGIA POWER CO
Qualifying hedges:
Changes in fair value, tax	0	(12)	(1)	(21)
Reclassification adjustment for amounts included in net income, tax	0	0	2	0
MISSISSIPPI POWER CO
Qualifying hedges:
Reclassification adjustment for amounts included in net income, tax	0	0	0	0
SOUTHERN POWER CO
Qualifying hedges:
Changes in fair value, tax	15	(18)	(2)	(28)
Reclassification adjustment for amounts included in net income, tax	(13)	15	(8)	21
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, tax	0	0	0	0
SOUTHERN Co GAS
Qualifying hedges:
Changes in fair value, tax	1	(3)	(6)	(4)
Reclassification adjustment for amounts included in net income, tax	0	0	2	0
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, tax	$ 0	$ 0	$ 1	$ (1)

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019
Operating Activities:
Net income	$ 2,746	$ 4,335
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	2,903	2,514
Deferred income taxes	(196)	253
Utilization of federal investment tax credits	319	722
Allowance for equity funds used during construction	(106)	(96)
Impairment charges	0	142
Pension, postretirement, and other employee benefits	(190)	(114)
Settlement of asset retirement obligations	(315)	(225)
Stock based compensation expense	99	87
Estimated loss on Plant Vogtle Units 3 and 4	149	0
Storm damage reserve accruals	171	34
Impairment charges	154	0
(Gain) loss on dispositions, net	(36)	(2,517)
Other, net	93	(20)
Changes in certain current assets and liabilities —
-Receivables	125	588
-Prepayments	(39)	61
-Materials and supplies	(141)	(31)
-Other current assets	(80)	(31)
-Accounts payable	(428)	(1,155)
-Accrued taxes	289	679
-Accrued compensation	(183)	(191)
-Retail fuel cost over recovery	158	31
-Customer refunds	(226)	(30)
-Other current liabilities	(46)	(155)
Net cash provided from operating activities	5,220	4,881
Investing Activities:
Property additions	(5,365)	(5,417)
Nuclear decommissioning trust fund purchases	(714)	(683)
Nuclear decommissioning trust fund sales	708	678
Proceeds from dispositions and asset sales	987	5,036
Cost of removal, net of salvage	(233)	(290)
Change in construction payables, net	(40)	(132)
Investment in unconsolidated subsidiaries	(79)	(141)
Payments pursuant to LTSAs	(139)	(139)
Other investing activities	(17)	15
Net cash used for investing activities	(4,892)	(1,073)
Financing Activities:
Decrease in notes payable, net	(1,534)	(773)
Proceeds —
Long-term debt	7,543	4,737
Common stock	63	623
Short-term borrowings	615	250
Redemptions and repurchases —
Long-term debt	(2,472)	(3,216)
Short-term borrowings	(840)	(1,850)
Distributions to noncontrolling interests	(164)	(125)
Capital contributions from noncontrolling interests	173	11
Purchase of membership interests from noncontrolling interests	(60)	0
Payment of common stock dividends	(2,008)	(1,919)
Other financing activities	(239)	(130)
Net cash provided from (used for) financing activities	1,077	(2,392)
Net Change in Cash, Cash Equivalents, and Restricted Cash	1,405	1,416
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	1,978	1,519
Cash, Cash Equivalents, and Restricted Cash at End of Period	3,383	2,935
Cash paid during the period for —
Interest, net of amounts capitalized	1,346	1,318
Income taxes, net	66	265
Accrued property additions at end of period	917	953
Right-of-use assets obtained under operating leases	158	76
Right-of-use assets obtained under finance leases	8	31
Interest capitalized	61	55
ALABAMA POWER CO
Operating Activities:
Net income	1,033	993
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	731	756
Deferred income taxes	71	148
Allowance for equity funds used during construction	(34)	(41)
Pension, postretirement, and other employee benefits	(71)	(30)
Settlement of asset retirement obligations	(157)	(76)
Other, net	69	18
Changes in certain current assets and liabilities —
-Receivables	(130)	(115)
-Prepayments	(32)	(30)
-Materials and supplies	(55)	11
-Other current assets	(32)	(30)
-Accounts payable	(248)	(267)
-Accrued taxes	142	149
-Accrued compensation	(55)	(55)
-Retail fuel cost over recovery	74	21
-Customer refunds	(64)	(28)
-Other current liabilities	(13)	47
Net cash provided from operating activities	1,229	1,471
Investing Activities:
Property additions	(1,460)	(1,239)
Nuclear decommissioning trust fund purchases	(213)	(201)
Nuclear decommissioning trust fund sales	213	201
Cost of removal, net of salvage	(68)	(79)
Change in construction payables, net	(46)	(99)
Other investing activities	(17)	(22)
Net cash used for investing activities	(1,591)	(1,439)
Proceeds —
Senior notes	600	600
Pollution control revenue bonds	87	0
Capital contributions from parent company	649	1,252
Redemptions and repurchases —
Pollution control revenue bonds	(87)	0
Senior notes	0	(200)
Payment of common stock dividends	(718)	(633)
Other financing activities	(26)	(27)
Net cash provided from (used for) financing activities	505	992
Net Change in Cash, Cash Equivalents, and Restricted Cash	143	1,024
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	894	313
Cash, Cash Equivalents, and Restricted Cash at End of Period	1,037	1,337
Cash paid during the period for —
Interest, net of amounts capitalized	249	246
Income taxes, net	203	89
Accrued property additions at end of period	154	173
Right-of-use assets obtained under operating leases	63	7
Right-of-use assets obtained under finance leases	2	1
Interest capitalized	11	15
GEORGIA POWER CO
Operating Activities:
Net income	1,411	1,598
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	1,206	887
Deferred income taxes	(167)	145
Allowance for equity funds used during construction	(63)	(49)
Pension, postretirement, and other employee benefits	(98)	(85)
Settlement of asset retirement obligations	(130)	(110)
Estimated loss on Plant Vogtle Units 3 and 4	149	0
Storm damage reserve accruals	160	22
Other, net	12	40
Changes in certain current assets and liabilities —
-Receivables	(168)	(128)
-Prepaid income taxes	0	102
-Materials and supplies	(74)	(2)
-Contract assets	(34)	(33)
-Other current assets	(31)	(13)
-Accounts payable	25	(134)
-Accrued taxes	44	138
-Accrued compensation	(36)	(12)
-Retail fuel cost over recovery	84	0
-Customer refunds	(162)	18
-Other current liabilities	(3)	(19)
Net cash provided from operating activities	2,125	2,365
Investing Activities:
Property additions	(2,519)	(2,581)
Nuclear decommissioning trust fund purchases	(500)	(483)
Nuclear decommissioning trust fund sales	495	477
Proceeds from dispositions and asset sales	143	9
Cost of removal, net of salvage	(93)	(136)
Change in construction payables, net	(14)	(75)
Payments pursuant to LTSAs	(44)	(17)
Other investing activities	6	13
Net cash used for investing activities	(2,526)	(2,793)
Financing Activities:
Decrease in notes payable, net	(115)	(294)
Proceeds —
FFB loan	519	835
Senior notes	1,500	750
Pollution control revenue bonds	53	584
Short-term borrowings	250	250
Capital contributions from parent company	1,379	82
Redemptions and repurchases —
Short-term borrowings	(375)	0
Pollution control revenue bonds	(148)	(223)
Senior notes	(950)	0
FFB loan	(55)	0
Payment of common stock dividends	(1,156)	(1,182)
Other financing activities	(35)	(37)
Net cash provided from (used for) financing activities	867	765
Net Change in Cash, Cash Equivalents, and Restricted Cash	466	337
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	52	112
Cash, Cash Equivalents, and Restricted Cash at End of Period	518	449
Cash paid during the period for —
Interest, net of amounts capitalized	316	296
Income taxes, net	311	45
Accrued property additions at end of period	523	589
Right-of-use assets obtained under operating leases	30	18
Right-of-use assets obtained under finance leases	0	24
Interest capitalized	34	25
MISSISSIPPI POWER CO
Operating Activities:
Net income	138	139
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	142	148
Deferred income taxes	(19)	10
Settlement of asset retirement obligations	(16)	(28)
Other, net	9	8
Changes in certain current assets and liabilities —
-Receivables	(3)	(11)
-Other current assets	(7)	18
-Accounts payable	(54)	(26)
-Accrued taxes	15	(12)
-Accrued compensation	(8)	(10)
-Other current liabilities	(11)	6
Net cash provided from operating activities	186	242
Investing Activities:
Property additions	(174)	(134)
Change in construction payables, net	7	(16)
Payments pursuant to LTSAs	(20)	(18)
Other investing activities	(13)	(30)
Net cash used for investing activities	(200)	(198)
Proceeds —
Pollution control revenue bonds	34	43
Short-term borrowings	40	0
Capital contributions from parent company	80	2
Other long-term debt	100	0
Redemptions and repurchases —
Short-term borrowings	(40)	0
Pollution control revenue bonds	(41)	0
Senior notes	(275)	0
Return of capital to parent company	(74)	(113)
Payment of common stock dividends	(37)	0
Other financing activities	(1)	(1)
Net cash provided from (used for) financing activities	(214)	(69)
Net Change in Cash, Cash Equivalents, and Restricted Cash	(228)	(25)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	286	293
Cash, Cash Equivalents, and Restricted Cash at End of Period	58	268
Cash paid during the period for —
Interest, net of amounts capitalized	49	55
Income taxes, net	9	0
Accrued property additions at end of period	42	20
Interest capitalized	0	1
SOUTHERN POWER CO
Operating Activities:
Net income	215	342
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	386	377
Deferred income taxes	(59)	(122)
Utilization of federal investment tax credits	318	705
Amortization of investment tax credits	(44)	(136)
(Gain) loss on dispositions, net	(39)	(24)
Other, net	(16)	(19)
Changes in certain current assets and liabilities —
-Receivables	(28)	15
-Prepaid income taxes	74	33
-Other current assets	(17)	(3)
-Accounts payable	(12)	(5)
-Accrued taxes	21	66
-Other current liabilities	(25)	(8)
Net cash provided from operating activities	774	1,221
Investing Activities:
Business acquisitions, net of cash acquired	(81)	(50)
Property additions	(135)	(284)
Proceeds from dispositions and asset sales	663	572
Investment in unconsolidated subsidiaries	0	(116)
Payments pursuant to LTSAs	(61)	(85)
Other investing activities	38	(1)
Net cash used for investing activities	424	36
Financing Activities:
Decrease in notes payable, net	(449)	0
Proceeds —
Capital contributions from parent company	0	59
Redemptions and repurchases —
Short-term borrowings	(100)	(100)
Senior notes	(300)	0
Return of capital to parent company	0	(755)
Distributions to noncontrolling interests	(164)	(125)
Capital contributions from noncontrolling interests	173	11
Purchase of membership interests from noncontrolling interests	(60)	0
Payment of common stock dividends	(151)	(154)
Other financing activities	(9)	(6)
Net cash provided from (used for) financing activities	(1,060)	(1,070)
Net Change in Cash, Cash Equivalents, and Restricted Cash	138	187
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	279	181
Cash, Cash Equivalents, and Restricted Cash at End of Period	417	368
Cash paid during the period for —
Interest, net of amounts capitalized	123	133
Income taxes, net	(278)	(612)
Accrued property additions at end of period	44	41
Right-of-use assets obtained under operating leases	30	0
Interest capitalized	10	11
SOUTHERN Co GAS
Operating Activities:
Net income	360	347
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	368	359
Deferred income taxes	(1)	96
Mark-to-market adjustments	104	44
Impairment charges	0	92
Other, net	(20)	(58)
Changes in certain current assets and liabilities —
-Receivables	403	832
-Natural gas for sale	26	49
-Other current assets	(45)	45
-Accounts payable	(75)	(607)
-Accrued taxes	7	(68)
-Accrued compensation	(17)	(34)
-Other current liabilities	12	(48)
Net cash provided from operating activities	1,122	1,049
Investing Activities:
Property additions	(1,045)	(1,008)
Proceeds from dispositions and asset sales	178	32
Cost of removal, net of salvage	(60)	(59)
Change in construction payables, net	25	57
Investment in unconsolidated subsidiaries	(79)	(25)
Other investing activities	8	14
Net cash used for investing activities	(973)	(989)
Financing Activities:
Decrease in notes payable, net	(500)	(383)
Proceeds —
Senior notes	500	0
First mortgage bonds	150	200
Capital contributions from parent company	215	820
Redemptions and repurchases —
First mortgage bonds	0	(50)
Senior notes	0	(300)
Payment of common stock dividends	(399)	(353)
Other financing activities	(3)	(2)
Net cash provided from (used for) financing activities	(37)	(68)
Net Change in Cash, Cash Equivalents, and Restricted Cash	112	(8)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	49	70
Cash, Cash Equivalents, and Restricted Cash at End of Period	161	62
Cash paid during the period for —
Interest, net of amounts capitalized	162	180
Income taxes, net	45	48
Accrued property additions at end of period	146	154
Interest capitalized	$ 5	$ 5

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) (Parenthetical) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019
Interest capitalized	$ 61	$ 55
ALABAMA POWER CO
Interest capitalized	11	15
GEORGIA POWER CO
Interest capitalized	34	25
MISSISSIPPI POWER CO
Interest capitalized	0	1
SOUTHERN POWER CO
Interest capitalized	10	11
SOUTHERN Co GAS
Interest capitalized	$ 5	$ 5

XML

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Current Assets:
Cash and cash equivalents	$ 3,379	$ 1,975
Receivables —
Customer accounts receivable	1,778	1,614
Energy marketing receivables	328	428
Unbilled revenues	503	599
Other accounts and notes receivable	506	817
Accumulated provision for uncollectible accounts	(99)	(49)
Materials and supplies	1,522	1,388
Fossil fuel for generation	506	521
Natural gas for sale	448	479
Prepaid expenses	299	314
Assets from risk management activities, net of collateral	135	183
Regulatory assets – asset retirement obligations	246	287
Other regulatory assets	813	885
Assets held for sale	0	188
Other current assets	210	188
Total current assets	10,574	9,817
Property, Plant, and Equipment:
In service	108,831	105,114
Less: Accumulated depreciation	32,099	30,765
Plant in service, net of depreciation	76,732	74,349
Nuclear fuel, at amortized cost	804	851
Construction work in progress	8,861	7,880
Total property, plant, and equipment	86,397	83,080
Other Property and Investments:
Goodwill	5,280	5,280
Equity investments in unconsolidated subsidiaries	1,358	1,303
Other intangible assets, net of amortization	499	536
Nuclear decommissioning trusts, at fair value	2,109	2,036
Leveraged leases	653	788
Miscellaneous property and investments	403	391
Total other property and investments	10,302	10,334
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	1,791	1,800
Deferred charges related to income taxes	799	798
Unamortized loss on reacquired debt	285	300
Regulatory assets – asset retirement obligations, deferred	4,984	4,094
Other regulatory assets, deferred	6,502	6,805
Assets held for sale, deferred	0	601
Other deferred charges and assets	1,524	1,071
Total deferred charges and other assets	15,885	15,469
Total Assets	123,158	118,700
Current Liabilities:
Securities due within one year	4,378	2,989
Notes payable	171	2,055
Energy marketing trade payables	361	442
Accounts payable —
Accounts payable	1,924	2,115
Customer deposits	496	496
Accrued taxes —
Accrued income taxes	75	0
Other accrued taxes	742	659
Accrued interest	421	474
Accrued compensation	843	992
Asset retirement obligations	640	504
Other regulatory liabilities	616	756
Liabilities held for sale	0	5
Operating lease obligations	235	229
Other current liabilities	848	830
Total current liabilities	11,750	12,546
Long-term Debt	45,581	41,798
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	8,342	7,888
Deferred credits related to income taxes	5,763	6,078
Accumulated deferred ITCs	2,251	2,291
Employee benefit obligations	1,753	1,814
Operating lease obligations, deferred	1,570	1,615
Asset retirement obligations, deferred	10,020	9,282
Accrued environmental remediation	220	234
Other cost of removal obligations	2,231	2,239
Other regulatory liabilities, deferred	315	256
Other deferred credits and liabilities	571	609
Total deferred credits and other liabilities	33,036	32,306
Total Liabilities	90,367	86,650
Redeemable Preferred Stock of Subsidiaries	291	291
Common Stockholder's Equity (See accompanying statements)	32,500	31,759
Total Liabilities and Stockholders' Equity	123,158	118,700
ALABAMA POWER CO
Current Assets:
Cash and cash equivalents	1,037	894
Receivables —
Customer accounts receivable	499	425
Unbilled revenues	138	134
Affiliated	37	37
Other accounts and notes receivable	84	72
Accumulated provision for uncollectible accounts	(32)	(22)
Materials and supplies	562	512
Fossil fuel for generation	208	212
Prepaid expenses	71	50
Other regulatory assets	207	242
Other current assets	42	30
Total current assets	2,853	2,586
Property, Plant, and Equipment:
In service	31,355	30,023
Less: Accumulated depreciation	9,920	9,540
Plant in service, net of depreciation	21,435	20,483
Nuclear fuel, at amortized cost	257	296
Construction work in progress	926	890
Total property, plant, and equipment	22,618	21,669
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	63	66
Nuclear decommissioning trusts, at fair value	1,039	1,023
Miscellaneous property and investments	130	128
Total other property and investments	1,232	1,217
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	162	132
Deferred charges related to income taxes	242	244
Deferred under recovered regulatory clause revenues	62	40
Regulatory assets – asset retirement obligations, deferred	1,475	1,019
Other regulatory assets, deferred	1,923	1,976
Other deferred charges and assets	402	269
Total deferred charges and other assets	4,266	3,680
Total Assets	30,969	29,152
Current Liabilities:
Securities due within one year	496	251
Accounts payable —
Affiliated	272	316
Other	353	514
Customer deposits	104	100
Accrued taxes —
Accrued taxes	210	78
Accrued interest	83	92
Accrued compensation	172	216
Asset retirement obligations	251	195
Other regulatory liabilities	144	193
Other current liabilities	116	105
Total current liabilities	2,201	2,060
Long-term Debt	8,622	8,270
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,372	3,260
Deferred credits related to income taxes	1,917	1,960
Accumulated deferred ITCs	96	100
Employee benefit obligations	191	206
Operating lease obligations, deferred	121	107
Asset retirement obligations, deferred	3,707	3,345
Other cost of removal obligations	360	412
Other regulatory liabilities, deferred	137	146
Other deferred credits and liabilities	39	40
Total deferred credits and other liabilities	9,940	9,576
Total Liabilities	20,763	19,906
Redeemable Preferred Stock	291	291
Common Stockholder's Equity (See accompanying statements)	9,915	8,955
Total Liabilities and Stockholders' Equity	30,969	29,152
GEORGIA POWER CO
Current Assets:
Cash and cash equivalents	518	52
Receivables —
Customer accounts receivable	715	533
Unbilled revenues	237	203
Joint owner accounts receivable	120	136
Affiliated	17	21
Other accounts and notes receivable	39	209
Accumulated provision for uncollectible accounts	(29)	(2)
Materials and supplies	572	501
Fossil fuel for generation	269	272
Regulatory assets – storm damage reserves	213	213
Regulatory assets – asset retirement obligations	209	254
Other regulatory assets	251	263
Other current assets	162	140
Total current assets	3,293	2,795
Property, Plant, and Equipment:
In service	39,170	38,137
Less: Accumulated depreciation	12,139	11,753
Plant in service, net of depreciation	27,031	26,384
Nuclear fuel, at amortized cost	547	555
Construction work in progress	6,752	5,650
Total property, plant, and equipment	34,330	32,589
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	50	52
Nuclear decommissioning trusts, at fair value	1,070	1,013
Miscellaneous property and investments	67	64
Total other property and investments	1,187	1,129
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	1,345	1,428
Deferred charges related to income taxes	522	519
Regulatory assets – asset retirement obligations, deferred	3,307	2,865
Other regulatory assets, deferred	2,521	2,716
Other deferred charges and assets	541	500
Total deferred charges and other assets	8,236	8,028
Total Assets	47,046	44,541
Current Liabilities:
Securities due within one year	531	1,025
Notes payable	0	365
Accounts payable —
Affiliated	561	512
Other	731	711
Customer deposits	280	283
Accrued taxes —
Accrued taxes	415	407
Accrued interest	100	118
Accrued compensation	198	233
Asset retirement obligations	351	265
Other regulatory liabilities	302	447
Operating lease obligations	151	144
Over recovered fuel clause revenues	84	0
Other current liabilities	201	187
Total current liabilities	3,905	4,697
Long-term Debt	12,314	10,791
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,296	3,257
Deferred credits related to income taxes	2,664	2,862
Accumulated deferred ITCs	272	255
Employee benefit obligations	486	540
Operating lease obligations, deferred	1,163	1,282
Asset retirement obligations, deferred	5,901	5,519
Other deferred credits and liabilities	339	273
Total deferred credits and other liabilities	14,121	13,988
Total Liabilities	30,340	29,476
Common Stockholder's Equity (See accompanying statements)	16,706	15,065
Total Liabilities and Stockholders' Equity	47,046	44,541
MISSISSIPPI POWER CO
Current Assets:
Cash and cash equivalents	58	286
Receivables —
Customer accounts receivable	46	35
Unbilled revenues	40	39
Affiliated	14	27
Other accounts and notes receivable	34	26
Materials and supplies	63	61
Fossil fuel for generation	19	26
Other regulatory assets	60	99
Other current assets	19	10
Total current assets	353	609
Property, Plant, and Equipment:
In service	4,966	4,857
Less: Accumulated depreciation	1,553	1,463
Plant in service, net of depreciation	3,413	3,394
Construction work in progress	140	126
Total property, plant, and equipment	3,553	3,520
Other Property and Investments:
Total other property and investments	149	131
Deferred Charges and Other Assets:
Deferred charges related to income taxes	32	32
Regulatory assets – asset retirement obligations, deferred	202	210
Other regulatory assets, deferred	357	360
Accumulated deferred income taxes	130	139
Other deferred charges and assets	72	34
Total deferred charges and other assets	793	775
Total Assets	4,848	5,035
Current Liabilities:
Securities due within one year	0	281
Accounts payable —
Affiliated	54	76
Other	50	75
Accrued taxes —
Accrued taxes	120	105
Accrued interest	14	15
Accrued compensation	28	35
Asset retirement obligations	23	33
Other regulatory liabilities	56	21
Over recovered fuel clause revenues	31	29
Other current liabilities	42	64
Total current liabilities	418	734
Long-term Debt	1,402	1,308
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	422	424
Deferred credits related to income taxes	299	352
Employee benefit obligations	95	99
Asset retirement obligations, deferred	158	157
Other cost of removal obligations	195	189
Other regulatory liabilities, deferred	64	76
Other deferred credits and liabilities	35	44
Total deferred credits and other liabilities	1,268	1,341
Total Liabilities	3,088	3,383
Common Stockholder's Equity (See accompanying statements)	1,760	1,652
Total Liabilities and Stockholders' Equity	4,848	5,035
SOUTHERN POWER CO
Current Assets:
Cash and cash equivalents	416	279
Receivables —
Customer accounts receivable	135	107
Affiliated	41	30
Other accounts and notes receivable	37	73
Materials and supplies	204	191
Prepaid income taxes	33	36
Other current assets	37	43
Total current assets	903	759
Property, Plant, and Equipment:
In service	13,600	13,270
Less: Accumulated depreciation	2,776	2,464
Plant in service, net of depreciation	10,824	10,806
Construction work in progress	335	515
Total property, plant, and equipment	11,159	11,321
Other Property and Investments:
Intangible assets, net of amortization	307	322
Equity investments in unconsolidated subsidiaries	19	28
Miscellaneous property and investments	19	28
Total other property and investments	326	350
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	395	369
Prepaid LTSAs	160	128
Assets held for sale, deferred	0	601
Accumulated deferred income taxes	231	551
Income taxes receivable, non-current	13	5
Other deferred charges and assets	237	216
Total deferred charges and other assets	1,036	1,870
Total Assets	13,424	14,300
Current Liabilities:
Securities due within one year	525	824
Notes payable	0	549
Accounts payable —
Affiliated	49	56
Other	69	85
Accrued taxes —
Accrued income taxes	9	0
Other accrued taxes	31	26
Accrued interest	26	32
Other current liabilities	104	132
Total current liabilities	813	1,704
Long-term Debt	3,630	3,574
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	117	115
Accumulated deferred ITCs	1,687	1,731
Operating lease obligations, deferred	404	376
Other deferred credits and liabilities	162	178
Total deferred credits and other liabilities	2,370	2,400
Total Liabilities	6,813	7,678
Common Stockholder's Equity (See accompanying statements)	6,611	6,622
Total Liabilities and Stockholders' Equity	13,424	14,300
SOUTHERN Co GAS
Current Assets:
Cash and cash equivalents	157	46
Receivables —
Customer accounts receivable	214	323
Energy marketing receivables	328	428
Unbilled revenues	60	183
Affiliated	3	5
Other accounts and notes receivable	42	114
Accumulated provision for uncollectible accounts	(34)	(18)
Natural gas for sale	448	479
Prepaid expenses	92	65
Assets from risk management activities, net of collateral	75	177
Other regulatory assets	110	92
Assets held for sale	0	171
Other current assets	43	41
Total current assets	1,538	2,106
Property, Plant, and Equipment:
In service	17,202	16,344
Less: Accumulated depreciation	4,761	4,650
Plant in service, net of depreciation	12,441	11,694
Construction work in progress	655	613
Total property, plant, and equipment	13,096	12,307
Other Property and Investments:
Goodwill	5,015	5,015
Equity investments in unconsolidated subsidiaries	1,301	1,251
Other intangible assets, net of amortization	55	70
Miscellaneous property and investments	20	20
Total other property and investments	6,391	6,356
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	85	93
Other regulatory assets, deferred	580	618
Other deferred charges and assets	242	207
Total deferred charges and other assets	907	918
Total Assets	21,932	21,687
Current Liabilities:
Securities due within one year	334	0
Notes payable	150	650
Energy marketing trade payables	361	442
Accounts payable —
Affiliated	46	41
Other	341	315
Customer deposits	94	96
Accrued taxes —
Accrued taxes	78	71
Accrued interest	66	52
Accrued compensation	83	100
Liabilities from risk management activities, net of collateral	31	21
Other regulatory liabilities	112	94
Other current liabilities	128	128
Total current liabilities	1,824	2,010
Long-term Debt	6,127	5,845
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	1,213	1,219
Deferred credits related to income taxes	854	874
Employee benefit obligations	247	265
Operating lease obligations, deferred	70	78
Accrued environmental remediation	220	233
Other cost of removal obligations	1,642	1,606
Other deferred credits and liabilities	50	51
Total deferred credits and other liabilities	4,296	4,326
Total Liabilities	12,247	12,181
Common Stockholder's Equity (See accompanying statements)	9,685	9,506
Total Liabilities and Stockholders' Equity	$ 21,932	$ 21,687

XML

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Other intangible assets, amortization	$ 316	$ 280
SOUTHERN POWER CO
Other intangible assets, amortization	84	69
SOUTHERN Co GAS
Other intangible assets, amortization	$ 191	$ 176

XML

Consolidated Statements of Stockholders' Equity (Unaudited) - USD ($) shares in Millions, $ in Millions	Total	Common Stock	Treasury	Paid-In Capital	Retained Earnings (Accumulated Deficit)	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interests	ALABAMA POWER CO	ALABAMA POWER CO Common Stock	ALABAMA POWER CO Paid-In Capital	ALABAMA POWER CO Retained Earnings (Accumulated Deficit)	ALABAMA POWER CO Accumulated Other Comprehensive Income (Loss)	GEORGIA POWER CO	GEORGIA POWER CO Common Stock	GEORGIA POWER CO Paid-In Capital	GEORGIA POWER CO Retained Earnings (Accumulated Deficit)	GEORGIA POWER CO Accumulated Other Comprehensive Income (Loss)	MISSISSIPPI POWER CO	MISSISSIPPI POWER CO Common Stock	MISSISSIPPI POWER CO Paid-In Capital	MISSISSIPPI POWER CO Retained Earnings (Accumulated Deficit)	MISSISSIPPI POWER CO Accumulated Other Comprehensive Income (Loss)	SOUTHERN POWER CO	SOUTHERN POWER CO Total Common Stockholders' Equity	SOUTHERN POWER CO Paid-In Capital	SOUTHERN POWER CO Retained Earnings (Accumulated Deficit)	SOUTHERN POWER CO Accumulated Other Comprehensive Income (Loss)	SOUTHERN POWER CO Noncontrolling Interests	SOUTHERN Co GAS	SOUTHERN Co GAS Paid-In Capital	SOUTHERN Co GAS Retained Earnings (Accumulated Deficit)	SOUTHERN Co GAS Accumulated Other Comprehensive Income (Loss)
Beginning balance (in shares) at Dec. 31, 2018		1,035	1						31					9					1
Beginning balance at Dec. 31, 2018	$ 29,039	$ 5,164	$ (38)	$ 11,094	$ 8,706	$ (203)	$ 4,316	$ 7,477	$ 1,222	$ 3,508	$ 2,775	$ (28)	$ 14,323	$ 398	$ 10,322	$ 3,612	$ (9)	$ 1,609	$ 38	$ 4,546	$ (2,971)	$ (4)	$ 7,284	$ 2,968	$ 1,600	$ 1,352	$ 16	$ 4,316	$ 8,570	$ 8,856	$ (312)	$ 26
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	2,055				2,084		(29)
Net income (loss)													311			311		37			37		27	56		56		(29)	270		270
Net income								217			217
Return of capital to parent company																		(38)		(38)
Capital contributions from parent company								1,236		1,236			29		29			2		2			1	1	1				17	17
Other comprehensive income (loss)								1				1	1				1						(4)	(4)			(4)		(1)			(1)
Stock issued (in shares)		6
Stock issued	224	$ 28		196
Stock-based compensation	24			24
Cash dividends on common stock	(623)				(623)			(211)			(211)		(394)			(394)							(51)	(51)		(51)			(118)		(118)
Contributions from noncontrolling interests	3						3																3					3
Distributions to noncontrolling interests	(41)						(41)																(41)					(41)
Other	6		$ (2)	7			1						(1)		(1)								(1)	(2)	(1)	(1)		1
Ending balance (in shares) at Mar. 31, 2019		1,041	1						31					9					1
Ending balance at Mar. 31, 2019	30,687	$ 5,192	$ (40)	11,321	10,167	(203)	4,250	8,720	$ 1,222	4,744	2,781	(27)	14,269	$ 398	10,350	3,529	(8)	1,610	$ 38	4,510	(2,934)	(4)	7,218	2,968	1,600	1,356	12	4,250	8,738	8,873	(160)	25
Beginning balance (in shares) at Dec. 31, 2018		1,035	1						31					9					1
Beginning balance at Dec. 31, 2018	29,039	$ 5,164	$ (38)	11,094	8,706	(203)	4,316	7,477	$ 1,222	3,508	2,775	(28)	14,323	$ 398	10,322	3,612	(9)	1,609	$ 38	4,546	(2,971)	(4)	7,284	2,968	1,600	1,352	16	4,316	8,570	8,856	(312)	26
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	4,335							993					1,598					139					342						347
Net income	4,298							982															316						347
Purchase of membership interests from noncontrolling interests	0																						0
Ending balance (in shares) at Sep. 30, 2019		1,050	1						31					9					1
Ending balance at Sep. 30, 2019	31,791	$ 5,234	$ (41)	11,512	11,087	(279)	4,278	9,086	$ 1,222	4,765	3,124	(25)	14,764	$ 398	10,408	4,028	(70)	1,639	$ 38	4,437	(2,832)	(4)	6,693	2,415	905	1,514	(4)	4,278	9,393	9,692	(318)	19
Beginning balance (in shares) at Mar. 31, 2019		1,041	1						31					9					1
Beginning balance at Mar. 31, 2019	30,687	$ 5,192	$ (40)	11,321	10,167	(203)	4,250	8,720	$ 1,222	4,744	2,781	(27)	14,269	$ 398	10,350	3,529	(8)	1,610	$ 38	4,510	(2,934)	(4)	7,218	2,968	1,600	1,356	12	4,250	8,738	8,873	(160)	25
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	928				899		29
Net income (loss)													448			448		37			37		203	174		174		29	106		106
Net income								296			296
Return of capital to parent company																		(38)		(38)			(505)	(505)	(505)
Capital contributions from parent company								23		23			20		20			8		8			7	7	7				35	35
Other comprehensive income (loss)	(35)					(35)		1				1	(27)				(27)						(8)	(8)			(8)		(3)			(3)
Stock issued (in shares)		5
Stock issued	228	$ 25		203
Stock-based compensation	11			11
Cash dividends on common stock	(646)				(646)			(211)			(211)		(394)			(394)							(52)	(52)		(52)			(117)		(117)
Contributions from noncontrolling interests	2						2																2					2
Distributions to noncontrolling interests	(47)						(47)																(47)					(47)
Other	3		$ (1)	5			(1)						0		1	(1)							0	1		1		(1)
Ending balance (in shares) at Jun. 30, 2019		1,046	1						31					9					1
Ending balance at Jun. 30, 2019	31,131	$ 5,217	$ (41)	11,540	10,420	(238)	4,233	8,829	$ 1,222	4,767	2,866	(26)	14,316	$ 398	10,371	3,582	(35)	1,617	$ 38	4,480	(2,897)	(4)	6,818	2,585	1,102	1,479	4	4,233	8,759	8,908	(171)	22
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	1,341				1,316		25
Net income (loss)	1,345							473					839			839		65			65		111	86		86		25	(29)		(29)
Net income	1,316							469			469												86						(29)
Return of capital to parent company								(2)		(2)								(43)		(43)			(250)	(250)	(250)
Capital contributions from parent company													38		38								53	53	53				784	784
Other comprehensive income (loss)	(41)					(41)		1				1	(35)				(35)						(8)	(8)			(8)		(3)			(3)
Issuance of equity units	(198)			(198)
Stock issued (in shares)		4
Stock issued	171	$ 17		154
Stock-based compensation	12			12
Cash dividends on common stock	(649)				(649)			(211)			(211)		(394)			(394)							(51)	(51)		(51)			(118)		(118)
Contributions from noncontrolling interests	63						63																63					63
Distributions to noncontrolling interests	(43)						(43)																(43)					(43)
Other	4		$ 0	4			0						0		(1)	1
Ending balance (in shares) at Sep. 30, 2019		1,050	1						31					9					1
Ending balance at Sep. 30, 2019	31,791	$ 5,234	$ (41)	11,512	11,087	(279)	4,278	9,086	$ 1,222	4,765	3,124	(25)	14,764	$ 398	10,408	4,028	(70)	1,639	$ 38	4,437	(2,832)	(4)	6,693	2,415	905	1,514	(4)	4,278	9,393	9,692	(318)	19
Beginning balance (in shares) at Dec. 31, 2019		1,054	1						31					9					1
Beginning balance at Dec. 31, 2019	31,759	$ 5,257	$ (42)	11,734	10,877	(321)	4,254	8,955	$ 1,222	4,755	3,001	(23)	15,065	$ 398	10,962	3,756	(51)	1,652	$ 38	4,449	(2,832)	(3)	6,622	2,368	909	1,485	(26)	4,254	9,506	9,697	(198)	7
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	837				868		(31)
Net income (loss)													331			331		32			32		44	75		75		(31)	275		275
Net income								280			280
Return of capital to parent company																		(37)		(37)									(2)	(2)
Capital contributions from parent company								612		612			502		502			76		76
Other comprehensive income (loss)	(47)					(47)		1				1	(1)				(1)						(33)	(33)			(33)		(15)			(15)
Stock issued (in shares)		3
Stock issued	52	$ 9		43
Stock-based compensation	5			5
Cash dividends on common stock	(655)				(655)			(239)			(239)		(385)			(385)							(50)	(50)		(50)			(133)		(133)
Contributions from noncontrolling interests	16						16																16					16
Distributions to noncontrolling interests	(48)						(48)																(48)					(48)
Other	(3)		$ (2)		(2)	1												(1)		(1)
Ending balance (in shares) at Mar. 31, 2020		1,057	1						31					9					1
Ending balance at Mar. 31, 2020	31,916	$ 5,266	$ (44)	11,782	11,088	(367)	4,191	9,609	$ 1,222	5,367	3,042	(22)	15,512	$ 398	11,464	3,702	(52)	1,722	$ 38	4,487	(2,800)	(3)	6,551	2,360	909	1,510	(59)	4,191	9,631	9,695	(56)	(8)
Beginning balance (in shares) at Dec. 31, 2019		1,054	1						31					9					1
Beginning balance at Dec. 31, 2019	31,759	$ 5,257	$ (42)	11,734	10,877	(321)	4,254	8,955	$ 1,222	4,755	3,001	(23)	15,065	$ 398	10,962	3,756	(51)	1,652	$ 38	4,449	(2,832)	(3)	6,622	2,368	909	1,485	(26)	4,254	9,506	9,697	(198)	7
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	2,746							1,033					1,411					138					215						360
Net income	2,732							1,022															212						360
Purchase of membership interests from noncontrolling interests	60																						60
Ending balance (in shares) at Sep. 30, 2020		1,057	1						31					9					1
Ending balance at Sep. 30, 2020	32,500	$ 5,267	$ (44)	11,810	11,600	(344)	4,211	9,915	$ 1,222	5,408	3,305	(20)	16,706	$ 398	12,345	4,011	(48)	1,760	$ 38	4,456	(2,731)	(3)	6,611	2,400	908	1,546	(54)	4,211	9,685	9,925	(237)	(3)
Beginning balance (in shares) at Mar. 31, 2020		1,057	1						31					9					1
Beginning balance at Mar. 31, 2020	31,916	$ 5,266	$ (44)	11,782	11,088	(367)	4,191	9,609	$ 1,222	5,367	3,042	(22)	15,512	$ 398	11,464	3,702	(52)	1,722	$ 38	4,487	(2,800)	(3)	6,551	2,360	909	1,510	(59)	4,191	9,631	9,695	(56)	(8)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	617				612		5
Net income (loss)													308			308		39			39		68	63		63		5	71		71
Net income								298			298
Return of capital to parent company																		(37)		(37)
Capital contributions from parent company								1		1			1		1														200	200
Other comprehensive income (loss)	4					4		1				1	2				2						(3)	(3)			(3)
Stock issued	7			7
Stock-based compensation	11			11
Cash dividends on common stock	(677)				(677)			(239)			(239)		(386)			(386)							(50)	(50)		(50)			(133)		(133)
Contributions from noncontrolling interests	165						165																165					165
Distributions to noncontrolling interests	(70)						(70)																(70)					(70)
Other	(12)			(13)	1																		(2)	(2)	(2)	0	0	0
Ending balance (in shares) at Jun. 30, 2020		1,057	1						31					9					1
Ending balance at Jun. 30, 2020	31,961	$ 5,266	$ (44)	11,787	11,024	(363)	4,291	9,670	$ 1,222	5,368	3,101	(21)	15,437	$ 398	11,465	3,624	(50)	1,724	$ 38	4,450	(2,761)	(3)	6,659	2,368	907	1,523	(62)	4,291	9,769	9,895	(118)	(8)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	1,279				1,251		28
Net income (loss)	1,283							448					773			773		67			67		102	74		74		28	14		14
Net income	1,251							444			444												74						14
Return of capital to parent company																							(4)	(4)	(4)
Capital contributions from parent company								40		40			880		880			6		6									30	30
Other comprehensive income (loss)	20					20		1				1	2				2						8	8			8		5			5
Stock issued	4	1		3
Stock-based compensation	15			15
Cash dividends on common stock	(676)				(676)			(240)			(240)		(386)			(386)		(37)			(37)		(51)	(51)		(51)			(133)		(133)
Contributions from noncontrolling interests	2						2																2					2
Distributions to noncontrolling interests	(51)						(51)																(51)					(51)
Purchase of membership interests from noncontrolling interests	(55)			5			(60)																(55)	5	5			(60)
Other	1	$ 0	$ 0	0	1	(1)	1																1	0	0	0		1
Ending balance (in shares) at Sep. 30, 2020		1,057	1						31					9					1
Ending balance at Sep. 30, 2020	$ 32,500	$ 5,267	$ (44)	$ 11,810	$ 11,600	$ (344)	$ 4,211	$ 9,915	$ 1,222	$ 5,408	$ 3,305	$ (20)	$ 16,706	$ 398	$ 12,345	$ 4,011	$ (48)	$ 1,760	$ 38	$ 4,456	$ (2,731)	$ (3)	$ 6,611	$ 2,400	$ 908	$ 1,546	$ (54)	$ 4,211	$ 9,685	$ 9,925	$ (237)	$ (3)

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Consolidated Statements of Stockholders' Equity (Unaudited) (Parenthetical) - $ / shares	3 Months Ended
	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019
Statement of Stockholders' Equity [Abstract]
Cash dividends (in dollars per share)	$ 0.64	$ 0.64	$ 0.62	$ 0.62	$ 0.62	$ 0.60

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INTRODUCTION

9 Months Ended

Sep. 30, 2020

Organization, Consolidation and Presentation of Financial Statements [Abstract]

INTRODUCTION

INTRODUCTION

The condensed quarterly financial statements of each Registrant included herein have been prepared by such Registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 2019 have been derived from the audited financial statements of each Registrant. In the opinion of each Registrant's management, the information regarding such Registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended September 30, 2020 and 2019. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each Registrant believes that the disclosures regarding such Registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the 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, including the impacts of the COVID-19 pandemic, 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, 2020 and December 31, 2019 was as follows:

	Goodwill
	(in millions)
Southern Company	$	5,280
Southern Company Gas:
Gas distribution operations	$	4,034
Gas marketing services	981
Southern Company Gas total	$	5,015

Goodwill is not amortized but is subject to an annual impairment test in the fourth quarter of the year and on an interim basis as events and changes in circumstances occur, including, but not limited to, a significant change in operating performance, the business climate, legal or regulatory factors, or a planned sale or disposition of a significant portion of the business. The continued COVID-19 pandemic and related responses continue to disrupt supply chains, reduce labor availability and productivity, and reduce economic activity. These effects could have a variety of adverse impacts on Southern Company and its subsidiaries, including the $263 million of goodwill recorded at PowerSecure. If the impact of the COVID-19 pandemic becomes significant to the operating results of PowerSecure and its businesses, a portion of the associated goodwill may become impaired. The ultimate outcome of this matter cannot be determined at this time.

Other intangible assets were as follows:

	At September 30, 2020						At December 31, 2019
	Gross Carrying Amount		Accumulated Amortization		Other Intangible Assets, Net		Gross Carrying Amount		Accumulated Amortization		Other Intangible Assets, Net
	(in millions)						(in millions)
Southern Company
Other intangible assets subject to amortization:
Customer relationships	$	212	$	(130)	$	82	$	212	$	(116)	$	96
Trade names	64		(30)		34		64		(25)		39
Storage and transportation contracts	64		(64)		—		64		(62)		2
PPA fair value adjustments	390		(84)		306		390		(69)		321
Other	10		(8)		2		11		(8)		3
Total other intangible assets subject to amortization	$	740	$	(316)	$	424	$	741	$	(280)	$	461
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	75		—		75		75		—		75
Total other intangible assets	$	815	$	(316)	$	499	$	816	$	(280)	$	536
Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	$	390	$	(84)	$	306	$	390	$	(69)	$	321
Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services
Customer relationships	$	156	$	(115)	$	41	$	156	$	(104)	$	52
Trade names	26		(12)		14		26		(10)		16
Wholesale gas services
Storage and transportation contracts	64		(64)		—		64		(62)		2
Total other intangible assets subject to amortization	$	246	$	(191)	$	55	$	246	$	(176)	$	70

Amortization associated with other intangible assets was as follows:

	Three Months Ended		Nine Months Ended
	September 30, 2020
	(in millions)
Southern Company(a)	$	12	$	37
Southern Power(b)	$	5	$	15
Southern Company Gas
Gas marketing services	$	4	$	13
Wholesale gas services(b)	1		2
Southern Company Gas total	$	5	$	15

(a)Includes $6 million and $17 million for the three and nine months ended September 30, 2020, respectively, recorded as a reduction to operating revenues.

(b)Recorded as a reduction to operating revenues.

Restricted Cash

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed balance sheets that total to the amounts shown in the condensed statements of cash flows for the Registrants that had restricted cash at September 30, 2020 and/or December 31, 2019:

	Southern Company					Southern Power		Southern Company Gas
	At September 30, 2020			At December 31, 2019		At September 30, 2020		At September 30, 2020		At December 31, 2019
	(in millions)					(in millions)		(in millions)
Cash and cash equivalents	$	3,379		$	1,975	$	416	$	157	$	46
Restricted cash(a):
Other accounts and notes receivable	—			3		—		—		3
Other current assets	4			—		—		4		—
Other deferred charges and assets	1			—		1		—		—
Total cash, cash equivalents, and restricted cash	$	3,383	(b)	$	1,978	$	417	$	161	$	49

(a)For Southern Company Gas, reflects restricted cash held as collateral for workers' compensation, life insurance, and long-term disability insurance. For Southern Power, reflects restricted cash held for construction payables.

(b)Total does not add due to rounding.

Natural Gas for Sale

Southern Company Gas, with the exception of Nicor Gas, carries natural gas inventory on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value. 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 the three and nine months ended September 30, 2020 or the three months ended September 30, 2019 and recorded an adjustment of $10

million for the nine months ended September 30, 2019. Nicor Gas' inventory decrement at September 30, 2020 is expected to be restored prior to year end.

Asset Retirement Obligations

See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.

Details of changes in AROs for Southern Company, Alabama Power, and Georgia Power during the first nine months of 2020 are shown in the following table. There were no material changes in AROs for the other Registrants during the first nine months of 2020.

	Southern Company		Alabama Power		Georgia Power
	(in millions)
Balance at December 31, 2019	$	9,786	$	3,540	$	5,784
Liabilities incurred	15		—		10
Liabilities settled	(315)		(157)		(130)
Accretion	308		113		177
Cash flow revisions	866		462		411
Balance at September 30, 2020	$	10,660	$	3,958	$	6,252

In June 2020, Alabama Power recorded an increase of approximately $462 million to its AROs related to the CCR Rule and the related state rule primarily due to management's completion of a feasibility study and the related cost estimates during the second quarter 2020 for one of its ash ponds. Alabama Power's increase also reflects costs associated with the addition of a water treatment system to the design of another ash pond. The additional estimated costs to close these ash ponds under the planned closure-in-place methodology primarily relate to inputs from contractor bids, design revisions, and changes in the expected volume of ash handling.

During the third quarter 2020, Georgia Power completed an assessment of its plans to close the ash ponds at all of its generating plants in compliance with the CCR Rule and the related state rule. The related cost estimates were further refined, including updates to long-term post-closure care requirements, market pricing, and timing of future cash outlays. As a result, in September 2020, Georgia Power recorded an increase of approximately $411 million to its AROs related to the CCR Rule and the related state rule.

The traditional electric operating companies expect to continue updating their cost estimates and ARO liabilities periodically as additional information related to ash pond closure methodologies, schedules, and/or costs becomes available, and the changes could be material. Additionally, the closure designs and plans in the States of Alabama and Georgia are subject to approval by environmental regulatory agencies. Absent continued recovery of ARO costs through regulated rates, results of operations, cash flows, and financial condition for Southern Company and the traditional electric operating companies could be materially impacted. See Note (B) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Integrated Resource Plan" for additional information. The ultimate outcome of these matters cannot be determined at this time.

Depreciation and Amortization

See Note 5 to the financial statements under "Depreciation and Amortization – Southern Power" in Item 8 of the Form 10-K for additional information.

Effective January 1, 2020, Southern Power revised the depreciable lives of its natural gas generating facilities from up to 45 years to up to 50 years. This revision resulted in an immaterial decrease in depreciation for the three and nine months ended September 30, 2020 and is expected to result in an immaterial decrease in annual depreciation for 2020.

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REGULATORY MATTERS

9 Months Ended

Sep. 30, 2020

Regulated Operations [Abstract]

REGULATORY MATTERS

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, 2020 and December 31, 2019 were as follows:

Regulatory Clause	Balance Sheet Line Item	September 30, 2020		December 31, 2019
		(in millions)
Alabama Power
Rate CNP Compliance	Other regulatory liabilities, current	$	12	$	55
	Other regulatory liabilities, deferred	38		7
Rate CNP PPA	Deferred under recovered regulatory clause revenues	62		40
Retail Energy Cost Recovery	Other regulatory liabilities, current	107		32
	Other regulatory liabilities, deferred	16		17
Natural Disaster Reserve	Other regulatory liabilities, current	7		37
	Other regulatory liabilities, deferred	51		113
Georgia Power
Fuel Cost Recovery	Over recovered fuel clause revenues	$	84	$	—
	Other deferred credits and liabilities	67		73
Mississippi Power
Fuel Cost Recovery	Over recovered regulatory clause liabilities	$	23	$	23
Ad Valorem Tax	Other regulatory assets	11		47
	Other regulatory assets, deferred	36		—
Property Damage Reserve	Other regulatory liabilities, deferred	48		54
Southern Company Gas
Natural Gas Cost Recovery	Other regulatory liabilities	$	84	$	74

Alabama Power

Petition for Certificate of Convenience and Necessity

On August 14, 2020, the Alabama PSC issued its order regarding Alabama Power's petition for a certificate of convenience and necessity (CCN), which authorized Alabama Power to (i) construct an approximately 720-MW combined cycle facility at Alabama Power's Plant Barry (Plant Barry Unit 8), which is expected to be placed in service by the end of 2023, (ii) complete the Autauga Combined Cycle Acquisition, which occurred on August 31, 2020, (iii) purchase approximately 240 MWs of combined cycle generation under a long-term PPA, which began on September 1, 2020, and (iv) pursue up to approximately 200 MWs of cost-effective demand-side management and distributed energy resource programs.

The Alabama PSC authorized the recovery of actual costs for the construction of Plant Barry Unit 8 up to 5% above the estimated in-service cost of $652 million. In so doing, it recognized the potential for developments that could cause the project costs to exceed the capped amount, in which case Alabama Power would provide documentation to the Alabama PSC to explain and justify potential recovery of the additional costs.

The Alabama PSC further directed that the proposed solar generation of approximately 400 MWs, coupled with battery energy storage systems (solar/battery systems), be evaluated under an existing Renewable Generation

Certificate (RGC) issued by the Alabama PSC in September 2015. The contracts proposed in the CCN petition expired on July 31, 2020. Any future requests for solar/battery systems will be evaluated under the RGC process.

Energy Alabama, Gasp, Inc., and the Sierra Club filed petitions for reconsideration and rehearing with the Alabama PSC. Alabama PSC action on these petitions is expected by November 10, 2020. Upon issuance of a written order reflecting such action, affected parties would have 30 days to pursue an appeal through the State of Alabama court system.

Alabama Power expects to recover all approved costs associated with the CCN through existing rate mechanisms as outlined in Note 2 to the financial statements in Item 8 of the Form 10-K.

The ultimate outcome of these matters cannot be determined at this time.

Rate ECR

On August 7, 2020, the Alabama PSC issued an order authorizing Alabama Power to reduce its over-collected fuel balance by $100 million and return that amount to customers in the form of bill credits for the billing month of October 2020. Any portion of the $100 million undistributed following the bill credit process will remain in the Rate ECR regulatory liability for the benefit of customers.

Rate NDR

In the third quarter 2020, Alabama Power recorded $44 million against the NDR for damages incurred to its transmission and distribution facilities from Hurricane Sally. The NDR balance available for storm damages was $51 million as of September 30, 2020. If the balance falls below $50 million, a reserve establishment charge would be activated (and the ongoing reserve maintenance charge concurrently suspended) until the reserve balance reaches $75 million.

Georgia Power

Rate Plans

2019 ARP

In accordance with the terms of the 2019 ARP, on October 1, 2020, Georgia Power filed the following tariff adjustments to become effective January 1, 2021 pending approval by the Georgia PSC:

•increase traditional base tariffs by approximately $120 million;

•increase the Environmental Compliance Cost Recovery tariff by approximately $2 million;

•decrease Demand-Side Management tariffs by approximately $15 million; and

•increase Municipal Franchise Fee tariffs by approximately $4 million.

The ultimate outcome of this matter cannot be determined at this time.

2013 ARP

In 2019, Georgia Power's retail ROE exceeded 12.00% and, under the modified sharing mechanism pursuant to the 2019 ARP, Georgia Power reduced regulatory assets by approximately $60 million and accrued refunds for retail customers of approximately $60 million. On September 1, 2020, the Georgia PSC authorized Georgia Power to issue customers bill credits prior to final review of the 2019 Annual Surveillance Report by the staff of the Georgia PSC. Georgia Power issued the bill credits in October 2020.

Deferral of Incremental COVID-19 Costs

On April 7, 2020 and June 2, 2020, in response to the COVID-19 pandemic, the Georgia PSC approved orders directing Georgia Power to continue its previous, voluntary suspension of customer disconnections through July 14, 2020 and to defer the resulting incremental bad debt as a regulatory asset. On June 16, 2020 and July 7, 2020, the Georgia PSC approved orders establishing a methodology for identifying incremental bad debt and allowing the

deferral of other incremental costs associated with the COVID-19 pandemic. The period over which such costs will be recovered is expected to be determined in Georgia Power's next base rate case. At September 30, 2020, the incremental costs deferred totaled approximately $38 million. The ultimate outcome of this matter cannot be determined at this time.

Integrated Resource Plan

On March 5, 2020, the Sierra Club filed a petition for judicial review in the Superior Court of Fulton County to appeal the Georgia PSC's decision in the 2019 ARP allowing Georgia Power to recover compliance costs for CCR AROs. Georgia Power intervened in the appeal on June 22, 2020. The ultimate outcome of this matter cannot be determined at this time.

Fuel Cost Recovery

On May 28, 2020, the Georgia PSC approved a stipulation agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors to lower total fuel billings by approximately $740 million over a two-year period effective June 1, 2020. In addition, Georgia Power further lowered fuel billings by approximately $44 million under an interim fuel rider effective June 1, 2020 through September 30, 2020. Georgia Power continues to be allowed to adjust its fuel cost recovery rates under an interim fuel rider prior to its next fuel case if the under or over recovered fuel balance exceeds $200 million. Georgia Power is scheduled to file its next fuel case no later than February 28, 2023.

Nuclear Construction

In 2009, the Georgia PSC certified construction 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 begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement. In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.

In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into several transitional arrangements to allow construction to continue. In July 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into the Vogtle Services Agreement, whereby Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis. The Vogtle Services Agreement provides that it will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.

In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, executed the Bechtel Agreement, a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.

See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for information on the Amended and Restated Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.

Cost and Schedule

Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 by the expected in-service dates of November 2021 and November 2022, respectively, is as follows:

	(in billions)
Base project capital cost forecast(a)(b)	$	8.4
Construction contingency estimate	0.1
Total project capital cost forecast(a)(b)	8.5
Net investment as of September 30, 2020(b)	(6.9)
Remaining estimate to complete(a)	$	1.6

(a)    Excludes financing costs expected to be capitalized through AFUDC of approximately $240 million, of which $71 million had been accrued through September 30, 2020.

(b)    Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds.

Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.0 billion, of which $2.5 billion had been incurred through September 30, 2020.

As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of engineering support, commodity installation, system turnovers and related test results, and workforce statistics.

As of June 30, 2020, assignments of contingency exceeded the remaining balance of the $366 million construction contingency originally established in the second quarter 2018 by approximately $34 million. This contingency was used to address cost risks related to construction productivity, including the April 2020 reduction in workforce designed to mitigate impacts of the COVID-19 pandemic described below; craft labor incentives; adding resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement, among other factors. As a result of these factors, Georgia Power established $115 million of additional construction contingency as of June 30, 2020 for further potential risks including, among other factors, construction productivity and expected impacts of the COVID-19 pandemic; additional resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement.

After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income of $149 million ($111 million after tax) for the increase in the total project capital cost forecast as of June 30, 2020. As and when these amounts are spent, Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery.

During the third quarter 2020, approximately $5 million of the construction contingency established in the second quarter 2020 was assigned to the base capital cost forecast for cost risks primarily associated with construction productivity and field support.

In April 2019, Southern Nuclear established aggressive target values for monthly construction production and system turnover activities as part of a strategy to maintain and, where possible, build margin to the regulatory-approved in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4. Through early 2020, the project faced challenges with the April 2019 aggressive strategy targets including, but not limited to, electrical and pipefitting labor productivity and work package closure rates, which resulted in a backlog of activities and completion percentages below the April 2019 aggressive strategy targets.

In February 2020, Southern Nuclear updated its cost and schedule forecast, which, at that time, did not change the total project capital cost forecast and confirmed the expected in-service dates of November 2021 for Unit 3 and

November 2022 for Unit 4. This update included initiatives to improve productivity while refining and extending system turnover plans and certain near-term milestone dates. Other milestone dates did not change. Achievement of the February 2020 aggressive site work plan relied on meeting increased monthly production and activity target values during 2020.

In mid-March 2020, Southern Nuclear began implementing policies and procedures designed to mitigate the risk of transmission of COVID-19 at the construction site, including worker distancing measures, isolating individuals who have tested positive for COVID-19, are showing symptoms consistent with COVID-19, are being tested for COVID-19, or have been in close contact with such persons, requiring self-quarantine, and adopting additional precautionary measures.

In April 2020, Georgia Power, acting for itself and as agent for the other Vogtle Owners, announced a reduction in workforce at Plant Vogtle Units 3 and 4, which totaled approximately 20% of the then-existing site workforce. This reduction in workforce was a mitigation action intended to address the impact of the COVID-19 pandemic on the Plant Vogtle Units 3 and 4 workforce and construction site, including challenges with labor productivity that were exacerbated by the impact of the COVID-19 pandemic. The April 2020 workforce reduction was intended to provide operational efficiencies by increasing productivity of the remaining workforce and reducing workforce fatigue and absenteeism. Further, it was also intended to allow for increased social distancing by the workforce and facilitate compliance with the recommendations from the Centers for Disease Control and Prevention. The April 2020 workforce reduction did reduce absenteeism, providing an improvement in operational efficiency and allowing for increased social distancing. From the initial peak in April 2020, the number of active cases at the site declined significantly during May and early June, but began increasing again from mid-June through July, and continued to impact productivity levels and pace of activity completion. As a result of these factors, overall production improvements were not achieved at the levels anticipated, contributing to the June 30, 2020 allocation of, and increase in, construction contingency described above. Through mid-July 2020, Unit 3 mechanical, electrical, and subcontract activities continued to build a backlog to Southern Nuclear's February 2020 aggressive site work plan.

To address these issues, in July 2020, Southern Nuclear updated its aggressive site work plan for both Unit 3 and Unit 4. Through October 2020, the project has faced challenges in meeting the July 2020 aggressive site work plan targets including, but not limited to, overall construction and subcontractor labor productivity, which has resulted in a backlog of activities and completion percentages below the July 2020 aggressive site work plan targets. In addition, while the number of active COVID-19 cases at the site has declined since July 2020, the COVID-19 pandemic continues to impact productivity and the pace of activity completion. After considering these factors, Southern Nuclear has further extended milestone dates from the July 2020 aggressive site work plan. Achievement of these extended milestone dates depends on absenteeism rates continuing to normalize and overall construction productivity and production levels, including subcontractors, significantly improving and being sustained above pre-pandemic levels. In addition, appropriate levels of craft laborers, particularly electrical and pipefitter craft labor, need to be added and maintained. Georgia Power still expects to achieve the regulatory-approved in-service dates of November 2021 and November 2022 for Plant Vogtle Units 3 and 4, respectively. Southern Nuclear and Georgia Power continue to believe that pursuit of an aggressive site work plan is an appropriate strategy to achieve completion of the units by their regulatory-approved in-service dates.

As construction, including subcontract work, continues and testing and system turnover activities increase, challenges with management of contractors and vendors; subcontractor performance; supervision of craft labor and related productivity, particularly in the installation of electrical, mechanical, and instrumentation and controls commodities, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, installation, system turnover, and the initial testing and start-up, including any required engineering changes or any remediation related thereto, of plant systems, structures, or components (some of which are based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale), any of which may require additional labor and/or materials; or other issues could arise and change the projected schedule and estimated cost.

In addition, the continuing effects of the COVID-19 pandemic could further disrupt or delay construction, testing, supervisory, and support activities at Plant Vogtle Units 3 and 4. Georgia Power's proportionate share of the estimated incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is currently estimated to be between $70 million and $115 million, which is included in the total project capital cost forecast and assumes (i) absenteeism rates continue to normalize and (ii) the intended productivity efficiencies and production targets assumed in Southern Nuclear's July 2020 aggressive site work plan are realized in the coming months. However, the ultimate impact of the COVID-19 pandemic on the construction schedule and budget for Plant Vogtle Units 3 and 4 cannot be determined at this time.

There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel, may arise, which may result in additional license amendments or require other resolution. As part of the aggressive site work plan, in January 2020, Southern Nuclear notified the NRC of its intent to load fuel in 2020. On June 15, 2020, the NRC rejected Nuclear Watch South's April 20, 2020 petition requesting a hearing and challenging the closure of certain ITAAC. On August 10, 2020, the Atomic Safety and Licensing Board rejected the Blue Ridge Environmental Defense League's (BREDL) May 11, 2020 petition challenging a license amendment request. The staff of the NRC has issued the requested amendment to the combined construction and operating license for Plant Vogtle Unit 3. BREDL appealed the Atomic Safety and Licensing Board decision to the NRC. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.

The ultimate outcome of these matters cannot be determined at this time. However, any extension of the regulatory-approved project schedule is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $10 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.

Joint Owner Contracts

In November 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 to provide for, among other conditions, additional Vogtle Owner approval requirements. Effective in August 2018, the Vogtle Owners further amended the joint ownership agreements to clarify and provide procedures for certain provisions of the joint ownership agreements related to adverse events that require the vote of the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 to continue construction (as amended, and together with the November 2017 amendment, the Vogtle Joint Ownership Agreements). The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.

As a result of an increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs in conjunction with the nineteenth VCM report in 2018, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. In September 2018, the Vogtle Owners unanimously voted to continue construction of Plant Vogtle Units 3 and 4.

Amendments to the Vogtle Joint Ownership Agreements

In connection with the vote to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and MEAG Power's wholly-owned subsidiaries MEAG Power SPVJ, LLC (MEAG SPVJ), MEAG Power SPVM, LLC (MEAG SPVM), and MEAG Power SPVP, LLC (MEAG SPVP) to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners, including additional amendments to the Vogtle Joint Ownership Agreements and the purchase of PTCs from the other Vogtle Owners at pre-established prices, and (ii) a term sheet (MEAG Term Sheet) with MEAG Power and MEAG SPVJ to provide up to $300 million of funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. In January 2019, Georgia Power, MEAG Power, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. In February 2019, Georgia Power, the other Vogtle Owners, and MEAG Power's wholly-owned subsidiaries MEAG SPVJ, MEAG SPVM, and MEAG SPVP entered into certain amendments to the Vogtle Joint Ownership Agreements to implement the provisions of the Vogtle Owner Term Sheet (Global Amendments).

As previously disclosed, pursuant to the Global Amendments: (i) each Vogtle Owner must pay its proportionate share of qualifying construction costs for Plant Vogtle Units 3 and 4 based on its ownership percentage up to the estimated cost at completion (EAC) for Plant Vogtle Units 3 and 4 which formed the basis of Georgia Power's forecast of $8.4 billion in the nineteenth VCM plus $800 million; (ii) Georgia Power will be responsible for 55.7% of actual qualifying construction costs between $800 million and $1.6 billion over the EAC in the nineteenth VCM (resulting in $80 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests; and (iii) Georgia Power will be responsible for 65.7% of qualifying construction costs between $1.6 billion and $2.1 billion over the EAC in the nineteenth VCM (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests. If the EAC is revised and exceeds the EAC in the nineteenth VCM by more than $2.1 billion, each of the other Vogtle Owners will have a one-time option at the time the project budget forecast is so revised to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100% of such Vogtle Owner's remaining share of total construction costs in excess of the EAC in the nineteenth VCM plus $2.1 billion.

In addition, pursuant to the Global Amendments, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including, among other events: (i) the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power's public announcement of its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 or the Georgia PSC determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Vogtle Owners pursuant to the Global Amendments described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Georgia PSC for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates; and (iv) an incremental extension of one year or more over the most recently approved schedule.

The ultimate outcome of these matters cannot be determined at this time.

Regulatory Matters

In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. At September 30, 2020, Georgia Power had recovered approximately $2.5 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 will not record AFUDC related to any capital costs in excess of the total deemed reasonable by the Georgia PSC (currently $7.3 billion) and not requested for rate recovery. On October 1, 2020, Georgia Power filed a request to decrease the NCCR tariff by $142 million annually, effective January 1, 2021, pending Georgia PSC approval.

Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 of each year. In 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.

In 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) Georgia Power's seventeenth VCM report and modified the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.68 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and related customer refunds) was found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap and that prudence decisions on cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective Unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $75 million in 2019 and are estimated to have negative earnings impacts of approximately $145 million, $255 million, and $200 million in 2020, 2021, and 2022, respectively. In its January 11, 2018 order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.

In February 2018, Georgia Interfaith Power & Light, Inc. (GIPL) and Partnership for Southern Equity, Inc. (PSE) filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. In March 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's decision and denial of Georgia Watch's motion for reconsideration. In December 2018, the Fulton County Superior Court granted Georgia Power's motion to dismiss the two appeals. In January 2019, GIPL, PSE, and Georgia Watch filed an appeal of this decision with the Georgia Court of Appeals. In October 2019, the Georgia Court of Appeals issued an opinion affirming the Fulton County Superior Court's ruling that the Georgia PSC's January 11, 2018 order was not a final, appealable decision. In addition, the Georgia Court of Appeals remanded the

case to the Fulton County Superior Court to clarify its ruling as to whether the petitioners showed that review of the Georgia PSC's final order would not provide them an adequate remedy. On April 21, 2020, the Fulton County Superior Court granted Georgia Power's motion to dismiss the two appeals. The petitioners filed a notice of appeal of the dismissal on May 20, 2020, which was withdrawn on August 20, 2020. This matter is now concluded.

The Georgia PSC has approved 22 VCM reports covering the periods through December 31, 2019, including total construction capital costs incurred through that date of $7.4 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds). Georgia Power filed its twenty-third VCM report with the Georgia PSC on August 31, 2020, which reflects the capital cost forecast discussed above and requests approval of $701 million of construction capital costs incurred from January 1, 2020 through June 30, 2020.

The ultimate outcome of these matters cannot be determined at this time.

Mississippi Power

2019 Base Rate Case

On March 17, 2020, the Mississippi PSC approved a settlement agreement between Mississippi Power and the Mississippi Public Utilities Staff related to Mississippi Power's base rate case filed in November 2019 (Mississippi Power Rate Case Settlement Agreement).

Under the terms of the Mississippi Power Rate Case Settlement Agreement, annual retail rates decreased approximately $16.7 million, or 1.85%, effective for the first billing cycle of April 2020, based on a test year period of January 1, 2020 through December 31, 2020, a 53% average equity ratio, an allowed maximum actual equity ratio of 55% by the end of 2020, and a 7.57% return on investment.

Additionally, the approved Mississippi Power Rate Case Settlement Agreement: (i) established common amortization periods of four years for regulatory assets and three years for regulatory liabilities included in the approved revenue requirement, including those related to unprotected deferred income taxes; (ii) established new depreciation rates reflecting an annual increase in depreciation of approximately $10 million; and (iii) excluded certain compensation costs totaling approximately $3.9 million. It also eliminated separate rates for costs associated with Plant Ratcliffe and energy efficiency initiatives and includes such costs in the PEP, ECO Plan, and ad valorem tax adjustment factor, as applicable. In accordance with the previous order of the Mississippi PSC suspending the operation of PEP and the ECO Plan for 2018 through 2020, Mississippi Power plans to resume PEP proceedings and ECO Plan filings for 2021.

Performance Evaluation Plan

On July 24, 2020, the Mississippi PSC approved Mississippi Power's July 14, 2020 filing of its PEP compliance rate clause reflecting revisions agreed to in the Mississippi Power Rate Case Settlement Agreement. These revisions include, among other things, changing the filing date for the annual PEP rate filing from November of the immediately preceding year to March of the current year, utilizing a historic test year adjusted for "known and measurable" changes, using discounted cash flow and regression formulas to determine base return on equity, and moving all embedded ad valorem property taxes currently collected in PEP to the ad valorem tax adjustment clause.

Deferral of Incremental COVID-19 Costs

On April 14, 2020 and May 12, 2020, in order to mitigate the economic impact of the COVID-19 pandemic on customers, the Mississippi PSC approved orders directing Mississippi Power to continue its previous, voluntary suspension of customer disconnections through May 26, 2020 and to defer as a regulatory asset all necessary and reasonable incremental costs or expenses to plan, prepare, stage, or react to protect and keep safe its employees and customers, and to reliably operate its utility system during the COVID-19 pandemic. The period over which such costs will be recovered is expected to be determined in a future PEP filing. At September 30, 2020, the incremental costs deferred totaled approximately $2 million. The ultimate outcome of this matter cannot be determined at this time.

Municipal and Rural Associations Tariff

On June 25, 2020, the FERC accepted Mississippi Power's April 27, 2020 request for an increase in wholesale base revenues under the MRA tariff as agreed upon in a settlement agreement reached with its wholesale customers. The MRA settlement agreement resulted in a $2 million annual increase in base rates effective June 1, 2020.

Southern Company Gas

Rate Proceedings

On June 1, 2020, Virginia Natural Gas filed a general rate case with the Virginia Commission seeking an increase in rates of $49.6 million primarily to recover investments and increased costs associated with infrastructure, technology, and workforce development. The requested increase is based on a projected 12-month test year beginning November 1, 2020, a ROE of 10.35%, and an equity ratio of 54%. Rate adjustments are expected to be effective November 1, 2020, subject to refund. The Virginia Commission is expected to rule on the requested increase in the second quarter 2021.

On July 1, 2020, Atlanta Gas Light filed its 2020 GRAM filing with the Georgia PSC. The filing requests an annual base rate increase of $37.6 million based on the projected 12-month period beginning January 1, 2021, which does not exceed the 5% limitation established by the Georgia PSC in its December 2019 approval of Atlanta Gas Light's general base rate case. Resolution of the 2020 GRAM filing is expected by December 31, 2020, with rates effective January 1, 2021.

The ultimate outcome of these matters cannot be determined at this time.

Deferral of Incremental COVID-19 Costs

Atlanta Gas Light

On April 30, 2020, in response to the COVID-19 pandemic, the Georgia PSC approved orders directing Atlanta Gas Light to continue its previous, voluntary suspension of customer disconnections. On June 22, 2020, the Georgia PSC ordered Atlanta Gas Light to resume customer disconnections beginning July 1, 2020, with exceptions for customers still covered by a shelter-in-place order. The orders provide the Marketers, including SouthStar, with a mechanism to receive credits from Atlanta Gas Light for the base rates it charged to the Marketers of non-paying customers during the suspension. Atlanta Gas Light expects to recover these credits through the annual revenue true-up process within its future GRAM filings, which would impact rates starting on January 1, 2022. The ultimate outcome of this matter cannot be determined at this time.

Nicor Gas

On March 18, 2020, in response to the COVID-19 pandemic, the Illinois Commission issued an order directing utilities to cease disconnections for non-payment and to suspend the imposition of late payment fees or penalties. In response to this order, on March 27, 2020, Nicor Gas and other utilities in Illinois filed their plans seeking cost recovery and providing more flexible credit and collection plans.

On June 18, 2020, the Illinois Commission approved a stipulation pursuant to which the utilities will provide more flexible credit and collection procedures to assist customers with financial hardship and which authorizes a special purpose rider for recovery of the following COVID-19 pandemic-related impacts: incremental costs directly associated with the COVID-19 pandemic, net of the offset for COVID-19 pandemic-related credits received, foregone late fees, foregone reconnection charges, and the costs associated with a bill payment assistance program. Nicor Gas resumed late payment fees on July 27, 2020 and, on October 1, 2020, began recovery of the COVID-19 pandemic-related impacts through the special purpose rider, which will continue over a 24-month period. In response to an Illinois Commission request, Nicor Gas will continue to voluntarily suspend residential customer disconnections for non-payment through March 31, 2021. At September 30, 2020, Nicor Gas' related regulatory asset was $13 million.

Virginia Natural Gas

In response to the COVID-19 pandemic, the Virginia Commission issued orders requiring Virginia Natural Gas to suspend disconnections beginning on March 16, 2020 and also to suspend late payment and reconnection fees beginning on April 9, 2020, both of which expired on October 5, 2020. On April 29, 2020, the Virginia Commission authorized Virginia Natural Gas to defer the following COVID-19 pandemic-related costs as a regulatory asset: incremental uncollectible expense incurred, suspended late fees, suspended reconnection charges, carrying costs, and other incremental prudently incurred costs associated with the COVID-19 pandemic. Specific recovery of the amounts deferred in a regulatory asset will be addressed in a future rate proceeding. At September 30, 2020, Virginia Natural Gas' related regulatory asset was $1 million. The ultimate outcome of this matter cannot be determined at this time.

Infrastructure Replacement Programs and Capital Projects

In December 2019, Virginia Natural Gas filed an application with the Virginia Commission for a 24.1-mile header improvement project to improve resiliency and increase the supply of natural gas delivered to energy suppliers, including Virginia Natural Gas. On June 26, 2020, the Virginia Commission issued an order requiring Virginia Natural Gas to submit additional information by December 31, 2020 related to the financing plans of the project's primary customer before ruling on the December 2019 application. The ultimate outcome of this matter cannot be determined at this time.

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CONTINGENCIES

9 Months Ended

Sep. 30, 2020

Commitments and Contingencies Disclosure [Abstract]

CONTINGENCIES

CONTINGENCIESSee Note 3 to the financial statements in Item 8 of the Form 10-K for information relating to various lawsuits and other contingencies.

General Litigation Matters

The Registrants are involved in various other matters being litigated and regulatory matters. The ultimate outcome of such pending or potential litigation or regulatory matters against each Registrant and any subsidiaries cannot be determined at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such Registrant's financial statements.

The Registrants believe the pending legal challenges discussed below have no merit; however, the ultimate outcome of these matters cannot be determined at this time.

Southern Company

In January 2017, a securities class action complaint was filed in the U.S. District Court for the Northern District of Georgia by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint names as defendants Southern Company, certain of its current and former officers, and certain former Mississippi Power officers and alleges that the defendants made materially false and misleading statements regarding the Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. In 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. Also in 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition. In 2018, the court issued an order dismissing certain claims against certain officers of Southern Company and Mississippi Power and dismissing the allegations related to a number of the statements that plaintiffs challenged as being false or misleading. In 2018, the court denied the defendants' motion for reconsideration and also denied a motion to certify the issue for interlocutory appeal. In the third quarter 2019, the court certified the plaintiffs' proposed class and the defendants filed a petition for interlocutory appeal of the class certification order with the U.S. Court of Appeals for the Eleventh Circuit. In December 2019, the U.S. District Court for the Northern

District of Georgia entered an order staying all deadlines in the case pending mediation. The stay automatically expired on March 31, 2020; however, in light of the COVID-19 pandemic, the U.S. District Court for the Northern District of Georgia vacated all existing discovery deadlines until June 15, 2020. On June 30, 2020, the court entered a revised scheduling order, which resumed discovery and set out remaining case deadlines. On August 15, 2020, the parties reached a settlement. On September 8, 2020, the plaintiffs filed a stipulation of settlement and motion for preliminary approval to resolve the case on a class-wide basis, which the court granted on October 1, 2020. The settlement amount will be paid entirely through existing insurance policies and is not expected to have a material impact on Southern Company's financial statements.

In February 2017, Jean Vineyard and Judy Mesirov each filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its current and former officers, and certain former Mississippi Power officers. In 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. In 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the securities class action. On September 25, 2020, the plaintiffs filed a status report noting the settlement of the securities class action and informing the court that the parties have scheduled mediation of this case later in the fourth quarter 2020.

In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, Georgia that names as defendants Southern Company, certain of its directors, certain of its current and former officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. In 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the securities class action. In August 2019, the court granted a motion filed by the plaintiff in July 2019 to substitute a new named plaintiff, Martin J. Kobuck, in place of Helen E. Piper Survivor's Trust. On September 30, 2020, the plaintiffs filed a status report noting the settlement of the securities class action and informing the court that the parties have scheduled mediation of this case later in the fourth quarter 2020.

Georgia Power

In 2011, plaintiffs filed a putative class action against Georgia Power in the Superior Court of Fulton County, Georgia alleging that Georgia Power's collection in rates of amounts for municipal franchise fees (which fees are paid to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state law claims. This case has been ruled upon and appealed numerous times over the last several years. In one recent appeal, the Georgia Supreme Court remanded the case and noted that the trial court could refer the matter to the Georgia PSC to interpret its tariffs. Following a motion by Georgia Power, in February 2019, the Superior Court of Fulton County ordered the parties to submit petitions to the Georgia PSC for a declaratory ruling and also conditionally certified the proposed class. In March 2019, Georgia Power and the plaintiffs filed petitions with the Georgia PSC seeking confirmation of the proper application of the municipal franchise fee schedule pursuant to the Georgia PSC's orders. Also in March 2019, Georgia Power appealed the class certification decision to the Georgia Court of

Appeals. In October 2019, the Georgia PSC issued an order that found Georgia Power has appropriately implemented the municipal franchise fee schedule. On March 11, 2020, the Georgia Court of Appeals vacated the Superior Court of Fulton County's February 2019 order granting conditional class certification. The Court of Appeals remanded the case to the Superior Court of Fulton County for further proceedings. In September 2020, the plaintiffs and Georgia Power each filed motions for summary judgment on all claims and the plaintiffs renewed their motion for class certification. The amount of any possible losses cannot be calculated at this time because, among other factors, it is unknown whether a class will be certified, the ultimate composition of any class, and whether any losses would be subject to recovery from any municipalities.

On July 29, 2020, a group of individual plaintiffs filed a complaint in the Superior Court of Fulton County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater, surface water, and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages, a medical monitoring fund, and injunctive relief.

Mississippi Power

In May 2018, Southern Company and Mississippi Power received a notice of dispute and arbitration demand filed by Martin Product Sales, LLC (Martin) based on two agreements, both related to Kemper IGCC byproducts for which Mississippi Power provided termination notices in 2017. Martin alleges breach of contract, breach of good faith and fair dealing, fraud and misrepresentation, and civil conspiracy and makes a claim for damages in the amount of approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest. A portion of the claim for damages was on behalf of Martin Transport, Inc. (Martin Transport), an affiliate of Martin. In May 2019, the arbitration panel denied Mississippi Power's and Southern Company's motions to dismiss. In September 2019, Martin Transport filed a separate complaint against Mississippi Power in the Circuit Court of Kemper County, Mississippi alleging claims of fraud, negligent misrepresentation, promissory estoppel, and equitable estoppel, each arising out of the same alleged facts and circumstances that underlie Martin's arbitration demand. Martin Transport seeks compensatory damages of $5 million and punitive damages of $50 million. In November 2019, Martin Transport's claim was combined with the Martin arbitration case and the separate court case was dismissed. In December 2019, Southern Company and Mississippi Power each filed motions for summary judgment on all claims. On February 17, 2020, the arbitration panel granted Southern Company's motion and dismissed Southern Company from the arbitration. On March 12, 2020, the arbitration panel denied Mississippi Power's motions for summary judgment. During the third quarter 2020, the plaintiffs reduced their claim for damages to approximately $76 million. On October 12, 2020, the arbitration panel issued a unanimous award in favor of Mississippi Power on all claims. This matter is now concluded.

In November 2018, Ray C. Turnage and 10 other individual plaintiffs filed a putative class action complaint against Mississippi Power and the three then-serving members of the Mississippi PSC in the U.S. District Court for the Southern District of Mississippi. Mississippi Power received Mississippi PSC approval in 2013 to charge a mirror CWIP rate premised upon including in its rate base pre-construction and construction costs for the Kemper IGCC prior to placing the Kemper IGCC into service. The Mississippi Supreme Court reversed that approval and ordered Mississippi Power to refund the amounts paid by customers under the previously-approved mirror CWIP rate. The plaintiffs allege that the initial approval process, and the amount approved, were improper. They also allege that Mississippi Power underpaid customers by up to $23.5 million in the refund process by applying an incorrect interest rate. The plaintiffs seek to recover, on behalf of themselves and their putative class, actual damages, punitive damages, pre-judgment interest, post-judgment interest, attorney's fees, and costs. In response to Mississippi Power and the Mississippi PSC each filing a motion to dismiss, the plaintiffs filed an amended complaint in March 2019. The amended complaint included four additional plaintiffs and additional claims for gross negligence, reckless conduct, and intentional wrongdoing. Mississippi Power and the Mississippi PSC have each filed a motion to dismiss the amended complaint. On March 27, 2020, the Mississippi PSC's motion to dismiss was granted. Also on March 27, 2020, the plaintiffs filed a motion seeking to name the new members of the Mississippi PSC, the Mississippi Development Authority, and Southern Company as additional defendants and add a cause of action against all defendants based on a dormant commerce clause theory under the U.S. Constitution. On April 9, 2020 and April 10, 2020, Mississippi Power and the Mississippi PSC, respectively, filed responses opposing the

motion for leave to file a second amended complaint. On May 26, 2020, the court granted Mississippi Power's motion to dismiss the first amended complaint filed in 2019. On July 6, 2020, the plaintiffs filed a motion for revision of the court's decision. The plaintiffs' motion for leave to file a second amended complaint also remains pending before the court. On July 28, 2020, the plaintiffs filed a motion for leave to file a third amended complaint, which includes the same federal claims as the proposed second amended complaint, as well as several additional state law claims based on the allegation that Mississippi Power failed to disclose the annual percentage rate of interest applicable to refunds. An adverse outcome in this proceeding could have a material impact on Mississippi Power's financial statements.

See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility" in Item 8 of the Form 10-K for additional information.

Environmental Remediation

The Southern Company system must comply with environmental laws and regulations governing the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companies and the natural gas distribution utilities in Illinois and Georgia have each received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies.

Georgia Power's environmental remediation liability was $15 million at both September 30, 2020 and December 31, 2019. Georgia Power has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected.

In December 2019, Mississippi Power entered into an agreement with the Mississippi Commission on Environmental Quality related to groundwater conditions arising from the closed ash pond at Plant Watson. Mississippi Power will complete an assessment and remediation consistent with the requirements of the agreement and the CCR Rule. Potential remediation activities and related cost estimates are pending the result of further site assessment and cannot be determined at this time. Mississippi Power expects to recover the retail portion of remedial costs through the ECO Plan and the wholesale portion through MRA rates.

Southern Company Gas' environmental remediation liability was $252 million and $269 million as of September 30, 2020 and December 31, 2019, respectively, based on the estimated cost of environmental investigation and remediation associated with known current and former manufactured gas plant operating sites. These environmental remediation expenditures are generally recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies of the natural gas distribution utilities.

The ultimate outcome of these matters cannot be determined at this time; however, as a result of the regulatory treatment for environmental remediation expenses described above, the final disposition of these matters is not expected to have a material impact on the financial statements of the applicable Registrants.

Nuclear Fuel Disposal Costs

On August 13, 2020, Alabama Power and Georgia Power filed amended complaints in each of the lawsuits against the U.S. government in the Court of Federal Claims for the costs of continuing to store spent nuclear fuel at Plants Farley, Hatch, and Vogtle Units 1 and 2. The amended complaints add damages from January 1, 2018 to December 31, 2019 to the claim period. Damages will continue to accumulate until the issue is resolved, the U.S. government disposes of Alabama Power's and Georgia Power's spent nuclear fuel pursuant to its contractual obligations, or alternative storage is otherwise provided. No amounts have been recognized in the financial statements as of September 30, 2020 for any potential recoveries from the pending lawsuits. The final outcome of these matters cannot be determined at this time. However, Alabama Power and Georgia Power expect to credit any recoveries for

the benefit of customers in accordance with direction from their respective PSC; therefore, no material impact on Southern Company's, Alabama Power's, or Georgia Power's net income is expected.

Other Matters

Southern Company

See Notes 1 and 3 under "Leveraged Leases" and "Other Matters – Southern Company," respectively, in Item 8 of the Form 10-K for discussion of challenges associated with a leveraged lease agreement with a subsidiary of Southern Holdings. While all required lease payments through September 30, 2020 have been paid in full, the operational and remarketing risks and the resulting cash liquidity challenges persist and significant concerns continue regarding the lessee's ability to make the remaining required semi-annual lease payments to the Southern Holdings subsidiary through the term of the lease.

In its annual impairment analysis of the expected residual value of the generation assets and the overall collectability of the related lease receivable, Southern Company uses multiple scenarios of long-term market energy prices to estimate the cash flows expected to be received from remarketing the generation assets following the expiration of the existing PPA in 2032 and the residual value of the generation assets at the end of the lease in 2047. Southern Company received the latest annual forecasts of natural gas prices during the second quarter 2020 and considered the significant decline in forecasted prices to be an indicator of potential impairment that required an interim impairment assessment. Accordingly, consistent with prior years, Southern Company evaluated the recoverability of the lease receivable and the expected residual value of the generation assets under various natural gas price scenarios. Based on the current forecasts of energy prices in the years following the expiration of the existing PPA, Southern Company concluded that it is no longer probable that any of the associated rental payments will be received, because it is no longer probable the generation assets will be successfully remarketed and continue to operate after that date. During the second quarter 2020, Southern Company revised the estimated cash flows to be received under the leveraged lease to reflect this conclusion, which resulted in a full impairment of the lease investment and a pre-tax charge to earnings of $154 million ($74 million after tax).

If any future lease payment due prior to the expiration of the associated PPA is not paid in full, the Southern Holdings subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. Failure to make the required payment to the debtholders could represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the generation assets, in effect terminating the lease. As the remaining amount of the lease investment was charged against earnings in the second quarter 2020, termination would not be expected to result in additional charges. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments and meet its obligations associated with a future closure or retirement of the generation assets and associated properties, including the dry ash landfill.

Mississippi Power

Kemper County Energy Facility

See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility" in Item 8 of the Form 10-K for additional information.

As the mining permit holder, Liberty Fuels Company, LLC has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities related to the lignite mine and equipment and mineral reserves located around the Kemper County energy facility site. As a result of the abandonment of the Kemper IGCC, final mine reclamation began in 2018 and is expected to be substantially completed in 2020, with monitoring expected to continue through 2027. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.

For year-to-date 2020, Mississippi Power recorded pre-tax (and after-tax) charges to income totaling $2 million primarily associated with abandonment and related closure costs and ongoing period costs, net of salvage proceeds,

for the mine and gasifier-related assets at the Kemper County energy facility. Dismantlement of the abandoned gasifier-related assets and site restoration activities are expected to be completed in 2025. The additional pre-tax period costs associated with dismantlement and site restoration activities, including related costs for compliance and safety, ARO accretion, and property taxes, net of salvage, are estimated to total $3 million for the remainder of 2020 and $10 million to $15 million annually for 2021 through 2025.

In December 2019, Mississippi Power transferred ownership of the CO2 pipeline to an unrelated gas pipeline company, with no resulting impact on income. In conjunction with the transfer of the CO2 pipeline, the parties agreed to enter into a 15-year firm transportation agreement, which is expected to be signed by the end of 2020, providing for the conversion by the pipeline company of the CO2 pipeline to a natural gas pipeline to be used for the delivery of natural gas to Plant Ratcliffe. The agreement is expected to be treated as a finance lease for accounting purposes upon commencement.

On September 3, 2020, Mississippi Power and Southern Company executed an agreement with the DOE completing Mississippi Power's request for property closeout certification under the contract related to the DOE grants received for the Kemper County energy facility, which enables Mississippi Power to proceed with full dismantlement of the abandoned gasifier-related assets and site restoration activities. The execution of the agreement had no material impact on Mississippi Power's financial statements. In connection with the DOE closeout discussions, in April 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power of an investigation related to the $387 million of DOE grants received. The ultimate outcome of this matter cannot be determined at this time; however, it could have a material impact on Southern Company's and Mississippi Power's financial statements.

Plant Daniel

In conjunction with Southern Company's sale of Gulf Power, Mississippi Power and Gulf Power agreed to seek a restructuring of their 50% undivided ownership interests in Plant Daniel such that each of them would, after the restructuring, own 100% of a generating unit. On April 24, 2020, Mississippi Power and Gulf Power amended the terms of the agreement to extend the deadline from May 1, 2020 to August 1, 2020 for Mississippi Power to notify Gulf Power of which generating unit it has selected for 100% ownership. The parties agreed not to select a specific unit by August 1, 2020 and are continuing negotiations on a mutually acceptable revised operating agreement. The impacts of operating the units on an individual basis continue to be evaluated by Mississippi Power and any transfer of ownership would be subject to approval by the FERC and the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time.

Southern Company Gas

See Notes 3 and 7 to the financial statements in Item 8 of the Form 10-K under "Other Matters – Southern Company Gas" and "Southern Company Gas," respectively, and Note (E) under "Southern Company Gas" for additional information.

On March 24, 2020, Southern Company Gas completed the sale of its interest in Atlantic Coast Pipeline. See Note (K) under "Southern Company Gas" for additional information.

On February 20, 2020, the FERC approved a two-year extension for PennEast Pipeline to complete the project by January 19, 2022.

In September 2019, an appellate court ruled that the PennEast Pipeline does not have federal eminent domain authority over lands in which a state has property rights interests. On June 29, 2020, the U.S. Supreme Court requested the U.S. Solicitor General to provide an opinion on PennEast Pipeline's petition for a writ of certiorari seeking its review of the appellate court's decision.

Expected project costs related to the PennEast Pipeline for Southern Company Gas total approximately $300 million, excluding financing costs. The ultimate outcome of the PennEast Pipeline construction project cannot be determined at this time; however, any work delays, whether caused by judicial or regulatory action, abnormal weather, or other conditions, may result in additional cost or schedule modifications or, ultimately, in project

cancellation, any of which could result in impairment of Southern Company Gas' investment and could have a significant impact on Southern Company's financial statements and a material impact on Southern Company Gas' financial statements.

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REVENUE FROM CONTRACTS WITH CUSTOMERS AND LEASE INCOME

9 Months Ended

Sep. 30, 2020

Revenue from Contract with Customer [Abstract]

REVENUE FROM CONTRACTS WITH CUSTOMERS AND LEASE INCOME

REVENUE FROM CONTRACTS WITH CUSTOMERS AND LEASE INCOME

Revenue from Contracts with Customers

The Registrants generate revenues from a variety of sources, some of which are not accounted for as revenue from contracts with customers, such as leases, derivatives, and certain cost recovery mechanisms. See Note 1 to the financial statements under "Revenues" in Item 8 of the Form 10-K for additional information on the revenue policies of the Registrants. See "Lease Income" herein and Note (J) for additional information on revenue accounted for under lease and derivative accounting guidance, respectively.

The following table disaggregates revenue from contracts with customers for the three and nine months ended September 30, 2020 and 2019:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended September 30, 2020
Operating revenues
Retail electric revenues
Residential	$	2,019	$	752	$	1,183	$	84	$	—	$	—
Commercial	1,354		447		833		74		—		—
Industrial	783		358		352		73		—		—
Other	22		5		15		2		—		—
Total retail electric revenues	4,178		1,562		2,383		233		—		—
Natural gas distribution revenues
Residential	170		—		—		—		—		170
Commercial	41		—		—		—		—		41
Transportation	224		—		—		—		—		224
Industrial	4		—		—		—		—		4
Other	35		—		—		—		—		35
Total natural gas distribution revenues	474		—		—		—		—		474
Wholesale electric revenues
PPA energy revenues	214		40		13		2		165		—
PPA capacity revenues	136		26		15		1		95		—
Non-PPA revenues	59		10		3		93		68		—
Total wholesale electric revenues	409		76		31		96		328		—
Other natural gas revenues
Wholesale gas services	431		—		—		—		—		431
Gas marketing services	38		—		—		—		—		38
Other natural gas revenues	7		—		—		—		—		7
Total natural gas revenues	476		—		—		—		—		476
Other revenues	218		33		115		6		4		—
Total revenue from contracts with customers	5,755		1,671		2,529		335		332		950
Other revenue sources(a)	968		58		88		1		191		630
Other adjustments(b)	(1,103)		—		—		—		—		(1,103)
Total operating revenues	$	5,620	$	1,729	$	2,617	$	336	$	523	$	477

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Nine Months Ended September 30, 2020
Operating revenues
Retail electric revenues
Residential	$	4,802	$	1,839	$	2,760	$	203	$	—	$	—
Commercial	3,589		1,152		2,242		195		—		—
Industrial	2,081		956		907		218		—		—
Other	68		16		46		6		—		—
Total retail electric revenues	10,540		3,963		5,955		622		—		—
Natural gas distribution revenues
Residential	906		—		—		—		—		906
Commercial	229		—		—		—		—		229
Transportation	723		—		—		—		—		723
Industrial	21		—		—		—		—		21
Other	179		—		—		—		—		179
Total natural gas distribution revenues	2,058		—		—		—		—		2,058
Wholesale electric revenues
PPA energy revenues	550		94		38		7		425		—
PPA capacity revenues	339		78		30		3		231		—
Non-PPA revenues	159		33		7		235		184		—
Total wholesale electric revenues	1,048		205		75		245		840		—
Other natural gas revenues
Wholesale gas services	1,168		—		—		—		—		1,168
Gas marketing services	258		—		—		—		—		258
Other natural gas revenues	22		—		—		—		—		22
Total natural gas revenues	1,448		—		—		—		—		1,448
Other revenues	677		117		329		19		11		—
Total revenue from contracts with customers	15,771		4,285		6,359		886		851		3,506
Other revenue sources(a)	2,604		160		12		9		486		1,973
Other adjustments(b)	(3,117)		—		—		—		—		(3,117)
Total operating revenues	$	15,258	$	4,445	$	6,371	$	895	$	1,337	$	2,362

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended September 30, 2019
Operating revenues
Retail electric revenues
Residential	$	2,119	$	820	$	1,211	$	88	$	—	$	—
Commercial	1,563		512		965		86		—		—
Industrial	953		421		450		82		—		—
Other	26		7		16		3		—		—
Total retail electric revenues	4,661		1,760		2,642		259		—		—
Natural gas distribution revenues
Residential	162		—		—		—		—		162
Commercial	42		—		—		—		—		42
Transportation	204		—		—		—		—		204
Industrial	3		—		—		—		—		3
Other	30		—		—		—		—		30
Total natural gas distribution revenues	441		—		—		—		—		441
Wholesale electric revenues
PPA energy revenues	245		43		19		2		188		—
PPA capacity revenues	134		25		13		1		100		—
Non-PPA revenues	62		2		3		111		81		—
Total wholesale electric revenues	441		70		35		114		369		—
Other natural gas revenues
Wholesale gas services	425		—		—		—		—		425
Gas marketing services	37		—		—		—		—		37
Other natural gas revenues	10		—		—		—		—		10
Total natural gas revenues	472		—		—		—		—		472
Other revenues	267		36		113		4		3		—
Total revenue from contracts with customers	6,282		1,866		2,790		377		372		913
Other revenue sources(a)	855		(25)		(35)		(7)		202		727
Other adjustments(b)	(1,142)		—		—		—		—		(1,142)
Total operating revenues	$	5,995	$	1,841	$	2,755	$	370	$	574	$	498

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Nine Months Ended September 30, 2019
Operating revenues
Retail electric revenues
Residential	$	4,939	$	1,971	$	2,751	$	217	$	—	$	—
Commercial	3,951		1,301		2,427		223		—		—
Industrial	2,428		1,128		1,074		226		—		—
Other	69		20		41		8		—		—
Total retail electric revenues	11,387		4,420		6,293		674		—		—
Natural gas distribution revenues
Residential	992		—		—		—		—		992
Commercial	277		—		—		—		—		277
Transportation	673		—		—		—		—		673
Industrial	25		—		—		—		—		25
Other	191		—		—		—		—		191
Total natural gas distribution revenues	2,158		—		—		—		—		2,158
Wholesale electric revenues
PPA energy revenues	648		110		47		8		508		—
PPA capacity revenues	350		77		41		2		272		—
Non-PPA revenues	174		65		5		275		190		—
Total wholesale electric revenues	1,172		252		93		285		970		—
Other natural gas revenues
Wholesale gas services	1,590		—		—		—		—		1,590
Gas marketing services	313		—		—		—		—		313
Other natural gas revenues	32		—		—		—		—		32
Total natural gas revenues	1,935		—		—		—		—		1,935
Other revenues	763		119		298		14		10		—
Total revenue from contracts with customers	17,415		4,791		6,684		973		980		4,093
Other revenue sources(a)	3,266		(29)		22		(3)		547		2,744
Other adjustments(b)	(4,176)		—		—		—		—		(4,176)
Total operating revenues	$	16,505	$	4,762	$	6,706	$	970	$	1,527	$	2,661

(a)Other revenue sources primarily relate to revenues from customers accounted for as derivatives and leases, as well as alternative revenue programs at Southern Company Gas and other cost recovery mechanisms at the traditional electric operating companies.

(b)Other adjustments relate to the cost of Southern Company Gas' energy and risk management activities. Wholesale gas services revenues are presented net of the related costs of those activities on the statement of income. See Note (L) under "Southern Company Gas" for additional information on the components of wholesale gas services' operating revenues.

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, 2020 and December 31, 2019:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Accounts Receivables
As of September 30, 2020	$	2,344	$	686	$	901	$	93	$	100	$	385
As of December 31, 2019	2,413		586		688		79		97		749
Contract Assets
As of September 30, 2020	$	159	$	5	$	103	$	—	$	—	$	—
As of December 31, 2019	117		—		69		—		—		—
Contract Liabilities
As of September 30, 2020	$	56	$	1	$	24	$	—	$	3	$	1
As of December 31, 2019	52		10		13		—		1		1

As of September 30, 2020 and December 31, 2019, Georgia Power had contract assets primarily related to fixed retail customer bill programs, where the payment is contingent upon Georgia Power's continued performance and the customer's continued participation in the program over a one-year contract term, 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 certain unregulated service agreements. Alabama Power had contract liabilities for outstanding performance obligations primarily related to extended service agreements. Southern Company's unregulated distributed generation business had $47 million and $40 million of contract assets and $22 million and $28 million of contract liabilities at September 30, 2020 and December 31, 2019, respectively, for outstanding performance obligations.

Revenues recognized by Southern Company in the three and nine months ended September 30, 2020, which were included in contract liabilities at December 31, 2019, were $8 million and $29 million, respectively, and immaterial for all other applicable Registrants.

Remaining Performance Obligations

The traditional electric operating companies and Southern Power have long-term contracts with customers in which revenues are recognized as performance obligations are satisfied over the contract term. These contracts primarily relate to PPAs whereby the traditional electric operating companies and Southern Power provide electricity and generation capacity to a customer. The revenue recognized for the delivery of electricity is variable; however, certain PPAs include a fixed payment for fixed generation capacity over the term of the contract. Southern Company's unregulated distributed generation business also has partially satisfied performance obligations related to certain fixed price contracts. Revenue from contracts with customers related to these performance obligations remaining at September 30, 2020 are expected to be recognized as follows:

	2020 (remaining)		2021		2022		2023		2024		2025 and Thereafter
	(in millions)
Southern Company	$	170	$	487	$	362	$	339	$	319	$	3,062
Alabama Power	7		33		31		24		7		5
Georgia Power	20		71		43		35		24		62
Southern Power	60		290		292		282		290		3,013

Revenue expected to be recognized for performance obligations remaining at September 30, 2020 was immaterial for Mississippi Power.

Lease Income

Lease income for the three and nine months ended September 30, 2020 and 2019 is as follows:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
For the Three Months Ended September 30, 2020
Lease income - interest income on sales-type leases	$	3	$	—	$	—	$	3	$	—	$	—
Lease income - operating leases	50		11		14		—		21		9
Variable lease income	145		—		—		—		153		—
Total lease income	$	198	$	11	$	14	$	3	$	174	$	9
For the Nine Months Ended September 30, 2020
Lease income - interest income on sales-type leases	$	8	$	—	$	—	$	8	$	—	$	—
Lease income - operating leases	148		24		44		1		66		26
Variable lease income	345		—		—		—		368		—
Total lease income	$	501	$	24	$	44	$	9	$	434	$	26
For the Three Months Ended September 30, 2019
Lease income - interest income on sales-type leases	$	2	$	—	$	—	$	2	$	—	$	—
Lease income - operating leases	64		5		18		—		31		9
Variable lease income	141		—		—		—		151		—
Total lease income	$	207	$	5	$	18	$	2	$	182	$	9
For the Nine Months Ended September 30, 2019
Lease income - interest income on sales-type leases	$	7	$	—	$	—	$	7	$	—	$	—
Lease income - operating leases	216		19		57		—		111		26
Variable lease income	324		—		—		—		349		—
Total lease income	$	547	$	19	$	57	$	7	$	460	$	26

Lease income for Southern Power is included in wholesale revenues. Lease payments received under tolling arrangements and PPAs consist of either scheduled payments or variable payments based on the amount of energy produced by the underlying electric generating units.

As part of the Autauga Combined Cycle Acquisition, Alabama Power assumed an existing power sales agreement under which the full output of the generating facility remains committed to another third party for its remaining term of approximately three years. These revenues are included above as lease income from operating leases. See Note (B) and Note 15 to the financial statements in Item 8 of the Form 10-K under "Alabama Power" for additional information.

Lease Receivables

Mississippi Power completed construction of additional leased assets under an existing sales-type lease during the third quarter 2020. Upon completion of construction, the book value of $25 million was transferred from CWIP to lease receivables, of which $22 million and $3 million is included in other property and investments and other accounts and notes receivable, respectively, at September 30, 2020. The transfer represents a non-cash investing transaction for purposes of the statements of cash flows.

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CONSOLIDATED ENTITIES AND EQUITY METHOD INVESTMENTS

9 Months Ended

Sep. 30, 2020

Regulated Operations [Abstract]

CONSOLIDATED ENTITIES AND EQUITY METHOD INVESTMENTS

CONSOLIDATED ENTITIES AND EQUITY METHOD INVESTMENTSSee Note 7 to the financial statements in Item 8 of the Form 10-K for additional information.

Southern Power

Variable Interest Entities

Southern Power has certain subsidiaries that are determined to be VIEs. Southern Power is considered the 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.

SP Solar and SP Wind

At September 30, 2020 and December 31, 2019, SP Solar had total assets of $6.3 billion and $6.4 billion, respectively, and total liabilities of $382 million. Noncontrolling interests totaled $1.1 billion at both September 30, 2020 and December 31, 2019. Cash distributions from SP Solar are allocated 67% to Southern Power and 33% to Global Atlantic in accordance with their partnership interest percentage. Under the terms of the limited partnership agreement, distributions without limited partner consent are limited to available cash and SP Solar is obligated to 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, 2020 and December 31, 2019, SP Wind had total assets of $2.4 billion and $2.5 billion, respectively, total liabilities of $129 million and $128 million, respectively, and noncontrolling interests of $44 million and $45 million, respectively. Under the terms of the limited liability agreement, distributions without Class A member consent are limited to 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, 2020 and December 31, 2019, the other VIEs had total assets of $1.1 billion, total liabilities of $109 million and $104 million, respectively, and noncontrolling interests of $471 million and $409 million, 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, 2020 and December 31, 2019, Southern Power had equity method investments in wind and battery storage projects totaling $19 million and $28 million, respectively.

Southern Company Gas

Equity Method Investments

On March 24, 2020, Southern Company Gas completed the sale of its interests in Pivotal LNG and Atlantic Coast Pipeline. See Note (K) under "Southern Company Gas" for additional information.

The carrying amounts of Southern Company Gas' equity method investments as of September 30, 2020 and December 31, 2019 and related income from those investments for the three and nine months ended September 30, 2020 and 2019 were as follows:

Investment Balance	September 30, 2020		December 31, 2019(a)
	(in millions)
SNG(b)	$	1,180	$	1,137
PennEast Pipeline(c)	89		82
Other	32		32
Total	$	1,301	$	1,251

(a)Excludes investments in Atlantic Coast Pipeline and Pivotal JAX LNG classified as held for sale at December 31, 2019. See Note 15 to the financial statements under "Assets Held for Sale" in Item 8 of the Form 10-K for additional information.

(b)Increase primarily relates to a capital contribution, partially offset by the continued amortization of deferred tax assets established upon acquisition.

(c)See Note (C) under "Other Matters – Southern Company Gas" for additional information on the PennEast Pipeline.

Earnings from Equity Method Investments	Three Months Ended September 30, 2020		Three Months Ended September 30, 2019		Nine Months Ended September 30, 2020		Nine Months Ended September 30, 2019
	(in millions)
SNG	$	30	$	30	$	95	$	104
Atlantic Coast Pipeline(a)(b)	—		3		3		9
PennEast Pipeline(a)	2		2		5		5
Other	1		—		3		(3)
Total	$	33	$	35	$	106	$	115

(a)Amounts primarily result from AFUDC equity recorded by the project entity.

(b)On March 24, 2020, Southern Company Gas completed the sale of its interest in Atlantic Coast Pipeline. See Note (K) under "Southern Company Gas" for additional information.

SNG

Selected financial information of SNG for the three and nine months ended September 30, 2020 and 2019 is as follows:

Income Statement Information	Three Months Ended September 30, 2020		Three Months Ended September 30, 2019		Nine Months Ended September 30, 2020		Nine Months Ended September 30, 2019
	(in millions)
Revenues	$	150	$	152	$	457	$	473
Operating income	85		82		262		274
Net income	59		60		189		208

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FINANCING

9 Months Ended

Sep. 30, 2020

Debt Disclosure [Abstract]

FINANCING

FINANCING

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, 2020, committed credit arrangements with banks were as follows:

	Expires
Company	2021		2022		2023		2024		Total		Unused		Due within One Year
	(in millions)
Southern Company parent	$	—	$	—	$	—	$	2,000	$	2,000	$	1,999	$	—
Alabama Power	3		525		—		800		1,328		1,328		3
Georgia Power	—		—		—		1,750		1,750		1,728		—
Mississippi Power	—		150		125		—		275		250		—
Southern Power(a)	—		—		—		600		600		591		—
Southern Company Gas(b)	—		—		—		1,750		1,750		1,745		—
SEGCO	30		—		—		—		30		30		30
Southern Company	$	33	$	675	$	125	$	6,900	$	7,733	$	7,671	$	33

(a)Does not include Southern Power Company's $120 million and $60 million continuing letter of credit facilities for standby letters of credit expiring in 2021 and 2023, respectively, of which $23 million and $40 million, respectively, was unused at September 30, 2020. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities.

(b)Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.25 billion of this arrangement. Southern Company Gas' committed credit arrangement also includes $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. Pursuant to this multi-year credit arrangement, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted.

As reflected in the table above, in March 2020, Mississippi Power entered into a $125 million revolving credit facility that matures in March 2023.

Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.

These bank credit arrangements, as well as the term loan arrangements of the Registrants and SEGCO, contain covenants that limit debt levels and contain cross-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 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 the applicable borrower defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2020, 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 borrowings.

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, 2020 was approximately $1.4 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia Power, and $34 million at Mississippi Power). In addition, at September 30, 2020, Georgia Power had approximately $257 million of fixed rate revenue bonds outstanding that are required to be remarketed within the next 12 months.

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 equity units issued in August 2019. 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 the Form 10-K for information on the August 2019 equity units issuance and Note 12 to the financial statements in Item 8 of the Form 10-K for information on stock-based compensation plans. Shares used to compute diluted earnings per share were as follows:

	Three Months Ended September 30, 2020	Three Months Ended September 30, 2019	Nine Months Ended September 30, 2020	Nine Months Ended September 30, 2019
	(in millions)
As reported shares	1,058	1,048	1,058	1,043
Effect of stock-based compensation	6	9	6	8
Diluted shares	1,064	1,057	1,064	1,051

An immaterial number of stock-based compensation awards was not included in the diluted earnings per share calculation because the awards were anti-dilutive for the three and nine months ended September 30, 2020. There were no such amounts for the three and nine months ended September 30, 2019.

An immaterial number of shares related to the equity units issued in August 2019 was included in the calculation of diluted earnings per share for the nine months ended September 30, 2020. There were no such amounts for all other periods presented.

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INCOME TAXES

9 Months Ended

Sep. 30, 2020

Income Tax Disclosure [Abstract]

INCOME TAXES

INCOME TAXES

See Note 10 to the financial statements in Item 8 of the Form 10-K for additional tax information.

Current and Deferred Income Taxes

Tax Credit and Net Operating Loss Carryforwards

Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) totaling $1.5 billion as of September 30, 2020 compared to $1.8 billion as of December 31, 2019.

The federal ITC and PTC carryforwards begin expiring in 2034 and 2032, respectively, but are expected to be fully utilized by 2024. The utilization of each Registrants' estimated tax credit and net operating loss carryforwards and related valuation allowances could be impacted by numerous factors, including the acquisition of additional renewable projects, the purchase of rights to additional PTCs of Plant Vogtle Units 3 and 4 pursuant to certain joint ownership agreements, potential impacts of the COVID-19 pandemic, and changes in taxable income projections. See Note (B) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information on Plant Vogtle Units 3 and 4.

Effective Tax Rate

Details of significant changes in the effective tax rate for the applicable Registrants are provided herein.

Southern Company

Southern Company's effective tax rate is typically lower than the statutory rate due to employee stock plans' dividend deduction, non-taxable AFUDC equity at the traditional electric operating companies, flowback of excess deferred income taxes at the regulated utilities, and federal income tax benefits from ITCs and PTCs primarily at Southern Power.

Southern Company's effective tax rate was 13.9% for the nine months ended September 30, 2020 compared to 30.2% for the corresponding period in 2019. The effective tax rate decrease was primarily due to the tax impact from the sale of Gulf Power in 2019, as well as an increase in the flowback of excess deferred income taxes in 2020 primarily at Georgia Power. See Note 15 to the financial statements under "Southern Company" in Item 8 of the Form 10-K for additional information.

Georgia Power

Georgia Power's effective tax rate was 12.3% for the nine months ended September 30, 2020 compared to 22.6% for the corresponding period in 2019. The effective tax rate decrease was primarily due to an increase in the flowback of excess deferred income taxes in 2020 as authorized in the 2019 ARP, as well as the second quarter 2020 charge to earnings associated with the construction of Plant Vogtle Units 3 and 4. See Note (B) under "Georgia Power – Nuclear Construction" and Note 2 to the financial statements under "Georgia Power" in Item 8 of the Form 10-K for additional information.

Mississippi Power

Mississippi Power's effective tax rate was 12.7% for the nine months ended September 30, 2020 compared to 16.3% for the corresponding period in 2019. The effective tax rate decrease was primarily due to an increase in the flowback of excess deferred income taxes in 2020 as authorized in the Mississippi Power Rate Case Settlement Agreement. See Note (B) under "Mississippi Power – 2019 Base Rate Case" for additional information.

Southern Power

Southern Power's effective tax rate was 11.3% for the nine months ended September 30, 2020 compared to a benefit rate of (13.6)% for the corresponding period in 2019. The effective tax rate increase was primarily due to tax benefits resulting from ITCs recognized upon the sale of Plant Nacogdoches in 2019. See Note (K) under "Southern Power" for additional information.

Southern Company Gas

Southern Company Gas' effective tax rate was 21.4% for the nine months ended September 30, 2020 compared to 15.0% for the corresponding period in 2019. The effective tax rate increase was primarily due to higher flowback of excess deferred income taxes in 2019, primarily at Atlanta Gas Light as previously authorized by the Georgia PSC, and the reversal of a federal tax valuation allowance in connection with Southern Company Gas' sale of its investment in Triton in 2019. See Notes 2 and 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.

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RETIREMENT BENEFITS

9 Months Ended

Sep. 30, 2020

Retirement Benefits [Abstract]

RETIREMENT BENEFITS

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, 2020. The Southern Company system also provides certain non-qualified defined benefits for a select group of management and highly compensated employees, which are funded on a cash basis. In addition, the Southern Company system provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric operating companies fund other postretirement trusts to the extent required by their respective regulatory commissions. Southern Company Gas has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses.

See Note 11 to the financial statements in Item 8 of the Form 10-K for additional information.

Effective January 1, 2020, Southern Company adopted a change in method of calculating the market-related value of the liability-hedging securities included in its pension plan assets. The market-related value is used to determine the expected return on plan assets component of net periodic pension cost. Southern Company previously used the

calculated value approach for all plan assets, which smoothed asset returns and deferred gains and losses by amortizing them into the calculation of the market-related value over five years. Southern Company changed to the fair value approach for liability-hedging securities, which includes measuring the market-related value of that portion of the plan assets at fair value for purposes of determining the expected return on plan assets. The remaining asset classes of plan assets will continue to use the calculated value approach in determining the market-related value. Southern Company considers the fair value approach to be preferable because it results in a current reflection of changes in the value of plan assets in the measurement of net periodic pension cost. Southern Company evaluated the effect of this change in accounting method and deemed it immaterial to the historical and current financial statements of all Registrants and therefore did not account for the change retrospectively. The change in accounting principle was recorded through earnings as a prior period adjustment for the amounts related to the unregulated businesses of Southern Company and Southern Power. Amounts related to the traditional electric operating companies and the natural gas distribution utilities have been reflected as adjustments to regulatory assets as appropriate, consistent with the expected regulatory treatment.

On each Registrant's condensed statements of income, the service cost component of net periodic benefit costs is included in other operations and maintenance expenses and all other components of net periodic benefit costs are included in other income (expense), net. Components of the net periodic benefit costs for the three and nine months ended September 30, 2020 and 2019 are presented in the following tables.

Three Months Ended September 30, 2020	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	94	$	23	$	24	$	3	$	2	$	8
Interest cost	108		25		33		5		1		8
Expected return on plan assets	(274)		(66)		(87)		(13)		(4)		(20)
Amortization:
Prior service costs	—		1		—		—		—		(1)
Regulatory asset	—		—		—		—		—		4
Net (gain)/loss	67		17		22		4		1		2
Net periodic pension cost (income)	$	(5)	$	—	$	(8)	$	(1)	$	—	$	1
Postretirement Benefits
Service cost	$	6	$	1	$	2	$	(1)	$	1	$	—
Interest cost	13		4		5		1		—		2
Expected return on plan assets	(18)		(7)		(7)		—		—		(2)
Amortization:
Prior service costs	—		—		(1)		—		—		—
Regulatory asset	—		—		—		—		—		2
Net (gain)/loss	1		—		1		—		—		(1)
Net periodic postretirement benefit cost	$	2	$	(2)	$	—	$	—	$	1	$	1

Nine Months Ended September 30, 2020	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	282	$	67	$	72	$	11	$	6	$	24
Interest cost	324		75		100		15		4		23
Expected return on plan assets	(824)		(198)		(261)		(38)		(10)		(59)
Amortization:
Prior service costs	1		1		1		—		—		(2)
Regulatory asset	—		—		—		—		—		12
Net (gain)/loss	201		53		65		10		2		7
Net periodic pension cost (income)	$	(16)	$	(2)	$	(23)	$	(2)	$	2	$	5
Postretirement Benefits
Service cost	$	17	$	4	$	5	$	—	$	1	$	1
Interest cost	40		10		15		2		—		5
Expected return on plan assets	(54)		(21)		(20)		(1)		—		(5)
Amortization:
Prior service costs	(1)		—		(1)		—		—		—
Regulatory asset	—		—		—		—		—		5
Net (gain)/loss	2		—		2		—		—		(2)
Net periodic postretirement benefit cost	$	4	$	(7)	$	1	$	1	$	1	$	4

Three Months Ended September 30, 2019	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	73	$	17	$	19	$	3	$	2	$	7
Interest cost	123		28		38		6		1		9
Expected return on plan assets	(222)		(51)		(73)		(10)		(2)		(15)
Amortization:
Prior service costs	1		—		—		—		—		(1)
Regulatory asset	—		—		—		—		—		3
Net (gain)/loss	30		9		11		1		—		1
Net periodic pension cost (income)	$	5	$	3	$	(5)	$	—	$	1	$	4
Postretirement Benefits
Service cost	$	5	$	1	$	2	$	1	$	—	$	—
Interest cost	18		4		6		—		—		2
Expected return on plan assets	(16)		(6)		(7)		—		—		(1)
Amortization:
Prior service costs	—		1		—		—		—		—
Regulatory asset	—		—		—		—		—		1
Net (gain)/loss	(1)		—		1		—		—		—
Net periodic postretirement benefit cost	$	6	$	—	$	2	$	1	$	—	$	2

Nine Months Ended September 30, 2019	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	219	$	51	$	56	$	9	$	5	$	19
Interest cost	369		85		116		17		4		27
Expected return on plan assets	(664)		(154)		(219)		(30)		(7)		(45)
Amortization:
Prior service costs	2		1		1		—		—		(2)
Regulatory asset	—		—		—		—		—		10
Net (gain)/loss	90		27		33		4		—		2
Net periodic pension cost (income)	$	16	$	10	$	(13)	$	—	$	2	$	11
Postretirement Benefits
Service cost	$	14	$	3	$	4	$	1	$	—	$	1
Interest cost	52		12		19		2		—		7
Expected return on plan assets	(49)		(19)		(19)		(1)		—		(4)
Amortization:
Prior service costs	2		3		—		—		—		—
Regulatory asset	—		—		—		—		—		4
Net (gain)/loss	(2)		—		1		—		—		(2)
Net periodic postretirement benefit cost	$	17	$	(1)	$	5	$	2	$	—	$	6

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FAIR VALUE MEASUREMENTS

9 Months Ended

Sep. 30, 2020

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

As of September 30, 2020, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:

	Fair Value Measurements Using:
As of September 30, 2020:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Southern Company
Assets:
Energy-related derivatives(a)	$	488	$	218	$	117	$	—	$	823
Interest rate derivatives	—		20		—		—		20
Foreign currency derivatives	—		29		—		—		29
Investments in trusts:(b)(c)
Domestic equity	754		137		—		—		891
Foreign equity	71		220		—		—		291
U.S. Treasury and government agency securities	—		268		—		—		268
Municipal bonds	—		99		—		—		99
Pooled funds – fixed income	—		17		—		—		17
Corporate bonds	15		376		—		—		391
Mortgage and asset backed securities	—		79		—		—		79
Private equity	—		—		—		68		68
Cash and cash equivalents	1		—		—		—		1
Other	25		6		—		—		31
Cash equivalents	2,750		11		—		—		2,761
Other investments	9		19		—		—		28
Total	$	4,113	$	1,499	$	117	$	68	$	5,797
Liabilities:
Energy-related derivatives(a)	$	521	$	155	$	75	$	—	$	751
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		19		—		19
Total	$	521	$	178	$	94	$	—	$	793

	Fair Value Measurements Using:
As of September 30, 2020:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Alabama Power
Assets:
Energy-related derivatives	$	—	$	23	$	—	$	—	$	23
Nuclear decommissioning trusts:(b)
Domestic equity	477		128		—		—		605
Foreign equity	71		64		—		—		135
U.S. Treasury and government agency securities	—		21		—		—		21
Municipal bonds	—		1		—		—		1
Corporate bonds	15		159		—		—		174
Mortgage and asset backed securities	—		27		—		—		27
Private equity	—		—		—		68		68
Other	6		—		—		—		6
Cash equivalents	825		11		—		—		836
Other investments	—		19		—		—		19
Total	$	1,394	$	453	$	—	$	68	$	1,915
Liabilities:
Energy-related derivatives	$	—	$	6	$	—	$	—	$	6
Georgia Power
Assets:
Energy-related derivatives	$	—	$	31	$	—	$	—	$	31
Nuclear decommissioning trusts:(b)(c)
Domestic equity	277		1		—		—		278
Foreign equity	—		153		—		—		153
U.S. Treasury and government agency securities	—		247		—		—		247
Municipal bonds	—		98		—		—		98
Corporate bonds	—		217		—		—		217
Mortgage and asset backed securities	—		52		—		—		52
Other	19		6		—		—		25
Cash equivalents	485		—		—		—		485
Total	$	781	$	805	$	—	$	—	$	1,586
Liabilities:
Energy-related derivatives	$	—	$	9	$	—	$	—	$	9

	Fair Value Measurements Using:
As of September 30, 2020:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	18	$	—	$	—	$	18
Cash equivalents	36		—		—		—		36
Total	$	36	$	18	$	—	$	—	$	54
Liabilities:
Energy-related derivatives	$	—	$	7	$	—	$	—	$	7
Southern Power
Assets:
Energy-related derivatives	$	—	$	5	$	—	$	—	$	5
Foreign currency derivatives	—		29		—		—		29
Cash equivalents	149		—		—		—		149
Total	$	149	$	34	$	—	$	—	$	183
Liabilities:
Energy-related derivatives	$	—	$	1	$	—	$	—	$	1
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		19		—		19
Total	$	—	$	24	$	19	$	—	$	43
Southern Company Gas
Assets:
Energy-related derivatives(a)	$	488	$	141	$	117	$	—	$	746
Non-qualified deferred compensation trusts:
Domestic equity	—		8		—		—		8
Foreign equity	—		3		—		—		3
Pooled funds – fixed income	—		17		—		—		17
Cash equivalents	1		—		—		—		1
Cash equivalents and restricted cash	113		—		—		—		113
Total	$	602	$	169	$	117	$	—	$	888
Liabilities:
Energy-related derivatives(a)	$	521	$	132	$	75	$	—	$	728

(a)Energy-related derivatives exclude cash collateral of $70 million.

(b)Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.

(c)Includes investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of September 30, 2020, approximately $25 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan to creditors under the funds' managers' securities lending program. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.

Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. The fair value of the funds, including reinvested interest 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, 2020 and 2019. The changes were recorded as a change to the regulatory assets and liabilities related to AROs for Georgia Power and Alabama Power, respectively.

Fair value increases (decreases)	Three Months Ended September 30, 2020		Three Months Ended September 30, 2019		Nine Months Ended September 30, 2020		Nine Months Ended September 30, 2019
	(in millions)
Southern Company	$	108	$	27	$	85	$	255
Alabama Power	66		15		24		140
Georgia Power	42		12		61		115

Valuation Methodologies

The energy-related derivatives primarily consist of exchange-traded and over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The fair value of cross-currency swaps reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and discount rates. The interest rate derivatives and cross-currency swaps are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note (J) for additional information on how these derivatives are used.

For fair value measurements of the investments within the nuclear decommissioning trusts and the non-qualified deferred compensation trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgments, are also obtained when available.

The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. See Note 6 to the financial statements under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

Southern Power has contingent payment obligations related to certain acquisitions whereby Southern Power is primarily obligated to make generation-based payments to the seller, which commenced at the commercial operation of the respective facility and continue through 2026. The obligation is categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate.

The fair value of contingent consideration reflects the net present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial.

"Other investments" include investments traded in the open market that have maturities greater than 90 days, which are categorized as Level 2 under Fair Value Measurements and are comprised of corporate bonds, bank certificates of deposit, treasury bonds, and/or agency bonds.

As of September 30, 2020, the fair value measurements of private equity investments held in Alabama Power's nuclear decommissioning trusts that are calculated at net asset value per share (or its equivalent) as a practical expedient totaled $68 million and unfunded commitments related to the private equity investments totaled $67 million. Private equity investments include high-quality private equity funds across several market sectors and funds that invest in real estate assets. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated.

As of September 30, 2020, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas(*)
	(in millions)
Long-term debt, including securities due within one year:
Carrying amount	$	49,743	$	9,113	$	12,700	$	1,402	$	4,155	$	6,461
Fair value	56,739		10,741		15,052		1,562		4,535		7,640

(*)The long-term debt of Southern Company Gas is recorded at amortized cost, including the fair value adjustments at the effective date of the 2016 merger with Southern Company. Southern Company Gas amortizes the fair value adjustments over the lives of the respective bonds.

The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to the Registrants.

Commodity Contracts with Level 3 Valuation Inputs

As of September 30, 2020, the fair value of Southern Company Gas' Level 3 physical natural gas forward contracts was $42 million. Since commodity contracts classified as Level 3 typically include a combination of observable and unobservable components, the changes in fair value may include amounts due in part to observable market factors, or changes to assumptions on the unobservable components. The following table includes transfers to Level 3, which represent the fair value of Southern Company Gas' commodity derivative contracts that include a significant unobservable component for the first time during the period.

	Three Months Ended September 30, 2020		Nine Months Ended September 30, 2020
	(in millions)
Beginning balance	$	80	$	14
Transfers to Level 3	—		70
Transfers from Level 3	(2)		(5)
Instruments realized or otherwise settled during period	(9)		(16)
Changes in fair value	(27)		(21)
Ending balance	$	42	$	42

Changes in fair value of Level 3 instruments represent changes in gains and losses for the periods that are reported on Southern Company Gas' statements of income in natural gas revenues.

The valuation of certain commodity contracts requires the use of certain unobservable inputs. All forward pricing used in the valuation of such contracts is directly based on third-party market data, such as broker quotes and exchange settlements, when that data is available. If third-party market data is not available, then industry standard methodologies are used to develop inputs that maximize the use of relevant observable inputs and minimize the use of unobservable inputs. Observable inputs, including some forward prices used for determining fair value, reflect the best available market information. Unobservable inputs are updated using industry standard techniques such as extrapolation, combining observable forward inputs supplemented by historical market and other relevant data. Level 3 physical natural gas forward contracts include unobservable forward price inputs (ranging from $(1.11) to $0.24 per mmBtu). Forward price increases (decreases) as of September 30, 2020 would have resulted in higher (lower) values on a net basis.

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DERIVATIVES

9 Months Ended

Sep. 30, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVES

DERIVATIVES

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Southern Company Gas' wholesale gas operations use various contracts in its commercial activities that generally meet the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note (I) for additional fair value information. In the statements of cash flows, any cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Any cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with classification of the hedged interest or principal, respectively. See Note 1 to the financial statements under "Financial Instruments" in Item 8 of the Form 10-K for additional information.

Energy-Related Derivatives

The traditional electric operating companies, Southern Power, and Southern Company Gas enter into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies and the natural gas distribution utilities have limited exposure to market volatility in energy-related commodity prices. Each of the traditional electric operating companies and certain of the natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs, implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies, through the use of financial derivative contracts, which are expected to continue to mitigate price volatility. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in energy-related commodity prices because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted capacity is used to sell electricity. Southern Company Gas retains exposure to price changes that can, in a volatile energy market, be material and can adversely affect its results of operations.

Southern Company Gas also enters into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in operating revenues.

Energy-related derivative contracts are accounted for under one of three methods:

•Regulatory Hedges — Energy-related derivative contracts designated as regulatory hedges relate primarily to the traditional electric operating companies' and the natural gas distribution utilities' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses.

•Cash Flow Hedges — Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in accumulated OCI before being recognized in the statements of income in the same period and in the same income statement line item as the earnings effect of the hedged transactions.

•Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric and natural gas industries. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.

At September 30, 2020, the net volume of energy-related derivative contracts for natural gas positions, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows:

	Net Purchased mmBtu	Longest Hedge Date	Longest Non-Hedge Date
	(in millions)
Southern Company(*)	877	2024	2031
Alabama Power	78	2024	—
Georgia Power	131	2023	—
Mississippi Power	86	2024	—
Southern Power	14	2022	2021
Southern Company Gas(*)	568	2023	2031

(*)Southern Company Gas' derivative instruments include both long and short natural gas positions. A long position is a contract to purchase natural gas and a short position is a contract to sell natural gas. Southern Company Gas' volume represents the net of long natural gas positions of 4.6 billion mmBtu and short natural gas positions of 4.1 billion mmBtu as of September 30, 2020, which is also included in Southern Company's total volume.

At September 30, 2020, the net volume of Southern Power's energy-related derivative contracts for power to be sold was 1 million MWHs, all of which expire in 2021.

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 12 million mmBtu for Southern Company, which includes 3 million mmBtu for Alabama Power, 4 million mmBtu for Georgia Power, 1 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, 2021 are immaterial for all Registrants.

Interest Rate Derivatives

Southern Company and certain subsidiaries may enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and presented on the same income statement line item as the earnings effect of the hedged transactions. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

At September 30, 2020, the following interest rate derivatives were outstanding:

	Notional Amount		Interest Rate Received	Weighted Average Interest Rate Paid	Hedge Maturity Date	Fair Value Gain (Loss) at September 30, 2020
	(in millions)					(in millions)
Cash Flow Hedges of Existing Debt
Mississippi Power	$	60	1-month LIBOR	0.58%	December 2021	$	—
Fair Value Hedges of Existing Debt
Southern Company parent	1,500		2.35%	1-month LIBOR + 0.87%	July 2021	20
Southern Company	$	1,560				$	20

For cash flow hedge 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, 2021 total $(25) million for Southern Company and are immaterial for all other Registrants. Deferred gains and losses related to interest rate derivatives are expected to be amortized into earnings through 2046 for the Southern Company parent entity, 2035 for Alabama Power, 2044 for Georgia Power, 2028 for Mississippi Power, and 2046 for Southern Company Gas.

Foreign Currency Derivatives

Southern Company and certain subsidiaries, including Southern Power, may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and on the same income statement line as the earnings effect of the hedged transactions, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

At September 30, 2020, the following foreign currency derivatives were outstanding:

	Pay Notional		Pay Rate	Receive Notional		Receive Rate	Hedge Maturity Date	Fair Value Gain (Loss) at September 30, 2020
	(in millions)			(in millions)				(in millions)
Cash Flow Hedges of Existing Debt
Southern Power	$	677	2.95%	€	600	1.00%	June 2022	$	11
Southern Power	564		3.78%	500		1.85%	June 2026	(5)
Total	$	1,241		€	1,100			$	6

The estimated pre-tax gains (losses) related to Southern Power's foreign currency derivatives expected to be reclassified from accumulated OCI to earnings for the 12-month period ending September 30, 2021 are $(14) million.

Derivative Financial Statement Presentation and Amounts

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas enter into derivative contracts that may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Southern Company and certain subsidiaries also utilize master netting agreements to mitigate exposure to counterparty credit risk. These agreements may contain provisions that permit netting across product lines and against cash collateral. The fair value amounts of derivative assets and liabilities on the balance sheet are presented net to the extent that there are netting arrangements or similar agreements with the counterparties.

The fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:

	As of September 30, 2020				As of December 31, 2019
Derivative Category and Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
	(in millions)				(in millions)
Southern Company
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	52	$	13	$	3	$	70
Other deferred charges and assets/Other deferred credits and liabilities	30		15		6		44
Total derivatives designated as hedging instruments for regulatory purposes	$	82	$	28	$	9	$	114
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	8	$	3	$	1	$	6
Other deferred charges and assets/Other deferred credits and liabilities	2		—		—		—
Interest rate derivatives:
Other current assets/Other current liabilities	19		—		2		23
Other deferred charges and assets/Other deferred credits and liabilities	—		—		—		1
Foreign currency derivatives:
Other current assets/Other current liabilities	—		23		—		24
Other deferred charges and assets/Other deferred credits and liabilities	29		—		16		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	58	$	26	$	19	$	54
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	392	$	428	$	461	$	358
Other deferred charges and assets/Other deferred credits and liabilities	338		291		207		225
Total derivatives not designated as hedging instruments	$	730	$	719	$	668	$	583
Gross amounts recognized	$	870	$	773	$	696	$	751
Gross amounts offset(a)	(636)		(706)		(463)		(562)
Net amounts recognized in the Balance Sheets(b)	$	234	$	67	$	233	$	189

	As of September 30, 2020				As of December 31, 2019
Derivative Category and Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
	(in millions)				(in millions)
Alabama Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	14	$	2	$	2	$	14
Other deferred charges and assets/Other deferred credits and liabilities	9		4		2		10
Total derivatives designated as hedging instruments for regulatory purposes	$	23	$	6	$	4	$	24
Gross amounts recognized	$	23	$	6	$	4	$	24
Gross amounts offset	(5)		(5)		(2)		(2)
Net amounts recognized in the Balance Sheets	$	18	$	1	$	2	$	22
Georgia Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	18	$	3	$	1	$	32
Other deferred charges and assets/Other deferred credits and liabilities	13		6		3		21
Total derivatives designated as hedging instruments for regulatory purposes	$	31	$	9	$	4	$	53
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	—	$	—	$	—	$	17
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	—	$	—	$	—	$	17
Gross amounts recognized	$	31	$	9	$	4	$	70
Gross amounts offset	(9)		(9)		(3)		(3)
Net amounts recognized in the Balance Sheets	$	22	$	—	$	1	$	67

	As of September 30, 2020				As of December 31, 2019
Derivative Category and Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
	(in millions)				(in millions)
Mississippi Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	10	$	2	$	—	$	15
Other deferred charges and assets/Other deferred credits and liabilities	8		5		1		12
Total derivatives designated as hedging instruments for regulatory purposes	$	18	$	7	$	1	$	27
Gross amounts recognized	$	18	$	7	$	1	$	27
Gross amounts offset	(7)		(7)		(1)		(1)
Net amounts recognized in the Balance Sheets	$	11	$	—	$	—	$	26
Southern Power
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	4	$	1	$	1	$	2
Other deferred charges and assets/Other deferred credits and liabilities	1		—		—		—
Foreign currency derivatives:
Other current assets/Other current liabilities	—		23		—		24
Other deferred charges and assets/Other deferred credits and liabilities	29		—		16		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	34	$	24	$	17	$	26
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	—	$	—	$	2	$	1
Total derivatives not designated as hedging instruments	$	—	$	—	$	2	$	1
Gross amounts recognized	$	34	$	24	$	19	$	27
Gross amounts offset	(1)		(1)		—		—
Net amounts recognized in the Balance Sheets	$	33	$	23	$	19	$	27

	As of September 30, 2020				As of December 31, 2019
Derivative Category and Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
	(in millions)				(in millions)
Southern Company Gas
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	10	$	6	$	—	$	9
Other deferred charges and assets/Other deferred credits and liabilities	—		—		—		1
Total derivatives designated as hedging instruments for regulatory purposes	$	10	$	6	$	—	$	10
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	4	$	2	$	—	$	4
Other deferred charges and assets/Other deferred credits and liabilities	1		—		—		—
Interest rate derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	—		—		2		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	5	$	2	$	2	$	4
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	392	$	428	$	459	$	357
Other deferred charges and assets/Other deferred credits and liabilities	338		291		207		225
Total derivatives not designated as hedging instruments	$	730	$	719	$	666	$	582
Gross amounts of recognized	$	745	$	727	$	668	$	596
Gross amounts offset(a)	(614)		(684)		(456)		(555)
Net amounts recognized in the Balance Sheets(b)	$	131	$	43	$	212	$	41

(a)Gross amounts offset include cash collateral held on deposit in broker margin accounts of $70 million and $99 million as of September 30, 2020 and December 31, 2019, respectively.

(b)Net amounts of derivative instruments outstanding exclude premium and intrinsic value associated with weather derivatives of $3 million and $4 million as of September 30, 2020 and December 31, 2019, respectively.

The traditional electric operating companies had no energy-related derivatives not designated as hedging instruments at September 30, 2020 and immaterial amounts at December 31, 2019.

At September 30, 2020 and December 31, 2019, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Company Gas
	(in millions)
At September 30, 2020:
Energy-related derivatives:
Other regulatory assets, current	$	(5)	$	—	$	—	$	—	$	(5)
Other regulatory liabilities, current	41		12		15		8		6
Other regulatory liabilities, deferred	15		5		7		3		—
Total energy-related derivative gains (losses)	$	51	$	17	$	22	$	11	$	1
At December 31, 2019:
Energy-related derivatives:
Other regulatory assets, current	$	(63)	$	(14)	$	(31)	$	(15)	$	(3)
Other regulatory assets, deferred	(37)		(8)		(18)		(11)		—
Other regulatory liabilities, current	6		2		—		—		4
Total energy-related derivative gains (losses)	$	(94)	$	(20)	$	(49)	$	(26)	$	1

For the three and nine months ended September 30, 2020 and 2019, the pre-tax effects of cash flow hedge accounting on accumulated OCI were as follows:

Gain (Loss) Recognized in OCI on Derivative	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)				(in millions)
Southern Company
Energy-related derivatives	$	9	$	(5)	$	2	$	(11)
Interest rate derivatives	1		(52)		(27)		(88)
Foreign currency derivatives	54		(68)		(10)		(107)
Total	$	64	$	(125)	$	(35)	$	(206)
Georgia Power
Interest rate derivatives	$	—	$	(47)	$	(3)	$	(83)
Southern Power
Energy-related derivatives	$	5	$	(3)	$	2	$	(5)
Foreign currency derivatives	54		(68)		(10)		(107)
Total	$	59	$	(71)	$	(8)	$	(112)
Southern Company Gas
Energy-related derivatives	$	4	$	(2)	$	—	$	(6)
Interest rate derivatives	1		(5)		(24)		(5)
Total	$	5	$	(7)	$	(24)	$	(11)

For the three and nine months ended September 30, 2020 and 2019, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on accumulated OCI were immaterial for the other Registrants.

For the three and nine months ended September 30, 2020 and 2019, the pre-tax effects of cash flow and fair value hedge accounting on income were as follows:

Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)				(in millions)
Southern Company
Total cost of natural gas	$	71	$	79	$	654	$	956
Gain (loss) on energy-related cash flow hedges(a)	—		—		(8)		—
Total depreciation and amortization	889		760		2,619		2,267
Gain (loss) on energy-related cash flow hedges(a)	(1)		(1)		(3)		(5)
Total interest expense, net of amounts capitalized	(443)		(434)		(1,343)		(1,294)
Gain (loss) on interest rate cash flow hedges(a)	(6)		(5)		(19)		(14)
Gain (loss) on foreign currency cash flow hedges(a)	(6)		(6)		(18)		(18)
Gain (loss) on interest rate fair value hedges(b)	(3)		10		27		43
Total other income (expense), net	113		61		319		239
Gain (loss) on foreign currency cash flow hedges(a)(c)	56		(54)		52		(62)
Southern Power
Total depreciation and amortization	$	129	$	120	$	367	$	357
Gain (loss) on energy-related cash flow hedges(a)	(1)		(1)		(3)		(5)
Total interest expense, net of amounts capitalized	(36)		(43)		(114)		(127)
Gain (loss) on foreign currency cash flow hedges(a)	(6)		(6)		(18)		(18)
Total other income (expense), net	13		6		19		48
Gain (loss) on foreign currency cash flow hedges(a)(c)	56		(54)		52		(62)

(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, 2020 and 2019, the pre-tax effects of cash flow and fair value hedge accounting on income for energy-related derivatives and interest rate derivatives were immaterial for the traditional electric operating companies and Southern Company Gas.

As of September 30, 2020 and December 31, 2019, the following amounts were recorded on the balance sheets related to cumulative basis adjustments for fair value hedges:

	Carrying Amount of the Hedged Item				Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item
Balance Sheet Location of Hedged Items	As of September 30, 2020		As of December 31, 2019		As of September 30, 2020		As of December 31, 2019
	(in millions)				(in millions)
Southern Company
Securities due within one year	$	(1,513)	$	(599)	$	(15)	$	—
Long-term debt	—		(1,494)		—		3

For the three and nine months ended September 30, 2020 and 2019, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income of Southern Company and Southern Company Gas were as follows:

		Gain (Loss)
		Three Months Ended September 30,				Nine Months Ended September 30,
Derivatives in Non-Designated Hedging Relationships	Statements of Income Location	2020		2019		2020		2019
		(in millions)				(in millions)
Energy-related derivatives:	Natural gas revenues(*)	$	(30)	$	(2)	$	54	$	81
	Cost of natural gas	5		2		18		5
Total derivatives in non-designated hedging relationships		$	(25)	$	—	$	72	$	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, 2020 and 2019, the pre-tax effects of energy-related derivatives not designated as hedging instruments were immaterial for all other Registrants.

Contingent Features

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At September 30, 2020, the Registrants had no collateral posted with derivative counterparties to satisfy these arrangements.

For the Registrants with interest rate derivatives at September 30, 2020, the fair value of interest rate derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, was immaterial. At September 30, 2020, the fair value of energy-related derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were immaterial for all Registrants. The maximum potential collateral requirements arising from the credit-risk-related contingent features for the traditional electric operating companies and Southern Power include certain agreements that could require collateral in the event that one or more Southern Company power pool participants has a credit rating change to below investment grade. Following the sale of Gulf Power to NextEra Energy, Gulf Power is continuing to participate in the Southern Company power pool for a defined transition period that, subject to certain potential adjustments, is scheduled to end on January 1, 2024.

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.

Alabama Power and Southern Power maintain accounts with certain regional transmission organizations to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Alabama Power and Southern Power may be required to post collateral. At September 30, 2020, cash collateral posted in these accounts was immaterial. Southern Company Gas maintains accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Southern Company Gas may be required to deposit cash into these accounts. At September 30, 2020, cash collateral held on deposit in broker margin accounts was $70 million.

The Registrants are exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Registrants only enter into agreements and material transactions with counterparties that have

investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Registrants have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate their exposure to counterparty credit risk. Prior to entering into a physical transaction, Southern Company Gas assigns physical wholesale counterparties an internal credit rating 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.

In addition, Southern Company Gas conducts credit evaluations and obtains appropriate internal approvals for the counterparty's line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody's and BBB- from S&P. Generally, Southern Company Gas requires credit enhancements by way of a guaranty, cash deposit, or letter of credit for transaction counterparties that do not have investment grade ratings.

Southern Company Gas also utilizes master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When Southern Company Gas is engaged in more than one outstanding derivative transaction with the same counterparty and it also has a legally enforceable netting agreement with that counterparty, the "net" mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of Southern Company Gas' credit risk. Southern Company Gas also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Master netting agreements enable Southern Company Gas to net certain assets and liabilities by counterparty. Southern Company Gas also nets across product lines and against cash collateral provided the master netting and cash collateral agreements include such provisions. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.

The Registrants do not anticipate a material adverse effect on their respective financial statements as a result of counterparty nonperformance.

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ACQUISITIONS AND DISPOSITIONS

9 Months Ended

Sep. 30, 2020

Business Combinations [Abstract]

ACQUISITIONS AND DISPOSITIONS

ACQUISITIONS AND DISPOSITIONSSee Note 15 to the financial statements in Item 8 of the Form 10-K for additional information, including details of assets and liabilities held for sale at December 31, 2019 for Southern Company, Southern Power, and Southern Company Gas. The Registrants had no material assets or liabilities held for sale at September 30, 2020.

Southern Power

Asset Acquisitions

During the nine months ended September 30, 2020, Southern Power acquired a controlling interest in the wind facility listed below. Acquisition-related costs were expensed as incurred and were not material.

Project Facility	Resource	Seller	Approximate Nameplate Capacity (MW)	Location	Southern Power Ownership Percentage		COD	PPA Contract Period
Beech Ridge II	Wind	Invenergy Renewables LLC	56	Greenbrier County, West Virginia	100% of Class A	(*)	May 2020	12 years

(*)In May 2020, Southern Power purchased 100% of the Class A membership interests and now owns the controlling interest in the project, with the Class B member, Invenergy Renewables LLC, owning the noncontrolling interest.

In March 2020, Southern Power entered into an agreement to acquire a controlling membership interest in an approximately 300-MW wind facility located in South Dakota. The acquisition is subject to FERC approval and certain other customary conditions to closing, including commercial operation of the facility, which is expected to occur in the first quarter 2021. The facility's output is contracted under two long-term PPAs. The ultimate outcome of this matter cannot be determined at this time.

Construction Projects

During the nine months ended September 30, 2020, Southern Power completed construction of and placed in service the Reading wind facility, continued construction of the Skookumchuck wind facility, and commenced construction of the Garland and Tranquillity battery energy storage facilities. Total aggregate construction costs, excluding acquisition costs, are expected to be between $475 million and $545 million for the facilities under construction. At September 30, 2020, total costs of construction incurred for these projects were $244 million and are included in CWIP. The ultimate outcome of these matters cannot be determined at this time.

Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Actual/Expected COD	PPA Contract Period
Projects Completed During the Nine Months Ended September 30, 2020
Reading(a)	Wind	200	Osage and Lyon Counties, KS	May 2020	12 years
Projects Under Construction as of September 30, 2020
Skookumchuck(b)	Wind	136	Lewis and Thurston Counties, WA	November 2020	20 years
Garland Solar Storage(c)	Battery energy storage system	88	Kern County, CA	Second quarter 2021	20 years
Tranquillity Solar Storage(c)	Battery energy storage system	72	Fresno County, CA	Second quarter 2021	20 years

(a)In 2018, Southern Power purchased 100% of the membership interests of the Reading facility pursuant to a joint development arrangement. At the time the facility was placed in service, Southern Power recorded an operating lease right-of-use asset and an operating lease liability, each in the amount of $24 million. In June 2020, Southern Power completed a tax equity transaction whereby it received $156 million and now owns 100% of the Class B membership interests.

(b)In October 2019, Southern Power purchased 100% of the membership interests of the Skookumchuck facility pursuant to a joint development arrangement. Southern Power expects to complete a tax equity transaction upon commercial operation and retain the Class B membership interests. Shortly after the completed tax equity transaction, Southern Power may sell a noncontrolling interest in these Class B membership interests to another partner. Southern Power would retain the controlling ownership interest in the facility. The ultimate outcome of these matters cannot be determined at this time.

(c)Prior to commercial operation, Southern Power may enter into one or more partnerships, in which case it would ultimately own less than 100% of the Class B membership interests, but would retain ownership of the controlling interest. The ultimate outcome of this matter cannot be determined at this time.

Development Projects

Southern Power continues to evaluate and refine the deployment of the remaining wind turbine equipment purchased in 2016 and 2017 to development and construction projects. During the nine months ended September 30, 2020, certain wind turbine equipment was sold, resulting in an immaterial gain.

Sales of Natural Gas and Biomass Plants

On January 17, 2020, Southern Power completed the sale of its equity interests in Plant Mankato (including the 385-MW expansion unit completed in May 2019) to a subsidiary of Xcel for a purchase price of approximately $663 million, including final working capital adjustments. The sale resulted in a gain of approximately $39 million ($23 million after tax). The assets and liabilities of Plant Mankato were classified as held for sale on Southern Company's and Southern Power's balance sheets at December 31, 2019.

Plants Nacogdoches (sold in June 2019) and Mankato represented individually significant components of Southern Power; therefore, pre-tax income for these components for the three months ended September 30, 2019 and the nine months ended September 30, 2020 and 2019 is presented below:

	Three Months Ended September 30, 2019		Nine Months Ended September 30,
			2020		2019
	(in millions)
Southern Power's earnings before income taxes:(*)
Plant Nacogdoches	$	—	N/A		$	16
Plant Mankato	$	12	$	2	$	20

(*)Earnings before income taxes for components reflect the cessation of depreciation and amortization on the long-lived assets being sold upon classification as held for sale in November 2018 and April 2019 for Plant Mankato and Plant Nacogdoches, respectively.

Southern Company Gas

On March 24, 2020, Southern Company Gas completed the sale of its interests in Pivotal LNG and Atlantic Coast Pipeline to Dominion Modular LNG Holdings, Inc. and Dominion Atlantic Coast Pipeline, LLC, respectively, with aggregate proceeds of $178 million, including working capital adjustments. The loss associated with the transactions was immaterial. Southern Company Gas also expects to receive payments in February 2021 and September 2021 of $5 million each contingent upon Dominion Modular LNG Holdings, Inc. meeting certain milestones related to Pivotal LNG. The assets and liabilities of Pivotal LNG and the interest in Atlantic Coast Pipeline were classified as held for sale at December 31, 2019. See Notes 3 and 7 under "Other Matters – Southern Company Gas – Gas Pipeline Projects" and "Southern Company Gas – Equity Method Investments," respectively, in Item 8 of the Form 10-K and Notes (C) and (E) under "Other Matters – Southern Company Gas" and "Southern Company Gas," respectively.

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SEGMENT AND RELATED INFORMATION

9 Months Ended

Sep. 30, 2020

Segment Reporting [Abstract]

SEGMENT AND RELATED INFORMATION

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 – Alabama Power, Georgia Power, and Mississippi Power – 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 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, wholesale gas services, and gas marketing services.

Southern Company's reportable business segments are the sale of electricity by the traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Company Gas. Revenues from sales by Southern Power to the traditional electric operating companies were $101 million and $279 million for the three and nine months ended September 30, 2020, respectively, and $116 million and $320 million for the three and nine months ended September 30, 2019, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies were immaterial for the three and nine months ended September 30, 2020 and $9 million and $13 million for the three and nine months ended September 30, 2019, respectively. Revenues from sales of natural gas from Southern Company Gas to Southern Power were $9 million and $22 million for the three and nine months ended September 30, 2020, respectively, and $20 million and $53 million for the three and nine months ended September 30, 2019, respectively. The "All Other" column includes the Southern Company parent entity, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include providing energy solutions to electric utilities and their customers in the areas of distributed generation, energy storage and renewables, and energy efficiency, as well as investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material.

Financial data for business segments and products and services for the three and nine months ended September 30, 2020 and 2019 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, 2020
Operating revenues	$	4,629	$	523	$	(103)	$	5,049	$	477	$	132	$	(38)	$	5,620
Segment net income (loss)(a)	1,284		74		—		1,358		14		(122)		1		1,251
Nine Months Ended September 30, 2020
Operating revenues	$	11,576	$	1,337	$	(285)	$	12,628	$	2,362	$	380	$	(112)	$	15,258
Segment net income (loss)(a)(b)(c)(d)	2,571		212		—		2,783		360		(420)		9		2,732
At September 30, 2020
Goodwill	$	—	$	2	$	—	$	2	$	5,015	$	263	$	—	$	5,280
Total assets	85,218		13,424		(671)		97,971		21,932		4,116		(861)		123,158
Three Months Ended September 30, 2019
Operating revenues	$	4,908	$	574	$	(119)	$	5,363	$	498	$	146	$	(12)	$	5,995
Segment net income (loss)(a)(e)(f)	1,373		86		—		1,459		(29)		(110)		(4)		1,316
Nine Months Ended September 30, 2019
Operating revenues	$	12,252	$	1,527	$	(331)	$	13,448	$	2,661	$	514	$	(118)	$	16,505
Segment net income (loss)(a)(e)(f)(g)	2,719		316		—		3,035		347		931		(15)		4,298
At December 31, 2019
Goodwill	$	—	$	2	$	—	$	2	$	5,015	$	263	$	—	$	5,280
Total assets	81,063		14,300		(713)		94,650		21,687		3,511		(1,148)		118,700

(a)Attributable to Southern Company.

(b)Segment net income (loss) for the traditional electric operating companies includes a pre-tax charge of $149 million ($111 million after tax) related to Plant Vogtle Units 3 and 4. See Note (B) under "Georgia Power – Nuclear Construction" for additional information.

(c)Segment net income (loss) for the "All Other" column includes a pre-tax impairment charge of $154 million ($74 million after tax) related to a leveraged lease investment. See Note (C) under "Other Matters – Southern Company" for additional information.

(d)Segment net income (loss) for Southern Power includes a $39 million pre-tax gain ($23 million gain after tax) on the sale of Plant Mankato. See Note (K) under "Southern Power" for additional information.

(e)Segment net income (loss) for Southern Company Gas includes a pre-tax impairment charge of $92 million ($65 million after tax) related to a natural gas storage facility in Louisiana. See Note 3 to the financial statements under "Other Matters – Southern Company Gas – Natural Gas Storage Facilities" in Item 8 of the Form 10-K for additional information.

(f)Segment net income (loss) for the "All Other" column includes the preliminary pre-tax gain associated with the sale of Gulf Power of $2.5 billion ($1.3 billion after tax) for the nine months ended September 30, 2019, as well as impairment charges in contemplation of the sales of two of PowerSecure's business units totaling $18 million and $50 million for the three and nine months ended September 30, 2019, respectively. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company" for additional information.

(g)Segment net income (loss) for Southern Power includes a $23 million pre-tax gain ($88 million gain after tax) on the sale of Plant Nacogdoches. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power – Sale of Natural Gas and Biomass Plants" for additional information.

Products and Services

	Electric Utilities' Revenues
	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended September 30, 2020	$	4,243	$	584	$	222	$	5,049
Three Months Ended September 30, 2019	4,512		625		226		5,363
Nine Months Ended September 30, 2020	$	10,503	$	1,473	$	652	$	12,628
Nine Months Ended September 30, 2019	11,136		1,667		645		13,448

	Southern Company Gas' Revenues
	Gas Distribution Operations		Wholesale Gas Services(*)		Gas Marketing Services		Other		Total
	(in millions)
Three Months Ended September 30, 2020	$	476	$	(51)	$	39	$	13	$	477
Three Months Ended September 30, 2019	445		(2)		39		16		498
Nine Months Ended September 30, 2020	$	2,072	$	(19)	$	272	$	37	$	2,362
Nine Months Ended September 30, 2019	2,169		132		326		34		2,661

(*)The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. See "Southern Company Gas" herein for additional information.

Southern Company Gas

Southern Company Gas manages its business through four reportable segments – gas distribution operations, gas pipeline investments, wholesale gas services, and gas marketing services. The non-reportable segments are combined and presented as all other.

Gas distribution operations is the largest component of Southern Company Gas' business and includes natural gas local distribution utilities that construct, manage, and maintain intrastate natural gas pipelines and gas distribution facilities in four states.

Gas pipeline investments consists of joint ventures in natural gas pipeline investments including a 50% interest in SNG, a 20% ownership interest in the PennEast Pipeline construction project, a 50% joint ownership interest in the Dalton Pipeline, and a 5% ownership interest in the Atlantic Coast Pipeline construction project through its sale on March 24, 2020. These natural gas pipelines enable the provision of diverse sources of natural gas supplies to the customers of Southern Company Gas.

Wholesale gas services provides natural gas asset management and/or related logistics services for each of Southern Company Gas' utilities except Nicor Gas as well as for non-affiliated companies. Additionally, wholesale gas services engages in natural gas storage and gas pipeline arbitrage and related activities.

Gas marketing services provides natural gas marketing to end-use customers primarily in Georgia, Illinois, and Ohio through SouthStar.

The all other column includes segments below the quantitative threshold for separate disclosure, including natural gas storage businesses, fuels operations through the sale of Southern Company Gas' interest in Pivotal LNG on March 24, 2020, the investment in Triton through its sale on May 29, 2019, and other subsidiaries that fall below the quantitative threshold for separate disclosure. See Notes (E) and (K) under "Southern Company Gas" for additional information.

Business segment financial data for the three and nine months ended September 30, 2020 and 2019 was as follows:

	Gas Distribution Operations		Gas Pipeline Investments		Wholesale Gas Services(a)		Gas Marketing Services		Total		All Other(b)		Eliminations		Consolidated
	(in millions)
Three Months Ended September 30, 2020
Operating revenues	$	479	$	8	$	(51)	$	39	$	475	$	8	$	(6)	$	477
Segment net income (loss)	46		23		(45)		(3)		21		(7)		—		14
Nine Months Ended September 30, 2020
Operating revenues	$	2,086	$	24	$	(19)	$	272	$	2,363	$	24	$	(25)	$	2,362
Segment net income (loss)	284		74		(45)		59		372		(12)		—		360
Total assets at September 30, 2020	18,715		1,609		650		1,461		22,435		10,979		(11,482)		21,932
Three Months Ended September 30, 2019
Operating revenues	$	448	$	8	$	(2)	$	39	$	493	$	10	$	(5)	$	498
Segment net income (loss)	37		6		(9)		(4)		30		(59)		—		(29)
Nine Months Ended September 30, 2019
Operating revenues	$	2,188	$	24	$	132	$	326	$	2,670	$	34	$	(43)	$	2,661
Segment net income (loss)	228		63		61		54		406		(59)		—		347
Total assets at December 31, 2019	18,204		1,678		850		1,496		22,228		10,759		(11,300)		21,687

(a)The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table.

	Third Party Gross Revenues		Intercompany Revenues		Total Gross Revenues		Less Gross Gas Costs		Operating Revenues
	(in millions)
Three Months Ended September 30, 2020	$	1,050	$	33	$	1,083	$	1,134	$	(51)
Three Months Ended September 30, 2019	1,138		72		1,210		1,212		(2)
Nine Months Ended September 30, 2020	$	3,089	$	81	$	3,170	$	3,189	$	(19)
Nine Months Ended September 30, 2019	4,287		223		4,510		4,378		132

(b)Segment net income (loss) for the "All Other" column includes a pre-tax impairment charge of $92 million ($65 million after tax) for the three and nine months ended September 30, 2019 related to a natural gas storage facility in Louisiana. See Note 3 to the financial statements under "Other Matters – Southern Company Gas – Natural Gas Storage Facilities" in Item 8 of the Form 10-K for additional information.

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INTRODUCTION (Policies)

9 Months Ended

Sep. 30, 2020

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Accounting

The condensed quarterly financial statements of each Registrant included herein have been prepared by such Registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 2019 have been derived from the audited financial statements of each Registrant. In the opinion of each Registrant's management, the information regarding such Registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended September 30, 2020 and 2019. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each Registrant believes that the disclosures regarding such Registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the 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, including the impacts of the COVID-19 pandemic, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.

Reclassifications

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 is not amortized but is subject to an annual impairment test in the fourth quarter of the year and on an interim basis as events and changes in circumstances occur, including, but not limited to, a significant change in operating performance, the business climate, legal or regulatory factors, or a planned sale or disposition of a significant portion of the business. The continued COVID-19 pandemic and related responses continue to disrupt supply chains, reduce labor availability and productivity, and reduce economic activity. These effects could have a variety of adverse impacts on Southern Company and its subsidiaries, including the $263 million of goodwill recorded at PowerSecure. If the impact of the COVID-19 pandemic becomes significant to the operating results of PowerSecure and its businesses, a portion of the associated goodwill may become impaired. The ultimate outcome of this matter cannot be determined at this time.

Natural Gas For Sale

Southern Company Gas, with the exception of Nicor Gas, carries natural gas inventory on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value. 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 the three and nine months ended September 30, 2020 or the three months ended September 30, 2019 and recorded an adjustment of $10

million for the nine months ended September 30, 2019.

Valuation Methodologies

Valuation Methodologies

The energy-related derivatives primarily consist of exchange-traded and over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The fair value of cross-currency swaps reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and discount rates. The interest rate derivatives and cross-currency swaps are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note (J) for additional information on how these derivatives are used.

For fair value measurements of the investments within the nuclear decommissioning trusts and the non-qualified deferred compensation trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgments, are also obtained when available.

The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. See Note 6 to the financial statements under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

Southern Power has contingent payment obligations related to certain acquisitions whereby Southern Power is primarily obligated to make generation-based payments to the seller, which commenced at the commercial operation of the respective facility and continue through 2026. The obligation is categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate.

Derivatives

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Southern Company Gas' wholesale gas operations use various contracts in its commercial activities that generally meet the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note (I) for additional fair value information. In the statements of cash flows, any cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Any cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with classification of the hedged interest or principal, respectively. See Note 1 to the financial statements under "Financial Instruments" in Item 8 of the Form 10-K for additional information.

Energy-Related Derivatives

The traditional electric operating companies, Southern Power, and Southern Company Gas enter into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies and the natural gas distribution utilities have limited exposure to market volatility in energy-related commodity prices. Each of the traditional electric operating companies and certain of the natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs, implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies, through the use of financial derivative contracts, which are expected to continue to mitigate price volatility. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in energy-related commodity prices because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted capacity is used to sell electricity. Southern Company Gas retains exposure to price changes that can, in a volatile energy market, be material and can adversely affect its results of operations.

Southern Company Gas also enters into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in operating revenues.

Energy-related derivative contracts are accounted for under one of three methods:

•Regulatory Hedges — Energy-related derivative contracts designated as regulatory hedges relate primarily to the traditional electric operating companies' and the natural gas distribution utilities' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses.

•Cash Flow Hedges — Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in accumulated OCI before being recognized in the statements of income in the same period and in the same income statement line item as the earnings effect of the hedged transactions.

•Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric and natural gas industries. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.

Interest Rate Derivatives

Southern Company and certain subsidiaries may enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and presented on the same income statement line item as the earnings effect of the hedged transactions. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Foreign Currency Derivatives

Southern Company and certain subsidiaries, including Southern Power, may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and on the same income statement line as the earnings effect of the hedged transactions, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

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INTRODUCTION (Tables)

9 Months Ended

Sep. 30, 2020

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Goodwill

Goodwill at September 30, 2020 and December 31, 2019 was as follows:

	Goodwill
	(in millions)
Southern Company	$	5,280
Southern Company Gas:
Gas distribution operations	$	4,034
Gas marketing services	981
Southern Company Gas total	$	5,015

Schedule of Other Intangible Assets, Indefinite-Lived

Other intangible assets were as follows:

	At September 30, 2020						At December 31, 2019
	Gross Carrying Amount		Accumulated Amortization		Other Intangible Assets, Net		Gross Carrying Amount		Accumulated Amortization		Other Intangible Assets, Net
	(in millions)						(in millions)
Southern Company
Other intangible assets subject to amortization:
Customer relationships	$	212	$	(130)	$	82	$	212	$	(116)	$	96
Trade names	64		(30)		34		64		(25)		39
Storage and transportation contracts	64		(64)		—		64		(62)		2
PPA fair value adjustments	390		(84)		306		390		(69)		321
Other	10		(8)		2		11		(8)		3
Total other intangible assets subject to amortization	$	740	$	(316)	$	424	$	741	$	(280)	$	461
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	75		—		75		75		—		75
Total other intangible assets	$	815	$	(316)	$	499	$	816	$	(280)	$	536
Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	$	390	$	(84)	$	306	$	390	$	(69)	$	321
Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services
Customer relationships	$	156	$	(115)	$	41	$	156	$	(104)	$	52
Trade names	26		(12)		14		26		(10)		16
Wholesale gas services
Storage and transportation contracts	64		(64)		—		64		(62)		2
Total other intangible assets subject to amortization	$	246	$	(191)	$	55	$	246	$	(176)	$	70

Schedule of Other Intangible Assets, Finite-Lived

Other intangible assets were as follows:

	At September 30, 2020						At December 31, 2019
	Gross Carrying Amount		Accumulated Amortization		Other Intangible Assets, Net		Gross Carrying Amount		Accumulated Amortization		Other Intangible Assets, Net
	(in millions)						(in millions)
Southern Company
Other intangible assets subject to amortization:
Customer relationships	$	212	$	(130)	$	82	$	212	$	(116)	$	96
Trade names	64		(30)		34		64		(25)		39
Storage and transportation contracts	64		(64)		—		64		(62)		2
PPA fair value adjustments	390		(84)		306		390		(69)		321
Other	10		(8)		2		11		(8)		3
Total other intangible assets subject to amortization	$	740	$	(316)	$	424	$	741	$	(280)	$	461
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	75		—		75		75		—		75
Total other intangible assets	$	815	$	(316)	$	499	$	816	$	(280)	$	536
Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	$	390	$	(84)	$	306	$	390	$	(69)	$	321
Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services
Customer relationships	$	156	$	(115)	$	41	$	156	$	(104)	$	52
Trade names	26		(12)		14		26		(10)		16
Wholesale gas services
Storage and transportation contracts	64		(64)		—		64		(62)		2
Total other intangible assets subject to amortization	$	246	$	(191)	$	55	$	246	$	(176)	$	70

Finite-lived Intangible Assets Amortization Expense

Amortization associated with other intangible assets was as follows:

	Three Months Ended		Nine Months Ended
	September 30, 2020
	(in millions)
Southern Company(a)	$	12	$	37
Southern Power(b)	$	5	$	15
Southern Company Gas
Gas marketing services	$	4	$	13
Wholesale gas services(b)	1		2
Southern Company Gas total	$	5	$	15

(a)Includes $6 million and $17 million for the three and nine months ended September 30, 2020, respectively, recorded as a reduction to operating revenues.

(b)Recorded as a reduction to operating revenues.

Restrictions on Cash and Cash Equivalents

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed balance sheets that total to the amounts shown in the condensed statements of cash flows for the Registrants that had restricted cash at September 30, 2020 and/or December 31, 2019:

	Southern Company					Southern Power		Southern Company Gas
	At September 30, 2020			At December 31, 2019		At September 30, 2020		At September 30, 2020		At December 31, 2019
	(in millions)					(in millions)		(in millions)
Cash and cash equivalents	$	3,379		$	1,975	$	416	$	157	$	46
Restricted cash(a):
Other accounts and notes receivable	—			3		—		—		3
Other current assets	4			—		—		4		—
Other deferred charges and assets	1			—		1		—		—
Total cash, cash equivalents, and restricted cash	$	3,383	(b)	$	1,978	$	417	$	161	$	49

(a)For Southern Company Gas, reflects restricted cash held as collateral for workers' compensation, life insurance, and long-term disability insurance. For Southern Power, reflects restricted cash held for construction payables.

(b)Total does not add due to rounding.

Schedule of Cash and Cash Equivalents

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed balance sheets that total to the amounts shown in the condensed statements of cash flows for the Registrants that had restricted cash at September 30, 2020 and/or December 31, 2019:

	Southern Company					Southern Power		Southern Company Gas
	At September 30, 2020			At December 31, 2019		At September 30, 2020		At September 30, 2020		At December 31, 2019
	(in millions)					(in millions)		(in millions)
Cash and cash equivalents	$	3,379		$	1,975	$	416	$	157	$	46
Restricted cash(a):
Other accounts and notes receivable	—			3		—		—		3
Other current assets	4			—		—		4		—
Other deferred charges and assets	1			—		1		—		—
Total cash, cash equivalents, and restricted cash	$	3,383	(b)	$	1,978	$	417	$	161	$	49

(a)For Southern Company Gas, reflects restricted cash held as collateral for workers' compensation, life insurance, and long-term disability insurance. For Southern Power, reflects restricted cash held for construction payables.

(b)Total does not add due to rounding.

Schedule of Changes in Asset Retirement Obligations

Details of changes in AROs for Southern Company, Alabama Power, and Georgia Power during the first nine months of 2020 are shown in the following table. There were no material changes in AROs for the other Registrants during the first nine months of 2020.

	Southern Company		Alabama Power		Georgia Power
	(in millions)
Balance at December 31, 2019	$	9,786	$	3,540	$	5,784
Liabilities incurred	15		—		10
Liabilities settled	(315)		(157)		(130)
Accretion	308		113		177
Cash flow revisions	866		462		411
Balance at September 30, 2020	$	10,660	$	3,958	$	6,252

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REGULATORY MATTERS (Tables)

9 Months Ended

Sep. 30, 2020

Regulated Operations [Abstract]

Cost Recovery Clauses

The recovery balances for certain retail regulatory clauses of the traditional electric operating companies and Southern Company Gas at September 30, 2020 and December 31, 2019 were as follows:

Regulatory Clause	Balance Sheet Line Item	September 30, 2020		December 31, 2019
		(in millions)
Alabama Power
Rate CNP Compliance	Other regulatory liabilities, current	$	12	$	55
	Other regulatory liabilities, deferred	38		7
Rate CNP PPA	Deferred under recovered regulatory clause revenues	62		40
Retail Energy Cost Recovery	Other regulatory liabilities, current	107		32
	Other regulatory liabilities, deferred	16		17
Natural Disaster Reserve	Other regulatory liabilities, current	7		37
	Other regulatory liabilities, deferred	51		113
Georgia Power
Fuel Cost Recovery	Over recovered fuel clause revenues	$	84	$	—
	Other deferred credits and liabilities	67		73
Mississippi Power
Fuel Cost Recovery	Over recovered regulatory clause liabilities	$	23	$	23
Ad Valorem Tax	Other regulatory assets	11		47
	Other regulatory assets, deferred	36		—
Property Damage Reserve	Other regulatory liabilities, deferred	48		54
Southern Company Gas
Natural Gas Cost Recovery	Other regulatory liabilities	$	84	$	74

Cost and Schedule

Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 by the expected in-service dates of November 2021 and November 2022, respectively, is as follows:

	(in billions)
Base project capital cost forecast(a)(b)	$	8.4
Construction contingency estimate	0.1
Total project capital cost forecast(a)(b)	8.5
Net investment as of September 30, 2020(b)	(6.9)
Remaining estimate to complete(a)	$	1.6

(a)    Excludes financing costs expected to be capitalized through AFUDC of approximately $240 million, of which $71 million had been accrued through September 30, 2020.

(b)    Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds.

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REVENUE FROM CONTRACTS WITH CUSTOMERS AND LEASE INCOME (Tables)

9 Months Ended

Sep. 30, 2020

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

The following table disaggregates revenue from contracts with customers for the three and nine months ended September 30, 2020 and 2019:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended September 30, 2020
Operating revenues
Retail electric revenues
Residential	$	2,019	$	752	$	1,183	$	84	$	—	$	—
Commercial	1,354		447		833		74		—		—
Industrial	783		358		352		73		—		—
Other	22		5		15		2		—		—
Total retail electric revenues	4,178		1,562		2,383		233		—		—
Natural gas distribution revenues
Residential	170		—		—		—		—		170
Commercial	41		—		—		—		—		41
Transportation	224		—		—		—		—		224
Industrial	4		—		—		—		—		4
Other	35		—		—		—		—		35
Total natural gas distribution revenues	474		—		—		—		—		474
Wholesale electric revenues
PPA energy revenues	214		40		13		2		165		—
PPA capacity revenues	136		26		15		1		95		—
Non-PPA revenues	59		10		3		93		68		—
Total wholesale electric revenues	409		76		31		96		328		—
Other natural gas revenues
Wholesale gas services	431		—		—		—		—		431
Gas marketing services	38		—		—		—		—		38
Other natural gas revenues	7		—		—		—		—		7
Total natural gas revenues	476		—		—		—		—		476
Other revenues	218		33		115		6		4		—
Total revenue from contracts with customers	5,755		1,671		2,529		335		332		950
Other revenue sources(a)	968		58		88		1		191		630
Other adjustments(b)	(1,103)		—		—		—		—		(1,103)
Total operating revenues	$	5,620	$	1,729	$	2,617	$	336	$	523	$	477

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Nine Months Ended September 30, 2020
Operating revenues
Retail electric revenues
Residential	$	4,802	$	1,839	$	2,760	$	203	$	—	$	—
Commercial	3,589		1,152		2,242		195		—		—
Industrial	2,081		956		907		218		—		—
Other	68		16		46		6		—		—
Total retail electric revenues	10,540		3,963		5,955		622		—		—
Natural gas distribution revenues
Residential	906		—		—		—		—		906
Commercial	229		—		—		—		—		229
Transportation	723		—		—		—		—		723
Industrial	21		—		—		—		—		21
Other	179		—		—		—		—		179
Total natural gas distribution revenues	2,058		—		—		—		—		2,058
Wholesale electric revenues
PPA energy revenues	550		94		38		7		425		—
PPA capacity revenues	339		78		30		3		231		—
Non-PPA revenues	159		33		7		235		184		—
Total wholesale electric revenues	1,048		205		75		245		840		—
Other natural gas revenues
Wholesale gas services	1,168		—		—		—		—		1,168
Gas marketing services	258		—		—		—		—		258
Other natural gas revenues	22		—		—		—		—		22
Total natural gas revenues	1,448		—		—		—		—		1,448
Other revenues	677		117		329		19		11		—
Total revenue from contracts with customers	15,771		4,285		6,359		886		851		3,506
Other revenue sources(a)	2,604		160		12		9		486		1,973
Other adjustments(b)	(3,117)		—		—		—		—		(3,117)
Total operating revenues	$	15,258	$	4,445	$	6,371	$	895	$	1,337	$	2,362

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended September 30, 2019
Operating revenues
Retail electric revenues
Residential	$	2,119	$	820	$	1,211	$	88	$	—	$	—
Commercial	1,563		512		965		86		—		—
Industrial	953		421		450		82		—		—
Other	26		7		16		3		—		—
Total retail electric revenues	4,661		1,760		2,642		259		—		—
Natural gas distribution revenues
Residential	162		—		—		—		—		162
Commercial	42		—		—		—		—		42
Transportation	204		—		—		—		—		204
Industrial	3		—		—		—		—		3
Other	30		—		—		—		—		30
Total natural gas distribution revenues	441		—		—		—		—		441
Wholesale electric revenues
PPA energy revenues	245		43		19		2		188		—
PPA capacity revenues	134		25		13		1		100		—
Non-PPA revenues	62		2		3		111		81		—
Total wholesale electric revenues	441		70		35		114		369		—
Other natural gas revenues
Wholesale gas services	425		—		—		—		—		425
Gas marketing services	37		—		—		—		—		37
Other natural gas revenues	10		—		—		—		—		10
Total natural gas revenues	472		—		—		—		—		472
Other revenues	267		36		113		4		3		—
Total revenue from contracts with customers	6,282		1,866		2,790		377		372		913
Other revenue sources(a)	855		(25)		(35)		(7)		202		727
Other adjustments(b)	(1,142)		—		—		—		—		(1,142)
Total operating revenues	$	5,995	$	1,841	$	2,755	$	370	$	574	$	498

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Nine Months Ended September 30, 2019
Operating revenues
Retail electric revenues
Residential	$	4,939	$	1,971	$	2,751	$	217	$	—	$	—
Commercial	3,951		1,301		2,427		223		—		—
Industrial	2,428		1,128		1,074		226		—		—
Other	69		20		41		8		—		—
Total retail electric revenues	11,387		4,420		6,293		674		—		—
Natural gas distribution revenues
Residential	992		—		—		—		—		992
Commercial	277		—		—		—		—		277
Transportation	673		—		—		—		—		673
Industrial	25		—		—		—		—		25
Other	191		—		—		—		—		191
Total natural gas distribution revenues	2,158		—		—		—		—		2,158
Wholesale electric revenues
PPA energy revenues	648		110		47		8		508		—
PPA capacity revenues	350		77		41		2		272		—
Non-PPA revenues	174		65		5		275		190		—
Total wholesale electric revenues	1,172		252		93		285		970		—
Other natural gas revenues
Wholesale gas services	1,590		—		—		—		—		1,590
Gas marketing services	313		—		—		—		—		313
Other natural gas revenues	32		—		—		—		—		32
Total natural gas revenues	1,935		—		—		—		—		1,935
Other revenues	763		119		298		14		10		—
Total revenue from contracts with customers	17,415		4,791		6,684		973		980		4,093
Other revenue sources(a)	3,266		(29)		22		(3)		547		2,744
Other adjustments(b)	(4,176)		—		—		—		—		(4,176)
Total operating revenues	$	16,505	$	4,762	$	6,706	$	970	$	1,527	$	2,661

(a)Other revenue sources primarily relate to revenues from customers accounted for as derivatives and leases, as well as alternative revenue programs at Southern Company Gas and other cost recovery mechanisms at the traditional electric operating companies.

(b)Other adjustments relate to the cost of Southern Company Gas' energy and risk management activities. Wholesale gas services revenues are presented net of the related costs of those activities on the statement of income. See Note (L) under "Southern Company Gas" for additional information on the components of wholesale gas services' operating revenues.

Contract with Customer, Asset and Liability and Revenue Recognized

The following table reflects the closing balances of receivables, contract assets, and contract liabilities related to revenues from contracts with customers at September 30, 2020 and December 31, 2019:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Accounts Receivables
As of September 30, 2020	$	2,344	$	686	$	901	$	93	$	100	$	385
As of December 31, 2019	2,413		586		688		79		97		749
Contract Assets
As of September 30, 2020	$	159	$	5	$	103	$	—	$	—	$	—
As of December 31, 2019	117		—		69		—		—		—
Contract Liabilities
As of September 30, 2020	$	56	$	1	$	24	$	—	$	3	$	1
As of December 31, 2019	52		10		13		—		1		1

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction

Revenue from contracts with customers related to these performance obligations remaining at September 30, 2020 are expected to be recognized as follows:

	2020 (remaining)		2021		2022		2023		2024		2025 and Thereafter
	(in millions)
Southern Company	$	170	$	487	$	362	$	339	$	319	$	3,062
Alabama Power	7		33		31		24		7		5
Georgia Power	20		71		43		35		24		62
Southern Power	60		290		292		282		290		3,013

Summary of Lease Income

Lease income for the three and nine months ended September 30, 2020 and 2019 is as follows:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
For the Three Months Ended September 30, 2020
Lease income - interest income on sales-type leases	$	3	$	—	$	—	$	3	$	—	$	—
Lease income - operating leases	50		11		14		—		21		9
Variable lease income	145		—		—		—		153		—
Total lease income	$	198	$	11	$	14	$	3	$	174	$	9
For the Nine Months Ended September 30, 2020
Lease income - interest income on sales-type leases	$	8	$	—	$	—	$	8	$	—	$	—
Lease income - operating leases	148		24		44		1		66		26
Variable lease income	345		—		—		—		368		—
Total lease income	$	501	$	24	$	44	$	9	$	434	$	26
For the Three Months Ended September 30, 2019
Lease income - interest income on sales-type leases	$	2	$	—	$	—	$	2	$	—	$	—
Lease income - operating leases	64		5		18		—		31		9
Variable lease income	141		—		—		—		151		—
Total lease income	$	207	$	5	$	18	$	2	$	182	$	9
For the Nine Months Ended September 30, 2019
Lease income - interest income on sales-type leases	$	7	$	—	$	—	$	7	$	—	$	—
Lease income - operating leases	216		19		57		—		111		26
Variable lease income	324		—		—		—		349		—
Total lease income	$	547	$	19	$	57	$	7	$	460	$	26

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CONSOLIDATED ENTITIES AND EQUITY METHOD INVESTMENTS (Tables)

9 Months Ended

Sep. 30, 2020

Regulated Operations [Abstract]

Equity Method Investments

The carrying amounts of Southern Company Gas' equity method investments as of September 30, 2020 and December 31, 2019 and related income from those investments for the three and nine months ended September 30, 2020 and 2019 were as follows:

Investment Balance	September 30, 2020		December 31, 2019(a)
	(in millions)
SNG(b)	$	1,180	$	1,137
PennEast Pipeline(c)	89		82
Other	32		32
Total	$	1,301	$	1,251

(a)Excludes investments in Atlantic Coast Pipeline and Pivotal JAX LNG classified as held for sale at December 31, 2019. See Note 15 to the financial statements under "Assets Held for Sale" in Item 8 of the Form 10-K for additional information.

(b)Increase primarily relates to a capital contribution, partially offset by the continued amortization of deferred tax assets established upon acquisition.

(c)See Note (C) under "Other Matters – Southern Company Gas" for additional information on the PennEast Pipeline.

Selected financial information of SNG for the three and nine months ended September 30, 2020 and 2019 is as follows:

Income Statement Information	Three Months Ended September 30, 2020		Three Months Ended September 30, 2019		Nine Months Ended September 30, 2020		Nine Months Ended September 30, 2019
	(in millions)
Revenues	$	150	$	152	$	457	$	473
Operating income	85		82		262		274
Net income	59		60		189		208

Schedule of Other Nonoperating Income, by Component

Earnings from Equity Method Investments	Three Months Ended September 30, 2020		Three Months Ended September 30, 2019		Nine Months Ended September 30, 2020		Nine Months Ended September 30, 2019
	(in millions)
SNG	$	30	$	30	$	95	$	104
Atlantic Coast Pipeline(a)(b)	—		3		3		9
PennEast Pipeline(a)	2		2		5		5
Other	1		—		3		(3)
Total	$	33	$	35	$	106	$	115

(a)Amounts primarily result from AFUDC equity recorded by the project entity.

(b)On March 24, 2020, Southern Company Gas completed the sale of its interest in Atlantic Coast Pipeline. See Note (K) under "Southern Company Gas" for additional information.

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FINANCING (Tables)

9 Months Ended

Sep. 30, 2020

Debt Disclosure [Abstract]

Credit Arrangements by Company

At September 30, 2020, committed credit arrangements with banks were as follows:

	Expires
Company	2021		2022		2023		2024		Total		Unused		Due within One Year
	(in millions)
Southern Company parent	$	—	$	—	$	—	$	2,000	$	2,000	$	1,999	$	—
Alabama Power	3		525		—		800		1,328		1,328		3
Georgia Power	—		—		—		1,750		1,750		1,728		—
Mississippi Power	—		150		125		—		275		250		—
Southern Power(a)	—		—		—		600		600		591		—
Southern Company Gas(b)	—		—		—		1,750		1,750		1,745		—
SEGCO	30		—		—		—		30		30		30
Southern Company	$	33	$	675	$	125	$	6,900	$	7,733	$	7,671	$	33

(a)Does not include Southern Power Company's $120 million and $60 million continuing letter of credit facilities for standby letters of credit expiring in 2021 and 2023, respectively, of which $23 million and $40 million, respectively, was unused at September 30, 2020. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities.

(b)Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.25 billion of this arrangement. Southern Company Gas' committed credit arrangement also includes $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. Pursuant to this multi-year credit arrangement, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted.

Shares Used to Compute Diluted Earnings Per Share

Shares used to compute diluted earnings per share were as follows:

	Three Months Ended September 30, 2020	Three Months Ended September 30, 2019	Nine Months Ended September 30, 2020	Nine Months Ended September 30, 2019
	(in millions)
As reported shares	1,058	1,048	1,058	1,043
Effect of stock-based compensation	6	9	6	8
Diluted shares	1,064	1,057	1,064	1,051

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RETIREMENT BENEFITS (Tables)

9 Months Ended

Sep. 30, 2020

Retirement Benefits [Abstract]

Pension Plans and Postretirement Plans

Components of the net periodic benefit costs for the three and nine months ended September 30, 2020 and 2019 are presented in the following tables.

Three Months Ended September 30, 2020	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	94	$	23	$	24	$	3	$	2	$	8
Interest cost	108		25		33		5		1		8
Expected return on plan assets	(274)		(66)		(87)		(13)		(4)		(20)
Amortization:
Prior service costs	—		1		—		—		—		(1)
Regulatory asset	—		—		—		—		—		4
Net (gain)/loss	67		17		22		4		1		2
Net periodic pension cost (income)	$	(5)	$	—	$	(8)	$	(1)	$	—	$	1
Postretirement Benefits
Service cost	$	6	$	1	$	2	$	(1)	$	1	$	—
Interest cost	13		4		5		1		—		2
Expected return on plan assets	(18)		(7)		(7)		—		—		(2)
Amortization:
Prior service costs	—		—		(1)		—		—		—
Regulatory asset	—		—		—		—		—		2
Net (gain)/loss	1		—		1		—		—		(1)
Net periodic postretirement benefit cost	$	2	$	(2)	$	—	$	—	$	1	$	1

Nine Months Ended September 30, 2020	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	282	$	67	$	72	$	11	$	6	$	24
Interest cost	324		75		100		15		4		23
Expected return on plan assets	(824)		(198)		(261)		(38)		(10)		(59)
Amortization:
Prior service costs	1		1		1		—		—		(2)
Regulatory asset	—		—		—		—		—		12
Net (gain)/loss	201		53		65		10		2		7
Net periodic pension cost (income)	$	(16)	$	(2)	$	(23)	$	(2)	$	2	$	5
Postretirement Benefits
Service cost	$	17	$	4	$	5	$	—	$	1	$	1
Interest cost	40		10		15		2		—		5
Expected return on plan assets	(54)		(21)		(20)		(1)		—		(5)
Amortization:
Prior service costs	(1)		—		(1)		—		—		—
Regulatory asset	—		—		—		—		—		5
Net (gain)/loss	2		—		2		—		—		(2)
Net periodic postretirement benefit cost	$	4	$	(7)	$	1	$	1	$	1	$	4

Three Months Ended September 30, 2019	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	73	$	17	$	19	$	3	$	2	$	7
Interest cost	123		28		38		6		1		9
Expected return on plan assets	(222)		(51)		(73)		(10)		(2)		(15)
Amortization:
Prior service costs	1		—		—		—		—		(1)
Regulatory asset	—		—		—		—		—		3
Net (gain)/loss	30		9		11		1		—		1
Net periodic pension cost (income)	$	5	$	3	$	(5)	$	—	$	1	$	4
Postretirement Benefits
Service cost	$	5	$	1	$	2	$	1	$	—	$	—
Interest cost	18		4		6		—		—		2
Expected return on plan assets	(16)		(6)		(7)		—		—		(1)
Amortization:
Prior service costs	—		1		—		—		—		—
Regulatory asset	—		—		—		—		—		1
Net (gain)/loss	(1)		—		1		—		—		—
Net periodic postretirement benefit cost	$	6	$	—	$	2	$	1	$	—	$	2

Nine Months Ended September 30, 2019	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	219	$	51	$	56	$	9	$	5	$	19
Interest cost	369		85		116		17		4		27
Expected return on plan assets	(664)		(154)		(219)		(30)		(7)		(45)
Amortization:
Prior service costs	2		1		1		—		—		(2)
Regulatory asset	—		—		—		—		—		10
Net (gain)/loss	90		27		33		4		—		2
Net periodic pension cost (income)	$	16	$	10	$	(13)	$	—	$	2	$	11
Postretirement Benefits
Service cost	$	14	$	3	$	4	$	1	$	—	$	1
Interest cost	52		12		19		2		—		7
Expected return on plan assets	(49)		(19)		(19)		(1)		—		(4)
Amortization:
Prior service costs	2		3		—		—		—		—
Regulatory asset	—		—		—		—		—		4
Net (gain)/loss	(2)		—		1		—		—		(2)
Net periodic postretirement benefit cost	$	17	$	(1)	$	5	$	2	$	—	$	6

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FAIR VALUE MEASUREMENTS (Tables)

9 Months Ended

Sep. 30, 2020

Fair Value Disclosures [Abstract]

Assets and Liabilities Measured at Fair Value on a Recurring Basis

As of September 30, 2020, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:

	Fair Value Measurements Using:
As of September 30, 2020:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Southern Company
Assets:
Energy-related derivatives(a)	$	488	$	218	$	117	$	—	$	823
Interest rate derivatives	—		20		—		—		20
Foreign currency derivatives	—		29		—		—		29
Investments in trusts:(b)(c)
Domestic equity	754		137		—		—		891
Foreign equity	71		220		—		—		291
U.S. Treasury and government agency securities	—		268		—		—		268
Municipal bonds	—		99		—		—		99
Pooled funds – fixed income	—		17		—		—		17
Corporate bonds	15		376		—		—		391
Mortgage and asset backed securities	—		79		—		—		79
Private equity	—		—		—		68		68
Cash and cash equivalents	1		—		—		—		1
Other	25		6		—		—		31
Cash equivalents	2,750		11		—		—		2,761
Other investments	9		19		—		—		28
Total	$	4,113	$	1,499	$	117	$	68	$	5,797
Liabilities:
Energy-related derivatives(a)	$	521	$	155	$	75	$	—	$	751
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		19		—		19
Total	$	521	$	178	$	94	$	—	$	793

	Fair Value Measurements Using:
As of September 30, 2020:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Alabama Power
Assets:
Energy-related derivatives	$	—	$	23	$	—	$	—	$	23
Nuclear decommissioning trusts:(b)
Domestic equity	477		128		—		—		605
Foreign equity	71		64		—		—		135
U.S. Treasury and government agency securities	—		21		—		—		21
Municipal bonds	—		1		—		—		1
Corporate bonds	15		159		—		—		174
Mortgage and asset backed securities	—		27		—		—		27
Private equity	—		—		—		68		68
Other	6		—		—		—		6
Cash equivalents	825		11		—		—		836
Other investments	—		19		—		—		19
Total	$	1,394	$	453	$	—	$	68	$	1,915
Liabilities:
Energy-related derivatives	$	—	$	6	$	—	$	—	$	6
Georgia Power
Assets:
Energy-related derivatives	$	—	$	31	$	—	$	—	$	31
Nuclear decommissioning trusts:(b)(c)
Domestic equity	277		1		—		—		278
Foreign equity	—		153		—		—		153
U.S. Treasury and government agency securities	—		247		—		—		247
Municipal bonds	—		98		—		—		98
Corporate bonds	—		217		—		—		217
Mortgage and asset backed securities	—		52		—		—		52
Other	19		6		—		—		25
Cash equivalents	485		—		—		—		485
Total	$	781	$	805	$	—	$	—	$	1,586
Liabilities:
Energy-related derivatives	$	—	$	9	$	—	$	—	$	9

	Fair Value Measurements Using:
As of September 30, 2020:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	18	$	—	$	—	$	18
Cash equivalents	36		—		—		—		36
Total	$	36	$	18	$	—	$	—	$	54
Liabilities:
Energy-related derivatives	$	—	$	7	$	—	$	—	$	7
Southern Power
Assets:
Energy-related derivatives	$	—	$	5	$	—	$	—	$	5
Foreign currency derivatives	—		29		—		—		29
Cash equivalents	149		—		—		—		149
Total	$	149	$	34	$	—	$	—	$	183
Liabilities:
Energy-related derivatives	$	—	$	1	$	—	$	—	$	1
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		19		—		19
Total	$	—	$	24	$	19	$	—	$	43
Southern Company Gas
Assets:
Energy-related derivatives(a)	$	488	$	141	$	117	$	—	$	746
Non-qualified deferred compensation trusts:
Domestic equity	—		8		—		—		8
Foreign equity	—		3		—		—		3
Pooled funds – fixed income	—		17		—		—		17
Cash equivalents	1		—		—		—		1
Cash equivalents and restricted cash	113		—		—		—		113
Total	$	602	$	169	$	117	$	—	$	888
Liabilities:
Energy-related derivatives(a)	$	521	$	132	$	75	$	—	$	728

(a)Energy-related derivatives exclude cash collateral of $70 million.

(b)Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.

(c)Includes investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of September 30, 2020, approximately $25 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.

Schedule of Increase (Decrease) In Fair Value Of 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, 2020 and 2019. The changes were recorded as a change to the regulatory assets and liabilities related to AROs for Georgia Power and Alabama Power, respectively.

Fair value increases (decreases)	Three Months Ended September 30, 2020		Three Months Ended September 30, 2019		Nine Months Ended September 30, 2020		Nine Months Ended September 30, 2019
	(in millions)
Southern Company	$	108	$	27	$	85	$	255
Alabama Power	66		15		24		140
Georgia Power	42		12		61		115

Financial Instruments for Which Carrying Amount Did Not Equal Fair Value

As of September 30, 2020, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas(*)
	(in millions)
Long-term debt, including securities due within one year:
Carrying amount	$	49,743	$	9,113	$	12,700	$	1,402	$	4,155	$	6,461
Fair value	56,739		10,741		15,052		1,562		4,535		7,640

(*)The long-term debt of Southern Company Gas is recorded at amortized cost, including the fair value adjustments at the effective date of the 2016 merger with Southern Company. Southern Company Gas amortizes the fair value adjustments over the lives of the respective bonds.

Fair Value of Commodity Derivative Contracts that Include a Significant Unobservable Component

The following table includes transfers to Level 3, which represent the fair value of Southern Company Gas' commodity derivative contracts that include a significant unobservable component for the first time during the period.

	Three Months Ended September 30, 2020		Nine Months Ended September 30, 2020
	(in millions)
Beginning balance	$	80	$	14
Transfers to Level 3	—		70
Transfers from Level 3	(2)		(5)
Instruments realized or otherwise settled during period	(9)		(16)
Changes in fair value	(27)		(21)
Ending balance	$	42	$	42

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DERIVATIVES (Tables)

9 Months Ended

Sep. 30, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Energy-Related Derivatives

At September 30, 2020, the net volume of energy-related derivative contracts for natural gas positions, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows:

	Net Purchased mmBtu	Longest Hedge Date	Longest Non-Hedge Date
	(in millions)
Southern Company(*)	877	2024	2031
Alabama Power	78	2024	—
Georgia Power	131	2023	—
Mississippi Power	86	2024	—
Southern Power	14	2022	2021
Southern Company Gas(*)	568	2023	2031

(*)Southern Company Gas' derivative instruments include both long and short natural gas positions. A long position is a contract to purchase natural gas and a short position is a contract to sell natural gas. Southern Company Gas' volume represents the net of long natural gas positions of 4.6 billion mmBtu and short natural gas positions of 4.1 billion mmBtu as of September 30, 2020, which is also included in Southern Company's total volume.

Schedule of Interest Rate Derivatives

At September 30, 2020, the following interest rate derivatives were outstanding:

	Notional Amount		Interest Rate Received	Weighted Average Interest Rate Paid	Hedge Maturity Date	Fair Value Gain (Loss) at September 30, 2020
	(in millions)					(in millions)
Cash Flow Hedges of Existing Debt
Mississippi Power	$	60	1-month LIBOR	0.58%	December 2021	$	—
Fair Value Hedges of Existing Debt
Southern Company parent	1,500		2.35%	1-month LIBOR + 0.87%	July 2021	20
Southern Company	$	1,560				$	20

Schedule of Foreign Currency Derivatives

At September 30, 2020, the following foreign currency derivatives were outstanding:

	Pay Notional		Pay Rate	Receive Notional		Receive Rate	Hedge Maturity Date	Fair Value Gain (Loss) at September 30, 2020
	(in millions)			(in millions)				(in millions)
Cash Flow Hedges of Existing Debt
Southern Power	$	677	2.95%	€	600	1.00%	June 2022	$	11
Southern Power	564		3.78%	500		1.85%	June 2026	(5)
Total	$	1,241		€	1,100			$	6

Fair Value of Energy-Related Derivatives and Interest Rate Derivatives

The fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:

	As of September 30, 2020				As of December 31, 2019
Derivative Category and Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
	(in millions)				(in millions)
Southern Company
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	52	$	13	$	3	$	70
Other deferred charges and assets/Other deferred credits and liabilities	30		15		6		44
Total derivatives designated as hedging instruments for regulatory purposes	$	82	$	28	$	9	$	114
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	8	$	3	$	1	$	6
Other deferred charges and assets/Other deferred credits and liabilities	2		—		—		—
Interest rate derivatives:
Other current assets/Other current liabilities	19		—		2		23
Other deferred charges and assets/Other deferred credits and liabilities	—		—		—		1
Foreign currency derivatives:
Other current assets/Other current liabilities	—		23		—		24
Other deferred charges and assets/Other deferred credits and liabilities	29		—		16		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	58	$	26	$	19	$	54
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	392	$	428	$	461	$	358
Other deferred charges and assets/Other deferred credits and liabilities	338		291		207		225
Total derivatives not designated as hedging instruments	$	730	$	719	$	668	$	583
Gross amounts recognized	$	870	$	773	$	696	$	751
Gross amounts offset(a)	(636)		(706)		(463)		(562)
Net amounts recognized in the Balance Sheets(b)	$	234	$	67	$	233	$	189

	As of September 30, 2020				As of December 31, 2019
Derivative Category and Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
	(in millions)				(in millions)
Alabama Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	14	$	2	$	2	$	14
Other deferred charges and assets/Other deferred credits and liabilities	9		4		2		10
Total derivatives designated as hedging instruments for regulatory purposes	$	23	$	6	$	4	$	24
Gross amounts recognized	$	23	$	6	$	4	$	24
Gross amounts offset	(5)		(5)		(2)		(2)
Net amounts recognized in the Balance Sheets	$	18	$	1	$	2	$	22
Georgia Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	18	$	3	$	1	$	32
Other deferred charges and assets/Other deferred credits and liabilities	13		6		3		21
Total derivatives designated as hedging instruments for regulatory purposes	$	31	$	9	$	4	$	53
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	—	$	—	$	—	$	17
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	—	$	—	$	—	$	17
Gross amounts recognized	$	31	$	9	$	4	$	70
Gross amounts offset	(9)		(9)		(3)		(3)
Net amounts recognized in the Balance Sheets	$	22	$	—	$	1	$	67

	As of September 30, 2020				As of December 31, 2019
Derivative Category and Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
	(in millions)				(in millions)
Mississippi Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	10	$	2	$	—	$	15
Other deferred charges and assets/Other deferred credits and liabilities	8		5		1		12
Total derivatives designated as hedging instruments for regulatory purposes	$	18	$	7	$	1	$	27
Gross amounts recognized	$	18	$	7	$	1	$	27
Gross amounts offset	(7)		(7)		(1)		(1)
Net amounts recognized in the Balance Sheets	$	11	$	—	$	—	$	26
Southern Power
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	4	$	1	$	1	$	2
Other deferred charges and assets/Other deferred credits and liabilities	1		—		—		—
Foreign currency derivatives:
Other current assets/Other current liabilities	—		23		—		24
Other deferred charges and assets/Other deferred credits and liabilities	29		—		16		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	34	$	24	$	17	$	26
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	—	$	—	$	2	$	1
Total derivatives not designated as hedging instruments	$	—	$	—	$	2	$	1
Gross amounts recognized	$	34	$	24	$	19	$	27
Gross amounts offset	(1)		(1)		—		—
Net amounts recognized in the Balance Sheets	$	33	$	23	$	19	$	27

	As of September 30, 2020				As of December 31, 2019
Derivative Category and Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
	(in millions)				(in millions)
Southern Company Gas
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	10	$	6	$	—	$	9
Other deferred charges and assets/Other deferred credits and liabilities	—		—		—		1
Total derivatives designated as hedging instruments for regulatory purposes	$	10	$	6	$	—	$	10
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	4	$	2	$	—	$	4
Other deferred charges and assets/Other deferred credits and liabilities	1		—		—		—
Interest rate derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	—		—		2		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	5	$	2	$	2	$	4
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	392	$	428	$	459	$	357
Other deferred charges and assets/Other deferred credits and liabilities	338		291		207		225
Total derivatives not designated as hedging instruments	$	730	$	719	$	666	$	582
Gross amounts of recognized	$	745	$	727	$	668	$	596
Gross amounts offset(a)	(614)		(684)		(456)		(555)
Net amounts recognized in the Balance Sheets(b)	$	131	$	43	$	212	$	41

(a)Gross amounts offset include cash collateral held on deposit in broker margin accounts of $70 million and $99 million as of September 30, 2020 and December 31, 2019, respectively.

(b)Net amounts of derivative instruments outstanding exclude premium and intrinsic value associated with weather derivatives of $3 million and $4 million as of September 30, 2020 and December 31, 2019, respectively.

Pre-tax Effects of Unrealized Derivative Gains (Losses) Arising from Energy-Related Derivative Instruments

At September 30, 2020 and December 31, 2019, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Company Gas
	(in millions)
At September 30, 2020:
Energy-related derivatives:
Other regulatory assets, current	$	(5)	$	—	$	—	$	—	$	(5)
Other regulatory liabilities, current	41		12		15		8		6
Other regulatory liabilities, deferred	15		5		7		3		—
Total energy-related derivative gains (losses)	$	51	$	17	$	22	$	11	$	1
At December 31, 2019:
Energy-related derivatives:
Other regulatory assets, current	$	(63)	$	(14)	$	(31)	$	(15)	$	(3)
Other regulatory assets, deferred	(37)		(8)		(18)		(11)		—
Other regulatory liabilities, current	6		2		—		—		4
Total energy-related derivative gains (losses)	$	(94)	$	(20)	$	(49)	$	(26)	$	1

Pre-tax Effects of Interest Rate Derivatives, Designated as Cash Flow Hedging Instruments

For the three and nine months ended September 30, 2020 and 2019, the pre-tax effects of cash flow hedge accounting on accumulated OCI were as follows:

Gain (Loss) Recognized in OCI on Derivative	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)				(in millions)
Southern Company
Energy-related derivatives	$	9	$	(5)	$	2	$	(11)
Interest rate derivatives	1		(52)		(27)		(88)
Foreign currency derivatives	54		(68)		(10)		(107)
Total	$	64	$	(125)	$	(35)	$	(206)
Georgia Power
Interest rate derivatives	$	—	$	(47)	$	(3)	$	(83)
Southern Power
Energy-related derivatives	$	5	$	(3)	$	2	$	(5)
Foreign currency derivatives	54		(68)		(10)		(107)
Total	$	59	$	(71)	$	(8)	$	(112)
Southern Company Gas
Energy-related derivatives	$	4	$	(2)	$	—	$	(6)
Interest rate derivatives	1		(5)		(24)		(5)
Total	$	5	$	(7)	$	(24)	$	(11)

Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location

For the three and nine months ended September 30, 2020 and 2019, the pre-tax effects of cash flow and fair value hedge accounting on income were as follows:

Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)				(in millions)
Southern Company
Total cost of natural gas	$	71	$	79	$	654	$	956
Gain (loss) on energy-related cash flow hedges(a)	—		—		(8)		—
Total depreciation and amortization	889		760		2,619		2,267
Gain (loss) on energy-related cash flow hedges(a)	(1)		(1)		(3)		(5)
Total interest expense, net of amounts capitalized	(443)		(434)		(1,343)		(1,294)
Gain (loss) on interest rate cash flow hedges(a)	(6)		(5)		(19)		(14)
Gain (loss) on foreign currency cash flow hedges(a)	(6)		(6)		(18)		(18)
Gain (loss) on interest rate fair value hedges(b)	(3)		10		27		43
Total other income (expense), net	113		61		319		239
Gain (loss) on foreign currency cash flow hedges(a)(c)	56		(54)		52		(62)
Southern Power
Total depreciation and amortization	$	129	$	120	$	367	$	357
Gain (loss) on energy-related cash flow hedges(a)	(1)		(1)		(3)		(5)
Total interest expense, net of amounts capitalized	(36)		(43)		(114)		(127)
Gain (loss) on foreign currency cash flow hedges(a)	(6)		(6)		(18)		(18)
Total other income (expense), net	13		6		19		48
Gain (loss) on foreign currency cash flow hedges(a)(c)	56		(54)		52		(62)

(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.

Schedule of Fair Value Hedging Instruments, Statements of Financial Performance and Financial Position, Location

As of September 30, 2020 and December 31, 2019, the following amounts were recorded on the balance sheets related to cumulative basis adjustments for fair value hedges:

	Carrying Amount of the Hedged Item				Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item
Balance Sheet Location of Hedged Items	As of September 30, 2020		As of December 31, 2019		As of September 30, 2020		As of December 31, 2019
	(in millions)				(in millions)
Southern Company
Securities due within one year	$	(1,513)	$	(599)	$	(15)	$	—
Long-term debt	—		(1,494)		—		3

Pre-tax Effect of Interest Rate and Energy Related Derivatives

For the three and nine months ended September 30, 2020 and 2019, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income of Southern Company and Southern Company Gas were as follows:

		Gain (Loss)
		Three Months Ended September 30,				Nine Months Ended September 30,
Derivatives in Non-Designated Hedging Relationships	Statements of Income Location	2020		2019		2020		2019
		(in millions)				(in millions)
Energy-related derivatives:	Natural gas revenues(*)	$	(30)	$	(2)	$	54	$	81
	Cost of natural gas	5		2		18		5
Total derivatives in non-designated hedging relationships		$	(25)	$	—	$	72	$	86

(*)Excludes immaterial gains (losses) recorded in natural gas revenues associated with weather derivatives for all periods presented.

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ACQUISITIONS AND DISPOSITIONS (Tables)

9 Months Ended

Sep. 30, 2020

Business Combinations [Abstract]

Schedule of Asset Acquisitions

During the nine months ended September 30, 2020, Southern Power acquired a controlling interest in the wind facility listed below. Acquisition-related costs were expensed as incurred and were not material.

Project Facility	Resource	Seller	Approximate Nameplate Capacity (MW)	Location	Southern Power Ownership Percentage		COD	PPA Contract Period
Beech Ridge II	Wind	Invenergy Renewables LLC	56	Greenbrier County, West Virginia	100% of Class A	(*)	May 2020	12 years

(*)In May 2020, Southern Power purchased 100% of the Class A membership interests and now owns the controlling interest in the project, with the Class B member, Invenergy Renewables LLC, owning the noncontrolling interest.

Schedule of Construction Projects

Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Actual/Expected COD	PPA Contract Period
Projects Completed During the Nine Months Ended September 30, 2020
Reading(a)	Wind	200	Osage and Lyon Counties, KS	May 2020	12 years
Projects Under Construction as of September 30, 2020
Skookumchuck(b)	Wind	136	Lewis and Thurston Counties, WA	November 2020	20 years
Garland Solar Storage(c)	Battery energy storage system	88	Kern County, CA	Second quarter 2021	20 years
Tranquillity Solar Storage(c)	Battery energy storage system	72	Fresno County, CA	Second quarter 2021	20 years

(a)In 2018, Southern Power purchased 100% of the membership interests of the Reading facility pursuant to a joint development arrangement. At the time the facility was placed in service, Southern Power recorded an operating lease right-of-use asset and an operating lease liability, each in the amount of $24 million. In June 2020, Southern Power completed a tax equity transaction whereby it received $156 million and now owns 100% of the Class B membership interests.

(b)In October 2019, Southern Power purchased 100% of the membership interests of the Skookumchuck facility pursuant to a joint development arrangement. Southern Power expects to complete a tax equity transaction upon commercial operation and retain the Class B membership interests. Shortly after the completed tax equity transaction, Southern Power may sell a noncontrolling interest in these Class B membership interests to another partner. Southern Power would retain the controlling ownership interest in the facility. The ultimate outcome of these matters cannot be determined at this time.

(c)Prior to commercial operation, Southern Power may enter into one or more partnerships, in which case it would ultimately own less than 100% of the Class B membership interests, but would retain ownership of the controlling interest. The ultimate outcome of this matter cannot be determined at this time.

Disposal Groups, Including Discontinued Operations

Plants Nacogdoches (sold in June 2019) and Mankato represented individually significant components of Southern Power; therefore, pre-tax income for these components for the three months ended September 30, 2019 and the nine months ended September 30, 2020 and 2019 is presented below:

	Three Months Ended September 30, 2019		Nine Months Ended September 30,
			2020		2019
	(in millions)
Southern Power's earnings before income taxes:(*)
Plant Nacogdoches	$	—	N/A		$	16
Plant Mankato	$	12	$	2	$	20

(*)Earnings before income taxes for components reflect the cessation of depreciation and amortization on the long-lived assets being sold upon classification as held for sale in November 2018 and April 2019 for Plant Mankato and Plant Nacogdoches, respectively.

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SEGMENT AND RELATED INFORMATION (Tables)

9 Months Ended

Sep. 30, 2020

Segment Reporting [Abstract]

Financial Data for Business Segments

Financial data for business segments and products and services for the three and nine months ended September 30, 2020 and 2019 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, 2020
Operating revenues	$	4,629	$	523	$	(103)	$	5,049	$	477	$	132	$	(38)	$	5,620
Segment net income (loss)(a)	1,284		74		—		1,358		14		(122)		1		1,251
Nine Months Ended September 30, 2020
Operating revenues	$	11,576	$	1,337	$	(285)	$	12,628	$	2,362	$	380	$	(112)	$	15,258
Segment net income (loss)(a)(b)(c)(d)	2,571		212		—		2,783		360		(420)		9		2,732
At September 30, 2020
Goodwill	$	—	$	2	$	—	$	2	$	5,015	$	263	$	—	$	5,280
Total assets	85,218		13,424		(671)		97,971		21,932		4,116		(861)		123,158
Three Months Ended September 30, 2019
Operating revenues	$	4,908	$	574	$	(119)	$	5,363	$	498	$	146	$	(12)	$	5,995
Segment net income (loss)(a)(e)(f)	1,373		86		—		1,459		(29)		(110)		(4)		1,316
Nine Months Ended September 30, 2019
Operating revenues	$	12,252	$	1,527	$	(331)	$	13,448	$	2,661	$	514	$	(118)	$	16,505
Segment net income (loss)(a)(e)(f)(g)	2,719		316		—		3,035		347		931		(15)		4,298
At December 31, 2019
Goodwill	$	—	$	2	$	—	$	2	$	5,015	$	263	$	—	$	5,280
Total assets	81,063		14,300		(713)		94,650		21,687		3,511		(1,148)		118,700

(a)Attributable to Southern Company.

(b)Segment net income (loss) for the traditional electric operating companies includes a pre-tax charge of $149 million ($111 million after tax) related to Plant Vogtle Units 3 and 4. See Note (B) under "Georgia Power – Nuclear Construction" for additional information.

(c)Segment net income (loss) for the "All Other" column includes a pre-tax impairment charge of $154 million ($74 million after tax) related to a leveraged lease investment. See Note (C) under "Other Matters – Southern Company" for additional information.

(d)Segment net income (loss) for Southern Power includes a $39 million pre-tax gain ($23 million gain after tax) on the sale of Plant Mankato. See Note (K) under "Southern Power" for additional information.

(e)Segment net income (loss) for Southern Company Gas includes a pre-tax impairment charge of $92 million ($65 million after tax) related to a natural gas storage facility in Louisiana. See Note 3 to the financial statements under "Other Matters – Southern Company Gas – Natural Gas Storage Facilities" in Item 8 of the Form 10-K for additional information.

(f)Segment net income (loss) for the "All Other" column includes the preliminary pre-tax gain associated with the sale of Gulf Power of $2.5 billion ($1.3 billion after tax) for the nine months ended September 30, 2019, as well as impairment charges in contemplation of the sales of two of PowerSecure's business units totaling $18 million and $50 million for the three and nine months ended September 30, 2019, respectively. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company" for additional information.

(g)Segment net income (loss) for Southern Power includes a $23 million pre-tax gain ($88 million gain after tax) on the sale of Plant Nacogdoches. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power – Sale of Natural Gas and Biomass Plants" for additional information.

Business segment financial data for the three and nine months ended September 30, 2020 and 2019 was as follows:

	Gas Distribution Operations		Gas Pipeline Investments		Wholesale Gas Services(a)		Gas Marketing Services		Total		All Other(b)		Eliminations		Consolidated
	(in millions)
Three Months Ended September 30, 2020
Operating revenues	$	479	$	8	$	(51)	$	39	$	475	$	8	$	(6)	$	477
Segment net income (loss)	46		23		(45)		(3)		21		(7)		—		14
Nine Months Ended September 30, 2020
Operating revenues	$	2,086	$	24	$	(19)	$	272	$	2,363	$	24	$	(25)	$	2,362
Segment net income (loss)	284		74		(45)		59		372		(12)		—		360
Total assets at September 30, 2020	18,715		1,609		650		1,461		22,435		10,979		(11,482)		21,932
Three Months Ended September 30, 2019
Operating revenues	$	448	$	8	$	(2)	$	39	$	493	$	10	$	(5)	$	498
Segment net income (loss)	37		6		(9)		(4)		30		(59)		—		(29)
Nine Months Ended September 30, 2019
Operating revenues	$	2,188	$	24	$	132	$	326	$	2,670	$	34	$	(43)	$	2,661
Segment net income (loss)	228		63		61		54		406		(59)		—		347
Total assets at December 31, 2019	18,204		1,678		850		1,496		22,228		10,759		(11,300)		21,687

(a)The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table.

	Third Party Gross Revenues		Intercompany Revenues		Total Gross Revenues		Less Gross Gas Costs		Operating Revenues
	(in millions)
Three Months Ended September 30, 2020	$	1,050	$	33	$	1,083	$	1,134	$	(51)
Three Months Ended September 30, 2019	1,138		72		1,210		1,212		(2)
Nine Months Ended September 30, 2020	$	3,089	$	81	$	3,170	$	3,189	$	(19)
Nine Months Ended September 30, 2019	4,287		223		4,510		4,378		132

(b)Segment net income (loss) for the "All Other" column includes a pre-tax impairment charge of $92 million ($65 million after tax) for the three and nine months ended September 30, 2019 related to a natural gas storage facility in Louisiana. See Note 3 to the financial statements under "Other Matters – Southern Company Gas – Natural Gas Storage Facilities" in Item 8 of the Form 10-K for additional information.

Financial Data for Products and Services

	Electric Utilities' Revenues
	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended September 30, 2020	$	4,243	$	584	$	222	$	5,049
Three Months Ended September 30, 2019	4,512		625		226		5,363
Nine Months Ended September 30, 2020	$	10,503	$	1,473	$	652	$	12,628
Nine Months Ended September 30, 2019	11,136		1,667		645		13,448

	Southern Company Gas' Revenues
	Gas Distribution Operations		Wholesale Gas Services(*)		Gas Marketing Services		Other		Total
	(in millions)
Three Months Ended September 30, 2020	$	476	$	(51)	$	39	$	13	$	477
Three Months Ended September 30, 2019	445		(2)		39		16		498
Nine Months Ended September 30, 2020	$	2,072	$	(19)	$	272	$	37	$	2,362
Nine Months Ended September 30, 2019	2,169		132		326		34		2,661

(*)The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. See "Southern Company Gas" herein for additional information.

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INTRODUCTION - Narrative (Details) $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended
	Jun. 30, 2020 USD ($) facility	Sep. 30, 2020 USD ($)	Mar. 31, 2020	Sep. 30, 2020 USD ($)	Sep. 30, 2019 USD ($)	Dec. 31, 2019 USD ($)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Goodwill		$ 5,280		$ 5,280		$ 5,280
SOUTHERN Co GAS
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Goodwill		5,015		5,015		$ 5,015
Inventory decrement					$ 10
ALABAMA POWER CO
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Asset retirement obligation, period increase	$ 462
Number of facilities, closure designs completed | facility	1
GEORGIA POWER CO
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Asset retirement obligation, period increase		411
PowerSecure
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Goodwill		$ 263		$ 263
Maximum | Natural Gas Generating Facility | SOUTHERN POWER CO
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Property, plant and equipment, useful life			45 years	50 years

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INTRODUCTION - Goodwill (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Goodwill [Line Items]
Goodwill	$ 5,280	$ 5,280
SOUTHERN Co GAS
Goodwill [Line Items]
Goodwill	5,015	5,015
SOUTHERN Co GAS | Gas Distribution Operations
Goodwill [Line Items]
Goodwill	4,034	4,034
SOUTHERN Co GAS | Gas Marketing Services
Goodwill [Line Items]
Goodwill	$ 981	$ 981

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INTRODUCTION - Other Intangible Assets (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Other intangible assets subject to amortization:
Gross Carrying Amount	$ 740	$ 741
Accumulated Amortization	(316)	(280)
Other Intangible Assets, Net	424	461
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	75	75
Total other intangible assets
Gross Carrying Amount	815	816
Accumulated Amortization	(316)	(280)
Other Intangible Assets, Net	499	536
Customer relationships
Other intangible assets subject to amortization:
Gross Carrying Amount	212	212
Accumulated Amortization	(130)	(116)
Other Intangible Assets, Net	82	96
Total other intangible assets
Accumulated Amortization	(130)	(116)
Trade names
Other intangible assets subject to amortization:
Gross Carrying Amount	64	64
Accumulated Amortization	(30)	(25)
Other Intangible Assets, Net	34	39
Total other intangible assets
Accumulated Amortization	(30)	(25)
Storage and transportation contracts
Other intangible assets subject to amortization:
Gross Carrying Amount	64	64
Accumulated Amortization	(64)	(62)
Other Intangible Assets, Net	0	2
Total other intangible assets
Accumulated Amortization	(64)	(62)
PPA fair value adjustments
Other intangible assets subject to amortization:
Gross Carrying Amount	390	390
Accumulated Amortization	(84)	(69)
Other Intangible Assets, Net	306	321
Total other intangible assets
Accumulated Amortization	(84)	(69)
Other
Other intangible assets subject to amortization:
Gross Carrying Amount	10	11
Accumulated Amortization	(8)	(8)
Other Intangible Assets, Net	2	3
Total other intangible assets
Accumulated Amortization	(8)	(8)
SOUTHERN POWER CO
Other intangible assets subject to amortization:
Accumulated Amortization	(84)	(69)
Total other intangible assets
Accumulated Amortization	(84)	(69)
SOUTHERN POWER CO | PPA fair value adjustments
Other intangible assets subject to amortization:
Gross Carrying Amount	390	390
Accumulated Amortization	(84)	(69)
Other Intangible Assets, Net	306	321
Total other intangible assets
Accumulated Amortization	(84)	(69)
SOUTHERN Co GAS
Other intangible assets subject to amortization:
Gross Carrying Amount	246	246
Accumulated Amortization	(191)	(176)
Other Intangible Assets, Net	55	70
Total other intangible assets
Accumulated Amortization	(191)	(176)
Other Intangible Assets, Net	55	70
SOUTHERN Co GAS | Customer relationships
Other intangible assets subject to amortization:
Gross Carrying Amount	156	156
Accumulated Amortization	(115)	(104)
Other Intangible Assets, Net	41	52
Total other intangible assets
Accumulated Amortization	(115)	(104)
SOUTHERN Co GAS | Trade names
Other intangible assets subject to amortization:
Gross Carrying Amount	26	26
Accumulated Amortization	(12)	(10)
Other Intangible Assets, Net	14	16
Total other intangible assets
Accumulated Amortization	(12)	(10)
SOUTHERN Co GAS | Storage and transportation contracts
Other intangible assets subject to amortization:
Gross Carrying Amount	64	64
Accumulated Amortization	(64)	(62)
Other Intangible Assets, Net	0	2
Total other intangible assets
Accumulated Amortization	$ (64)	$ (62)

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INTRODUCTION - Other Intangible Assets, Amortization (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2020	Sep. 30, 2020
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	$ 12	$ 37
Decrease in operating revenues	6	17
SOUTHERN POWER CO
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	5	15
SOUTHERN Co GAS
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	5	15
Gas Marketing Services | SOUTHERN Co GAS
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	4	13
Wholesale Gas Services | SOUTHERN Co GAS
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	$ 1	$ 2

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INTRODUCTION - Restricted Cash (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019	Sep. 30, 2019	Dec. 31, 2018
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents	$ 3,379	$ 1,975
Restricted cash:
Total cash, cash equivalents, and restricted cash	3,383	1,978	$ 2,935	$ 1,519
Other accounts and notes receivable
Restricted cash:
Restricted cash	0	3
Other current assets
Restricted cash:
Restricted cash	4	0
Other deferred charges and assets
Restricted cash:
Restricted cash	1	0
SOUTHERN POWER CO
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents	416	279
Restricted cash:
Total cash, cash equivalents, and restricted cash	417	279	368	181
SOUTHERN POWER CO | Other accounts and notes receivable
Restricted cash:
Restricted cash	0
SOUTHERN POWER CO | Other current assets
Restricted cash:
Restricted cash	0
SOUTHERN POWER CO | Other deferred charges and assets
Restricted cash:
Restricted cash	1
SOUTHERN Co GAS
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents	157	46
Restricted cash:
Total cash, cash equivalents, and restricted cash	161	49	$ 62	$ 70
SOUTHERN Co GAS | Other accounts and notes receivable
Restricted cash:
Restricted cash	0	3
SOUTHERN Co GAS | Other current assets
Restricted cash:
Restricted cash	4	0
SOUTHERN Co GAS | Other deferred charges and assets
Restricted cash:
Restricted cash	$ 0	$ 0

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INTRODUCTION - Asset Retirement Obligations (Details) $ in Millions	9 Months Ended
	Sep. 30, 2020 USD ($)
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at December 31, 2019	$ 9,786
Liabilities incurred	15
Liabilities settled	(315)
Accretion	308
Cash flow revisions	866
Balance at September 30, 2020	10,660
ALABAMA POWER CO
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at December 31, 2019	3,540
Liabilities incurred	0
Liabilities settled	(157)
Accretion	113
Cash flow revisions	462
Balance at September 30, 2020	3,958
GEORGIA POWER CO
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at December 31, 2019	5,784
Liabilities incurred	10
Liabilities settled	(130)
Accretion	177
Cash flow revisions	411
Balance at September 30, 2020	$ 6,252

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REGULATORY MATTERS - Cost Recovery Clauses (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
ALABAMA POWER CO | Other regulatory liabilities, current
Loss Contingencies [Line Items]
Rate CNP Compliance	$ 12	$ 55
Retail Energy Cost Recovery	107	32
Natural Disaster Reserve	7	37
ALABAMA POWER CO | Other regulatory liabilities, deferred
Loss Contingencies [Line Items]
Rate CNP Compliance	38	7
Retail Energy Cost Recovery	16	17
Natural Disaster Reserve	51	113
ALABAMA POWER CO | Deferred under recovered regulatory clause revenues
Loss Contingencies [Line Items]
Rate CNP PPA	62	40
GEORGIA POWER CO | Over recovered fuel clause revenues
Loss Contingencies [Line Items]
Fuel Cost Recovery	84	0
GEORGIA POWER CO | Other deferred credits and liabilities
Loss Contingencies [Line Items]
Fuel Cost Recovery	67	73
MISSISSIPPI POWER CO | Other regulatory liabilities, deferred
Loss Contingencies [Line Items]
Property Damage Reserve	48	54
MISSISSIPPI POWER CO | Over recovered regulatory clause liabilities
Loss Contingencies [Line Items]
Fuel Cost Recovery	23	23
MISSISSIPPI POWER CO | Other regulatory assets
Loss Contingencies [Line Items]
Ad Valorem Tax	11	47
MISSISSIPPI POWER CO | Other regulatory assets, deferred
Loss Contingencies [Line Items]
Ad Valorem Tax	36	0
SOUTHERN Co GAS | Other regulatory liabilities
Loss Contingencies [Line Items]
Natural Gas Cost Recovery	$ 84	$ 74

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REGULATORY MATTERS - Alabama Power (Details) - ALABAMA POWER CO $ in Millions	3 Months Ended
	Sep. 30, 2020 USD ($)	Aug. 14, 2020 USD ($) MW	Aug. 07, 2020 USD ($)
Public Utilities, General Disclosures [Line Items]
Approved additional generating capacity, purchases (in MWs) | MW		240
Approved additional generating capacity, demand-side management and distributed energy resource programs (in MWs) | MW		200
Additional generating capacity (in MWs) | MW		400
Bill credits			$ 100
Decrease in NDR for damages incurred	$ 44
Natural disaster reserve	51
Minimum natural disaster reserve balance, triggering establishment charge	50
Natural disaster reserve authorized limit	$ 75
Plant Barry Unit 8
Public Utilities, General Disclosures [Line Items]
Approved additional generating capacity, construction (in MWs) | MW		720
Costs incurred, percentage of estimated in-service costs		5.00%
Estimated in-service cost		$ 652

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REGULATORY MATTERS - Georgia Power (Details) - GEORGIA POWER CO - USD ($)		4 Months Ended	9 Months Ended
	May 28, 2020	Sep. 30, 2020	Sep. 30, 2020	Oct. 01, 2020	Dec. 31, 2019	Dec. 31, 2013
Public Utilities, General Disclosures [Line Items]
Retail rate of return on common equity						10.95%
Customer refund liability in absence of base rate case					$ 60,000,000
Portion of actual earnings above approved ROE band refunded to customers, value					$ 60,000,000
Incremental COVID-19 costs deferred		$ 38,000,000	$ 38,000,000
Requested decrease in fuel billings	$ 740,000,000	$ 44,000,000
Requested decrease in fuel billings, term	2 years
Adjustment to fuel cost recovery rate if under recovered fuel balance exceeds budget thereafter			$ 200,000,000
Subsequent Event | Traditional Base
Public Utilities, General Disclosures [Line Items]
Requested rate increase (decrease), amount, due in next fiscal year				$ 120,000,000
Subsequent Event | Environmental Compliance Cost Recovery
Public Utilities, General Disclosures [Line Items]
Requested rate increase (decrease), amount, due in next fiscal year				2,000,000
Subsequent Event | Demand-Side Management
Public Utilities, General Disclosures [Line Items]
Requested rate increase (decrease), amount, due in next fiscal year				(15,000,000)
Subsequent Event | Municipal Franchise Fee
Public Utilities, General Disclosures [Line Items]
Requested rate increase (decrease), amount, due in next fiscal year				$ 4,000,000
Maximum
Public Utilities, General Disclosures [Line Items]
Retail rate of return on common equity					12.00%

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REGULATORY MATTERS - Nuclear Construction (Details) $ in Millions						1 Months Ended			3 Months Ended	9 Months Ended	12 Months Ended
	Jan. 01, 2021	Aug. 31, 2020 USD ($)	Jan. 01, 2020	Jan. 11, 2018 USD ($)	Jan. 01, 2016	Apr. 30, 2020	Dec. 31, 2019 USD ($) report	Dec. 31, 2018 appeal	Sep. 30, 2020 USD ($)	Sep. 30, 2020 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($) report	Dec. 31, 2012 utility MW	Dec. 31, 2009 USD ($)	Jun. 30, 2020 USD ($)	Aug. 31, 2018	Jun. 30, 2018 USD ($)	Dec. 31, 2013
Loss Contingencies [Line Items]
Construction contingency estimate									$ 5	$ 5
GEORGIA POWER CO
Loss Contingencies [Line Items]
Additional construction capital costs				$ 3,300
Estimated in-service capital cost																$ 4,418
Financing costs collected, net of tax										$ 2,500
Decrease in NCCR tariff							$ 142
Amendment to estimated in-service capital cost				$ 5,680
Retail rate of return on common equity																				10.95%
Number of appeals | appeal								2
GEORGIA POWER CO | Plant Vogtle Units 3 And 4
Loss Contingencies [Line Items]
Proportionate ownership share									45.70%	45.70%
Number of construction units approved | utility															2
Electric generating capacity in mega watts under consortium agreement | MW															1,100
Construction costs incurred										$ 2,500
Construction contingency estimate																			$ 366
Construction contingency estimate, amount in excess of original estimate																	$ 34
Construction contingency estimate, additional amount									$ 115	115
Estimated loss on Plant Vogtle Units 3 and 4									149	149
Estimated loss on plants under construction, after tax									111	111
Expected percentage of positions eliminated						20.00%
Base project capital cost forecast, monthly										50
Monthly AFUDC										10
Percentage of ownership interest required for voting for continuing construction																		90.00%
Production tax credits, aggregate purchase price, maximum										300
Preliminary estimated cost to complete									8,500	$ 8,500
Remaining share of construction costs, agreement to pay, percentage										100.00%
Percentage of costs, disallowed for recovery										6.00%
Costs disallowed for recovery, period										6 months
Public utilities, extension project schedule, term										1 year
Cost settlement agreement revised forecast, net of payments									7,300	$ 7,300
Public utilities, approved return on equity percentage			8.30%		10.00%
Public utilities, approved return on equity, monthly percentage decrease										0.10%
Return on equity reduction, negative impact on earnings														$ 75
GEORGIA POWER CO | Plant Vogtle Units 3 And 4 | Scenario, Forecast
Loss Contingencies [Line Items]
Construction costs incurred													$ 3,000
Public utilities, approved return on equity percentage	5.30%
Return on equity reduction, negative impact on earnings											$ 200	$ 255	$ 145
GEORGIA POWER CO | Plant Vogtle Units 3 And 4 | Vogtle Owners
Loss Contingencies [Line Items]
Period of notice required in the event letters of credit are not renewed										30 days
Twenty Second Construction Monitoring Report | GEORGIA POWER CO | Plant Vogtle Units 3 And 4
Loss Contingencies [Line Items]
Number of approved construction management reports | report							22							22
Requested capital construction costs														$ 7,400
Guarantor obligations							$ 1,700							1,700
Customer refund														$ 188
Twenty Third Construction Monitoring Report | GEORGIA POWER CO | Plant Vogtle Units 3 And 4
Loss Contingencies [Line Items]
Requested capital construction costs		$ 701
Minimum | GEORGIA POWER CO | COVID-19
Loss Contingencies [Line Items]
Estimate of possible loss									70	$ 70
Maximum | GEORGIA POWER CO
Loss Contingencies [Line Items]
Retail rate of return on common equity							12.00%							12.00%
Maximum | GEORGIA POWER CO | COVID-19
Loss Contingencies [Line Items]
Estimate of possible loss									115	115
Category I | GEORGIA POWER CO | Plant Vogtle Units 3 And 4
Loss Contingencies [Line Items]
Preliminary estimated cost to complete									$ 8,400	8,400
Additional construction capital costs, threshold										$ 800
Category II | GEORGIA POWER CO | Plant Vogtle Units 3 And 4
Loss Contingencies [Line Items]
Percentage of construction costs, responsibility to pay										55.70%
Additional construction capital costs										$ 80
Category II | GEORGIA POWER CO | Plant Vogtle Units 3 And 4 | Vogtle Owners
Loss Contingencies [Line Items]
Percentage of construction costs, responsibility to pay										44.30%
Category II | Minimum | GEORGIA POWER CO | Plant Vogtle Units 3 And 4
Loss Contingencies [Line Items]
Additional construction capital costs, threshold										$ 800
Category II | Maximum | GEORGIA POWER CO | Plant Vogtle Units 3 And 4
Loss Contingencies [Line Items]
Additional construction capital costs, threshold										$ 1,600
Category III | GEORGIA POWER CO | Plant Vogtle Units 3 And 4
Loss Contingencies [Line Items]
Percentage of construction costs, responsibility to pay										65.70%
Additional construction capital costs										$ 100
Category III | GEORGIA POWER CO | Plant Vogtle Units 3 And 4 | Vogtle Owners
Loss Contingencies [Line Items]
Percentage of construction costs, responsibility to pay										34.30%
Category III | Maximum | GEORGIA POWER CO | Plant Vogtle Units 3 And 4
Loss Contingencies [Line Items]
Additional construction capital costs, threshold										$ 2,100

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REGULATORY MATTERS - Nuclear Construction Cost and Schedule (Details) - GEORGIA POWER CO - Plant Vogtle Units 3 And 4 $ in Millions	9 Months Ended
	Sep. 30, 2020 USD ($)
Loss Contingencies [Line Items]
Base project capital cost forecast	$ 8,400
Construction contingency estimate	100
Total project capital cost forecast	8,500
Net investment as of September 30, 2019	(6,900)
Remaining estimate to complete	1,600
Expected capitalized costs	240
Capitalized interest accrued	$ 71

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REGULATORY MATTERS - Mississippi Power (Details) - MISSISSIPPI POWER CO - USD ($) $ in Millions	Jun. 25, 2020	Mar. 17, 2020	Sep. 30, 2020
Loss Contingencies [Line Items]
Decrease in retail rates, percentage		1.85%
Base rate case filing, measurement input, average equity ratio		53.00%
Base rate case filing, measurement input, maximum equity ratio		55.00%
Base rate case filing, measurement input, return on investment		7.57%
Regulatory asset, amortization period		4 years
Regulatory liability, amortization period		3 years
Annual base rate adjustment, increase in depreciation		$ 10.0
Annual base rate adjustment, compensation costs excluded		3.9
Incremental COVID-19 costs deferred			$ 2.0
Increase in retail rates	$ 2.0	$ (16.7)

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REGULATORY MATTERS - Southern Company Gas (Details) - USD ($) $ in Millions	Jul. 01, 2020	Jun. 01, 2020	Sep. 30, 2020
Nicor Gas
Loss Contingencies [Line Items]
Requested rate increase		$ 49.6
Requested rate increase, projected test year, period		12 months
Requested return on equity percentage		10.35%
Requested equity ratio percentage		54.00%
Atlanta Gas Light
Loss Contingencies [Line Items]
Requested rate increase	$ 37.6
Requested rate increase, projected test year, period	12 months
Maximum base rate	5.00%
COVID-19 | Nicor Gas
Loss Contingencies [Line Items]
Regulatory assets			$ 13.0
COVID-19 | Virginia Natural Gas
Loss Contingencies [Line Items]
Regulatory assets			$ 1.0

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CONTINGENCIES - General Litigation Matters (Details) $ in Millions	1 Months Ended				3 Months Ended	12 Months Ended
	Sep. 30, 2019 USD ($)	Mar. 31, 2019 plaintiff	Nov. 30, 2018 USD ($) defendant plaintiff	May 31, 2018 USD ($) agreement	Sep. 30, 2020 USD ($)	Dec. 31, 2018	Dec. 31, 2017 claim
Pending Litigation | Putative Securities Class Action
Loss Contingencies [Line Items]
Increase in the purported class period							1 day
Pending Litigation | Shareholder Derivative Lawsuits
Loss Contingencies [Line Items]
Pending number of claims | claim							2
Stay period						30 days
MISSISSIPPI POWER CO | Pending Litigation | Purported Violations Of Mississippi Consumer Protection Act
Loss Contingencies [Line Items]
Number of plaintiffs | plaintiff		4	10
Number of defendants | defendant			3
Underpayment of refunds			$ 23.5
MISSISSIPPI POWER CO | Settled Litigation | Martin Product Sales, LLC Litigation
Loss Contingencies [Line Items]
Number of agreements | agreement				2
Damages sought by litigation				$ 143.0	$ 76.0
Compensatory damages sought by litigation	$ 5.0
Punitive damages sought by litigation	$ 50.0

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CONTINGENCIES - Environmental Remediation (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
GEORGIA POWER CO
Loss Contingencies [Line Items]
Environmental remediation liability, current and former sites	$ 15	$ 15
SOUTHERN Co GAS
Loss Contingencies [Line Items]
Environmental remediation liability, current and former sites	$ 252	$ 269

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CONTINGENCIES - Other Matters (Details) - USD ($) $ in Millions				1 Months Ended	3 Months Ended					9 Months Ended		12 Months Ended
	Apr. 24, 2020	Apr. 23, 2020	Feb. 20, 2020	Dec. 31, 2019	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Sep. 30, 2019	Mar. 31, 2019	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Loss Contingencies [Line Items]
Leveraged lease investments impairment loss						$ 0	$ 154	$ 0		$ 154	$ 0
Leveraged lease investments impairment loss, net of tax							$ 74
Liabilities settled										315
Liabilities incurred										15
MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
Firm transportation agreement, term				15 years
MISSISSIPPI POWER CO | Kemper IGCC
Loss Contingencies [Line Items]
Liabilities settled										2
Government grants received									$ 387
MISSISSIPPI POWER CO | Scenario, Forecast | Kemper IGCC
Loss Contingencies [Line Items]
Liabilities incurred					$ 3
GULF POWER CO | Plant Daniel Units 1 And 2
Loss Contingencies [Line Items]
Undivided ownership interest to be restructured		50.00%
Undivided ownership interest, ownership interest in individual unit	100.00%	100.00%
Minimum | MISSISSIPPI POWER CO | Scenario, Forecast | Kemper IGCC
Loss Contingencies [Line Items]
Liabilities incurred												$ 10	$ 10	$ 10	$ 10	$ 10
Maximum | MISSISSIPPI POWER CO | Scenario, Forecast | Kemper IGCC
Loss Contingencies [Line Items]
Liabilities incurred												$ 15	$ 15	$ 15	$ 15	$ 15
PennEast Pipelines
Loss Contingencies [Line Items]
Construction contingency, extension request, term			2 years
PennEast Pipelines | SOUTHERN Co GAS
Loss Contingencies [Line Items]
Construction contingency estimate						$ 300				$ 300

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REVENUE FROM CONTRACTS WITH CUSTOMERS AND LEASE INCOME - Disaggregate Revenue Sources (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Disaggregation of Revenue [Line Items]
Operating revenues	$ 5,755	$ 6,282	$ 15,771	$ 17,415
Revenues	5,620	5,995	15,258	16,505
Total retail electric revenues
Disaggregation of Revenue [Line Items]
Operating revenues	4,178	4,661	10,540	11,387
Residential
Disaggregation of Revenue [Line Items]
Operating revenues	2,019	2,119	4,802	4,939
Commercial
Disaggregation of Revenue [Line Items]
Operating revenues	1,354	1,563	3,589	3,951
Industrial
Disaggregation of Revenue [Line Items]
Operating revenues	783	953	2,081	2,428
Other
Disaggregation of Revenue [Line Items]
Operating revenues	22	26	68	69
Natural gas distribution revenues
Disaggregation of Revenue [Line Items]
Operating revenues	474	441	2,058	2,158
Residential
Disaggregation of Revenue [Line Items]
Operating revenues	170	162	906	992
Commercial
Disaggregation of Revenue [Line Items]
Operating revenues	41	42	229	277
Transportation
Disaggregation of Revenue [Line Items]
Operating revenues	224	204	723	673
Industrial
Disaggregation of Revenue [Line Items]
Operating revenues	4	3	21	25
Other
Disaggregation of Revenue [Line Items]
Operating revenues	35	30	179	191
Wholesale electric revenues
Disaggregation of Revenue [Line Items]
Operating revenues	409	441	1,048	1,172
PPA energy revenues
Disaggregation of Revenue [Line Items]
Operating revenues	214	245	550	648
PPA capacity revenues
Disaggregation of Revenue [Line Items]
Operating revenues	136	134	339	350
Non-PPA revenues
Disaggregation of Revenue [Line Items]
Operating revenues	59	62	159	174
Other natural gas revenues
Disaggregation of Revenue [Line Items]
Operating revenues	476	472	1,448	1,935
Wholesale gas services
Disaggregation of Revenue [Line Items]
Operating revenues	431	425	1,168	1,590
Gas marketing services
Disaggregation of Revenue [Line Items]
Operating revenues	38	37	258	313
Other natural gas revenues
Disaggregation of Revenue [Line Items]
Operating revenues	7	10	22	32
Other revenues
Disaggregation of Revenue [Line Items]
Operating revenues	218	267	677	763
Other revenue sources
Disaggregation of Revenue [Line Items]
Other	968	855	2,604	3,266
Other adjustments
Disaggregation of Revenue [Line Items]
Other	(1,103)	(1,142)	(3,117)	(4,176)
ALABAMA POWER CO
Disaggregation of Revenue [Line Items]
Operating revenues	1,671	1,866	4,285	4,791
Revenues	1,729	1,841	4,445	4,762
ALABAMA POWER CO | Total retail electric revenues
Disaggregation of Revenue [Line Items]
Operating revenues	1,562	1,760	3,963	4,420
ALABAMA POWER CO | Residential
Disaggregation of Revenue [Line Items]
Operating revenues	752	820	1,839	1,971
ALABAMA POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Operating revenues	447	512	1,152	1,301
ALABAMA POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Operating revenues	358	421	956	1,128
ALABAMA POWER CO | Other
Disaggregation of Revenue [Line Items]
Operating revenues	5	7	16	20
ALABAMA POWER CO | Natural gas distribution revenues
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
ALABAMA POWER CO | Residential
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
ALABAMA POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
ALABAMA POWER CO | Transportation
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
ALABAMA POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
ALABAMA POWER CO | Other
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
ALABAMA POWER CO | Wholesale electric revenues
Disaggregation of Revenue [Line Items]
Operating revenues	76	70	205	252
ALABAMA POWER CO | PPA energy revenues
Disaggregation of Revenue [Line Items]
Operating revenues	40	43	94	110
ALABAMA POWER CO | PPA capacity revenues
Disaggregation of Revenue [Line Items]
Operating revenues	26	25	78	77
ALABAMA POWER CO | Non-PPA revenues
Disaggregation of Revenue [Line Items]
Operating revenues	10	2	33	65
ALABAMA POWER CO | Other natural gas revenues
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
ALABAMA POWER CO | Wholesale gas services
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
ALABAMA POWER CO | Gas marketing services
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
ALABAMA POWER CO | Other natural gas revenues
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
ALABAMA POWER CO | Other revenues
Disaggregation of Revenue [Line Items]
Operating revenues	33	36	117	119
ALABAMA POWER CO | Other revenue sources
Disaggregation of Revenue [Line Items]
Other	58	(25)	160	(29)
ALABAMA POWER CO | Other adjustments
Disaggregation of Revenue [Line Items]
Other	0	0	0	0
GEORGIA POWER CO
Disaggregation of Revenue [Line Items]
Operating revenues	2,529	2,790	6,359	6,684
Revenues	2,617	2,755	6,371	6,706
GEORGIA POWER CO | Total retail electric revenues
Disaggregation of Revenue [Line Items]
Operating revenues	2,383	2,642	5,955	6,293
GEORGIA POWER CO | Residential
Disaggregation of Revenue [Line Items]
Operating revenues	1,183	1,211	2,760	2,751
GEORGIA POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Operating revenues	833	965	2,242	2,427
GEORGIA POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Operating revenues	352	450	907	1,074
GEORGIA POWER CO | Other
Disaggregation of Revenue [Line Items]
Operating revenues	15	16	46	41
GEORGIA POWER CO | Natural gas distribution revenues
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
GEORGIA POWER CO | Residential
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
GEORGIA POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
GEORGIA POWER CO | Transportation
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
GEORGIA POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
GEORGIA POWER CO | Other
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
GEORGIA POWER CO | Wholesale electric revenues
Disaggregation of Revenue [Line Items]
Operating revenues	31	35	75	93
GEORGIA POWER CO | PPA energy revenues
Disaggregation of Revenue [Line Items]
Operating revenues	13	19	38	47
GEORGIA POWER CO | PPA capacity revenues
Disaggregation of Revenue [Line Items]
Operating revenues	15	13	30	41
GEORGIA POWER CO | Non-PPA revenues
Disaggregation of Revenue [Line Items]
Operating revenues	3	3	7	5
GEORGIA POWER CO | Other natural gas revenues
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
GEORGIA POWER CO | Wholesale gas services
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
GEORGIA POWER CO | Gas marketing services
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
GEORGIA POWER CO | Other natural gas revenues
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
GEORGIA POWER CO | Other revenues
Disaggregation of Revenue [Line Items]
Operating revenues	115	113	329	298
GEORGIA POWER CO | Other revenue sources
Disaggregation of Revenue [Line Items]
Other	88	(35)	12	22
GEORGIA POWER CO | Other adjustments
Disaggregation of Revenue [Line Items]
Other	0	0	0	0
MISSISSIPPI POWER CO
Disaggregation of Revenue [Line Items]
Operating revenues	335	377	886	973
Revenues	336	370	895	970
MISSISSIPPI POWER CO | Total retail electric revenues
Disaggregation of Revenue [Line Items]
Operating revenues	233	259	622	674
MISSISSIPPI POWER CO | Residential
Disaggregation of Revenue [Line Items]
Operating revenues	84	88	203	217
MISSISSIPPI POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Operating revenues	74	86	195	223
MISSISSIPPI POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Operating revenues	73	82	218	226
MISSISSIPPI POWER CO | Other
Disaggregation of Revenue [Line Items]
Operating revenues	2	3	6	8
MISSISSIPPI POWER CO | Natural gas distribution revenues
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
MISSISSIPPI POWER CO | Residential
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
MISSISSIPPI POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
MISSISSIPPI POWER CO | Transportation
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
MISSISSIPPI POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
MISSISSIPPI POWER CO | Other
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
MISSISSIPPI POWER CO | Wholesale electric revenues
Disaggregation of Revenue [Line Items]
Operating revenues	96	114	245	285
MISSISSIPPI POWER CO | PPA energy revenues
Disaggregation of Revenue [Line Items]
Operating revenues	2	2	7	8
MISSISSIPPI POWER CO | PPA capacity revenues
Disaggregation of Revenue [Line Items]
Operating revenues	1	1	3	2
MISSISSIPPI POWER CO | Non-PPA revenues
Disaggregation of Revenue [Line Items]
Operating revenues	93	111	235	275
MISSISSIPPI POWER CO | Other natural gas revenues
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
MISSISSIPPI POWER CO | Wholesale gas services
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
MISSISSIPPI POWER CO | Gas marketing services
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
MISSISSIPPI POWER CO | Other natural gas revenues
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
MISSISSIPPI POWER CO | Other revenues
Disaggregation of Revenue [Line Items]
Operating revenues	6	4	19	14
MISSISSIPPI POWER CO | Other revenue sources
Disaggregation of Revenue [Line Items]
Other	1	(7)	9	(3)
MISSISSIPPI POWER CO | Other adjustments
Disaggregation of Revenue [Line Items]
Other	0	0	0	0
SOUTHERN POWER CO
Disaggregation of Revenue [Line Items]
Operating revenues	332	372	851	980
Revenues	523	574	1,337	1,527
SOUTHERN POWER CO | Total retail electric revenues
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
SOUTHERN POWER CO | Residential
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
SOUTHERN POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
SOUTHERN POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
SOUTHERN POWER CO | Other
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
SOUTHERN POWER CO | Natural gas distribution revenues
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
SOUTHERN POWER CO | Residential
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
SOUTHERN POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
SOUTHERN POWER CO | Transportation
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
SOUTHERN POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
SOUTHERN POWER CO | Other
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
SOUTHERN POWER CO | Wholesale electric revenues
Disaggregation of Revenue [Line Items]
Operating revenues	328	369	840	970
SOUTHERN POWER CO | PPA energy revenues
Disaggregation of Revenue [Line Items]
Operating revenues	165	188	425	508
SOUTHERN POWER CO | PPA capacity revenues
Disaggregation of Revenue [Line Items]
Operating revenues	95	100	231	272
SOUTHERN POWER CO | Non-PPA revenues
Disaggregation of Revenue [Line Items]
Operating revenues	68	81	184	190
SOUTHERN POWER CO | Other natural gas revenues
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
SOUTHERN POWER CO | Wholesale gas services
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
SOUTHERN POWER CO | Gas marketing services
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
SOUTHERN POWER CO | Other natural gas revenues
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
SOUTHERN POWER CO | Other revenues
Disaggregation of Revenue [Line Items]
Operating revenues	4	3	11	10
SOUTHERN POWER CO | Other revenue sources
Disaggregation of Revenue [Line Items]
Other	191	202	486	547
SOUTHERN POWER CO | Other adjustments
Disaggregation of Revenue [Line Items]
Other	0	0	0	0
SOUTHERN Co GAS
Disaggregation of Revenue [Line Items]
Operating revenues	950	913	3,506	4,093
Revenues	477	498	2,362	2,661
SOUTHERN Co GAS | Total retail electric revenues
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
SOUTHERN Co GAS | Residential
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
SOUTHERN Co GAS | Commercial
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
SOUTHERN Co GAS | Industrial
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
SOUTHERN Co GAS | Other
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
SOUTHERN Co GAS | Natural gas distribution revenues
Disaggregation of Revenue [Line Items]
Operating revenues	474	441	2,058	2,158
SOUTHERN Co GAS | Residential
Disaggregation of Revenue [Line Items]
Operating revenues	170	162	906	992
SOUTHERN Co GAS | Commercial
Disaggregation of Revenue [Line Items]
Operating revenues	41	42	229	277
SOUTHERN Co GAS | Transportation
Disaggregation of Revenue [Line Items]
Operating revenues	224	204	723	673
SOUTHERN Co GAS | Industrial
Disaggregation of Revenue [Line Items]
Operating revenues	4	3	21	25
SOUTHERN Co GAS | Other
Disaggregation of Revenue [Line Items]
Operating revenues	35	30	179	191
SOUTHERN Co GAS | Wholesale electric revenues
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
SOUTHERN Co GAS | PPA energy revenues
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
SOUTHERN Co GAS | PPA capacity revenues
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
SOUTHERN Co GAS | Non-PPA revenues
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
SOUTHERN Co GAS | Other natural gas revenues
Disaggregation of Revenue [Line Items]
Operating revenues	476	472	1,448	1,935
SOUTHERN Co GAS | Wholesale gas services
Disaggregation of Revenue [Line Items]
Operating revenues	431	425	1,168	1,590
SOUTHERN Co GAS | Gas marketing services
Disaggregation of Revenue [Line Items]
Operating revenues	38	37	258	313
SOUTHERN Co GAS | Other natural gas revenues
Disaggregation of Revenue [Line Items]
Operating revenues	7	10	22	32
SOUTHERN Co GAS | Other revenues
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0	0
SOUTHERN Co GAS | Other revenue sources
Disaggregation of Revenue [Line Items]
Other	630	727	1,973	2,744
SOUTHERN Co GAS | Other adjustments
Disaggregation of Revenue [Line Items]
Other	$ (1,103)	$ (1,142)	$ (3,117)	$ (4,176)

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REVENUE FROM CONTRACTS WITH CUSTOMERS AND LEASE INCOME - Contract Balances (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Disaggregation of Revenue [Line Items]
Accounts Receivables	$ 2,344	$ 2,413
Contract Assets	159	117
Contract Liabilities	56	52
ALABAMA POWER CO
Disaggregation of Revenue [Line Items]
Accounts Receivables	686	586
Contract Assets	5	0
Contract Liabilities	1	10
GEORGIA POWER CO
Disaggregation of Revenue [Line Items]
Accounts Receivables	901	688
Contract Assets	103	69
Contract Liabilities	24	13
MISSISSIPPI POWER CO
Disaggregation of Revenue [Line Items]
Accounts Receivables	93	79
Contract Assets	0	0
Contract Liabilities	0	0
SOUTHERN POWER CO
Disaggregation of Revenue [Line Items]
Accounts Receivables	100	97
Contract Assets	0	0
Contract Liabilities	3	1
SOUTHERN Co GAS
Disaggregation of Revenue [Line Items]
Accounts Receivables	385	749
Contract Assets	0	0
Contract Liabilities	$ 1	$ 1

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REVENUE FROM CONTRACTS WITH CUSTOMERS AND LEASE INCOME - Narrative (Details) - USD ($) $ in Millions		3 Months Ended	9 Months Ended
	Aug. 31, 2020	Sep. 30, 2020	Sep. 30, 2020	Dec. 31, 2019
Disaggregation of Revenue [Line Items]
Contract assets		$ 159	$ 159	$ 117
Contract liabilities		56	56	52
Revenue from contracts with customers recognized		8	29
Unregulated Distributed Generation
Disaggregation of Revenue [Line Items]
Contract assets		47	47	40
Contract liabilities		22	$ 22	28
GEORGIA POWER CO
Disaggregation of Revenue [Line Items]
Revenue, performance obligation, description of timing			Georgia Power had contract assets primarily related to fixed retail customer bill programs, where the payment is contingent upon Georgia Power's continued performance and the customer's continued participation in the program over a one-year contract term, 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 certain unregulated service agreements. Alabama Power had contract liabilities for outstanding performance obligations primarily related to extended service agreements.
Contract assets		103	$ 103	69
Contract liabilities		24	24	13
ALABAMA POWER CO
Disaggregation of Revenue [Line Items]
Contract assets		5	5	0
Contract liabilities		1	1	10
ALABAMA POWER CO | Autauga Combined Cycle
Disaggregation of Revenue [Line Items]
Power sales agreement, remaining term	3 years
MISSISSIPPI POWER CO
Disaggregation of Revenue [Line Items]
Contract assets		0	0	0
Contract liabilities		0	0	$ 0
Sales-type lease, lease receivable		25	25
Transfer of construction work in progress to lease receivables		25
MISSISSIPPI POWER CO | Other Property and Investments
Disaggregation of Revenue [Line Items]
Sales-type lease, lease receivable		22	22
MISSISSIPPI POWER CO | Other Accounts Notes and Loans Receivable
Disaggregation of Revenue [Line Items]
Sales-type lease, lease receivable		$ 3	$ 3

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REVENUE FROM CONTRACTS WITH CUSTOMERS AND LEASE INCOME - Performance Obligations (Details) $ in Millions	Sep. 30, 2020 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 170
Performance obligation, expected timing of satisfaction	3 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 487
Performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 362
Performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 339
Performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 319
Performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 3,062
Performance obligation, expected timing of satisfaction
ALABAMA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 7
Performance obligation, expected timing of satisfaction	3 months
ALABAMA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 33
Performance obligation, expected timing of satisfaction	1 year
ALABAMA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 31
Performance obligation, expected timing of satisfaction	1 year
ALABAMA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 24
Performance obligation, expected timing of satisfaction	1 year
ALABAMA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 7
Performance obligation, expected timing of satisfaction	1 year
ALABAMA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 5
Performance obligation, expected timing of satisfaction
GEORGIA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 20
Performance obligation, expected timing of satisfaction	3 months
GEORGIA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 71
Performance obligation, expected timing of satisfaction	1 year
GEORGIA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 43
Performance obligation, expected timing of satisfaction	1 year
GEORGIA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 35
Performance obligation, expected timing of satisfaction	1 year
GEORGIA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 24
Performance obligation, expected timing of satisfaction	1 year
GEORGIA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 62
Performance obligation, expected timing of satisfaction
SOUTHERN POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 60
Performance obligation, expected timing of satisfaction	3 months
SOUTHERN POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 290
Performance obligation, expected timing of satisfaction	1 year
SOUTHERN POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 292
Performance obligation, expected timing of satisfaction	1 year
SOUTHERN POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 282
Performance obligation, expected timing of satisfaction	1 year
SOUTHERN POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 290
Performance obligation, expected timing of satisfaction	1 year
SOUTHERN POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 3,013
Performance obligation, expected timing of satisfaction

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REVENUE FROM CONTRACTS WITH CUSTOMERS AND LEASE INCOME - Summary of Lease Income (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Lessor, Lease, Description [Line Items]
Lease income - interest income on sales-type leases	$ 3	$ 2	$ 8	$ 7
Lease income - operating leases	50	64	148	216
Variable lease income	145	141	345	324
Total lease income	198	207	501	547
ALABAMA POWER CO
Lessor, Lease, Description [Line Items]
Lease income - interest income on sales-type leases	0	0	0	0
Lease income - operating leases	11	5	24	19
Variable lease income	0	0	0	0
Total lease income	11	5	24	19
GEORGIA POWER CO
Lessor, Lease, Description [Line Items]
Lease income - interest income on sales-type leases	0	0	0	0
Lease income - operating leases	14	18	44	57
Variable lease income	0	0	0	0
Total lease income	14	18	44	57
MISSISSIPPI POWER CO
Lessor, Lease, Description [Line Items]
Lease income - interest income on sales-type leases	3	2	8	7
Lease income - operating leases	0	0	1	0
Variable lease income	0	0	0	0
Total lease income	3	2	9	7
SOUTHERN POWER CO
Lessor, Lease, Description [Line Items]
Lease income - interest income on sales-type leases	0	0	0	0
Lease income - operating leases	21	31	66	111
Variable lease income	153	151	368	349
Total lease income	174	182	434	460
SOUTHERN Co GAS
Lessor, Lease, Description [Line Items]
Lease income - interest income on sales-type leases	0	0	0	0
Lease income - operating leases	9	9	26	26
Variable lease income	0	0	0	0
Total lease income	$ 9	$ 9	$ 26	$ 26

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CONSOLIDATED ENTITIES AND EQUITY METHOD INVESTMENTS - Narrative (Details) $ in Millions	9 Months Ended
	Sep. 30, 2020 USD ($) investor	Dec. 31, 2019 USD ($)
Schedule of Equity Method Investments [Line Items]
Assets	$ 123,158	$ 118,700
Liabilities	90,367	86,650
Equity method investments	403	391
SOUTHERN POWER CO
Schedule of Equity Method Investments [Line Items]
Assets	13,424	14,300
Liabilities	6,813	7,678
Equity method investments	$ 19	28
SP Solar Holdings I, LP | SOUTHERN POWER CO
Schedule of Equity Method Investments [Line Items]
Distribution made to limited partner, cash distributions paid, percentage	67.00%
SP Solar Holdings I, LP | Global Atlantic
Schedule of Equity Method Investments [Line Items]
Distribution made to limited partner, cash distributions paid, percentage	33.00%
Variable Interest Entity, Primary Beneficiary | SP Solar Holdings I, LP | SOUTHERN POWER CO
Schedule of Equity Method Investments [Line Items]
Assets	$ 6,300	6,400
Liabilities	382	382
Noncontrolling interests related to other partners' interests	1,100	1,100
Variable Interest Entity, Primary Beneficiary | SP Wind | SOUTHERN POWER CO
Schedule of Equity Method Investments [Line Items]
Assets	2,400	2,500
Liabilities	129	128
Noncontrolling interests related to other partners' interests	$ 44	45
Distribution made to limited partner, cash distributions paid, percentage	60.00%
Number of financial investors | investor	3
Variable Interest Entity, Primary Beneficiary | SP Wind | Financial Investors
Schedule of Equity Method Investments [Line Items]
Distribution made to limited partner, cash distributions paid, percentage	40.00%
Variable Interest Entity, Primary Beneficiary | Other Variable Interest Entities | SOUTHERN POWER CO
Schedule of Equity Method Investments [Line Items]
Assets	$ 1,100
Liabilities	109	104
Noncontrolling interests related to other partners' interests	$ 471	$ 409

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CONSOLIDATED ENTITIES AND EQUITY METHOD INVESTMENTS - Balance Sheet Equity Method Investment Carrying Amount (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Schedule of Equity Method Investments [Line Items]
Investment Balance	$ 1,358	$ 1,303
SOUTHERN Co GAS
Schedule of Equity Method Investments [Line Items]
Investment Balance	1,301	1,251
SOUTHERN Co GAS | SNG
Schedule of Equity Method Investments [Line Items]
Investment Balance	1,180	1,137
SOUTHERN Co GAS | PennEast Pipeline
Schedule of Equity Method Investments [Line Items]
Investment Balance	89	82
SOUTHERN Co GAS | Other
Schedule of Equity Method Investments [Line Items]
Investment Balance	$ 32	$ 32

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CONSOLIDATED ENTITIES AND EQUITY METHOD INVESTMENTS - Income Statement Equity Method Investment Carrying Amount (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Schedule of Equity Method Investments [Line Items]
Earnings from Equity Method Investments	$ 33	$ 39	$ 105	$ 120
SOUTHERN Co GAS
Schedule of Equity Method Investments [Line Items]
Earnings from Equity Method Investments	33	35	106	115
SOUTHERN Co GAS | SNG
Schedule of Equity Method Investments [Line Items]
Earnings from Equity Method Investments	30	30	95	104
SOUTHERN Co GAS | Atlantic Coast Pipeline
Schedule of Equity Method Investments [Line Items]
Earnings from Equity Method Investments	0	3	3	9
SOUTHERN Co GAS | PennEast Pipeline
Schedule of Equity Method Investments [Line Items]
Earnings from Equity Method Investments	2	2	5	5
SOUTHERN Co GAS | Other
Schedule of Equity Method Investments [Line Items]
Earnings from Equity Method Investments	$ 1	$ 0	$ 3	$ (3)

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CONSOLIDATED ENTITIES AND EQUITY METHOD INVESTMENTS - Investment in SNG (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Schedule of Equity Method Investments [Line Items]
Revenues	$ 5,620	$ 5,995	$ 15,258	$ 16,505
Operating income	1,835	2,013	4,156	7,046
Net income	1,283	1,345	2,746	4,335
Equity Method Investment | SNG
Schedule of Equity Method Investments [Line Items]
Revenues	150	152	457	473
Operating income	85	82	262	274
Net income	$ 59	$ 60	$ 189	$ 208

XML

FINANCING - Schedule of Credit Arrangements (Details)	Sep. 30, 2020 USD ($)
Line of Credit Facility [Line Items]
Expires, 2021	$ 33,000,000
Expires, 2022	675,000,000
Expires, 2023	125,000,000
Expires, 2024	6,900,000,000
Total	7,733,000,000
Unused	7,671,000,000
Due within One Year	33,000,000
Southern Company
Line of Credit Facility [Line Items]
Expires, 2021	0
Expires, 2022	0
Expires, 2023	0
Expires, 2024	2,000,000,000
Total	2,000,000,000
Unused	1,999,000,000
Due within One Year	0
ALABAMA POWER CO
Line of Credit Facility [Line Items]
Expires, 2021	3,000,000
Expires, 2022	525,000,000
Expires, 2023	0
Expires, 2024	800,000,000
Total	1,328,000,000
Unused	1,328,000,000
Due within One Year	3,000,000
GEORGIA POWER CO
Line of Credit Facility [Line Items]
Expires, 2021	0
Expires, 2022	0
Expires, 2023	0
Expires, 2024	1,750,000,000
Total	1,750,000,000
Unused	1,728,000,000
Due within One Year	0
MISSISSIPPI POWER CO
Line of Credit Facility [Line Items]
Expires, 2021	0
Expires, 2022	150,000,000
Expires, 2023	125,000,000
Expires, 2024	0
Total	275,000,000
Unused	250,000,000
Due within One Year	0
SOUTHERN POWER CO
Line of Credit Facility [Line Items]
Expires, 2021	0
Expires, 2022	0
Expires, 2023	0
Expires, 2024	600,000,000
Total	600,000,000
Unused	591,000,000
Due within One Year	0
SOUTHERN POWER CO | Standby Letters of Credit
Line of Credit Facility [Line Items]
Expires, 2021	120,000,000
Expires, 2024	60,000,000
Unused, 2021	23,000,000
Unused, 2023	40,000,000
SOUTHERN Co GAS
Line of Credit Facility [Line Items]
Expires, 2021	0
Expires, 2022	0
Expires, 2023	0
Expires, 2024	1,750,000,000
Total	1,750,000,000
Unused	1,745,000,000
Due within One Year	0
SEGCO
Line of Credit Facility [Line Items]
Expires, 2021	30,000,000
Expires, 2022	0
Expires, 2023	0
Expires, 2024	0
Total	30,000,000
Unused	30,000,000
Due within One Year	30,000,000
Southern Company Gas Capital
Line of Credit Facility [Line Items]
Total	1,250,000,000
Nicor Gas
Line of Credit Facility [Line Items]
Total	$ 500,000,000

XML

FINANCING - Narrative (Details) $ in Millions	Sep. 30, 2020 USD ($)
Debt Instrument [Line Items]
Line of credit expiring in 2023	$ 125
Variable rate pollution control revenue bonds outstanding	1,400
MISSISSIPPI POWER CO
Debt Instrument [Line Items]
Line of credit expiring in 2023	125
Variable rate pollution control revenue bonds outstanding	34
ALABAMA POWER CO
Debt Instrument [Line Items]
Line of credit expiring in 2023	0
Variable rate pollution control revenue bonds outstanding	854
GEORGIA POWER CO
Debt Instrument [Line Items]
Line of credit expiring in 2023	0
Variable rate pollution control revenue bonds outstanding	550
Fixed rate pollution control revenue bonds outstanding	$ 257

XML

FINANCING - Shares Used to Compute Diluted Earnings Per Share (Details) - shares	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Debt Disclosure [Abstract]
As reported shares (in shares)	1,058,000,000	1,048,000,000	1,058,000,000	1,043,000,000
Effect of stock-based compensation (in shares)	6,000,000	9,000,000	6,000,000	8,000,000
Diluted shares (in shares)	1,064,000,000	1,057,000,000	1,064,000,000	1,051,000,000
Antidilutive securities excluded from computation of earnings per share (in shares)	0			0

XML

INCOME TAXES (Details) - USD ($) $ in Billions	9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019
Income Tax Contingency [Line Items]
Effective tax (benefit) rate	13.90%	30.20%
GEORGIA POWER CO
Income Tax Contingency [Line Items]
Effective tax (benefit) rate	12.30%	22.60%
MISSISSIPPI POWER CO
Income Tax Contingency [Line Items]
Effective tax (benefit) rate	12.70%	16.30%
SOUTHERN POWER CO
Income Tax Contingency [Line Items]
Effective tax (benefit) rate	11.30%	(13.60%)
SOUTHERN Co GAS
Income Tax Contingency [Line Items]
Effective tax (benefit) rate	21.40%	15.00%
ITC and PTC carryforwards
Income Tax Contingency [Line Items]
Tax credit carryforward, amount	$ 1.5		$ 1.8

XML

RETIREMENT BENEFITS (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Amortization:
Net (gain)/loss
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, expected future employer contributions, remainder of fiscal year	$ 0		$ 0
Pension Plans and Postretirement Plans
Service cost	94,000,000	73,000,000	282,000,000	$ 219,000,000
Interest cost	108,000,000	123,000,000	324,000,000	369,000,000
Expected return on plan assets	(274,000,000)	(222,000,000)	(824,000,000)	(664,000,000)
Amortization:
Prior service costs	0	1,000,000	1,000,000	2,000,000
Regulatory asset	0	0	0	0
Net (gain)/loss	67,000,000	30,000,000	201,000,000	90,000,000
Net periodic pension cost (income)	(5,000,000)	5,000,000	(16,000,000)	16,000,000
Pension Plans | ALABAMA POWER CO
Pension Plans and Postretirement Plans
Service cost	23,000,000	17,000,000	67,000,000	51,000,000
Interest cost	25,000,000	28,000,000	75,000,000	85,000,000
Expected return on plan assets	(66,000,000)	(51,000,000)	(198,000,000)	(154,000,000)
Amortization:
Prior service costs	1,000,000	0	1,000,000	1,000,000
Regulatory asset	0	0	0	0
Net (gain)/loss	17,000,000	9,000,000	53,000,000	27,000,000
Net periodic pension cost (income)	0	3,000,000	(2,000,000)	10,000,000
Pension Plans | GEORGIA POWER CO
Pension Plans and Postretirement Plans
Service cost	24,000,000	19,000,000	72,000,000	56,000,000
Interest cost	33,000,000	38,000,000	100,000,000	116,000,000
Expected return on plan assets	(87,000,000)	(73,000,000)	(261,000,000)	(219,000,000)
Amortization:
Prior service costs	0	0	1,000,000	1,000,000
Regulatory asset	0	0	0	0
Net (gain)/loss	22,000,000	11,000,000	65,000,000	33,000,000
Net periodic pension cost (income)	(8,000,000)	(5,000,000)	(23,000,000)	(13,000,000)
Pension Plans | MISSISSIPPI POWER CO
Pension Plans and Postretirement Plans
Service cost	3,000,000	3,000,000	11,000,000	9,000,000
Interest cost	5,000,000	6,000,000	15,000,000	17,000,000
Expected return on plan assets	(13,000,000)	(10,000,000)	(38,000,000)	(30,000,000)
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	0	0	0	0
Net (gain)/loss	4,000,000	1,000,000	10,000,000	4,000,000
Net periodic pension cost (income)	(1,000,000)	0	(2,000,000)	0
Pension Plans | SOUTHERN POWER CO
Pension Plans and Postretirement Plans
Service cost	2,000,000	2,000,000	6,000,000	5,000,000
Interest cost	1,000,000	1,000,000	4,000,000	4,000,000
Expected return on plan assets	(4,000,000)	(2,000,000)	(10,000,000)	(7,000,000)
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	0	0	0	0
Net (gain)/loss	1,000,000	0	2,000,000	0
Net periodic pension cost (income)	0	1,000,000	2,000,000	2,000,000
Pension Plans | SOUTHERN Co GAS
Pension Plans and Postretirement Plans
Service cost	8,000,000	7,000,000	24,000,000	19,000,000
Interest cost	8,000,000	9,000,000	23,000,000	27,000,000
Expected return on plan assets	(20,000,000)	(15,000,000)	(59,000,000)	(45,000,000)
Amortization:
Prior service costs	(1,000,000)	(1,000,000)	(2,000,000)	(2,000,000)
Regulatory asset	4,000,000	3,000,000	12,000,000	10,000,000
Net (gain)/loss	2,000,000	1,000,000	7,000,000	2,000,000
Net periodic pension cost (income)	1,000,000	4,000,000	5,000,000	11,000,000
Postretirement Benefits
Pension Plans and Postretirement Plans
Service cost	6,000,000	5,000,000	17,000,000	14,000,000
Interest cost	13,000,000	18,000,000	40,000,000	52,000,000
Expected return on plan assets	(18,000,000)	(16,000,000)	(54,000,000)	(49,000,000)
Amortization:
Prior service costs	0	0	(1,000,000)	2,000,000
Regulatory asset	0	0	0	0
Net (gain)/loss	1,000,000	(1,000,000)	2,000,000	(2,000,000)
Net periodic pension cost (income)	2,000,000	6,000,000	4,000,000	17,000,000
Postretirement Benefits | ALABAMA POWER CO
Pension Plans and Postretirement Plans
Service cost	1,000,000	1,000,000	4,000,000	3,000,000
Interest cost	4,000,000	4,000,000	10,000,000	12,000,000
Expected return on plan assets	(7,000,000)	(6,000,000)	(21,000,000)	(19,000,000)
Amortization:
Prior service costs	0	1,000,000	0	3,000,000
Regulatory asset	0	0	0	0
Net (gain)/loss	0	0	0	0
Net periodic pension cost (income)	(2,000,000)	0	(7,000,000)	(1,000,000)
Postretirement Benefits | GEORGIA POWER CO
Pension Plans and Postretirement Plans
Service cost	2,000,000	2,000,000	5,000,000	4,000,000
Interest cost	5,000,000	6,000,000	15,000,000	19,000,000
Expected return on plan assets	(7,000,000)	(7,000,000)	(20,000,000)	(19,000,000)
Amortization:
Prior service costs	(1,000,000)	0	(1,000,000)	0
Regulatory asset	0	0	0	0
Net (gain)/loss	1,000,000	1,000,000	2,000,000	1,000,000
Net periodic pension cost (income)	0	2,000,000	1,000,000	5,000,000
Postretirement Benefits | MISSISSIPPI POWER CO
Pension Plans and Postretirement Plans
Service cost	(1,000,000)	1,000,000	0	1,000,000
Interest cost	1,000,000	0	2,000,000	2,000,000
Expected return on plan assets	0	0	(1,000,000)	(1,000,000)
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	0	0	0	0
Net (gain)/loss	0	0	0	0
Net periodic pension cost (income)	0	1,000,000	1,000,000	2,000,000
Postretirement Benefits | SOUTHERN POWER CO
Pension Plans and Postretirement Plans
Service cost	1,000,000	0	1,000,000	0
Interest cost	0	0	0	0
Expected return on plan assets	0	0	0	0
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	0	0	0	0
Net (gain)/loss	0	0	0	0
Net periodic pension cost (income)	1,000,000	0	1,000,000	0
Postretirement Benefits | SOUTHERN Co GAS
Pension Plans and Postretirement Plans
Service cost	0	0	1,000,000	1,000,000
Interest cost	2,000,000	2,000,000	5,000,000	7,000,000
Expected return on plan assets	(2,000,000)	(1,000,000)	(5,000,000)	(4,000,000)
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	2,000,000	1,000,000	5,000,000	4,000,000
Net (gain)/loss	(1,000,000)	0	(2,000,000)	(2,000,000)
Net periodic pension cost (income)	$ 1,000,000	$ 2,000,000	$ 4,000,000	$ 6,000,000

XML

FAIR VALUE MEASUREMENTS - Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Assets:
Derivatives	$ 234	$ 233
Liabilities:
Derivatives	67	189
Collateral already posted, assets, aggregate fair value	70
ALABAMA POWER CO
Assets:
Derivatives	18	2
Liabilities:
Derivatives	1	22
GEORGIA POWER CO
Assets:
Derivatives	22	1
Investments in trusts	25
Liabilities:
Derivatives	0	67
MISSISSIPPI POWER CO
Assets:
Derivatives	11	0
Liabilities:
Derivatives	0	26
SOUTHERN POWER CO
Assets:
Derivatives	33	19
Liabilities:
Derivatives	23	27
SOUTHERN Co GAS
Assets:
Derivatives	131	212
Liabilities:
Derivatives	43	41
Collateral already posted, assets, aggregate fair value	70	$ 99
Fair Value, Measurements, Recurring
Assets:
Cash equivalents	2,761
Other investments	28
Total	5,797
Liabilities:
Contingent consideration	19
Total	793
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Cash equivalents	2,750
Other investments	9
Total	4,113
Liabilities:
Contingent consideration	0
Total	521
Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2)
Assets:
Cash equivalents	11
Other investments	19
Total	1,499
Liabilities:
Contingent consideration	0
Total	178
Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3)
Assets:
Cash equivalents	0
Other investments	0
Total	117
Liabilities:
Contingent consideration	19
Total	94
Fair Value, Measurements, Recurring | Net Asset Value as a Practical Expedient (NAV)
Assets:
Total	68
Fair Value, Measurements, Recurring | Energy-related derivatives
Assets:
Derivatives	823
Liabilities:
Derivatives	751
Fair Value, Measurements, Recurring | Energy-related derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Derivatives	488
Liabilities:
Derivatives	521
Fair Value, Measurements, Recurring | Energy-related derivatives | Significant Other Observable Inputs (Level 2)
Assets:
Derivatives	218
Liabilities:
Derivatives	155
Fair Value, Measurements, Recurring | Energy-related derivatives | Significant Unobservable Inputs (Level 3)
Assets:
Derivatives	117
Liabilities:
Derivatives	75
Fair Value, Measurements, Recurring | Interest rate derivatives
Assets:
Derivatives	20
Fair Value, Measurements, Recurring | Interest rate derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Derivatives	0
Fair Value, Measurements, Recurring | Interest rate derivatives | Significant Other Observable Inputs (Level 2)
Assets:
Derivatives	20
Fair Value, Measurements, Recurring | Interest rate derivatives | Significant Unobservable Inputs (Level 3)
Assets:
Derivatives	0
Fair Value, Measurements, Recurring | Foreign currency derivatives
Assets:
Derivatives	29
Liabilities:
Derivatives	23
Fair Value, Measurements, Recurring | Foreign currency derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | Foreign currency derivatives | Significant Other Observable Inputs (Level 2)
Assets:
Derivatives	29
Liabilities:
Derivatives	23
Fair Value, Measurements, Recurring | Foreign currency derivatives | Significant Unobservable Inputs (Level 3)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | Domestic equity
Assets:
Investments in trusts	891
Fair Value, Measurements, Recurring | Domestic equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	754
Fair Value, Measurements, Recurring | Domestic equity | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	137
Fair Value, Measurements, Recurring | Domestic equity | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Foreign equity
Assets:
Investments in trusts	291
Fair Value, Measurements, Recurring | Foreign equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	71
Fair Value, Measurements, Recurring | Foreign equity | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	220
Fair Value, Measurements, Recurring | Foreign equity | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | U.S. Treasury and government agency securities
Assets:
Investments in trusts	268
Fair Value, Measurements, Recurring | U.S. Treasury and government agency securities | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | U.S. Treasury and government agency securities | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	268
Fair Value, Measurements, Recurring | U.S. Treasury and government agency securities | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Municipal bonds
Assets:
Investments in trusts	99
Fair Value, Measurements, Recurring | Municipal bonds | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Municipal bonds | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	99
Fair Value, Measurements, Recurring | Municipal bonds | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Pooled funds – fixed income
Assets:
Investments in trusts	17
Fair Value, Measurements, Recurring | Pooled funds – fixed income | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Pooled funds – fixed income | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	17
Fair Value, Measurements, Recurring | Pooled funds – fixed income | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Corporate bonds
Assets:
Investments in trusts	391
Fair Value, Measurements, Recurring | Corporate bonds | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	15
Fair Value, Measurements, Recurring | Corporate bonds | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	376
Fair Value, Measurements, Recurring | Corporate bonds | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Mortgage and asset backed securities
Assets:
Investments in trusts	79
Fair Value, Measurements, Recurring | Mortgage and asset backed securities | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Mortgage and asset backed securities | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	79
Fair Value, Measurements, Recurring | Mortgage and asset backed securities | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Private equity
Assets:
Investments in trusts	68
Fair Value, Measurements, Recurring | Private equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Private equity | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Private equity | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Private equity | Net Asset Value as a Practical Expedient (NAV)
Assets:
Investments in trusts	68
Fair Value, Measurements, Recurring | Cash and cash equivalents
Assets:
Investments in trusts	1
Fair Value, Measurements, Recurring | Cash and cash equivalents | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	1
Fair Value, Measurements, Recurring | Cash and cash equivalents | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Cash and cash equivalents | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Other
Assets:
Investments in trusts	31
Fair Value, Measurements, Recurring | Other | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	25
Fair Value, Measurements, Recurring | Other | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	6
Fair Value, Measurements, Recurring | Other | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO
Assets:
Cash equivalents	836
Other investments	19
Total	1,915
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Cash equivalents	825
Other investments	0
Total	1,394
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Significant Other Observable Inputs (Level 2)
Assets:
Cash equivalents	11
Other investments	19
Total	453
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Significant Unobservable Inputs (Level 3)
Assets:
Cash equivalents	0
Other investments	0
Total	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Net Asset Value as a Practical Expedient (NAV)
Assets:
Total	68
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Energy-related derivatives
Assets:
Derivatives	23
Liabilities:
Derivatives	6
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Energy-related derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Energy-related derivatives | Significant Other Observable Inputs (Level 2)
Assets:
Derivatives	23
Liabilities:
Derivatives	6
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Energy-related derivatives | Significant Unobservable Inputs (Level 3)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Domestic equity
Assets:
Investments in trusts	605
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Domestic equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	477
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Domestic equity | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	128
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Domestic equity | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Foreign equity
Assets:
Investments in trusts	135
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Foreign equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	71
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Foreign equity | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	64
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Foreign equity | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | U.S. Treasury and government agency securities
Assets:
Investments in trusts	21
Fair Value, Measurements, Recurring | ALABAMA POWER CO | U.S. Treasury and government agency securities | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | U.S. Treasury and government agency securities | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	21
Fair Value, Measurements, Recurring | ALABAMA POWER CO | U.S. Treasury and government agency securities | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Municipal bonds
Assets:
Investments in trusts	1
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Municipal bonds | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Municipal bonds | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	1
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Municipal bonds | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Corporate bonds
Assets:
Investments in trusts	174
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Corporate bonds | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	15
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Corporate bonds | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	159
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Corporate bonds | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Mortgage and asset backed securities
Assets:
Investments in trusts	27
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Mortgage and asset backed securities | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Mortgage and asset backed securities | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	27
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Mortgage and asset backed securities | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Private equity
Assets:
Investments in trusts	68
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Private equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Private equity | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Private equity | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Private equity | Net Asset Value as a Practical Expedient (NAV)
Assets:
Investments in trusts	68
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Other
Assets:
Investments in trusts	6
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Other | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	6
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Other | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Other | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO
Assets:
Cash equivalents	485
Total	1,586
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Cash equivalents	485
Total	781
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Significant Other Observable Inputs (Level 2)
Assets:
Cash equivalents	0
Total	805
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Significant Unobservable Inputs (Level 3)
Assets:
Cash equivalents	0
Total	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Energy-related derivatives
Assets:
Derivatives	31
Liabilities:
Derivatives	9
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Energy-related derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Energy-related derivatives | Significant Other Observable Inputs (Level 2)
Assets:
Derivatives	31
Liabilities:
Derivatives	9
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Energy-related derivatives | Significant Unobservable Inputs (Level 3)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Domestic equity
Assets:
Investments in trusts	278
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Domestic equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	277
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Domestic equity | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	1
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Domestic equity | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Foreign equity
Assets:
Investments in trusts	153
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Foreign equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Foreign equity | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	153
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Foreign equity | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | U.S. Treasury and government agency securities
Assets:
Investments in trusts	247
Fair Value, Measurements, Recurring | GEORGIA POWER CO | U.S. Treasury and government agency securities | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | U.S. Treasury and government agency securities | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	247
Fair Value, Measurements, Recurring | GEORGIA POWER CO | U.S. Treasury and government agency securities | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Municipal bonds
Assets:
Investments in trusts	98
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Municipal bonds | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Municipal bonds | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	98
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Municipal bonds | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Corporate bonds
Assets:
Investments in trusts	217
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Corporate bonds | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Corporate bonds | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	217
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Corporate bonds | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Mortgage and asset backed securities
Assets:
Investments in trusts	52
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Mortgage and asset backed securities | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Mortgage and asset backed securities | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	52
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Mortgage and asset backed securities | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Other
Assets:
Investments in trusts	25
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Other | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	19
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Other | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	6
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Other | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | MISSISSIPPI POWER CO
Assets:
Cash equivalents	36
Total	54
Fair Value, Measurements, Recurring | MISSISSIPPI POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Cash equivalents	36
Total	36
Fair Value, Measurements, Recurring | MISSISSIPPI POWER CO | Significant Other Observable Inputs (Level 2)
Assets:
Cash equivalents	0
Total	18
Fair Value, Measurements, Recurring | MISSISSIPPI POWER CO | Significant Unobservable Inputs (Level 3)
Assets:
Cash equivalents	0
Total	0
Fair Value, Measurements, Recurring | MISSISSIPPI POWER CO | Energy-related derivatives
Assets:
Derivatives	18
Liabilities:
Derivatives	7
Fair Value, Measurements, Recurring | MISSISSIPPI POWER CO | Energy-related derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | MISSISSIPPI POWER CO | Energy-related derivatives | Significant Other Observable Inputs (Level 2)
Assets:
Derivatives	18
Liabilities:
Derivatives	7
Fair Value, Measurements, Recurring | MISSISSIPPI POWER CO | Energy-related derivatives | Significant Unobservable Inputs (Level 3)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | SOUTHERN POWER CO
Assets:
Cash equivalents	149
Total	183
Liabilities:
Contingent consideration	19
Total	43
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Cash equivalents	149
Total	149
Liabilities:
Contingent consideration	0
Total	0
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Significant Other Observable Inputs (Level 2)
Assets:
Cash equivalents	0
Total	34
Liabilities:
Contingent consideration	0
Total	24
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Significant Unobservable Inputs (Level 3)
Assets:
Cash equivalents	0
Total	0
Liabilities:
Contingent consideration	19
Total	19
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Energy-related derivatives
Assets:
Derivatives	5
Liabilities:
Derivatives	1
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Energy-related derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Energy-related derivatives | Significant Other Observable Inputs (Level 2)
Assets:
Derivatives	5
Liabilities:
Derivatives	1
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Energy-related derivatives | Significant Unobservable Inputs (Level 3)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Foreign currency derivatives
Assets:
Derivatives	29
Liabilities:
Derivatives	23
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Foreign currency derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Foreign currency derivatives | Significant Other Observable Inputs (Level 2)
Assets:
Derivatives	29
Liabilities:
Derivatives	23
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Foreign currency derivatives | Significant Unobservable Inputs (Level 3)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS
Assets:
Cash equivalents	113
Total	888
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Cash equivalents	113
Total	602
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Significant Other Observable Inputs (Level 2)
Assets:
Cash equivalents	0
Total	169
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3)
Assets:
Cash equivalents	0
Total	117
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Energy-related derivatives
Assets:
Derivatives	746
Liabilities:
Derivatives	728
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Energy-related derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Derivatives	488
Liabilities:
Derivatives	521
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Energy-related derivatives | Significant Other Observable Inputs (Level 2)
Assets:
Derivatives	141
Liabilities:
Derivatives	132
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Energy-related derivatives | Significant Unobservable Inputs (Level 3)
Assets:
Derivatives	117
Liabilities:
Derivatives	75
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Domestic equity
Assets:
Non-qualified deferred compensation trusts	8
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Domestic equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Non-qualified deferred compensation trusts	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Domestic equity | Significant Other Observable Inputs (Level 2)
Assets:
Non-qualified deferred compensation trusts	8
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Domestic equity | Significant Unobservable Inputs (Level 3)
Assets:
Non-qualified deferred compensation trusts	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Foreign equity
Assets:
Non-qualified deferred compensation trusts	3
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Foreign equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Non-qualified deferred compensation trusts	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Foreign equity | Significant Other Observable Inputs (Level 2)
Assets:
Non-qualified deferred compensation trusts	3
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Foreign equity | Significant Unobservable Inputs (Level 3)
Assets:
Non-qualified deferred compensation trusts	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Pooled funds – fixed income
Assets:
Non-qualified deferred compensation trusts	17
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Pooled funds – fixed income | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Non-qualified deferred compensation trusts	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Pooled funds – fixed income | Significant Other Observable Inputs (Level 2)
Assets:
Non-qualified deferred compensation trusts	17
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Pooled funds – fixed income | Significant Unobservable Inputs (Level 3)
Assets:
Non-qualified deferred compensation trusts	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Cash equivalents
Assets:
Non-qualified deferred compensation trusts	1
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Cash equivalents | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Non-qualified deferred compensation trusts	1
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Cash equivalents | Significant Other Observable Inputs (Level 2)
Assets:
Non-qualified deferred compensation trusts	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Cash equivalents | Significant Unobservable Inputs (Level 3)
Assets:
Non-qualified deferred compensation trusts	$ 0

XML

FAIR VALUE MEASUREMENTS - Schedule of Increase (Decrease) In Fair Value Of Funds (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Fair Value, Option, Quantitative Disclosures [Line Items]
Increase (decrease) in fair value of funds	$ 108	$ 27	$ 85	$ 255
ALABAMA POWER CO
Fair Value, Option, Quantitative Disclosures [Line Items]
Increase (decrease) in fair value of funds	66	15	24	140
GEORGIA POWER CO
Fair Value, Option, Quantitative Disclosures [Line Items]
Increase (decrease) in fair value of funds	$ 42	$ 12	$ 61	$ 115

XML

FAIR VALUE MEASUREMENTS - Narrative (Details) $ in Millions	Sep. 30, 2020 USD ($) $ / MMBTU
ALABAMA POWER CO | Private equity
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Fair value	$ 68
Unfunded commitments	67
SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3) | Energy-related derivatives
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Fair value of derivatives	$ 42
SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3) | Energy-related derivatives | Forward Price | Valuation, Market Approach | Minimum
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Measurement input (usd per mmbtu) | $ / MMBTU	(1.11)
SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3) | Energy-related derivatives | Forward Price | Valuation, Market Approach | Maximum
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Measurement input (usd per mmbtu) | $ / MMBTU	0.24

XML

FAIR VALUE MEASUREMENTS - Financial Instruments for which Carrying Amount did not Equal Fair Value (Details) $ in Millions	Sep. 30, 2020 USD ($)
Long-term debt, including securities due within one year:
Carrying amount	$ 49,743
Fair value	56,739
ALABAMA POWER CO
Long-term debt, including securities due within one year:
Carrying amount	9,113
Fair value	10,741
GEORGIA POWER CO
Long-term debt, including securities due within one year:
Carrying amount	12,700
Fair value	15,052
MISSISSIPPI POWER CO
Long-term debt, including securities due within one year:
Carrying amount	1,402
Fair value	1,562
SOUTHERN POWER CO
Long-term debt, including securities due within one year:
Carrying amount	4,155
Fair value	4,535
SOUTHERN Co GAS
Long-term debt, including securities due within one year:
Carrying amount	6,461
Fair value	$ 7,640

XML

FAIR VALUE MEASUREMENTS - Fair Value of Commodity Derivative Contracts that Include a Significant Unobservable Component (Details) - SOUTHERN Co GAS - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2020	Sep. 30, 2020
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	$ 80	$ 14
Transfers to Level 3	0	70
Transfers from Level 3	(2)	(5)
Instruments realized or otherwise settled during period	(9)	(16)
Changes in fair value	(27)	(21)
Ending balance	$ 42	$ 42

XML

DERIVATIVES - Energy-Related Derivatives (Details) - Energy-related, Natural Gas MMBTU in Millions	Sep. 30, 2020 MMBTU
Energy-related derivative contracts
Net Purchased mmBtu	877
ALABAMA POWER CO
Energy-related derivative contracts
Net Purchased mmBtu	78
GEORGIA POWER CO
Energy-related derivative contracts
Net Purchased mmBtu	131
MISSISSIPPI POWER CO
Energy-related derivative contracts
Net Purchased mmBtu	86
SOUTHERN POWER CO
Energy-related derivative contracts
Net Purchased mmBtu	14
SOUTHERN Co GAS
Energy-related derivative contracts
Net Purchased mmBtu	568
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Long
Energy-related derivative contracts
Derivative nonmonetary notional amount net long short position volume	4,600
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Short
Energy-related derivative contracts
Derivative nonmonetary notional amount net long short position volume	4,100

XML

DERIVATIVES - Narrative (Details) MWh in Millions, MMBTU in Millions	9 Months Ended
	Sep. 30, 2020 USD ($) MMBTU MWh	Dec. 31, 2019 USD ($)
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU	12
Cash flow hedge gain (loss) to be reclassified within twelve months | $	$ (25,000,000)
Collateral already posted, assets, aggregate fair value | $	$ 70,000,000
SOUTHERN POWER CO
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU	4
ALABAMA POWER CO
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU	3
GEORGIA POWER CO
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU	4
MISSISSIPPI POWER CO
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU	1
Parent Company and Southern Power
Derivative [Line Items]
Foreign currency cash flow hedge gain (loss) to be reclassified during next 12 months | $	$ (14,000,000)
Registrants | Derivative Counterparties
Derivative [Line Items]
Collateral already posted, assets, aggregate fair value | $	0
SOUTHERN Co GAS
Derivative [Line Items]
Collateral already posted, assets, aggregate fair value | $	$ 70,000,000	$ 99,000,000
Public Utilities, Inventory, Power Position | SOUTHERN POWER CO
Derivative [Line Items]
Net Purchased mmBtu | MWh	1

XML

DERIVATIVES - Interest Rate Derivatives (Details) - Interest rate derivatives $ in Millions	9 Months Ended
	Sep. 30, 2020 USD ($)
Derivative [Line Items]
Notional Amount	$ 1,560
Fair Value Gain (Loss) at September 30, 2020	20
MISSISSIPPI POWER CO | Cash Flow Hedges of Existing Debt
Derivative [Line Items]
Notional Amount	$ 60
Weighted Average Interest Rate Paid	0.58%
Fair Value Gain (Loss) at September 30, 2020	$ 0
Southern Company | Fair Value Hedges of Existing Debt
Derivative [Line Items]
Notional Amount	$ 1,500
Interest Rate Received	2.35%
Fair Value Gain (Loss) at September 30, 2020	$ 20
London Interbank Offered Rate (LIBOR) | Southern Company | Fair Value Hedges of Existing Debt
Derivative [Line Items]
Weighted Average Interest Rate Paid	0.87%

XML

DERIVATIVES - Foreign Currency Derivatives (Details) - 9 months ended Sep. 30, 2020 - Cash Flow Hedges of Forecasted Debt - Foreign currency derivatives € in Millions, $ in Millions	USD ($)	EUR (€)
Derivative [Line Items]
Pay Notional	$ 1,241
Receive Notional | €		€ 1,100
Fair Value Gain (Loss) at September 30, 2020	6
SOUTHERN POWER CO | June 2022
Derivative [Line Items]
Pay Notional	$ 677
Pay Rate	2.95%
Receive Notional | €		600
Receive Rate	1.00%
Fair Value Gain (Loss) at September 30, 2020	$ 11
SOUTHERN POWER CO | June 2026
Derivative [Line Items]
Pay Notional	$ 564
Pay Rate	3.78%
Receive Notional | €		€ 500
Receive Rate	1.85%
Fair Value Gain (Loss) at September 30, 2020	$ (5)

XML

DERIVATIVES - Derivative Financial Statement Presentation and Amounts With Balance Sheet Offsetting (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Derivatives, Fair Value [Line Items]
Derivatives, assets	$ 870	$ 696
Derivatives, liabilities	773	751
Derivative asset, Gross amounts offset	(636)	(463)
Derivative liability, Gross amounts offset	(706)	(562)
Derivative asset	234	233
Derivative liability	67	189
Collateral already posted, assets, aggregate fair value	70
Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Derivatives, assets	730	668
Derivatives, liabilities	719	583
Derivatives not designated as hedging instruments | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	392	461
Derivatives not designated as hedging instruments | Energy-related derivatives | Over recovered fuel clause revenues
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	428	358
Derivatives not designated as hedging instruments | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	338	207
Derivatives not designated as hedging instruments | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	291	225
Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivatives, assets	82	9
Derivatives, liabilities	28	114
Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	52	3
Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Over recovered fuel clause revenues
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	13	70
Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	30	6
Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	15	44
Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivatives, assets	58	19
Derivatives, liabilities	26	54
Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	8	1
Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Over recovered fuel clause revenues
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	3	6
Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	2	0
Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Interest rate derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	19	2
Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Interest rate derivatives | Over recovered fuel clause revenues
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	23
Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Interest rate derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Interest rate derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	1
Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Foreign currency derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Foreign currency derivatives | Over recovered fuel clause revenues
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	23	24
Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Foreign currency derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	29	16
Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Foreign currency derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
ALABAMA POWER CO
Derivatives, Fair Value [Line Items]
Derivatives, assets	23	4
Derivatives, liabilities	6	24
Derivative asset, Gross amounts offset	(5)	(2)
Derivative liability, Gross amounts offset	(5)	(2)
Derivative asset	18	2
Derivative liability	1	22
ALABAMA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivatives, assets	23	4
Derivatives, liabilities	6	24
ALABAMA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	14	2
ALABAMA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Over recovered fuel clause revenues
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	2	14
ALABAMA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	9	2
ALABAMA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	4	10
GEORGIA POWER CO
Derivatives, Fair Value [Line Items]
Derivatives, assets	31	4
Derivatives, liabilities	9	70
Derivative asset, Gross amounts offset	(9)	(3)
Derivative liability, Gross amounts offset	(9)	(3)
Derivative asset	22	1
Derivative liability	0	67
GEORGIA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivatives, assets	31	4
Derivatives, liabilities	9	53
GEORGIA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	18	1
GEORGIA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Over recovered fuel clause revenues
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	3	32
GEORGIA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	13	3
GEORGIA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	6	21
GEORGIA POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Derivatives, liabilities	0	17
GEORGIA POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Interest rate derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
GEORGIA POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Interest rate derivatives | Over recovered fuel clause revenues
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	17
MISSISSIPPI POWER CO
Derivatives, Fair Value [Line Items]
Derivatives, assets	18	1
Derivatives, liabilities	7	27
Derivative asset, Gross amounts offset	(7)	(1)
Derivative liability, Gross amounts offset	(7)	(1)
Derivative asset	11	0
Derivative liability	0	26
MISSISSIPPI POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivatives, assets	18	1
Derivatives, liabilities	7	27
MISSISSIPPI POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	10	0
MISSISSIPPI POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Over recovered fuel clause revenues
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	2	15
MISSISSIPPI POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	8	1
MISSISSIPPI POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	5	12
SOUTHERN POWER CO
Derivatives, Fair Value [Line Items]
Derivatives, assets	34	19
Derivatives, liabilities	24	27
Derivative asset, Gross amounts offset	(1)	0
Derivative liability, Gross amounts offset	(1)	0
Derivative asset	33	19
Derivative liability	23	27
SOUTHERN POWER CO | Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	2
Derivatives, liabilities	0	1
SOUTHERN POWER CO | Derivatives not designated as hedging instruments | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	2
SOUTHERN POWER CO | Derivatives not designated as hedging instruments | Energy-related derivatives | Over recovered fuel clause revenues
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	1
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivatives, assets	34	17
Derivatives, liabilities	24	26
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	4	1
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Over recovered fuel clause revenues
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	1	2
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	1	0
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Foreign currency derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Foreign currency derivatives | Over recovered fuel clause revenues
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	23	24
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Foreign currency derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	29	16
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Foreign currency derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
SOUTHERN Co GAS
Derivatives, Fair Value [Line Items]
Derivatives, assets	745	668
Derivatives, liabilities	727	596
Derivative asset, Gross amounts offset	(614)	(456)
Derivative liability, Gross amounts offset	(684)	(555)
Derivative asset	131	212
Derivative liability	43	41
Collateral already posted, assets, aggregate fair value	70	99
Weather derivative premium	3	4
SOUTHERN Co GAS | Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Derivatives, assets	730	666
Derivatives, liabilities	719	582
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	338	207
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	291	225
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Energy-related derivatives | Assets from risk management activities
Derivatives, Fair Value [Line Items]
Derivatives, assets	392	459
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Energy-related derivatives | Liabilities from risk management activities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	428	357
SOUTHERN Co GAS | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivatives, assets	10	0
Derivatives, liabilities	6	10
SOUTHERN Co GAS | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
SOUTHERN Co GAS | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	1
SOUTHERN Co GAS | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Assets from risk management activities
Derivatives, Fair Value [Line Items]
Derivatives, assets	10	0
SOUTHERN Co GAS | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Liabilities from risk management activities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	6	9
SOUTHERN Co GAS | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivatives, assets	5	2
Derivatives, liabilities	2	4
SOUTHERN Co GAS | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	1	0
SOUTHERN Co GAS | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
SOUTHERN Co GAS | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Assets from risk management activities
Derivatives, Fair Value [Line Items]
Derivatives, assets	4	0
SOUTHERN Co GAS | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Liabilities from risk management activities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	2	4
SOUTHERN Co GAS | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Interest rate derivatives | Assets from risk management activities
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	2
SOUTHERN Co GAS | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Interest rate derivatives | Liabilities from risk management activities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	$ 0	$ 0

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DERIVATIVES - Pre-tax Effects of Derivatives Designated as Cash Flow Hedging Instruments (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019
Derivative Instruments, Gain (Loss) [Line Items]
Collateral already posted, assets, aggregate fair value	$ 70		$ 70
Gain (Loss) Recognized in OCI on Derivative	64	$ (125)	(35)	$ (206)
SOUTHERN Co GAS
Derivative Instruments, Gain (Loss) [Line Items]
Collateral already posted, assets, aggregate fair value	70		70		$ 99
Gain (Loss) Recognized in OCI on Derivative	5	(7)	(24)	(11)
SOUTHERN POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	59	(71)	(8)	(112)
Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	51		51		(94)
Gain (Loss) Recognized in OCI on Derivative	9	(5)	2	(11)
Energy-related derivatives | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(5)		(5)		(63)
Energy-related derivatives | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)					(37)
Energy-related derivatives | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	41		41		6
Energy-related derivatives | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	15		15
Energy-related derivatives | ALABAMA POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	17		17		(20)
Energy-related derivatives | ALABAMA POWER CO | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	0		0		(14)
Energy-related derivatives | ALABAMA POWER CO | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)					(8)
Energy-related derivatives | ALABAMA POWER CO | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	12		12		2
Energy-related derivatives | ALABAMA POWER CO | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	5		5
Energy-related derivatives | GEORGIA POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	22		22		(49)
Energy-related derivatives | GEORGIA POWER CO | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	0		0		(31)
Energy-related derivatives | GEORGIA POWER CO | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)					(18)
Energy-related derivatives | GEORGIA POWER CO | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	15		15		0
Energy-related derivatives | GEORGIA POWER CO | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	7		7
Energy-related derivatives | MISSISSIPPI POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	11		11		(26)
Energy-related derivatives | MISSISSIPPI POWER CO | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	0		0		(15)
Energy-related derivatives | MISSISSIPPI POWER CO | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)					(11)
Energy-related derivatives | MISSISSIPPI POWER CO | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	8		8		0
Energy-related derivatives | MISSISSIPPI POWER CO | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	3		3
Energy-related derivatives | SOUTHERN Co GAS
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	1		1		1
Gain (Loss) Recognized in OCI on Derivative	4	(2)	0	(6)
Energy-related derivatives | SOUTHERN Co GAS | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(5)		(5)		(3)
Energy-related derivatives | SOUTHERN Co GAS | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)					0
Energy-related derivatives | SOUTHERN Co GAS | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	6		6		$ 4
Energy-related derivatives | SOUTHERN Co GAS | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	0		0
Energy-related derivatives | SOUTHERN POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	5	(3)	2	(5)
Interest rate derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	1	(52)	(27)	(88)
Interest rate derivatives | GEORGIA POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	0	(47)	(3)	(83)
Interest rate derivatives | SOUTHERN Co GAS
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	1	(5)	(24)	(5)
Foreign currency derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	54	(68)	(10)	(107)
Foreign currency derivatives | SOUTHERN POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	$ 54	$ (68)	$ (10)	$ (107)

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DERIVATIVES - Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Derivative [Line Items]
Total cost of sales	$ 71	$ 79	$ 654	$ 956
Depreciation and amortization	889	760	2,619	2,267
Total interest expense, net of amounts capitalized	(443)	(434)	(1,343)	(1,294)
Total other income (expense), net	113	61	319	239
Cash Flow Hedging | Energy-related derivatives | Total cost of natural gas
Derivative [Line Items]
Gain (loss) on hedge	0	0	(8)	0
Cash Flow Hedging | Energy-related derivatives | Total depreciation and amortization
Derivative [Line Items]
Gain (loss) on hedge	(1)	(1)	(3)	(5)
Cash Flow Hedging | Interest rate derivatives | Total interest expense, net of amounts capitalized
Derivative [Line Items]
Gain (loss) on hedge	(6)	(5)	(19)	(14)
Cash Flow Hedging | Foreign currency derivatives | Total interest expense, net of amounts capitalized
Derivative [Line Items]
Gain (loss) on hedge	(6)	(6)	(18)	(18)
Cash Flow Hedging | Foreign currency derivatives | Total other income (expense), net
Derivative [Line Items]
Gain (loss) on hedge	56	(54)	52	(62)
Fair Value Hedging | Interest rate derivatives | Total interest expense, net of amounts capitalized
Derivative [Line Items]
Gain (loss) on hedge	(3)	10	27	43
SOUTHERN POWER CO
Derivative [Line Items]
Depreciation and amortization	129	120	367	357
Total interest expense, net of amounts capitalized	(36)	(43)	(114)	(127)
Total other income (expense), net	13	6	19	48
SOUTHERN POWER CO | Cash Flow Hedging | Energy-related derivatives | Total depreciation and amortization
Derivative [Line Items]
Gain (loss) on hedge	(1)	(1)	(3)	(5)
SOUTHERN POWER CO | Cash Flow Hedging | Foreign currency derivatives | Total interest expense, net of amounts capitalized
Derivative [Line Items]
Gain (loss) on hedge	(6)	(6)	(18)	(18)
SOUTHERN POWER CO | Cash Flow Hedging | Foreign currency derivatives | Total other income (expense), net
Derivative [Line Items]
Gain (loss) on hedge	$ 56	$ (54)	$ 52	$ (62)

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DERIVATIVES - Cumulative Basis Adjustments for Fair Value Hedges (Details) - Fair Value Hedging - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Securities due within one year
Derivative [Line Items]
Carrying Amount of the Hedged Item	$ (1,513)	$ (599)
Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item	(15)	0
Long-term debt
Derivative [Line Items]
Carrying Amount of the Hedged Item	0	(1,494)
Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item	$ 0	$ 3

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DERIVATIVES - Pre-tax Effects of Derivatives Not Designated as Hedging (Details) - Derivatives not designated as hedging instruments - Energy-related derivatives - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	$ (25)	$ 0	$ 72	$ 86
Natural gas revenues
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	(30)	(2)	54	81
Cost of natural gas
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	$ 5	$ 2	$ 18	$ 5

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ACQUISITIONS AND DISPOSITIONS - Alabama Power Narrative (Details) - ALABAMA POWER CO - Autauga Combined Cycle $ in Millions	Aug. 31, 2020 USD ($)
Business Acquisition [Line Items]
Purchase price	$ 461
Property, plant, and equipment	$ 452
Power sales agreement, remaining term	3 years

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ACQUISITIONS AND DISPOSITIONS - Schedule of Acquisition (Details) - SOUTHERN POWER CO - MW	1 Months Ended
	May 31, 2020	Jun. 30, 2020
Business Acquisition [Line Items]
Approximate nameplate capacity (in MWs)		300
Beech Ridge II
Business Acquisition [Line Items]
Approximate nameplate capacity (in MWs)	56
PPA Contract Period	12 years
Beech Ridge II | Beech Ridge II
Business Acquisition [Line Items]
Ownership percentage by parent	100.00%

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ACQUISITIONS AND DISPOSITIONS - Southern Power Narrative (Details) $ in Millions		9 Months Ended
	Jan. 17, 2020 USD ($)	Sep. 30, 2020 USD ($) agreement	Sep. 30, 2019 USD ($)	Jun. 30, 2020 MW	Dec. 31, 2019 USD ($)	May 31, 2019 MW
Business Acquisition [Line Items]
Construction work in progress		$ 8,861			$ 7,880
Preliminary gain on sale		$ 36	$ 2,517
SOUTHERN POWER CO
Business Acquisition [Line Items]
Approximate nameplate capacity (in MWs) | MW				300
Business acquisition, number of Power Purchase Agreements | agreement		2
Construction work in progress		$ 335			$ 515
Preliminary gain on sale		39	$ 24
SOUTHERN POWER CO | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Mankato expansion
Business Acquisition [Line Items]
Approximate nameplate capacity (in MWs) | MW						385
Nacogdoches biomass-fueled facility	$ 663
Preliminary gain on sale	39
Preliminary gain on sale, net of tax	$ 23
SOUTHERN POWER CO | Series of Construction Projects
Business Acquisition [Line Items]
Construction work in progress		244
SOUTHERN POWER CO | Series of Construction Projects | Minimum
Business Acquisition [Line Items]
Estimated future construction payments		475
SOUTHERN POWER CO | Series of Construction Projects | Maximum
Business Acquisition [Line Items]
Estimated future construction payments		$ 545

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ACQUISITIONS AND DISPOSITIONS - Schedule of Construction Projects (Details) $ in Millions	1 Months Ended			3 Months Ended
	Nov. 30, 2020 MW	Jun. 30, 2020 USD ($) MW	May 31, 2020 MW	Jun. 30, 2021 MW	Sep. 30, 2020 USD ($)	Dec. 31, 2019 USD ($)	Oct. 31, 2019	Dec. 31, 2018 USD ($)
Business Acquisition [Line Items]
Operating lease ROU assets, net | $					$ 1,791	$ 1,800
SOUTHERN POWER CO
Business Acquisition [Line Items]
Approximate Nameplate Capacity (MW) | MW		300
Operating lease ROU assets, net | $					$ 395	$ 369
SOUTHERN POWER CO | Reading
Business Acquisition [Line Items]
Approximate Nameplate Capacity (MW) | MW			200
PPA Contract Period			12 years
SOUTHERN POWER CO | Reading | Reading
Business Acquisition [Line Items]
Ownership percentage by parent								100.00%
Operating lease ROU assets, net | $								$ 24
Operating lease obligations | $								$ 24
Proceeds from tax equity transaction | $		$ 156
SOUTHERN POWER CO | Reading | Reading | Class B Membership Interest
Business Acquisition [Line Items]
Ownership percentage by parent					100.00%
SOUTHERN POWER CO | Skookumchuck | Skookumchuck
Business Acquisition [Line Items]
Ownership percentage by parent							100.00%
SOUTHERN POWER CO | Scenario, Forecast | Skookumchuck
Business Acquisition [Line Items]
Approximate Nameplate Capacity (MW) | MW	136
PPA Contract Period	20 years
SOUTHERN POWER CO | Scenario, Forecast | Garland Solar Storage
Business Acquisition [Line Items]
Approximate Nameplate Capacity (MW) | MW				88
PPA Contract Period				20 years
SOUTHERN POWER CO | Scenario, Forecast | Tranquillity Solar Storage
Business Acquisition [Line Items]
Approximate Nameplate Capacity (MW) | MW				72
PPA Contract Period				20 years

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ACQUISITIONS AND DISPOSITIONS - Pre-tax Profit (Details) - SOUTHERN POWER CO - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Plant Nacogdoches
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Earnings before income taxes	$ 0		$ 16
Plant Mankato
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Earnings before income taxes	$ 12	$ 2	$ 20

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ACQUISITIONS AND DISPOSITIONS - Southern Company Gas Narrative (Details) - SOUTHERN Co GAS - USD ($) $ in Millions	Mar. 24, 2020	Sep. 30, 2021	Feb. 28, 2021
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Pivotal Home Solutions
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from divestiture of businesses, net of cash divested	$ 178
Pivotal LNG | Scenario, Forecast
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Contingent milestone payment, amount		$ 5	$ 5

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SEGMENT AND RELATED INFORMATION - Narrative (Details) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020 USD ($) state	Sep. 30, 2019 USD ($)	Sep. 30, 2020 USD ($) segment state	Sep. 30, 2019 USD ($)
Segment Reporting Information [Line Items]
Number of states in which entity operates | state	3		3
Operating revenues	$ 5,755	$ 6,282	$ 15,771	$ 17,415
SOUTHERN POWER CO
Segment Reporting Information [Line Items]
Operating revenues	332	372	851	980
SOUTHERN POWER CO | Traditional Electric Operating Companies | Wholesale revenues, affiliates
Segment Reporting Information [Line Items]
Operating revenues	$ 101	116	$ 279	320
SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Number of states in which entity operates | state	4		4
Operating revenues	$ 950	913	$ 3,506	4,093
Number of reportable segments | segment			4
SOUTHERN Co GAS | Traditional Electric Operating Companies | Natural gas
Segment Reporting Information [Line Items]
Operating revenues		9		13
SOUTHERN Co GAS | SOUTHERN POWER CO | Natural gas
Segment Reporting Information [Line Items]
Operating revenues	$ 9	$ 20	$ 22	$ 53
Southern Natural Gas Company, LLC | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Ownership percentage, equity method investment	50.00%		50.00%
PennEast Pipelines | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Ownership percentage, equity method investment	20.00%		20.00%
Dalton Pipeline | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Ownership percentage, equity method investment	50.00%		50.00%
Atlantic Coast Pipeline | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Ownership percentage, equity method investment	5.00%		5.00%

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SEGMENT AND RELATED INFORMATION - Financial Data for Business Segments (Details) - USD ($) $ in Millions		3 Months Ended			9 Months Ended
	Jan. 17, 2020	Sep. 30, 2020	Jun. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019
Segment Reporting Information [Line Items]
Operating revenues		$ 5,620		$ 5,995	$ 15,258	$ 16,505
Segment net income (loss)		1,251		1,316	2,732	4,298
Goodwill		5,280			5,280		$ 5,280
Total assets		123,158			123,158		118,700
Leveraged lease investments impairment loss		0	$ 154	0	154	0
Leveraged lease investments impairment loss, net of tax			$ 74
Impairment charges		0		110	0	142
Preliminary gain on sale					36	2,517
SOUTHERN POWER CO
Segment Reporting Information [Line Items]
Operating revenues		523		574	1,337	1,527
Segment net income (loss)		74		86	212	316
Total assets		13,424			13,424		14,300
Preliminary gain on sale					39	24
SOUTHERN POWER CO | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Plant Mankato
Segment Reporting Information [Line Items]
Gain on sale					39
Gain on sale, net of tax					23
Preliminary gain on sale	$ 39
Preliminary gain on sale, net of tax	$ 23
SOUTHERN POWER CO | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Plant Nacogdoches
Segment Reporting Information [Line Items]
Preliminary gain on sale				23
Preliminary gain on sale, net of tax				88
SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues		477		498	2,362	2,661
Segment net income (loss)		14		(29)	360	347
Goodwill		5,015			5,015		5,015
Total assets		21,932			21,932		21,687
Impairment charges		0		92	0	92
Impairment charges, net of tax				65		65
GEORGIA POWER CO
Segment Reporting Information [Line Items]
Operating revenues		2,617		2,755	6,371	6,706
Total assets		47,046			47,046		44,541
Electric Utilities
Segment Reporting Information [Line Items]
Operating revenues		5,049		5,363	12,628	13,448
Segment net income (loss)		1,358		1,459	2,783	3,035
Goodwill		2			2		2
Total assets		97,971			97,971		94,650
SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues		477		498	2,362	2,661
All Other
Segment Reporting Information [Line Items]
Leveraged lease investments impairment loss					154
Leveraged lease investments impairment loss, net of tax					74
All Other | Disposal Group, Disposed of by Sale, Not Discontinued Operations | GULF POWER CO
Segment Reporting Information [Line Items]
Impairment charges				18		50
Preliminary pre-tax gain on sale						2,500
Preliminary after-tax gain on sale						1,300
Gas Distribution Operations | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Goodwill		4,034			4,034		4,034
Wholesale Gas Services | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues		(51)		(2)	(19)	132
Gas Marketing Services | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Goodwill		981			981		981
Operating Segments | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues		475		493	2,363	2,670
Segment net income (loss)		21		30	372	406
Total assets		22,435			22,435		22,228
Operating Segments | Traditional Electric Operating Companies | Electric Utilities
Segment Reporting Information [Line Items]
Operating revenues		4,629		4,908	11,576	12,252
Segment net income (loss)		1,284		1,373	2,571	2,719
Goodwill		0			0		0
Total assets		85,218			85,218		81,063
Operating Segments | SOUTHERN POWER CO | Electric Utilities
Segment Reporting Information [Line Items]
Operating revenues		523		574	1,337	1,527
Segment net income (loss)		74		86	212	316
Goodwill		2			2		2
Total assets		13,424			13,424		14,300
Operating Segments | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues		477		498	2,362	2,661
Segment net income (loss)		14		(29)	360	347
Goodwill		5,015			5,015		5,015
Total assets		21,932			21,932		21,687
Operating Segments | All Other
Segment Reporting Information [Line Items]
Operating revenues		132		146	380	514
Segment net income (loss)		(122)		(110)	(420)	931
Goodwill		263			263		263
Total assets		4,116			4,116		3,511
Operating Segments | All Other | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues		8		10	24	34
Segment net income (loss)		(7)		(59)	(12)	(59)
Total assets		10,979			10,979		10,759
Operating Segments | Gas Distribution Operations | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues		479		448	2,086	2,188
Segment net income (loss)		46		37	284	228
Total assets		18,715			18,715		18,204
Operating Segments | Gas Pipeline Investments | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues		8		8	24	24
Segment net income (loss)		23		6	74	63
Total assets		1,609			1,609		1,678
Operating Segments | Wholesale Gas Services | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues		(51)		(2)	(19)	132
Segment net income (loss)		(45)		(9)	(45)	61
Total assets		650			650		850
Operating Segments | Gas Marketing Services | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues		39		39	272	326
Segment net income (loss)		(3)		(4)	59	54
Total assets		1,461			1,461		1,496
Eliminations
Segment Reporting Information [Line Items]
Operating revenues		(38)		(12)	(112)	(118)
Segment net income (loss)		1		(4)	9	(15)
Goodwill		0			0		0
Total assets		(861)			(861)		(1,148)
Eliminations | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues		(6)		(5)	(25)	(43)
Segment net income (loss)		0		0	0	0
Total assets		(11,482)			(11,482)		(11,300)
Eliminations | Electric Utilities
Segment Reporting Information [Line Items]
Operating revenues		(103)		(119)	(285)	(331)
Segment net income (loss)		0		$ 0	0	$ 0
Goodwill		0			0		0
Total assets		(671)			(671)		$ (713)
Plant Vogtle Units 3 And 4 | GEORGIA POWER CO
Segment Reporting Information [Line Items]
Estimated loss on Plant Vogtle Units 3 and 4		149			149
Estimated loss on plants under construction, after tax		$ 111			$ 111

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SEGMENT AND RELATED INFORMATION - Financial Data for Products and Services (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Concentration Risk [Line Items]
Operating revenues	$ 5,620	$ 5,995	$ 15,258	$ 16,505
Less Gross Gas Costs	71	79	654	956
Impairment charges	0	110	0	142
Retail
Concentration Risk [Line Items]
Operating revenues	4,243	4,512	10,503	11,136
Wholesale
Concentration Risk [Line Items]
Operating revenues	584	625	1,473	1,667
Other
Concentration Risk [Line Items]
Operating revenues	164	163	484	492
Electric Utilities' Revenues
Concentration Risk [Line Items]
Operating revenues	5,049	5,363	12,628	13,448
Electric Utilities' Revenues | Retail
Concentration Risk [Line Items]
Operating revenues	4,243	4,512	10,503	11,136
Electric Utilities' Revenues | Wholesale
Concentration Risk [Line Items]
Operating revenues	584	625	1,473	1,667
Electric Utilities' Revenues | Other
Concentration Risk [Line Items]
Operating revenues	222	226	652	645
Southern Company Gas' Revenues
Concentration Risk [Line Items]
Operating revenues	477	498	2,362	2,661
Southern Company Gas' Revenues | Gas Distribution Operations
Concentration Risk [Line Items]
Operating revenues	476	445	2,072	2,169
Southern Company Gas' Revenues | Wholesale Gas Services
Concentration Risk [Line Items]
Operating revenues	(51)	(2)	(19)	132
Southern Company Gas' Revenues | Gas Marketing Services
Concentration Risk [Line Items]
Operating revenues	39	39	272	326
Southern Company Gas' Revenues | Other
Concentration Risk [Line Items]
Operating revenues	13	16	37	34
Southern Company Gas' Revenues
Concentration Risk [Line Items]
Operating revenues	477	498	2,362	2,661
Impairment charges	0	92	0	92
Impairment charges, net of tax		65		65
Southern Company Gas' Revenues | Wholesale Gas Services
Concentration Risk [Line Items]
Operating revenues	(51)	(2)	(19)	132
Less Gross Gas Costs	1,134	1,212	3,189	4,378
Third Party Gross Revenues | Southern Company Gas' Revenues | Wholesale Gas Services
Concentration Risk [Line Items]
Operating revenues	1,050	1,138	3,089	4,287
Intercompany Revenues | Southern Company Gas' Revenues | Wholesale Gas Services
Concentration Risk [Line Items]
Operating revenues	33	72	81	223
Total Gross Revenues | Southern Company Gas' Revenues | Wholesale Gas Services
Concentration Risk [Line Items]
Operating revenues	$ 1,083	$ 1,210	$ 3,170	$ 4,510